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DOT-OST-2002-12210-0004 | Notice | "2002-05-29T04:00:00" | Notice of Action Taken re: American Airlines, Inc., United Air Lines, Inc. and Delta Air Lines, Inc. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Issued by the Department of Transportation on May 29, 2002
NOTICE OF ACTION TAKEN -- DOCKETS OST-2000-7149, OST-2002-12210, &
OST-2002-12183
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applications of American Airlines, Inc., Dockets: OST-2000-7149 and
OST-2002-12210, filed 4/29/2002;
United Air Lines, Inc., Docket: OST-2000-7149, filed 4/26/2002; and
Delta Air Lines, Inc., Docket: OST-2002-12183, filed 4/24/2001
XX Allocation of U.S.-Ghana Frequencies.
American, United, and Delta each request weekly frequencies to serve the
U.S.-Ghana market.
Docket OST-2000-7149: American requests four weekly frequencies to
operate third-country code-share services between the United States and
Ghana, by placing American’s designator code on Crossair Ltd., d/b/a
Swiss, between Zurich and Accra, Ghana, via Lagos, Nigeria, carrying
U.S.-Lagos and U.S.-Ghana passengers connecting at Zurich from
American’s and Swiss’s U.S. gateways.
Docket OST-2000-7149: United requests two weekly frequencies to operate
third-country code-share services between the United States and Ghana,
by placing United’s designator code on Lufthansa German Airlines
(Lufthansa), between the United States and Accra, Ghana, via Frankfurt,
through the intermediate point of Lagos, Nigeria.
Docket OST-2002-12183: Delta requests four weekly frequencies to
operate third-country code-share services between the United States and
Ghana, by placing Delta’s designator code on the flights of
Alitalia-Linee Aeree Italiane S.p.A., between Milan, Italy, and Accra,
Ghana.
XX Exemption for American Airlines, Inc., under 49 U.S.C. 40109 to
provide the following service:
Docket OST-2002-12210: Scheduled foreign air transportation of persons,
property, and mail between points in the United States and points in
Nigeria and Ghana, with the right to integrate such authority with
American’s certificates of public convenience and necessary and other
exemptions.
XX Motion of American Airlines, Inc., to withdraw its application as
follows:
Docket OST-2000-7149: American filed a motion on April 29, 2002, to
dismiss its April 14, 2000, application in this docket, to the extent
the carrier requested U.S.-Ghana code-share frequencies under a
code-share arrangement with British Airways.
Applicant reps: Carl B. Nelson, Jr., for American (202) 496-5647, Robert
E. Cohn for Delta (202) 663-8060; and Jeffrey A. Manley for United (202)
663-6670 DOT Analyst: Linda L. Lundell (202) 366-2336
D I S P O S I T I O N
XX Granted (see below).
The above action granting frequency allocations, in Dockets
OST-2000-7149 and OST-2002-12183, was effective when
taken: May 28, 2002, and will remain in effect indefinitely, subject
to the conditions described below.
The above action granting exemption authority to American Airlines,
Inc., in Docket OST-2002-12210, for U.S.-Nigeria and U.S.-Ghana
services, including route integration authority, was effective when
taken: May 28, 2002, through May 28, 2004, or until 90 days after final
Department action on a corresponding certification application,
whichever occurs earlier.
The above action granting the request of American Airlines, Inc., to
dismiss its April 14, 2000, application in Docket OST-2000-7149 was
effective when taken: May 28, 2002.
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the aviation agreements
between the United States and Ghana, and the United States and Nigeria.
Except to the extent exempted or waived, the authority for each carrier
is subject to the terms, conditions, and limitations indicated:
XX Each holder’s certificates of public convenience and necessity
XX Statements of Authorization for American/Swiss code-share operations
dated
dated April 23, 2002; Delta/Alitalia code-share operations dated
October 27, 2001; and
United/Lufthansa code-share operations dated April 8, 1998, and
conditions therein.
XX Standard Exemption Conditions (attached)
________________________________________________________________________
____________________
Background: Under the U.S.-Ghana aviation agreement, U.S. carriers may
operate a total of 27 weekly combination frequencies, of which no more
than 14 may be provided with the airlines’ own aircraft. Currently, a
total of 16 frequencies are held as follows: Northwest=7,
Continental=7, and United=2. Thus, 11 frequencies are available now for
allocation. The captioned applicants have requested a total of 10
frequencies, meaning that these requests do not exceed the frequencies
available to U.S. carriers under the agreement, with one remaining
available for future allocation.
Conditions: Consistent with our standard practice, the frequency
allocations granted are subject to the condition that they will expire
automatically and the frequencies will revert automatically to the
Department for reallocation if they are not used for a period of 90
days. As each of the carriers authorized has proposed to commence
services immediately, the 90-day dormancy period will begin on the issue
date of this notice.
Route Integration Condition for American Airlines: The route
integration authority granted to American Airlines, Inc., is subject to
the condition that any service provided under this exemption shall be
consistent with all applicable agreements between the United States and
the foreign countries involved. Furthermore, (a) nothing in the award
of the route integration authority granted should be construed as
conferring upon American rights (including fifth-freedom intermediate
and/or beyond rights) to serve markets where U.S. carrier entry is
limited unless the carrier notifies the Department of its intent to
serve such a market and unless and until the Department has completed
any necessary carrier selection procedures to determine which carrier(s)
should be authorized to exercise such rights; and (b) should there be a
request by any carrier to use the limited-entry route rights that are
included in American’s authority by virtue of the route integration
exemption granted here, but that are not being used by American, the
holding of such authority by route integration will not be construed as
providing any preference for American in a competitive carrier selection
proceeding to determine which carrier(s) should be entitled to use the
authority at issue.
Remarks: United filed an answer to American’s April 29, 2002,
applications (in Dockets OST-2000-7149 and OST-2002-12210); American
filed an answer to United’s April 26, 2002, application (in Docket
OST-2000-7149); United and American each filed answers to Delta’s
April 24, 2002, application (in Docket OST-2002-12183); and Delta filed
a consolidated reply to the answers of United and American (in Docket
OST-2002-12183). In these responses, the carriers stated that they had
no objection to the other applications filed so long as their own
application for Ghana frequencies was granted contemporaneously.
________________________________________________________________________
________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the authority was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted or dismissed, we denied all requests in the
referenced Dockets. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/report_aviation.asp
APPENDIX A
U.S. CARRIER
Standard Exemption Conditions
In the conduct of operations authorized by the attached order, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250 (for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying that coverage to the Department, contained in 14 CFR 205;
(5) Comply with the requirements of 14 CFR 203, concerning waiver of
Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration (FAA) Regulations, and with all U.S. Government
requirements concerning security; and
(7) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department of Transportation, with all applicable orders and regulations
of other U.S. agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
By Notice of Action Taken dated July 13, 2000, we deferred action on
American’s April 14, 2000 application, pending the Department’s
action on the underlying code-share arrangement between American and
British Airways in Docket OST-99-6507. By Order 2002-4-4, April 4,
2002, we granted the motion of American and British Airways to dismiss
the code-share application in Docket OST-99-6507. We will now grant the
April 29, 2002 American motion to dismiss in Docket OST-2000-7149.
On April 3, 2003, five additional frequencies become available (no
more than 21 of which may be provided with the airlines’ own
aircraft), and on April 1, 2004, frequency restrictions are eliminated
(no more than 21 of which may be provided with the airlines’ own
aircraft).
| dot | 2024-06-07T20:31:39.121438 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12210-0004/content.doc"
} |
DOT-OST-2002-12210-0006 | Notice | "2002-08-23T04:00:00" | Notice of Action Taken re: American Airlines, Inc. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Issued by the Department of Transportation on August 23, 2002
NOTICE OF ACTION TAKEN -- DOCKETS OST-2002-12210 &
2000-7149
_____________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Application of American Airlines, Inc. filed 8/8/02 for:
XX Waiver from dormancy condition:
By Notice of Action Taken dated May 29, 2002, the Department granted
American Airlines four weekly combination frequencies to provide
third-country code-share services in the U.S.-Ghana market, pursuant to
a code-share arrangement with Swiss International Air Lines, Ltd., via
Zurich Switzerland and Lagos, Nigeria. The frequencies are subject to
the condition that they will expire automatically and revert to the
Department for reallocation if they are not used for a period of 90
days. Under the terms of the Notice of Action Taken, American’s
frequency allocation would automatically expire if American does not
begin service by August 28, 2002. American and Swiss have applied to
the Government of Ghana for required authorizations and expect to
receive them shortly; however, American seeks a waiver from the 90-day
dormancy condition through October 28, 2002, to protect against the
possibility that the authorizations may not be ready in time to
implement the service by August 28, 2002.
Applicant rep.: Carl B. Nelson, Jr., 202-496-5647 DOT analyst:
Sylvia Moore, 202-366-6519
DISPOSITION
XX Granted (see Remarks)
The above action was effective when taken: August 23, 2002, through
October 28, 2002
XX Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
______________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; and (2) grant of the waiver was consistent with the public
interest. To the extent not granted, we denied all requests in the
referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
American's waiver from the dormancy condition is effective through
October 28, 2002, or until the date on which American begins service
with each of the frequencies, whichever occurs earlier. As to any
frequency with which American does not begin service by October 28,
2002, its frequency allocation with respect to that frequency expires
automatically.
| dot | 2024-06-07T20:31:39.123585 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12210-0006/content.doc"
} |
DOT-OST-2002-12211-0002 | Notice | "2002-05-30T04:00:00" | Notice of Action Taken re: MN Airlines, LLC d/b/a Sun Country Airlines | UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on May 30, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-12211
________________________________________________________________________
___________________This serves as notice to the public of the action
described below, taken by the Department official indicated (no
additional confirming order will be issued in this matter).
Application of MN AIRLINES, LLC d/b/a SUN COUNTRY AIRLINES filed
5/3/02, for:
XX Exemption for two years under 49 U.S.C. 40109 to provide the
following service:
Scheduled foreign air transportation of persons, property, and mail
between Minneapolis/St. Paul, Minnesota, on the one hand, and Cancun,
Cozumel, Puerto Vallarta, Mazatlan, Ixtapa/Zihuatanejo, and Manzanillo,
Mexico, on the other hand; and between Dallas/Ft. Worth, Texas, on the
one hand, and Cancun, Cozumel, and Puerto Vallarta, Mexico, on the other
hand. Sun Country also requests authority to integrate this service
with other exemption and certificate authorities held by Sun Country.
Sun Country states that it will provide seasonal services in all of the
subject markets.
Applicant rep: Ed Faberman (202) 639-7500 DOT Analyst: Linda Lundell
(202) 366-2336
D I S P O S I T I O N
XX Granted (subject to conditions, see below)
The authority granted was effective when taken: May 30, 2002, through
May 30, 2004, or until 90 days after final Department action on a
corresponding certificate application, whichever occurs earlier.
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the aviation agreement
between the United States and Mexico.
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated:
XX Holder’s certificates of public convenience and necessity
XX Standard Exemption Conditions (attached)
________________________________________________________________________
__________
Conditions: The U.S.-Mexico exemption authority granted is subject to
the dormancy notice requirements set forth in condition 7 of Appendix A
of Order 88-10-2. Consistent with our standard practice, the dormancy
notice period will begin on Sun Country’s proposed startup dates of
December 20, 2002, for the Minneapolis/St. Paul-Cancun/Puerto
Vallarta/Mazatlan markets;
December 21, 2002, for the Minneapolis/St.
Paul-Cozumel/Ixtapa/Zihuatanejo markets; January 21, 2003, for the
Minneapolis/St. Paul-Manzanillo market; October 17, 2002, for the
Dallas/Ft. Worth-
2
Cancun market; October 18, 2002, for the Dallas/Ft. Worth-Cozumel market
and December 18, 2002, for the Dallas/Ft. Worth-Puerto Vallarta market.
The route integration authority granted to Sun Country is subject to the
condition that any service provided under this exemption shall be
consistent with all applicable agreements between the United States and
the foreign countries involved. Furthermore, (a) nothing in the award
of the route integration authority requested should be construed as
conferring upon Sun Country additional rights (including fifth-freedom
intermediate and/or beyond rights) to serve markets where U.S. carrier
entry is limited unless Sun Country notifies the Department of its
intent to serve such a market and unless and until the Department has
completed any necessary carrier selection procedures to determine which
carrier(s) should be authorized to exercise such rights); (b) should
there be a request by any carrier to use the limited-entry route rights
that are included in Sun Country’s authority by virtue of the route
integration exemption granted here, but that are not then being used by
Sun Country, the holding of such authority by route integration will not
be considered as providing any preference for Sun Country in a
competitive carrier selection proceeding to determine which carrier(s)
should be entitled to use the authority at issue.
________________________________________________________________________
________________________________________
On the basis of data officially noticeable under Rule 24(g) of the
Department’s regulations, we found the applicant qualified to provide
the services authorized.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the application was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted, we denied all requests in the referenced
Docket. We may amend, modify, or revoke the authority granted in this
Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
APPENDIX A
U.S. CARRIER
Standard Exemption Conditions
In the conduct of operations authorized by the attached notice, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250 (for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying that coverage to the Department, contained in 14 CFR 205;
(5) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration (FAA) Regulations, and with all U.S. Government
requirements concerning security; and
(7) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department of Transportation, with all applicable orders and regulations
of other U.S. agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
| dot | 2024-06-07T20:31:39.125756 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12211-0002/content.doc"
} |
DOT-OST-2002-12477-0001 | Notice | "2002-06-10T04:00:00" | Notice of Termination of Service at Youngstown, Ohio | BEFORE THE
DEPARTMENT OF TRANSPORTATION
WASHINGTON, D.C.
Notice of
MESABA AVIATION, INC.
d/b/a MESABA AIRLINES
of intent to terminate service at Youngstown,
Ohio pursuant to 49 U.S.C. § 41734
and 14 C.F.R. § 323
)
)
)
)
)
)
)
)
)
) Docket OST-02-
Dated: June 10, 2002
NOTICE OF TERMINATION OF SERVICE AT
YOUNGSTOWN, OHIO
Mesaba Aviation, Inc. d/b/a Mesaba Airlines (“Mesaba”) hereby
submits notice, pursuant to 49 U.S.C § 41734 and 14 C.F.R. § 323.3, of
its intent to terminate service to Youngstown, Ohio, effective September
8, 2002. Mesaba provides this service as Northwest Airlink. In support
of this Notice, Mesaba states the following:
1. Mesaba is a certificated air carrier, whose corporate office is
located at:
7501 26th Avenue South
Minneapolis, MN 55450
(612) 726-5151.
Communications with respect to this Notice should be directed to:
Robert E. Weil
Vice President and Chief Financial Officer
Mesaba Airlines
7501 26th Avenue South
Minneapolis, MN 55450
(612) 726-5151
FAX: (612) 726-5168
2. No other carrier is currently serving Youngstown from a large or
medium hub. The Department, moreover, has determined that it cannot
require any carrier to continue service beyond the termination period
because Youngstown is located only 56 highway miles from a large hub
airport: Pittsburgh. See DOT Order 99-11-21, at 2-3 (Dec. 3, 1999).
3. The routing and schedule of the service that Mesaba is terminating on
September 8, 2002 is as follows:
From Departure To Arrival Frequency
DTW 13:50 YNG 15:42 Daily one stop via CAK
DTW 19:50 YNG 20:52 Daily one stop via CAK
YNG 16:05 DTW 17:59 Daily one stop via CAK
YNG 07:30 DTW 09:25 Daily one stop via CAK
4. Mesaba operates these flights with Saab SF340 aircraft (34 passenger
seats).
5. Mesaba intends to terminate the service on September 8, 2002.
6. In 1983, the Department determined that the level of essential air
service for Youngstown was a minimum of two daily roundtrips to/from
Chicago and two daily roundtrips to/from Pittsburgh. See DOT Order
83-11-19 (Nov. 4, 1983). This Order required that the Pittsburgh
service must be provided on a nonstop basis, while the Chicago service
may be provided on a two-stop basis. Id. Subsequently, in 1999, the
Department amended the 1983 essential air service requirement to
recognize service to any large or medium hub. DOT Order 99-11-21 (Dec.
3, 1999). The Department also determined that it could not subsidize
any carrier serving Youngstown because this community was 56 highway
miles from Pittsburgh and, therefore, could not require any carrier to
continue serving Youngstown beyond the 90-day termination notice period.
Id. The Department, however, continued to require notice of the
termination, and Mesaba is complying with this notice requirement.
7. The effective date of this Notice is June 10, 2002. Objections to
this Notice are due within 20 days of this Notice or on July 1, 2002.
8. As required by 14 C.F.R. § 323.7(a), this Notice is being served
upon all persons listed on the attached service list.
Respectfully submitted,
/s/ Robert E. Weil /s/
Robert E. Weil
Vice President and Chief Financial Officer
MESABA AIRLINES
7501 26TH Avenue South
Minneapolis, MS 55450
(612) 726-5151
Dated: June 10, 2002
SERVICE LIST
On this 10th day of June 2002, a copy of this NOTICE OF TERMINATION was
served by first class mail, postage prepaid, upon each of the persons
below:
Dennis DeVany, Chief
EAS and Domestic Analysis, X-53
U.S. Department of Transportation
400 Seventh Street, S.W.
Room 6417I
Washington, D.C. 20590
Thomas P. Nolan, Director
Youngstown-Warren Regional Airport
1453 Youngstown Kingsville Road, N.E.
Vienna, OH 44473
George McKelvey, Mayor
City of Youngstown
120 Market Street
Youngstown, OH 44503
Patricia E. Davis, Postmaster
Youngstown Post Office
99 South Walnut Street
Youngstown, OH 44501
(…continued)
(continued…)
NOTICE OF TERMINATION OF
MESABA AIRLINES
Page PAGE \* MERGEFORMAT 3
PAGE 2
| dot | 2024-06-07T20:31:39.131077 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12477-0001/content.doc"
} |
DOT-OST-2002-12481-0002 | Notice | "2002-07-03T04:00:00" | Notice of Action Taken re: US Airways, Inc. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Issued by the Department of Transportation on July 3, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-12481
________________________________________________________________________
_________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Application of US Airways, Inc. filed 6/11/2002 for:
XX Exemption under 49 U.S.C. 40109 to provide the following service:
Scheduled foreign air transportation of persons, property, and mail
between Washington, D.C., and Nassau, The Bahamas, for a period of two
years.
Applicant rep: Joel Stephen Burton, 202-383-5300 DOT Analyst:
Gerald Caolo, 202-366-2406
D I S P O S I T I O N
XX Granted
The above action was effective when taken: July 3, 2002, through July
3, 2004
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the U.S.-U.K. Air Services
Agreement of 1946, as amended, to which The Bahamas acceded upon its
independence.
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated: XX Holder’s
certificates of public convenience and necessity
XX Standard exemption conditions (attached)
________________________________________________________________________
______________
On the basis of data officially noticeable under Rule 24(g) of the
Department's regulations, we found the applicant qualified to provide
the services authorized.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that
(1) our action was consistent with Department policy; (2) grant of the
exemption authority was consistent with the public interest; and (3)
grant of the authority would not constitute a major regulatory action
under the Energy Policy and Conservation Act of 1975. To the extent not
granted, we denied all requests in the referenced Docket. We may amend,
modify, or revoke the authority granted in this Notice at any time
without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
APPENDIX
U.S. Carrier
Standard Exemption Conditions
In the conduct of operations authorized by the attached notice, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each
country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250
(for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying
that coverage to the Department, contained in 14 CFR 205;
(5) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR 203, concerning
waiver of Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration Regulations and with all U.S. Government requirements
concerning security; and
(7) Comply with such other reasonable terms, conditions, and
limitations required by
the public interest as may be prescribed by the Department of
Transportation, with all applicable orders and regulations of other U.S.
agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
| dot | 2024-06-07T20:31:39.134324 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12481-0002/content.doc"
} |
DOT-OST-2002-12496-0001-0001 | Notice | "2002-06-13T04:00:00" | Notice - U.S.-Vietnam Third-Country Code-Share Opportunity |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Docket: OST-2002-12496 Served: June 13, 2002
NOTICE
U.S.-Vietnam Third-Country Code-Share Opportunity
By this notice we invite all U.S. certificated air carriers interested
in using seven weekly frequencies and a third-country code-share
opportunity in the U.S.-Vietnam market to file applications as specified
below in the captioned docket.
The Memorandum of Discussions (MOD) signed in March 2000 by the United
States and Vietnam, states the intent of the respective authorities to
allow, inter alia, third-country code-sharing of passenger air
transportation in the U.S.-Vietnam market (via intermediate points) on
the basis of comity and reciprocity. Specifically, the MOD provides
that up to three cooperative marketing arrangements “between any
number of U.S. airlines and any number of third-country airlines” may
be authorized. The code-share arrangements may serve between any points
in the United States, on the one hand, and up to three Vietnamese points
selected by the United States (via any intermediate points), on the
other hand. The MOD provides for a total of 21 weekly round-trip
frequencies for use by U.S. carriers to operate these services.
By Order 2001-8-21, served August 23, 2001, the Department awarded Delta
Air Lines, Inc., Northwest Airlines, Inc. and United Air Lines, Inc.
seven weekly frequencies each for U.S.-Vietnam third-country
code-sharing services and granted the necessary regulatory authority for
the carriers to conduct their respective code-share services. Each
allocation of frequencies was subject to the condition that the
frequencies would revert automatically to the Department if unused for a
period of 90 days and the dormancy period began on the date of service
of the order (i.e., August 23, 2001). Subsequently, by Order
2001-11-15, the carriers were granted dormancy waivers due to the
circumstances of September 11, 2001, but that order noted that any
dormant limited-entry route authorities not resumed by April 1, 2002,
would revert automatically to the Department. Northwest Airlines did
not begin services to Vietnam by that date; thus, its frequencies have
reverted to the Department, and the designation as well as the
frequencies formerly held by Northwest are at issue before the
Department.
On May 9, 2002, American Airlines submitted an application for six
frequencies for third country services to Vietnam via Tokyo, Japan, with
Japan Airlines Company, Ltd. Subsequently, additional applications for
some or all of the available frequencies were filed in Docket 2000-7194,
the Docket for the previous allocation of frequencies in 2001, by Delta
Air Lines (with code-share partner Korean Airlines seeking six
frequencies), Northwest Airlines, Inc. (with code-share partner Malaysia
Airlines for reallocation of seven frequencies), and United Air Lines,
Inc. (with code-share partners All Nippon Airways Co. Ltd, and Thai
Airways International Public Co. Ltd. seeking seven frequencies).
Inasmuch as there are more requests for frequencies than there are
frequencies available, we will consolidate these requests (and related
pleadings thereto) into a new docket (noted in the heading of this
notice) to consider these requests as well as any other applications
that may be filed in response to this notice. We will allow carriers
with the pending requests to supplement their applications to provide
the information we are requiring for consideration.
We request by this notice that all U.S. air carriers interested in
making use of the code-share opportunity and related frequencies
described above file applications (or supplemented applications) with
the Department in the newly established docket no later than June 27,
2002. Answers to such applications should be filed no later than July
8, 2002. Replies to answers should be filed no later than July 15,
2002.
Carriers without the requisite operating authority should file
exemption/designation applications and requests for statements of
authorization to serve the affected markets in conjunction with the
foreign code-share carrier(s) involved. Carriers with the requisite
underlying authority and statements of authorization need only file
requests for the available code-share opportunity. All applications
should include, at a minimum, the following information: (a) the
proposed startup date; (b) the markets to be served, including the
number and identity of U.S. cities that would receive nonstop-to-nonstop
connections in the U.S.-Vietnan market, and the total elapsed travel
time (including layover time) for each flight between each initial point
of origin and each final destination in both directions (i.e. provide a
total elapsed round-trip travel time for each city pair and break-out
subtotals for the elapsed times on the U.S. to Vietnam flights and the
Vietnam to U.S. flights); (c) the number of frequencies to be provided
between the U.S. and Vietnam and the duration of service if not provided
on a year-round basis for each leg of the flights; (d) type of
aircraft, including the number of seats, to be used between the U.S. and
the intermediate point(s) and between the intermediate point(s) and
Vietnam; (e) the foreign code-share carrier involved, the country and
the specific intermediate point(s) over which the services will be
provided, and which carrier would be operating each leg of the flights;
(f) existing authority held to conduct the operations, if applicable;
and (g) assurance that the U.S. air carrier applicant has provided or
will provide the Department with the Compliance Statement referred to in
Section IV of the DOT Code-Share Safety Program Guidelines (issued
February 29, 2000) concerning a safety audit of the foreign air
carrier(s) involved. In addition, carriers must provide as a part of
their applications, copies of the relevant cooperative service
arrangements, if not already on file with the Department. Applicants
are free to submit any additional information that they believe will
help us in making our decision.
Except for the procedural dates, exemption applications should conform
to Part 302, Subpart C of our regulations (14 CFR Part 302). All
applications (for operating authority and/or designation) should be
filed with the Department of Transportation in the established docket,
Dockets and Media Management, Room PL-401, 400 Seventh Street, SW,
Washington, DC 20590.
We intend to allocate the available opportunities at issue based on the
applications and responsive pleadings filed in response to this notice.
We intend to make our decision using written, show-cause procedures in
accordance with Part 302 of our regulations (14 CFR Part 302).
We will authorize service of documents by facsimile and by electronic
mail. Carriers that are interested in such service, however, should
state if they want service by email and should provide interested
parties with their fax number and/or email address.
We will serve this notice on all U.S. certificated air carriers
operating large aircraft.
By:
PAUL L. GRETCH
Director
Office of International Aviation
(SEAL)
Dated: June 13, 2002
An electronic version of this document is available on the World Wide
Web at
http://dms.dot.gov//reports/reports_aviation.asp
The MOD does not contemplate direct service between the United States
and Vietnam.
The United States has selected the Vietnamese cities of Hanoi, Ho Chi
Minh City, and DaNang. The three points selected by the United States
may be changed subject to a 30-day advance notice requirement.
Delta’s code-share partner was Air France; Nortwest’s partners were
Malaysia Airlines and KLM Royal Dutch Airlines; and United’s partners
were All Nippon Airways Co., Ltd., Thai Airways International, and
Lufthansa German Airlines.
See Docket OST-2002-12301.
See Docket OST-2000-7194.
The original submission is to be unbound and without tabs on 8 ½" x 11"
white paper using dark ink (not green) to facilitate use of the
Department's docket imaging system. In the alternative, filers are
encouraged to use the electronic submission capability available through
the Dockets/DMS Internet site ( HYPERLINK "http://dms.dot.gov"
http://dms.dot.gov ) by following the instructions at the web site).
PAGE
PAGE 2
| dot | 2024-06-07T20:31:39.138080 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12496-0001-0001/content.doc"
} |
DOT-OST-2002-12496-0001-0002 | Notice | "2002-06-13T04:00:00" | Notice - U.S.-Vietnam Third-Country Code-Share Opportunity |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Docket: OST-2002-12496 Served: June 13, 2002
NOTICE
U.S.-Vietnam Third-Country Code-Share Opportunity
By this notice we invite all U.S. certificated air carriers interested
in using seven weekly frequencies and a third-country code-share
opportunity in the U.S.-Vietnam market to file applications as specified
below in the captioned docket.
The Memorandum of Discussions (MOD) signed in March 2000 by the United
States and Vietnam, states the intent of the respective authorities to
allow, inter alia, third-country code-sharing of passenger air
transportation in the U.S.-Vietnam market (via intermediate points) on
the basis of comity and reciprocity. Specifically, the MOD provides
that up to three cooperative marketing arrangements “between any
number of U.S. airlines and any number of third-country airlines” may
be authorized. The code-share arrangements may serve between any points
in the United States, on the one hand, and up to three Vietnamese points
selected by the United States (via any intermediate points), on the
other hand. The MOD provides for a total of 21 weekly round-trip
frequencies for use by U.S. carriers to operate these services.
By Order 2001-8-21, served August 23, 2001, the Department awarded Delta
Air Lines, Inc., Northwest Airlines, Inc. and United Air Lines, Inc.
seven weekly frequencies each for U.S.-Vietnam third-country
code-sharing services and granted the necessary regulatory authority for
the carriers to conduct their respective code-share services. Each
allocation of frequencies was subject to the condition that the
frequencies would revert automatically to the Department if unused for a
period of 90 days and the dormancy period began on the date of service
of the order (i.e., August 23, 2001). Subsequently, by Order
2001-11-15, the carriers were granted dormancy waivers due to the
circumstances of September 11, 2001, but that order noted that any
dormant limited-entry route authorities not resumed by April 1, 2002,
would revert automatically to the Department. Northwest Airlines did
not begin services to Vietnam by that date; thus, its frequencies have
reverted to the Department, and the designation as well as the
frequencies formerly held by Northwest are at issue before the
Department.
On May 9, 2002, American Airlines submitted an application for six
frequencies for third country services to Vietnam via Tokyo, Japan, with
Japan Airlines Company, Ltd. Subsequently, additional applications for
some or all of the available frequencies were filed in Docket 2000-7194,
the Docket for the previous allocation of frequencies in 2001, by Delta
Air Lines (with code-share partner Korean Airlines seeking six
frequencies), Northwest Airlines, Inc. (with code-share partner Malaysia
Airlines for reallocation of seven frequencies), and United Air Lines,
Inc. (with code-share partners All Nippon Airways Co. Ltd, and Thai
Airways International Public Co. Ltd. seeking seven frequencies).
Inasmuch as there are more requests for frequencies than there are
frequencies available, we will consolidate these requests (and related
pleadings thereto) into a new docket (noted in the heading of this
notice) to consider these requests as well as any other applications
that may be filed in response to this notice. We will allow carriers
with the pending requests to supplement their applications to provide
the information we are requiring for consideration.
We request by this notice that all U.S. air carriers interested in
making use of the code-share opportunity and related frequencies
described above file applications (or supplemented applications) with
the Department in the newly established docket no later than June 27,
2002. Answers to such applications should be filed no later than July
8, 2002. Replies to answers should be filed no later than July 15,
2002.
Carriers without the requisite operating authority should file
exemption/designation applications and requests for statements of
authorization to serve the affected markets in conjunction with the
foreign code-share carrier(s) involved. Carriers with the requisite
underlying authority and statements of authorization need only file
requests for the available code-share opportunity. All applications
should include, at a minimum, the following information: (a) the
proposed startup date; (b) the markets to be served, including the
number and identity of U.S. cities that would receive nonstop-to-nonstop
connections in the U.S.-Vietnan market, and the total elapsed travel
time (including layover time) for each flight between each initial point
of origin and each final destination in both directions (i.e. provide a
total elapsed round-trip travel time for each city pair and break-out
subtotals for the elapsed times on the U.S. to Vietnam flights and the
Vietnam to U.S. flights); (c) the number of frequencies to be provided
between the U.S. and Vietnam and the duration of service if not provided
on a year-round basis for each leg of the flights; (d) type of
aircraft, including the number of seats, to be used between the U.S. and
the intermediate point(s) and between the intermediate point(s) and
Vietnam; (e) the foreign code-share carrier involved, the country and
the specific intermediate point(s) over which the services will be
provided, and which carrier would be operating each leg of the flights;
(f) existing authority held to conduct the operations, if applicable;
and (g) assurance that the U.S. air carrier applicant has provided or
will provide the Department with the Compliance Statement referred to in
Section IV of the DOT Code-Share Safety Program Guidelines (issued
February 29, 2000) concerning a safety audit of the foreign air
carrier(s) involved. In addition, carriers must provide as a part of
their applications, copies of the relevant cooperative service
arrangements, if not already on file with the Department. Applicants
are free to submit any additional information that they believe will
help us in making our decision.
Except for the procedural dates, exemption applications should conform
to Part 302, Subpart C of our regulations (14 CFR Part 302). All
applications (for operating authority and/or designation) should be
filed with the Department of Transportation in the established docket,
Dockets and Media Management, Room PL-401, 400 Seventh Street, SW,
Washington, DC 20590.
We intend to allocate the available opportunities at issue based on the
applications and responsive pleadings filed in response to this notice.
We intend to make our decision using written, show-cause procedures in
accordance with Part 302 of our regulations (14 CFR Part 302).
We will authorize service of documents by facsimile and by electronic
mail. Carriers that are interested in such service, however, should
state if they want service by email and should provide interested
parties with their fax number and/or email address.
We will serve this notice on all U.S. certificated air carriers
operating large aircraft.
By:
PAUL L. GRETCH
Director
Office of International Aviation
(SEAL)
Dated: June 13, 2002
An electronic version of this document is available on the World Wide
Web at
http://dms.dot.gov//reports/reports_aviation.asp
The MOD does not contemplate direct service between the United States
and Vietnam.
The United States has selected the Vietnamese cities of Hanoi, Ho Chi
Minh City, and DaNang. The three points selected by the United States
may be changed subject to a 30-day advance notice requirement.
Delta’s code-share partner was Air France; Nortwest’s partners were
Malaysia Airlines and KLM Royal Dutch Airlines; and United’s partners
were All Nippon Airways Co., Ltd., Thai Airways International, and
Lufthansa German Airlines.
See Docket OST-2002-12301.
See Docket OST-2000-7194.
The original submission is to be unbound and without tabs on 8 ½" x 11"
white paper using dark ink (not green) to facilitate use of the
Department's docket imaging system. In the alternative, filers are
encouraged to use the electronic submission capability available through
the Dockets/DMS Internet site ( HYPERLINK "http://dms.dot.gov"
http://dms.dot.gov ) by following the instructions at the web site).
PAGE
PAGE 2
| dot | 2024-06-07T20:31:39.172787 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12496-0001-0002/content.doc"
} |
DOT-OST-2002-12496-0003-0001 | Notice | "2002-06-21T04:00:00" | Notice Revising Procedural Schedule | .
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
_______________________________
In the Matter of
U.S.-Vietnam Third-Country Code-Share Opportunity
Docket OST-2002-12496
________________________________
Served: June 21, 2002
NOTICE REVISING PROCEDURAL SCHEDULE
On June 13, 2002, the Department issued a Notice establishing a
procedural schedule in the above-captioned matter, whereby applications
or supplemented applications are due June 27, 2002, answers thereto are
due July 8, 2002, and replies are due July 15, 2002.
On June 17, 2002, American Airlines, Inc., Delta Air Lines, Inc.,
Northwest Airlines, Inc., and United Air Lines, Inc. (the “Movants”)
filed a joint motion to change the procedural dates in the
above-captioned matter.
The Movants request that the answer period established by the
Department’s June 13, 2002, Notice be changed from July 8, 2002, to
July 12, 2002, and that the reply date be changed from July 15, 2002, to
July 19, 2002. The Movants note that the present July 8 date falls on
the Monday following the long July 4 weekend and that in effect the
applicants would have only until July 3 to complete their answers absent
the extension requested. They state that in this proceeding, the
applicants’ answers constitute their principal opportunity to
demonstrate the comparative merits of their respective proposals and
that the requested extension will facilitate the development of a
complete record for the Department’s consideration, and will not
materially delay the Department’s decision.
The Movants have requested a modest extension for the answer and reply
periods. We believe, in the circumstances presented, that no interested
party will be harmed by grant of the requested extension.
Therefore, we shall, acting under authority assigned in 14 CFR 385.3,
require that answers in the above-captioned proceeding shall now be
filed no later than July 12, 2002, and replies shall now be filed no
later than July 19, 2002. As noted in the Department’s June 13, 2002,
Notice, service of documents may be by facsimile and by electronic mail.
We will serve this notice by facsimile on all carriers served with the
Department’s June 13, 2002, Notice.
By:
PAUL L. GRETCH
Director, Office of
International Aviation
(SEAL)
Dated: June 21, 2002
An electronic version of this notice is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_aviation.asp
| dot | 2024-06-07T20:31:39.175546 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12496-0003-0001/content.doc"
} |
DOT-OST-2002-12496-0003-0002 | Notice | "2002-06-21T04:00:00" | Notice Revising Procedural Schedule | .
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
_______________________________
In the Matter of
U.S.-Vietnam Third-Country Code-Share Opportunity
Docket OST-2002-12496
________________________________
Served: June 21, 2002
NOTICE REVISING PROCEDURAL SCHEDULE
On June 13, 2002, the Department issued a Notice establishing a
procedural schedule in the above-captioned matter, whereby applications
or supplemented applications are due June 27, 2002, answers thereto are
due July 8, 2002, and replies are due July 15, 2002.
On June 17, 2002, American Airlines, Inc., Delta Air Lines, Inc.,
Northwest Airlines, Inc., and United Air Lines, Inc. (the “Movants”)
filed a joint motion to change the procedural dates in the
above-captioned matter.
The Movants request that the answer period established by the
Department’s June 13, 2002, Notice be changed from July 8, 2002, to
July 12, 2002, and that the reply date be changed from July 15, 2002, to
July 19, 2002. The Movants note that the present July 8 date falls on
the Monday following the long July 4 weekend and that in effect the
applicants would have only until July 3 to complete their answers absent
the extension requested. They state that in this proceeding, the
applicants’ answers constitute their principal opportunity to
demonstrate the comparative merits of their respective proposals and
that the requested extension will facilitate the development of a
complete record for the Department’s consideration, and will not
materially delay the Department’s decision.
The Movants have requested a modest extension for the answer and reply
periods. We believe, in the circumstances presented, that no interested
party will be harmed by grant of the requested extension.
Therefore, we shall, acting under authority assigned in 14 CFR 385.3,
require that answers in the above-captioned proceeding shall now be
filed no later than July 12, 2002, and replies shall now be filed no
later than July 19, 2002. As noted in the Department’s June 13, 2002,
Notice, service of documents may be by facsimile and by electronic mail.
We will serve this notice by facsimile on all carriers served with the
Department’s June 13, 2002, Notice.
By:
PAUL L. GRETCH
Director, Office of
International Aviation
(SEAL)
Dated: June 21, 2002
An electronic version of this notice is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_aviation.asp
| dot | 2024-06-07T20:31:39.178130 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12496-0003-0002/content.doc"
} |
DOT-OST-2002-12502-0003 | Notice | "2002-06-21T04:00:00" | Notice of Action Taken re: Compania Mexicana de Aviacion, S.A. de C.V. and United Air Lines, Inc. | UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on June 21, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-12502
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Application of COMPANIA MEXICANA DE AVIACION, S.A. de C.V. (MEXICANA),
and UNITED AIR LINES, INC. (UNITED), filed 6/13/02, for:
XX Exemption for United for two years under 49 U.S.C. 40109 to provide
the following service:
Scheduled foreign air transportation of persons, property, and mail
between (1) Sacramento, California, and Guadalajara, Mexico; and (2)
Denver, Colorado, and Mexico City, Mexico. United intends to operate
this service under a code-share arrangement with Mexicana on flights
operated by Mexicana.
XX Statement of Authorization for Mexicana under Part 212 of the
Department’s Regulations to:
Display United’s “UA” designator code on flights operated by
Mexicana between Sacramento and Guadalajara, and between Denver and
Mexico City.
Applicant reps: Jeffrey Manley (United) (202) 663-6670 DOT Analyst:
Linda Lundell (202) 366-2336
Robert Papkin (Mexicana) (202) 626-6601
D I S P O S I T I O N
XX Granted (subject to conditions and remarks, see below)
The above action, granting exemption authority to United was effective
when taken: _June 20, 2002, through _June 20, 2004.
The above action, granting a statement of authorization to Mexicana was
effective when taken: June 20, 2002, and will remain in effect
indefinitely, subject to the conditions below.
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the aviation agreement
between the United States and Mexico.
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated:
XX United’s certificates of public convenience and necessity
XX Mexicana’s foreign air carrier permit
XX Standard Exemption Condtions for United
(attached)
(See next page)
2
Conditions/Remarks: The U.S.-Mexico exemption authority granted to
United is subject to the dormancy notice requirements set forth in
condition 7 of Appendix A of Order 88-10-2. The exemption authority
granted to United to serve the Sacramento-Guadalajara and Denver-Mexico
City markets is limited to operations conducted on a code-share basis
only.
The Statement of Authorization granted Mexicana is subject to the
following conditions:
The statement of authorization will remain in effect only as long as
United and Mexicana continue to hold the underlying authority to operate
the code-share services at issue, and the code-share agreement providing
for the code-share operations remains in effect.
United and Mexicana must promptly notify the Department (Office of
International Aviation) if the code-share agreement is no longer
effective or if the carriers decide to cease operating all of a portion
of the approved code-share services. (Such notice should be filed in
Docket OST-2002-12502.)
The code-sharing operations conducted under this authority must comply
with 14 CFR 257 and with any amendment to the Department’s regulations
concerning code-share arrangements that may be adopted. Notwithstanding
any provisions in the contract between the carriers, our approval here
is expressly conditioned upon the requirements that the subject foreign
air transportation be sold in the name of the carrier holding out such
service in computer reservation systems and elsewhere; that the carrier
selling such transportation (i.e., the carrier shown on the ticket)
accept responsibility for the entirety of the code-share journey for all
obligations established in its contract of carriage with the passenger;
and that the passenger liability of the operating carrier be unaffected.
Further, the operating carrier shall not permit the code of its U.S.
code-sharing carrier to be carried on any flight that enters, departs,
or transits the airspace of any area for whose airspace the Federal
Aviation Administration has issued a flight prohibition.
The authority granted here is specifically conditioned so that neither
United nor Mexicana shall give any force or effect to any contractual
provisions between themselves that are contrary to these conditions.
We may amend, modify, or revoke the authority granted at any time
without hearing, at our discretion.
We acted on this application without awaiting expiration of the 15-day
answer period with the consent of all parties served.
On the basis of data officially noticeable under Rule 24(g) of the
Department’s regulations, we found the applicant qualified to provide
the services authorized.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the application was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted, we denied all requests in the
referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time
without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
APPENDIX A
U.S. CARRIER
Standard Exemption Conditions
In the conduct of operations authorized by the attached notice, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250 (for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying that coverage to the Department, contained in 14 CFR 205;
(5) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR 203, concerning
waiver of Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration (FAA) Regulations, and with all U.S. Government
requirements concerning security; and
(7) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department of Transportation, with all applicable orders and regulations
of other U.S. agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
We expect this notification to be received within 10 days of such
non-effectiveness or of such decision.
| dot | 2024-06-07T20:31:39.180664 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-12502-0003/content.doc"
} |
DOT-OST-2002-12683-0006-0001 | Notice | "2002-08-01T04:00:00" | Notice |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Docket: OST-2002-12683 Served: August 1, 2002
NOTICE
By Order 2002-6-20, the Department instituted the 2002 U.S.-Brazil
All-Cargo Service Proceeding to select a carrier for an authorization to
be designated to serve the U.S.-Brazil all-cargo market and for
allocation of four U.S.-Brazil all-cargo frequencies under the
U.S.-Brazil aviation agreement. The instituting order established a
procedural schedule for the submission of evidentiary material needed by
the Department to make its selection(s), as follows: Applications by
July 19, 2002; Direct Exhibits by August 2; Rebuttal Exhibits by August
16; and Briefs by August 30. Gemini Air Cargo, Evergreen International
Airlines, and Amerijet International filed applications for the
available authorization and an allocation of frequencies.
On July 31, 2002, Amerijet filed a letter in the above-captioned docket,
served on all parties as well as Federal Express, United Parcel Service,
and Atlas Air/Polar Air Cargo, requesting that the Department require
each all-cargo carrier currently designated to provide service in the
U.S.-Brazil market (Federal Express, UPS, and Atlas/Polar) to submit, by
no later than August 9, a complete description of their services in the
U.S.-Brazil market for the period June 1, 2001 through May 31, 2002. In
the alternative, Amerijet states that the incumbent carriers may agree
to voluntarily submit the requested information for the record of the
case.
We will treat Amerijet’s letter as a motion under our regulations (14
CFR Part 302.11), which would normally allow seven days for answers
(i.e., August 9). However, to ensure that the issues raised by
Amerijet’s letter are addressed in an expedited manner, we will
require that answers to Amerijet’s letter be filed in the
above-referenced docket by Monday, August 5, 2002. Any replies shall be
filed by Tuesday, August 6, 2002.
We will authorize service of documents by facsimile and by electronic
mail. Carriers that are interested in such service, however, should
state if they want service by email and should provide interested
parties with their fax number and/or email address.
We will serve this notice on Gemini Air Cargo, Inc.; Evergreen
International Airlines, Inc.; Amerijet International, Inc.; Federal
Express Corporation; United Parcel Service Co.; and Atlas Air, Inc.
By:
Paul L. Gretch
Director, Office of International Aviation
(Seal)
Dated: August 1, 2002
An electronic version of this order is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_ aviation.asp
PAGE
PAGE 2
| dot | 2024-06-07T20:31:39.186698 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12683-0006-0001/content.doc"
} |
DOT-OST-2002-12683-0006-0002 | Notice | "2002-08-01T04:00:00" | Notice |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Docket: OST-2002-12683 Served: August 1, 2002
NOTICE
By Order 2002-6-20, the Department instituted the 2002 U.S.-Brazil
All-Cargo Service Proceeding to select a carrier for an authorization to
be designated to serve the U.S.-Brazil all-cargo market and for
allocation of four U.S.-Brazil all-cargo frequencies under the
U.S.-Brazil aviation agreement. The instituting order established a
procedural schedule for the submission of evidentiary material needed by
the Department to make its selection(s), as follows: Applications by
July 19, 2002; Direct Exhibits by August 2; Rebuttal Exhibits by August
16; and Briefs by August 30. Gemini Air Cargo, Evergreen International
Airlines, and Amerijet International filed applications for the
available authorization and an allocation of frequencies.
On July 31, 2002, Amerijet filed a letter in the above-captioned docket,
served on all parties as well as Federal Express, United Parcel Service,
and Atlas Air/Polar Air Cargo, requesting that the Department require
each all-cargo carrier currently designated to provide service in the
U.S.-Brazil market (Federal Express, UPS, and Atlas/Polar) to submit, by
no later than August 9, a complete description of their services in the
U.S.-Brazil market for the period June 1, 2001 through May 31, 2002. In
the alternative, Amerijet states that the incumbent carriers may agree
to voluntarily submit the requested information for the record of the
case.
We will treat Amerijet’s letter as a motion under our regulations (14
CFR Part 302.11), which would normally allow seven days for answers
(i.e., August 9). However, to ensure that the issues raised by
Amerijet’s letter are addressed in an expedited manner, we will
require that answers to Amerijet’s letter be filed in the
above-referenced docket by Monday, August 5, 2002. Any replies shall be
filed by Tuesday, August 6, 2002.
We will authorize service of documents by facsimile and by electronic
mail. Carriers that are interested in such service, however, should
state if they want service by email and should provide interested
parties with their fax number and/or email address.
We will serve this notice on Gemini Air Cargo, Inc.; Evergreen
International Airlines, Inc.; Amerijet International, Inc.; Federal
Express Corporation; United Parcel Service Co.; and Atlas Air, Inc.
By:
Paul L. Gretch
Director, Office of International Aviation
(Seal)
Dated: August 1, 2002
An electronic version of this order is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_ aviation.asp
PAGE
PAGE 2
| dot | 2024-06-07T20:31:39.189184 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12683-0006-0002/content.doc"
} |
DOT-OST-2002-12683-0015-0001 | Notice | "2002-08-07T04:00:00" | Notice - In the Matter of the 2002 U.S.-Brazil All-Cargo Service Proceeding |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Docket: OST-2002-12683 Served: August 7, 2002
NOTICE
In the Matter of the 2002 U.S.-Brazil All-Cargo Service Proceeding
SUMMARY
By this Notice, we have decided to decline to require that incumbent
U.S.-Brazil all-cargo carriers report on their U.S.-Brazil frequency
utilization in the 2002 U.S.-Brazil All-Cargo Service Proceeding, Docket
OST-2002-12683.
DISCUSSION AND SUMMARY OF PLEADINGS
By Order 2002-6-20, the Department instituted the 2002 U.S.-Brazil
All-Cargo Service Proceeding to select a carrier for an authorization to
be designated to serve the U.S.-Brazil all-cargo market and for
allocation of four U.S.-Brazil all-cargo frequencies under the
U.S.-Brazil aviation agreement. The instituting order established a
procedural schedule for the submission of evidentiary material needed by
the Department to make its selection(s), as follows: Applications by
July 19, 2002; Direct Exhibits by August 2; Rebuttal Exhibits by August
16; and Briefs by August 30. Gemini Air Cargo, Evergreen International
Airlines, and Amerijet International filed applications for the
available authorization and an allocation of frequencies.
On July 31, 2002, Amerijet filed a letter in the above-captioned docket
requesting that the Department require each all-cargo carrier currently
designated to provide service in the U.S.-Brazil market (Federal
Express, UPS, and Atlas/Polar) to submit, by no later than August 9, a
complete description of their services in the U.S.-Brazil market for the
period June 1, 2001 through May 31, 2002. In the alternative, Amerijet
states that the incumbent carriers may agree to voluntarily submit the
requested information for the record of the case.
By Notice dated August 1, 2002, in this Docket, we stated that we would
treat Amerijet’s letter as a motion, and we required that answers to
Amerijet’s letter be filed by August 5, 2002 and replies by
August 6, 2002. Atlas/Polar and Evergreen filed answers. UPS,
Amerijet, and Atlas/Polar filed replies.
In general, Atlas/Polar and UPS are opposed to Amerijet’s request
whereas Evergreen supports the request.
In its letter, Amerijet states that a relevant consideration in this or
any other route proceeding is the degree to which incumbent carriers are
and have been using frequencies allocated to them. Amerijet maintains
that neither the Department nor the applicants in this case currently
have access to that information, and that the T-100 reports do not allow
the parties to determine completely and accurately the extent to which
the incumbent carriers are and have been using their frequencies.
Amerijet further indicates that dormancy information with respect to
frequency utilization is unreliable.
Amerijet states that the Department’s instituting order appears to
have recognized this issue when it required that any incumbent carrier
applicant include a complete description of its services in the market.
In this regard, Amerijet notes that this information was not submitted
since none of the incumbent carriers applied for additional frequencies.
To help minimize any burden on the incumbent carriers, Amerijet
requests that the incumbents submit the requested information by August
9, one week after directs and one week before rebuttals are due in this
proceeding.
Atlas/Polar state that Amerijet’s own letter indicates that the T-100
reports for the U.S.-Brazil market are available to all applicants in
the proceeding, and that Amerijet has failed to specify the manner in
which these T-100 reports are inadequate or how the information that
Amerijet seeks would enhance the record of the proceeding. Moreover,
Atlas/Polar contend that Amerijet’s request expresses only a vague,
general interest in determining U.S.-Brazil frequency usage, which does
not validate the request for new information requirements.
Atlas/Polar further argue that incumbent carrier frequencies are beyond
the scope of the proceeding. In this connection, Atlas/Polar state that
this case arose because the Department decided to replace Polar’s
Brazil designation and reallocate its four frequencies. Atlas/Polar
also note that the instituting order allowed for petitions for
reconsideration, and none were filed.
UPS argues that Amerijet’s request harkens back to the time of strict
regulation when incumbents were required to provide extensive
information about their existing services. UPS states that the burden
of producing the data, when viewed in relation to its complete lack of
relevance to the proceeding, warrants a denial of the request. UPS
maintains that any information regarding frequency usage, aircraft
routings, schedules, etc. has no bearing whatsoever on this proceeding
since none of the applicants has requested any frequencies now held by
incumbents. UPS also notes that it is too late in this proceeding for
the requested information to be of use to the applicants, and that
questions concerning confidentiality and business sensitive information
need to be considered.
Evergreen states that it supports Amerijet’s request, and that
information concerning existing services could prove useful to the
Department and the parties in this proceeding. Evergreen maintains that
specific issues such as the need for service to intermediate points and
interior U.S. points justify the filing of the requested information
even though incumbents do not seek to increase Brazil service.
Evergreen urges the Department to require incumbents to provide
operational information by month and by direction and to identify all
Brazilian, U.S., and third-country points in their single-plane,
U.S.-Brazil scheduled services for the period June 1, 2001 to May 31,
2002. Evergreen indicates that the Department required similar
information by its June 21, 2000 Notice in the last U.S.-Brazil
all-cargo proceeding.
In its reply, Atlas/Polar state that Evergreen’s support of
Amerijet’s request similarly makes no claim that incumbent operational
data would affect the applicants’ service proposals or the
Department’s decision in any way. While the Department required the
submission of U.S.-Brazil all-cargo frequency utilization data two years
ago, Atlas/Polar maintain that that precedent is not relevant here
because there has been no suggestion (let alone proof) that the
incumbents have not been using their frequencies, as was the case two
years ago. Atlas/Polar note that the Department has already determined
that Polar’s designation and four frequencies will be the issue of the
current Brazil proceeding.
In its reply, Amerijet states that historical precedent shows that in
virtually every proceeding where the issuance of additional certificates
is at issue, the incumbent carrier(s) are called upon to provide data
with respect to the market(s) at issue. Amerijet maintains that if, as
Atlas/Polar suggest, the T-100 reports are sufficient, then incumbent
carriers would never be called upon to submit market information in
route proceedings. According to Amerijet, it and the other applicants
in this case must be able to examine market information in the
possession of Atlas/Polar, FedEx, and UPS in order to best determine the
nature of the need for additional service in the relevant market and
sub-markets. Amerijet states that if, for example, the wide-body
operators in the market are not and have not been fully utilizing
frequencies, it is far more likely that the Department would support the
selection of a carrier such as Amerijet, which would not simply add new
additional capacity between major terminals, but would expand its base
scheduled system in the region into Brazil.
DECISION
This proceeding began shortly after the Department approved a de facto
route transfer between Atlas and Polar, but did not approve the transfer
of Polar’s Brazil designation and four frequencies. The Department
found that the transaction with respect to Polar’s Brazil authority
would not be consistent with the public interest, as it would have
resulted in half of the four available designations for all-cargo
service and over half of the 24 available frequencies in the U.S.-Brazil
market being under single corporate control. Against this background,
the Department subsequently instituted the 2002 U.S.-Brazil All-Cargo
Service Proceeding in this docket to select a carrier for an
authorization to be designated to serve the U.S.-Brazil all-cargo market
and for allocation of four U.S.-Brazil all-cargo frequencies under the
U.S.-Brazil aviation agreement.
The scope of the authority at issue was already well known at the time
we instituted this case. In the circumstances presented, the
instituting order did not include a general requirement that incumbent
U.S.-Brazil all-cargo carriers report a complete description of their
services in the market. Such a requirement would apply only to
incumbents choosing to apply for an allocation of additional
frequencies. Clearly, the Department would want to know how such an
applicant had been using its own allocation before deciding on whether
to award that applicant additional frequencies. However, each applicant
in this case (Gemini, Evergreen, and Amerijet) is a non-incumbent
carrier applying for the available designation and an allocation of
frequencies. Neither Amerijet nor Evergreen has presented any
persuasive reason why it needs incumbent carrier data in order to make
its affirmative case in this proceeding. Indeed, Amerijet’s own
request only contemplated that the incumbent carrier data be submitted
one week after the direct exhibits in this case were due.
In these circumstances, we are not persuaded that the Department should
require incumbent U.S.-Brazil all-cargo carriers to report on their
current services in the market. We believe that such a requirement is
unnecessary in this case, and we continue to believe that the applicants
and the Department have access to the relevant information needed for,
respectively, prosecuting and deciding this proceeding. For these
reasons, we have decided that the public interest would be best served
here by declining to require that incumbent carriers report on their
U.S.-Brazil frequency utilization in this docket.
We will serve this notice on Gemini Air Cargo, Inc.; Evergreen
International Airlines, Inc.; Amerijet International, Inc.; Federal
Express Corporation; United Parcel Service Co.; and Atlas Air,
Inc./Polar Air Cargo, Inc.
By:
Paul L. Gretch
Director, Office of International Aviation
(Seal)
Dated: August 7, 2002
An electronic version of this order is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_ aviation.asp
On August 6, 2002, Amerijet filed a separate motion requesting that the
Department issue an order directing Gemini and Evergreen to produce
copies of their respective applications reportedly filed with the Air
Transportation Stabilization Board seeking Federal loan guarantees
pursuant to the Air Transportation Safety and System Stabilization Act,
together with copies of all other related or supportive documents.
Amerijet’s motion requests that the Department shorten the answer
period to its motion. Our regulations (14 CFR Part 302.11) would
normally allow seven days for answers (i.e., Thursday, August 15).
However, to ensure that the issues raised by Amerijet’s letter are
addressed in an expedited manner, we will require that answers to
Amerijet’s motion be filed in the above-referenced docket by Friday,
August 9, 2002. Any replies shall be filed by Monday, August 12, 2002.
See Order 2002-5-24. Atlas and Polar had reached an agreement under
which the two carriers would be owned by the same company but continue
to operate as separate airlines.
PAGE
PAGE 4
| dot | 2024-06-07T20:31:39.191174 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12683-0015-0001/content.doc"
} |
DOT-OST-2002-12683-0015-0002 | Notice | "2002-08-07T04:00:00" | Notice - In the Matter of the 2002 U.S.-Brazil All-Cargo Service Proceeding |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Docket: OST-2002-12683 Served: August 7, 2002
NOTICE
In the Matter of the 2002 U.S.-Brazil All-Cargo Service Proceeding
SUMMARY
By this Notice, we have decided to decline to require that incumbent
U.S.-Brazil all-cargo carriers report on their U.S.-Brazil frequency
utilization in the 2002 U.S.-Brazil All-Cargo Service Proceeding, Docket
OST-2002-12683.
DISCUSSION AND SUMMARY OF PLEADINGS
By Order 2002-6-20, the Department instituted the 2002 U.S.-Brazil
All-Cargo Service Proceeding to select a carrier for an authorization to
be designated to serve the U.S.-Brazil all-cargo market and for
allocation of four U.S.-Brazil all-cargo frequencies under the
U.S.-Brazil aviation agreement. The instituting order established a
procedural schedule for the submission of evidentiary material needed by
the Department to make its selection(s), as follows: Applications by
July 19, 2002; Direct Exhibits by August 2; Rebuttal Exhibits by August
16; and Briefs by August 30. Gemini Air Cargo, Evergreen International
Airlines, and Amerijet International filed applications for the
available authorization and an allocation of frequencies.
On July 31, 2002, Amerijet filed a letter in the above-captioned docket
requesting that the Department require each all-cargo carrier currently
designated to provide service in the U.S.-Brazil market (Federal
Express, UPS, and Atlas/Polar) to submit, by no later than August 9, a
complete description of their services in the U.S.-Brazil market for the
period June 1, 2001 through May 31, 2002. In the alternative, Amerijet
states that the incumbent carriers may agree to voluntarily submit the
requested information for the record of the case.
By Notice dated August 1, 2002, in this Docket, we stated that we would
treat Amerijet’s letter as a motion, and we required that answers to
Amerijet’s letter be filed by August 5, 2002 and replies by
August 6, 2002. Atlas/Polar and Evergreen filed answers. UPS,
Amerijet, and Atlas/Polar filed replies.
In general, Atlas/Polar and UPS are opposed to Amerijet’s request
whereas Evergreen supports the request.
In its letter, Amerijet states that a relevant consideration in this or
any other route proceeding is the degree to which incumbent carriers are
and have been using frequencies allocated to them. Amerijet maintains
that neither the Department nor the applicants in this case currently
have access to that information, and that the T-100 reports do not allow
the parties to determine completely and accurately the extent to which
the incumbent carriers are and have been using their frequencies.
Amerijet further indicates that dormancy information with respect to
frequency utilization is unreliable.
Amerijet states that the Department’s instituting order appears to
have recognized this issue when it required that any incumbent carrier
applicant include a complete description of its services in the market.
In this regard, Amerijet notes that this information was not submitted
since none of the incumbent carriers applied for additional frequencies.
To help minimize any burden on the incumbent carriers, Amerijet
requests that the incumbents submit the requested information by August
9, one week after directs and one week before rebuttals are due in this
proceeding.
Atlas/Polar state that Amerijet’s own letter indicates that the T-100
reports for the U.S.-Brazil market are available to all applicants in
the proceeding, and that Amerijet has failed to specify the manner in
which these T-100 reports are inadequate or how the information that
Amerijet seeks would enhance the record of the proceeding. Moreover,
Atlas/Polar contend that Amerijet’s request expresses only a vague,
general interest in determining U.S.-Brazil frequency usage, which does
not validate the request for new information requirements.
Atlas/Polar further argue that incumbent carrier frequencies are beyond
the scope of the proceeding. In this connection, Atlas/Polar state that
this case arose because the Department decided to replace Polar’s
Brazil designation and reallocate its four frequencies. Atlas/Polar
also note that the instituting order allowed for petitions for
reconsideration, and none were filed.
UPS argues that Amerijet’s request harkens back to the time of strict
regulation when incumbents were required to provide extensive
information about their existing services. UPS states that the burden
of producing the data, when viewed in relation to its complete lack of
relevance to the proceeding, warrants a denial of the request. UPS
maintains that any information regarding frequency usage, aircraft
routings, schedules, etc. has no bearing whatsoever on this proceeding
since none of the applicants has requested any frequencies now held by
incumbents. UPS also notes that it is too late in this proceeding for
the requested information to be of use to the applicants, and that
questions concerning confidentiality and business sensitive information
need to be considered.
Evergreen states that it supports Amerijet’s request, and that
information concerning existing services could prove useful to the
Department and the parties in this proceeding. Evergreen maintains that
specific issues such as the need for service to intermediate points and
interior U.S. points justify the filing of the requested information
even though incumbents do not seek to increase Brazil service.
Evergreen urges the Department to require incumbents to provide
operational information by month and by direction and to identify all
Brazilian, U.S., and third-country points in their single-plane,
U.S.-Brazil scheduled services for the period June 1, 2001 to May 31,
2002. Evergreen indicates that the Department required similar
information by its June 21, 2000 Notice in the last U.S.-Brazil
all-cargo proceeding.
In its reply, Atlas/Polar state that Evergreen’s support of
Amerijet’s request similarly makes no claim that incumbent operational
data would affect the applicants’ service proposals or the
Department’s decision in any way. While the Department required the
submission of U.S.-Brazil all-cargo frequency utilization data two years
ago, Atlas/Polar maintain that that precedent is not relevant here
because there has been no suggestion (let alone proof) that the
incumbents have not been using their frequencies, as was the case two
years ago. Atlas/Polar note that the Department has already determined
that Polar’s designation and four frequencies will be the issue of the
current Brazil proceeding.
In its reply, Amerijet states that historical precedent shows that in
virtually every proceeding where the issuance of additional certificates
is at issue, the incumbent carrier(s) are called upon to provide data
with respect to the market(s) at issue. Amerijet maintains that if, as
Atlas/Polar suggest, the T-100 reports are sufficient, then incumbent
carriers would never be called upon to submit market information in
route proceedings. According to Amerijet, it and the other applicants
in this case must be able to examine market information in the
possession of Atlas/Polar, FedEx, and UPS in order to best determine the
nature of the need for additional service in the relevant market and
sub-markets. Amerijet states that if, for example, the wide-body
operators in the market are not and have not been fully utilizing
frequencies, it is far more likely that the Department would support the
selection of a carrier such as Amerijet, which would not simply add new
additional capacity between major terminals, but would expand its base
scheduled system in the region into Brazil.
DECISION
This proceeding began shortly after the Department approved a de facto
route transfer between Atlas and Polar, but did not approve the transfer
of Polar’s Brazil designation and four frequencies. The Department
found that the transaction with respect to Polar’s Brazil authority
would not be consistent with the public interest, as it would have
resulted in half of the four available designations for all-cargo
service and over half of the 24 available frequencies in the U.S.-Brazil
market being under single corporate control. Against this background,
the Department subsequently instituted the 2002 U.S.-Brazil All-Cargo
Service Proceeding in this docket to select a carrier for an
authorization to be designated to serve the U.S.-Brazil all-cargo market
and for allocation of four U.S.-Brazil all-cargo frequencies under the
U.S.-Brazil aviation agreement.
The scope of the authority at issue was already well known at the time
we instituted this case. In the circumstances presented, the
instituting order did not include a general requirement that incumbent
U.S.-Brazil all-cargo carriers report a complete description of their
services in the market. Such a requirement would apply only to
incumbents choosing to apply for an allocation of additional
frequencies. Clearly, the Department would want to know how such an
applicant had been using its own allocation before deciding on whether
to award that applicant additional frequencies. However, each applicant
in this case (Gemini, Evergreen, and Amerijet) is a non-incumbent
carrier applying for the available designation and an allocation of
frequencies. Neither Amerijet nor Evergreen has presented any
persuasive reason why it needs incumbent carrier data in order to make
its affirmative case in this proceeding. Indeed, Amerijet’s own
request only contemplated that the incumbent carrier data be submitted
one week after the direct exhibits in this case were due.
In these circumstances, we are not persuaded that the Department should
require incumbent U.S.-Brazil all-cargo carriers to report on their
current services in the market. We believe that such a requirement is
unnecessary in this case, and we continue to believe that the applicants
and the Department have access to the relevant information needed for,
respectively, prosecuting and deciding this proceeding. For these
reasons, we have decided that the public interest would be best served
here by declining to require that incumbent carriers report on their
U.S.-Brazil frequency utilization in this docket.
We will serve this notice on Gemini Air Cargo, Inc.; Evergreen
International Airlines, Inc.; Amerijet International, Inc.; Federal
Express Corporation; United Parcel Service Co.; and Atlas Air,
Inc./Polar Air Cargo, Inc.
By:
Paul L. Gretch
Director, Office of International Aviation
(Seal)
Dated: August 7, 2002
An electronic version of this order is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_ aviation.asp
On August 6, 2002, Amerijet filed a separate motion requesting that the
Department issue an order directing Gemini and Evergreen to produce
copies of their respective applications reportedly filed with the Air
Transportation Stabilization Board seeking Federal loan guarantees
pursuant to the Air Transportation Safety and System Stabilization Act,
together with copies of all other related or supportive documents.
Amerijet’s motion requests that the Department shorten the answer
period to its motion. Our regulations (14 CFR Part 302.11) would
normally allow seven days for answers (i.e., Thursday, August 15).
However, to ensure that the issues raised by Amerijet’s letter are
addressed in an expedited manner, we will require that answers to
Amerijet’s motion be filed in the above-referenced docket by Friday,
August 9, 2002. Any replies shall be filed by Monday, August 12, 2002.
See Order 2002-5-24. Atlas and Polar had reached an agreement under
which the two carriers would be owned by the same company but continue
to operate as separate airlines.
PAGE
PAGE 4
| dot | 2024-06-07T20:31:39.195742 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12683-0015-0002/content.doc"
} |
DOT-OST-2002-12683-0021-0001 | Notice | "2002-08-16T04:00:00" | Notice-2002 U.S. Brazil All-Cargo Service Proceeding |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Docket: OST-2002-12683 Served: August 16, 2002
NOTICE
In the Matter of the 2002 U.S.-Brazil All-Cargo Service Proceeding
SUMMARY
By this Notice, we have decided to deny the request of Amerijet
International that Gemini Air Cargo and Evergreen Airlines International
submit in this docket copies of any applications and supporting
documents filed with the Air Transportation Stabilization Board seeking
Federal loan guarantees.
DISCUSSION AND SUMMARY OF PLEADINGS
By Order 2002-6-20, the Department instituted the 2002 U.S.-Brazil
All-Cargo Service Proceeding to select a carrier for an authorization to
be designated to serve the U.S.-Brazil all-cargo market and for
allocation of four U.S.-Brazil all-cargo frequencies under the
U.S.-Brazil aviation agreement. The instituting order established a
procedural schedule for the submission of evidentiary material needed by
the Department to make its selection(s), as follows: Applications by
July 19, 2002; Direct Exhibits by August 2; Rebuttal Exhibits by August
16; and Briefs by August 30. Gemini Air Cargo, Evergreen International
Airlines, and Amerijet International filed applications for the
available authorization and an allocation of frequencies.
On August 6, 2002, Amerijet filed a motion requesting that the
Department issue an order directing Gemini and Evergreen to produce
copies of their respective applications reportedly filed with the Air
Transportation Stabilization Board seeking Federal loan guarantees
pursuant to the Air Transportation Safety and System Stabilization Act,
together with copies of all other related or supportive documents.
Evergreen and Gemini filed answers opposing Amerijet’s request and
Amerijet filed a reply.
In its motion, Amerijet states that neither Gemini nor Evergreen
submitted any financial statements as part of their direct exhibits in
the 2002 U.S.-Brazil All-Cargo Service Proceeding. In support of its
motion, Amerijet asserts that the Department and the applicants must
have access to this information if the proceeding is to be conducted
fairly and on the basis of a complete record. Amerijet maintains that
the requested information is relevant because it relates to the fitness
determination that the Department must make prior to issuing
certificates pursuant to the award of new route authority. Moreover,
Amerijet argues that it would be hard to imagine how the Department
could issue certificates to either applicant if the proposed operations
are in any way dependent upon receipt of Federally subsidized loan
guarantees.
Evergreen states that Amerijet’s motion demonstrates a complete lack
of understanding of the rationale for the establishment of the Air
Transportation Stabilization Board (ATSB). The ATSB, according to
Evergreen, is not a bankruptcy court, and the underlying purpose of the
law that created the ATSB is to foster and develop airlines that have
every intention of continuing safe and commercially viable operations.
Evergreen argues that the fact that Evergreen is seeking loan guarantees
does not bring into question the financial health of the company and,
consequently, there is no basis for providing any of the ATSB filings
that Amerjiet has requested for the record of this proceeding.
Evergreen notes that since the filing of its ATSB application, the
Department has twice found the company fit to conduct its operations.
In addition, Evergreen states that neither the Department nor the
applicants in recent route cases have indicated a need for the type of
financial review that Amerijet has requested here.
Gemini states that the information it has provided to the ATSB is
confidential and relates solely to ATSB matters and ATSB requirements,
distinct from the Department’s regulatory jurisdiction. Gemini
maintains that the Department regularly takes notice of Form 41
information filed by carriers to update fitness determinations in route
proceedings such as the 2002 U.S.-Brazil All-Cargo Service Proceeding at
issue here. In addition, Gemini argues that Amerijet’s motion seems
to be designed to obstruct rather than facilitate the proceeding at
hand, especially in light of the fact that Amerijet filed its motion
long after petitions for reconsideration were due in this docket.
In its reply, Amerijet notes that both Evergreen and Gemini concede that
there is no information in their applications or direct exhibits
regarding their financial fitness. Amerijet also notes that neither
Evergreen nor Gemini disputes that the production of such information
would not constitute a significant burden. Amerijet argues that its
request for information is timely because it could not have known what
financial information Evergreen and Gemini would submit to the
Department until the direct exhibits were filed in this case. It
further argues that financial fitness and ability are always a relevant
consideration in a certification proceeding and that the information
presented to the ATSB is well suited for the purposes of determining
fitness and ability. Amerijet maintains that such information could
also shed light on an applicant’s ability to inaugurate and maintain
service as well as on possible structural changes that the applicant
might be required to undertake. Finally, Amerijet argues that
Evergreen’s suggestion that earlier Department fitness findings make
submission of ATSB filings unnecessary is without merit because
Evergreen fails to explain whether the fitness findings were based upon
financial information similar to that provided to the ATSB.
DECISION
We have decided to deny Amerijet’s request. The mere fact that
Evergreen and Gemini have filed applications before the ATSB in no way
in and of itself calls into question the financial fitness of either
carrier. Nor was the material requested to be submitted under the Air
Transportation Safety and System Stabilization Act intended to address
the question of an air carrier’s fitness to obtain or hold economic
authority under Section 41101 of our Act. In these circumstances, we
believe that the evidence we have already required to be submitted in
this proceeding, along with data officially noticeable under rule 24(g)
of the Department’s regulations, will be adequate for us to make any
fitness findings that may be necessary. Accordingly, we will not
require that Gemini and Evergreen submit copies of any applications and
supporting documents filed with the Air Transportation Stabilization
Board seeking Federal loan guarantees.
We will serve this notice on Gemini Air Cargo, Inc.; Evergreen
International Airlines, Inc.; and Amerijet International, Inc.
By:
Paul L. Gretch
Director, Office of International Aviation
(Seal)
Dated: August 16, 2002
An electronic version of this order is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_ aviation.asp
Amerijet states that it did not mean to suggest in its motion that
applicants before a bankruptcy court and the ATSB are in the same
position. However, Amerijet contends that the two situations are not
mutually exclusive either, as demonstrated by the case of U.S. Airways.
Amerijet further indicates that its own reorganization was a public
process, and that the materials produced by Amerijet are publicly
available. In addition, Amerijet notes that its direct exhibits were
not silent with respect to its reorganization or other pertinent
financial information.
PAGE
PAGE 2
| dot | 2024-06-07T20:31:39.197822 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12683-0021-0001/content.doc"
} |
DOT-OST-2002-12683-0021-0002 | Notice | "2002-08-16T04:00:00" | Notice-2002 U.S. Brazil All-Cargo Service Proceeding |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Docket: OST-2002-12683 Served: August 16, 2002
NOTICE
In the Matter of the 2002 U.S.-Brazil All-Cargo Service Proceeding
SUMMARY
By this Notice, we have decided to deny the request of Amerijet
International that Gemini Air Cargo and Evergreen Airlines International
submit in this docket copies of any applications and supporting
documents filed with the Air Transportation Stabilization Board seeking
Federal loan guarantees.
DISCUSSION AND SUMMARY OF PLEADINGS
By Order 2002-6-20, the Department instituted the 2002 U.S.-Brazil
All-Cargo Service Proceeding to select a carrier for an authorization to
be designated to serve the U.S.-Brazil all-cargo market and for
allocation of four U.S.-Brazil all-cargo frequencies under the
U.S.-Brazil aviation agreement. The instituting order established a
procedural schedule for the submission of evidentiary material needed by
the Department to make its selection(s), as follows: Applications by
July 19, 2002; Direct Exhibits by August 2; Rebuttal Exhibits by August
16; and Briefs by August 30. Gemini Air Cargo, Evergreen International
Airlines, and Amerijet International filed applications for the
available authorization and an allocation of frequencies.
On August 6, 2002, Amerijet filed a motion requesting that the
Department issue an order directing Gemini and Evergreen to produce
copies of their respective applications reportedly filed with the Air
Transportation Stabilization Board seeking Federal loan guarantees
pursuant to the Air Transportation Safety and System Stabilization Act,
together with copies of all other related or supportive documents.
Evergreen and Gemini filed answers opposing Amerijet’s request and
Amerijet filed a reply.
In its motion, Amerijet states that neither Gemini nor Evergreen
submitted any financial statements as part of their direct exhibits in
the 2002 U.S.-Brazil All-Cargo Service Proceeding. In support of its
motion, Amerijet asserts that the Department and the applicants must
have access to this information if the proceeding is to be conducted
fairly and on the basis of a complete record. Amerijet maintains that
the requested information is relevant because it relates to the fitness
determination that the Department must make prior to issuing
certificates pursuant to the award of new route authority. Moreover,
Amerijet argues that it would be hard to imagine how the Department
could issue certificates to either applicant if the proposed operations
are in any way dependent upon receipt of Federally subsidized loan
guarantees.
Evergreen states that Amerijet’s motion demonstrates a complete lack
of understanding of the rationale for the establishment of the Air
Transportation Stabilization Board (ATSB). The ATSB, according to
Evergreen, is not a bankruptcy court, and the underlying purpose of the
law that created the ATSB is to foster and develop airlines that have
every intention of continuing safe and commercially viable operations.
Evergreen argues that the fact that Evergreen is seeking loan guarantees
does not bring into question the financial health of the company and,
consequently, there is no basis for providing any of the ATSB filings
that Amerjiet has requested for the record of this proceeding.
Evergreen notes that since the filing of its ATSB application, the
Department has twice found the company fit to conduct its operations.
In addition, Evergreen states that neither the Department nor the
applicants in recent route cases have indicated a need for the type of
financial review that Amerijet has requested here.
Gemini states that the information it has provided to the ATSB is
confidential and relates solely to ATSB matters and ATSB requirements,
distinct from the Department’s regulatory jurisdiction. Gemini
maintains that the Department regularly takes notice of Form 41
information filed by carriers to update fitness determinations in route
proceedings such as the 2002 U.S.-Brazil All-Cargo Service Proceeding at
issue here. In addition, Gemini argues that Amerijet’s motion seems
to be designed to obstruct rather than facilitate the proceeding at
hand, especially in light of the fact that Amerijet filed its motion
long after petitions for reconsideration were due in this docket.
In its reply, Amerijet notes that both Evergreen and Gemini concede that
there is no information in their applications or direct exhibits
regarding their financial fitness. Amerijet also notes that neither
Evergreen nor Gemini disputes that the production of such information
would not constitute a significant burden. Amerijet argues that its
request for information is timely because it could not have known what
financial information Evergreen and Gemini would submit to the
Department until the direct exhibits were filed in this case. It
further argues that financial fitness and ability are always a relevant
consideration in a certification proceeding and that the information
presented to the ATSB is well suited for the purposes of determining
fitness and ability. Amerijet maintains that such information could
also shed light on an applicant’s ability to inaugurate and maintain
service as well as on possible structural changes that the applicant
might be required to undertake. Finally, Amerijet argues that
Evergreen’s suggestion that earlier Department fitness findings make
submission of ATSB filings unnecessary is without merit because
Evergreen fails to explain whether the fitness findings were based upon
financial information similar to that provided to the ATSB.
DECISION
We have decided to deny Amerijet’s request. The mere fact that
Evergreen and Gemini have filed applications before the ATSB in no way
in and of itself calls into question the financial fitness of either
carrier. Nor was the material requested to be submitted under the Air
Transportation Safety and System Stabilization Act intended to address
the question of an air carrier’s fitness to obtain or hold economic
authority under Section 41101 of our Act. In these circumstances, we
believe that the evidence we have already required to be submitted in
this proceeding, along with data officially noticeable under rule 24(g)
of the Department’s regulations, will be adequate for us to make any
fitness findings that may be necessary. Accordingly, we will not
require that Gemini and Evergreen submit copies of any applications and
supporting documents filed with the Air Transportation Stabilization
Board seeking Federal loan guarantees.
We will serve this notice on Gemini Air Cargo, Inc.; Evergreen
International Airlines, Inc.; and Amerijet International, Inc.
By:
Paul L. Gretch
Director, Office of International Aviation
(Seal)
Dated: August 16, 2002
An electronic version of this order is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_ aviation.asp
Amerijet states that it did not mean to suggest in its motion that
applicants before a bankruptcy court and the ATSB are in the same
position. However, Amerijet contends that the two situations are not
mutually exclusive either, as demonstrated by the case of U.S. Airways.
Amerijet further indicates that its own reorganization was a public
process, and that the materials produced by Amerijet are publicly
available. In addition, Amerijet notes that its direct exhibits were
not silent with respect to its reorganization or other pertinent
financial information.
PAGE
PAGE 2
| dot | 2024-06-07T20:31:39.201049 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12683-0021-0002/content.doc"
} |
DOT-OST-2002-12688-0006 | Notice | "2002-07-29T04:00:00" | Notice Establishing Procedural Dates | UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Served: July 29, 2002
Joint Application of American Airlines, Inc. and Swiss International Air
Lines Ltd.
for Approval of and Antitrust Immunity for Alliance Agreement
under 49 U.S.C. §§ 41308 and 41309 (Docket OST-2002-12688)
NOTICE ESTABLISHING PROCEDURAL DATES
On June 28, 2002, American Airlines and its affiliates and Swiss
International Air Lines Ltd. filed a joint application requesting
approval of and antitrust immunity for (1) a cooperative agreement
(Exhibit JA-1), and (2) all agreements among the applicants that
implement any part of the cooperative agreement or are entered into by
the applicants under the cooperative agreement (hereafter the
“Alliance Agreement”). On June 28, the applicants filed a joint
Motion under 14 C.F.R. 302.12 (Rule 12) of our regulations seeking
confidential treatment for supporting documents and information. On
July 2, American Airlines, Inc. filed a supplementary Motion under 14
C.F.R. 302.12 (Rule 12) of our regulations seeking confidential
treatment for additional documents and information. Both Motions state
that this material is proprietary, commercially sensitive, and
confidential in nature which qualifies for being withheld from public
disclosure. The applicants ask that access to this material be limited
to counsel and outside experts for interested parties.
We have now finished our initial review. We find the application is now
substantially complete. We will require that answers to the application
be filed no later than 21 calendar days from the issue date of this
Notice, and that replies be filed no later than 7 business days after
the last day for filing an answer.
We shall serve this notice on all persons on the service list for this
docket.
By:
READ C. VAN DE WATER
Assistant Secretary for Aviation
and International Affairs
(SEAL)
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov/search
Specifically, TWA Airlines LLC; American Eagle Airlines, Inc.; and
Executive Airlines, Inc. d/b/a American Eagle.
Answers to the Motion were due on July 10. The Motion is unopposed.
See Joint Motions at 1.
We will rule on the merits of the Rule 12 Motion by subsequent order.
By Notice dated July 10, we granted immediate interim access to all
documents covered by the applicants’ Motion, or to any subsequent
materials that may be filed confidentially in this proceeding, to
counsel and outside experts for interested parties, consistent with
conditions agreed to by the Joint Applicants and imposed by the
Department in similar recent cases. At the same time, we suspended the
procedural schedule of this case, pending a determination of
completeness.
We reserve the right to require the filing of additional information
deemed relevant to the proceeding at any time.
PAGE
PAGE 2
| dot | 2024-06-07T20:31:39.203244 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12688-0006/content.doc"
} |
DOT-OST-2002-12691-0002 | Notice | "2002-07-01T04:00:00" | Notice of Action Taken re: Volga-Dnepr J.S. Cargo Airline |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on July 1, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-12691
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: Volga-Dnepr J.S. Cargo Airline Date Filed: June 28, 2002
Relief requested: Exemption pursuant to 49 U.S.C. section 40109(g) to
permit it to operate one one-way cargo charter flight between
Philadelphia, PA, and Moffet Field, CA, on/about July 3, 2002, using its
AN-124 aircraft, to transport outsized cargo consisting of one NIMIQ-2
Satellite and associated equipment, on behalf of Lockheed Martin
Commercial Space Systems. The applicant stated that Lockheed Martin
required urgent delivery of the satellite to complete final assembly and
mission integration activities in order to meet scheduled shipment
deadlines to Cape Canaveral for subsequent launch processing; that the
cargo is too large for transportation on U.S. carrier aircraft; and that
surface transportation is not feasible because of the time involved, the
adverse effect a long road trip could have on the high-value cargo, and
the cargo’s size and highway oversized load restrictions.
Applicant representative: Glenn Wicks 202-457-7790
Responsive pleadings: Volga-Dnepr served its application on those U.S.
carriers operating large all-cargo aircraft. Each carrier indicated
that it did not have aircraft available to conduct the proposed
operation and that it had no comment or did not oppose grant of the
requested authority to Volga-Dnepr.
Statutory Standards: Under 49 U.S.C. section 40109(g), we may authorize
a foreign air carrier to carry commercial traffic between U.S. points
(i.e., cabotage traffic) under limited circumstances. Specifically, we
must find that the authority is required in the public interest; that
because of an emergency created by unusual circumstances not arising in
the normal course of business the traffic cannot be accommodated by U.S.
carriers holding certificates under 49 U.S.C. section 41102; that all
possible efforts have been made to place the traffic on U.S. carriers;
and that the transportation is necessary to avoid unreasonable hardship
to the traffic involved (an additional required finding, concerning
emergency transportation during labor disputes, was not relevant here).
For examples of earlier grants of authority of this type, see, e.g.,
Order 2001-5-23.
DISPOSITION
Action: Approved Action date: July 1, 2002
Effective dates of authority granted: July 3-5, 2002
Basis for approval: We found that the application met all the relevant
criteria of 49 U.S.C. section 40109(g) for the grant of an exemption of
this type and that the grant was required in the public interest.
Specifically, we were persuaded that the need to move the satellite
promptly in order to complete scheduled assembly and integration
activities and subsequent launch processing deadlines; the fact that the
satellite could not be transported by surface either in time to meet
that schedule or without the risk of damage; the potential negative
impact of delivery delays; and the unique, outsized nature of the cargo,
constituted an emergency not arising in the normal course of business.
Moreover, based on the representations of the U.S. carriers, we
concluded that no U.S. carrier had aircraft available which could be
used to conduct the operation at issue here. We also found that grant
of Volga-Dnepr’s request would prevent undue hardship to the cargo and
Lockheed Martin. Finally, we found that the applicant was qualified to
perform its proposed operations (see, e.g., Order 94-10-13).
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached) and to the condition that
Volga-Dnepr comply with an FAA-approved flight routing for the
authorized flight.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation
and International Affairs
An electronic version of this document is available on the World Wide
Web at: http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
6/2002
| dot | 2024-06-07T20:31:39.205444 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-12691-0002/content.doc"
} |
DOT-OST-2002-12708-0002 | Notice | "2002-07-09T04:00:00" | Notice of Action Taken re: Volga-Dnepr J.S. Cargo Airline |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on July 9, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-12708
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: Volga-Dnepr J.S. Cargo Airline Date Filed: July 5,
2002
Relief requested: Exemption pursuant to 49 U.S.C. section 40109(g) to
operate two one-way cargo charter flights:
(1) between Denver, CO, and Cape Canaveral, FL, to transport an outsized
Atlas and Centaur IIAS launch vehicle payload and associated equipment,
and (2) between Cape Canaveral and North Island, CA, to transport an
outsized booster trailer and track kit, during the period July 11-13,
2002, using its AN-124 aircraft, on behalf of Lockheed Martin Space
Systems. The applicant stated that Lockheed Martin needed urgent
delivery of the equipment in order to meet a schedule that requires
mission integration and subsequent launch processing activities in time
for a scheduled September launch. It also stated that the cargo is too
large for transportation on U.S. carrier aircraft, and that surface
transportation was not feasible because of the time involved, the
delicate nature and high value of the cargo, and conditions unsuitable
to maintaining system integrity compliance.
Applicant representative: Glenn Wicks 202-457-7790
Responsive pleadings: Volga Dnepr served its application on those U.S.
carriers operating large all-cargo aircraft. Each carrier indicated
that it did not have aircraft available to conduct the proposed
operation and that it had no comment or did not oppose grant of the
requested authority to Volga-Dnepr.
Statutory Standards: Under 49 U.S.C. section 40109(g), we may authorize
a foreign air carrier to carry commercial traffic between U.S. points
(i.e., cabotage traffic) under limited circumstances. Specifically, we
must find that the authority is required in the public interest; that
because of an emergency created by unusual circumstances not arising in
the normal course of business the traffic cannot be accommodated by U.S.
carriers holding certificates under 49 U.S.C. section 41102; that all
possible efforts have been made to place the traffic on U.S. carriers;
and that the transportation is necessary to avoid unreasonable hardship
to the traffic involved (an additional required finding, concerning
emergency transportation during labor disputes, was not relevant here).
For examples of earlier grants of authority of this type, see, e.g.,
Order 2001-5-23.
DISPOSITION
Action: Approved Action date: July 9, 2002
Effective dates of authority granted: July 11-16, 2002
Basis for approval: We found that the application met all the relevant
criteria of 49 U.S.C. section 40109(g) for the grant of an exemption of
this type and that the grant was required in the public interest.
Specifically, we were persuaded that the need to move the cargo promptly
in order to complete scheduled mission integration activities and
subsequent launch processing deadlines; the fact that the cargo could
not be transported by surface either in time to meet that schedule or
without the risk of damage; the potential negative impact of delivery
delays; and the unique, outsized nature of the cargo, constituted an
emergency not arising in the normal course of business. Moreover, based
on the representations of the U.S. carriers, we concluded that no U.S.
carrier had aircraft available which could be used to conduct the
operation at issue here. We also found that grant of Volga-Dnepr’s
request would prevent undue hardship to the cargo and Lockheed Martin.
Finally, we found that the applicant was qualified to perform its
proposed operations (see, e.g., Order 94-10-13).
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached) and to the condition that
Volga-Dnepr comply with an FAA-approved flight routing for the
authorized flights, and with any requisite Department of Defense
authorizations.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation
and International Affairs
An electronic version of this document is available on the World Wide
Web at: http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
7/2002
| dot | 2024-06-07T20:31:39.208613 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-12708-0002/content.doc"
} |
DOT-OST-2002-12784-0001 | Notice | "2002-07-10T04:00:00" | Notice of Termination of Service at Joplin, Missouri and Request for Waiver of 90-Day Notice Requirement | BEFORE THE
DEPARTMENT OF TRANSPORTATION
WASHINGTON, D.C.
Notice of
PINNACLE AIRLINES CORP.
of intent to terminate service at Joplin,
Missouri pursuant to 49 U.S.C. § 41734
and 14 C.F.R. § 323 )
)
)
)
)
)
)
)
) Docket OST-02-
Dated: July 10, 2002
NOTICE OF TERMINATION OF SERVICE AT JOPLIN, MISSOURI and request for
waiver of 90-day notice requirement
Pinnacle Airlines Corp. (“Pinnacle”) hereby submits notice, pursuant
to 49 U.S.C § 41734 and 14 C.F.R. § 323.3, of its intent to terminate
service to Joplin, Missouri no later than 90-days following the date of
this notice. Pinnacle seeks a waiver from the Department’s 90-day
notice requirement authorizing Pinnacle to terminate service to Joplin,
Missouri effective September 3, 2002 (with Pinnacle’s last flights
operating on September 2, 2002). Pinnacle serves Joplin, Missouri as
Northwest Airlink.
In support of this Notice and Request for Waiver, Pinnacle states the
following:
1. Pinnacle is a certificated air carrier, whose corporate office is
located at:
1689 Nonconnah Boulevard
Suite 111
Memphis, TN 38132
(901) 348-4100 Communications with respect to this Notice should be
directed to:
Curt E. Sawyer
Vice President and Chief Financial Officer
Pinnacle Airlines Corp.
1689 Nonconnah Boulevard, Suite 111
Memphis, TN 38132
(901) 348-4100
FAX: (901) 348-4162
2. After Pinnacle terminates service, Joplin will continue to receive
service to a large hub airport. Trans State Airlines, an American
Airlines codeshare partner, currently offers four roundtrips on Mondays
through Fridays, two roundtrips on Saturdays, and three roundtrips on
Sundays between Joplin and St. Louis, Missouri. All of these flights
are on a non-stop basis. 3. The routing and schedule of the service
that Pinnacle seeks to terminate is as follows:
From Departure To Arrival Frequency
MEM 12:40 JLN 14:20 Daily nonstop
JLN 14:40 MEM 16:15 Daily nonstop
4. Pinnacle operates these flights with Saab SF340 aircraft (33
passenger seats).
5. Pinnacle intends to terminate service at Joplin, Missouri effective
September 3, 2002, with its last flights operating on September 2, 2002,
or no later than 90 days following the date of this notice.
6. The Department has determined that the level of essential air service
for Joplin is a minimum of two daily roundtrip flights to/from Kansas
City and two daily roundtrips to/from St. Louis. The service to Kansas
City must be operated on a nonstop basis; the service to St. Louis may
be operated on a one-stop basis. See DOT Order 86-5-39 (May 13, 1986).
7. The effective date of this Notice is July 10, 2002. Objections to
this Notice are due within 20 days of this Notice or on July 30, 2002.
8. As required by 14 C.F.R. § 323.7(a), this Notice is being served
upon all persons listed on the attached service list.
Respectfully submitted,
/s/ Curtis E. Sawyer /s/
Curt E. Sawyer
Vice President and Chief Financial Officer
Pinnacle Airlines Corp.
1689 Nonconnah Boulevard
Suite 111
Memphis, TN 38132
(901) 348-4100
Dated: July 10, 2002
CERTIFICATE OF SERVICE
A copy of this NOTICE OF TERMINATION AND REQUEST FOR WAIVER was served
by first class mail, postage prepaid, upon each of the persons below:
Dennis DeVany, Chief
EAS and Domestic Analysis, X-53
U.S. Department of Transportation
400 Seventh Street, S.W.
Room 6417
Washington, D.C. 20590
Steve Stockam, Manager
Joplin Regional Airport
P.O. Box 1355
Joplin, MO 64802
Richard H. Russell, Mayor
City of Joplin
Municipal Building
303 East Third Street
Joplin, MO 64801
Rodney K. Bray, Postmaster
101 North Main Street
Joplin, MO 64801
(…continued)
(continued…)
NOTICE OF PINNACLE AIRLINES CORP.
Page PAGE \* MERGEFORMAT 3
NOTICE OF PINNACLE AIRLINES CORP.
Page PAGE \* MERGEFORMAT 2
PAGE 2
| dot | 2024-06-07T20:31:39.225305 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-12784-0001/content.doc"
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DOT-OST-2002-12903-0003 | Notice | "2002-08-23T04:00:00" | Notice of Action Taken re: European Air Transport N.V. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on August 23, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-12903
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: European Air Transport N.V. Date Filed: July 19, 2002
Relief requested: Exemption from 49 U.S.C. 41301 and statement of
authorization pursuant to 14 CFR 212 of the Department’s regulations
to wet lease aircraft to DHL International E.C. (DHLIEC) for the
operation of DHLIEC’s Brussels-Bahrain and Bahrain-Kuwait-Dubai
scheduled all-cargo services, for a period of 120 days. The applicant
stated that the wet lease is required until DHLIEC permanently replaces
an aircraft which was lost in a collision over Germany on July 1, 2002.
It further stated that it is qualified, and has the financial resources,
to provide the proposed services.
Applicant representative: Bruce Rabinovitz 202-663-6960
Responsive pleadings: None
DISPOSITION
Action: Approved Action date: August 23, 2002
Effective dates of authority granted: August 23, 2002 - December 23,
2002
Basis for approval: We found that comity and reciprocity with Belgium
supported grant of this authority. We also found the applicant
operationally and financially qualified, and properly licensed to
conduct the proposed services. The record indicates that the applicant
is 99.98% owned by DHL Aviation N.V., a Belgium corporation, which is a
subsidiary of DHL Worldwide Express B.V., which, in turn, is
substantially owned by German interests. The United States has open
skies aviation agreements with both Belgium and Germany. Thus, despite
the presence of non-homeland interests, we found that there was nothing
in the ownership and control of the carrier that would be inimical to
U.S. aviation policy or interests. Accordingly, we concluded that
waiver of our standard requirement that substantial ownership and
effective control of a foreign carrier rest in the hands of citizens of
its homeland was warranted. Finally, the FAA has advised us that it
knows of no reason why the Department should act unfavorably on the
carrier’s application.
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated:
X Standard exemption conditions (attached) __ Foreign air
carrier permit conditions (Order - - )
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
____________________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the authority was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
7/2002
See Notice of Action Taken dated April 25, 2002, in Docket OST-99-5470.
| dot | 2024-06-07T20:31:39.229649 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12903-0003/content.doc"
} |
DOT-OST-2002-12983-0002 | Notice | "2002-08-16T04:00:00" | Notice of Action Taken re: Lineas Aereas Azteca, S.A. de C.V. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on August 16, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST 2002-12983
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applicant: LINEAS AEREAS AZTECA, S.A. de C.V.
Date Filed: July 30, 2002
Relief requested: Exemption from 49 USC section 41301 to permit the
applicant to conduct scheduled, combination service between Guadalajara,
Mexico, and Chicago, Illinois.
If renewal, date and citation of last action: New authority.
Applicant representative(s): Pierre Murphy, 202-822-8050
Responsive pleadings: None.
DISPOSITION
Action: Approved. Action
date: August 16, 2002
Effective dates of authority granted: August 16, 2002, through August
16, 2003.
Basis for approval: United States-Mexico Air Transport Services
Agreement
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated: Standard exemption
conditions.
Special conditions/Remarks:
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
_______________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) the applicant was qualified to perform its proposed
operations; (3) grant of the authority was consistent with the public
interest; and (4) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
| dot | 2024-06-07T20:31:39.233413 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-12983-0002/content.doc"
} |
DOT-OST-2002-13002-0002-0001 | Notice | "2002-08-13T04:00:00" | Notice |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation
on the 13th day of August, 2002
________________________________________________
:
JOINT APPLICATION OF ALOHA AIRLINES, INC., : Served: August 13, 2002
And :
HAWAIIAN AIRLINES, INC., : Docket OST-
: 2002-13002
under Section 116 of the Aviation and Transportation :
Security Act of 2001 for Approval of and :
Antitrust Exemption for Agreement :
:
NOTICE
On July 31, 2002, Aloha Airlines and Hawaiian Airlines applied for
approval and antitrust immunity for an agreement whereby the two
airlines would coordinate capacity on five major routes within Hawaii.
They applied for approval and antitrust immunity under section 116 of
the Aviation and Transportation Security Act of 2001, P.L. No. 107-71,
115 Stat. 624 (November 19, 2001), which authorizes the Secretary,
notwithstanding the provisions of 49 U.S.C. 41309(a), to approve and
grant antitrust immunity to an agreement governing air transportation
within a single state, if the Governor of the state has issued a
declaration that the agreement is necessary to ensure the continuing
availability of such air transportation within the state. The Governor
of Hawaii has made such a declaration.
Any grant of approval and antitrust immunity would be made under 49
U.S.C. 41308 and 41309 under the standards set by section 116. As
provided by our procedural rules for such applications, 14 C.F.R. Part
303, we have reviewed the application and determined that it is
substantially complete. Answers would normally be due twenty-one days
from the date of adoption of this notice. The statute, however,
requires that any decision approving and granting antitrust immunity be
made by October 1, 2002. To enable us to fully consider any comments
and make our determination before this deadline, we will give commenters
fifteen days to file answers to the application.
While we have concluded that the application is substantially complete,
we reserve the right to require the filing of any additional information
deemed relevant to this proceeding at any time.
By:
READ C. VAN DE WATER
Assistant Secretary
for Aviation and International Affairs
(SEAL)
An electronic version of this document is available on the World Wide
Web at
http://dms.dot.gov/
| dot | 2024-06-07T20:31:39.235600 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13002-0002-0001/content.doc"
} |
DOT-OST-2002-13002-0002-0002 | Notice | "2002-08-13T04:00:00" | Notice |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation
on the 13th day of August, 2002
________________________________________________
:
JOINT APPLICATION OF ALOHA AIRLINES, INC., : Served: August 13, 2002
And :
HAWAIIAN AIRLINES, INC., : Docket OST-
: 2002-13002
under Section 116 of the Aviation and Transportation :
Security Act of 2001 for Approval of and :
Antitrust Exemption for Agreement :
:
NOTICE
On July 31, 2002, Aloha Airlines and Hawaiian Airlines applied for
approval and antitrust immunity for an agreement whereby the two
airlines would coordinate capacity on five major routes within Hawaii.
They applied for approval and antitrust immunity under section 116 of
the Aviation and Transportation Security Act of 2001, P.L. No. 107-71,
115 Stat. 624 (November 19, 2001), which authorizes the Secretary,
notwithstanding the provisions of 49 U.S.C. 41309(a), to approve and
grant antitrust immunity to an agreement governing air transportation
within a single state, if the Governor of the state has issued a
declaration that the agreement is necessary to ensure the continuing
availability of such air transportation within the state. The Governor
of Hawaii has made such a declaration.
Any grant of approval and antitrust immunity would be made under 49
U.S.C. 41308 and 41309 under the standards set by section 116. As
provided by our procedural rules for such applications, 14 C.F.R. Part
303, we have reviewed the application and determined that it is
substantially complete. Answers would normally be due twenty-one days
from the date of adoption of this notice. The statute, however,
requires that any decision approving and granting antitrust immunity be
made by October 1, 2002. To enable us to fully consider any comments
and make our determination before this deadline, we will give commenters
fifteen days to file answers to the application.
While we have concluded that the application is substantially complete,
we reserve the right to require the filing of any additional information
deemed relevant to this proceeding at any time.
By:
READ C. VAN DE WATER
Assistant Secretary
for Aviation and International Affairs
(SEAL)
An electronic version of this document is available on the World Wide
Web at
http://dms.dot.gov/
| dot | 2024-06-07T20:31:39.238016 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13002-0002-0002/content.doc"
} |
DOT-OST-2002-13004-0002 | Notice | "2002-08-05T04:00:00" | Notice of Action Taken re: Northwest Airlines, Inc. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Issued by the Department of Transportation on August 5, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13004
________________________________________________________________________
_________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Application of NORTHWEST AIRLINES, INC filed 8/02/02 for:
XX : Allocation of a one-half (.5) U.S.-Ukraine weekly roundtrip
frequency in order to expand its third-
country code-share services with KLM Royal Dutch to daily
service.
Under Annex 1 of the U.S.-Ukraine aviation agreement, there are a total
of 18 weekly roundtrip frequencies for combination services available
for distribution. Currently, a total of 9 frequencies are allocated as
follows: Delta (2.5 frequencies), Northwest (3.0 frequencies), and
United (3.5 frequencies). Thus, there are 9 remaining frequencies
currently unallocated.
Allocation of one-half frequency will leave 8.5 remaining frequencies
for distribution.
Applicant rep: Megan Rae Rosia, (202) 842-3193 DOT Analyst: Keith
Glatz, (202) 366-3260
D I S P O S I T I O N
XX Granted, subject to conditions (see below)
The above action was effective when taken: August 5, 2002, and will
remain in effect indefinitely.
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the overall state of
aviation relations between the United States and Ukraine.
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated: XX Holder’s
certificates of public convenience and necessity
XX Dormancy Condition:
The frequency allocation is subject to the condition that if any of the
frequencies are not used for a period of 90 days, the allocation as to
each of those frequencies will expire automatically and the unused
frequencies will revert to the Department for reallocation. The
dormancy condition will begin on the date of this notice.
___________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our
action was consistent with Department policy and (2) grant of the
authority was consistent with the public interest.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Under Annex 1 of the U.S.-Ukraine bilateral agreement, frequencies used
to provide third-country code-share service count as one-half of a
frequency.
Aviation relations between the United States and Ukraine are governed
by a bilateral aviation agreement. However, the Annexes to the
Agreement, which serve for the basis of authority sought here, expired
on December 31, 2001. While the Annexes have yet to be formally
extended, both parties have been continuing to observe their provisions
on a comity and reciprocity basis.
| dot | 2024-06-07T20:31:39.239516 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-13004-0002/content.doc"
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DOT-OST-2002-13011-0002 | Notice | "2002-08-23T04:00:00" | Notice of Action Taken re: Frontier Airlines, Inc. | UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on August 23, 2002
NOTICE OF ACTION TAKEN -- DOCKETS OST-2002-13061
OST-2002-13011
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applications of FRONTIER AIRLINES, INC. filed 8/6/2002 for:
XX Exemption for two years under 49 U.S.C. 40109 to provide the
following service:
Docket OST-2002-13061:
Scheduled foreign air transportation of persons, property, and mail
between
Denver, Colorado, and Cancun, Mexico.
Docket OST-2002-13011:
Scheduled foreign air transportation of persons, property, and mail
between
Denver, Colorado, on the one hand, and San Jose del Cabo and Mazatlan,
Mexico, on the other hand.
Applicant rep: Edward P. Faberman (202) 639-7501 DOT Analyst:
Linda L. Lundell (202) 366-2336
D I S P O S I T I O N
XX Granted (subject to conditions, see below)
The above action was effective when taken: August 23, 2002, through
August 23, 2004.
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the aviation agreement
between the United States and Mexico.
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated: XX Holder’s
certificates of public convenience and necessity
XX Standard Exemption Conditions (attached)
------------------------------------------------------------------------
------------------------------------------------------------------------
-------------------------------------------------------
Conditions: The U.S.-Mexico exemption authority granted is subject to
the dormancy notice requirements set forth in condition 7 of Appendix A
of Order 88-10-2. Consistent with our standard practice, the dormancy
notice period will begin on December 20, 2002, for the Denver-Cancun
service, and December 7, 2002, for the Denver-San Jose del Cabo/Mazatlan
service—Frontier’s proposed startup dates for the subject
U.S.-Mexico service.
------------------------------------------------------------------------
---------------------------------------------------------------------
On the basis of data officially noticeable under Rule 24(g) of the
Department’s regulations, we found the applicant qualified to provide
the services authorized.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the exemption authority was consistent with the
public interest; and (3) grant of the authority would not constitute a
major regulatory action under the Energy Policy and Conservation Act of
1975. To the extent not granted, we denied all requests in the
referenced Dockets. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp Attachment
U.S. CARRIER
Standard Exemption Conditions
In the conduct of operations authorized by the attached notice, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250 (for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying that coverage to the Department, contained in 14 CFR 205;
(5) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration (FAA) Regulations, and with all U.S. Government
requirements concerning security; and
(7) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department of Transportation, with all applicable orders and regulations
of other U.S. agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
| dot | 2024-06-07T20:31:39.242395 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13011-0002/content.doc"
} |
DOT-OST-2002-13061-0002 | Notice | "2002-08-23T04:00:00" | Notice of Action Taken re: Frontier Airlines, Inc. | UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on August 23, 2002
NOTICE OF ACTION TAKEN -- DOCKETS OST-2002-13061
OST-2002-13011
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applications of FRONTIER AIRLINES, INC. filed 8/6/2002 for:
XX Exemption for two years under 49 U.S.C. 40109 to provide the
following service:
Docket OST-2002-13061:
Scheduled foreign air transportation of persons, property, and mail
between
Denver, Colorado, and Cancun, Mexico.
Docket OST-2002-13011:
Scheduled foreign air transportation of persons, property, and mail
between
Denver, Colorado, on the one hand, and San Jose del Cabo and Mazatlan,
Mexico, on the other hand.
Applicant rep: Edward P. Faberman (202) 639-7501 DOT Analyst:
Linda L. Lundell (202) 366-2336
D I S P O S I T I O N
XX Granted (subject to conditions, see below)
The above action was effective when taken: August 23, 2002, through
August 23, 2004.
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the aviation agreement
between the United States and Mexico.
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated: XX Holder’s
certificates of public convenience and necessity
XX Standard Exemption Conditions (attached)
------------------------------------------------------------------------
------------------------------------------------------------------------
-------------------------------------------------------
Conditions: The U.S.-Mexico exemption authority granted is subject to
the dormancy notice requirements set forth in condition 7 of Appendix A
of Order 88-10-2. Consistent with our standard practice, the dormancy
notice period will begin on December 20, 2002, for the Denver-Cancun
service, and December 7, 2002, for the Denver-San Jose del Cabo/Mazatlan
service—Frontier’s proposed startup dates for the subject
U.S.-Mexico service.
------------------------------------------------------------------------
---------------------------------------------------------------------
On the basis of data officially noticeable under Rule 24(g) of the
Department’s regulations, we found the applicant qualified to provide
the services authorized.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the exemption authority was consistent with the
public interest; and (3) grant of the authority would not constitute a
major regulatory action under the Energy Policy and Conservation Act of
1975. To the extent not granted, we denied all requests in the
referenced Dockets. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp Attachment
U.S. CARRIER
Standard Exemption Conditions
In the conduct of operations authorized by the attached notice, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250 (for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying that coverage to the Department, contained in 14 CFR 205;
(5) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration (FAA) Regulations, and with all U.S. Government
requirements concerning security; and
(7) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department of Transportation, with all applicable orders and regulations
of other U.S. agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
| dot | 2024-06-07T20:31:39.244770 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13061-0002/content.doc"
} |
DOT-OST-2002-13089-0003-0001 | Notice | "2002-08-16T04:00:00" | Notice Consolidating Proceedings and Granting Extension of Time | UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Served: August 16, 2002
_____________________________________________________________________
In Re: COMPLIANCE WITH U.S. CITIZENSHIP
REQUIREMENTS of DHL AIRWAYS, INC.,
Third Party Complaint pursuant to 14 C.F.R. §302.404
Docket OST-2001-8736
and
PETITION OF UNITED PARCEL SERVICE CO.
TO INSTITUTE A PUBLIC INQUIRY INTO THE CITIZENSHIP
AND FOREIGN CONTROL OF DHL AIRWAYS, INC.
Docket OST-2002-13089
_____________________________________________________________________
NOTICE CONSOLIDATING PROCEEDINGS
AND GRANTING EXTENSION OF TIME
Summary
By this notice, for administrative convenience, we consolidate the
filing by Federal Express Corporation (“FedEx”), dated August 7,
2002, in Docket OST-2001-8736 into Docket OST-2002-13089, a petition by
United Parcel Service (“UPS”) to institute an inquiry into the
citizenship of DHL Airways, Inc. (“DHL Airways”).
We also extend the deadline for answers to both filings to September 6,
2002.
Consolidation of Proceedings
On August 7, 2002, FedEx filed in Docket OST-2001-8736 a petition for
reconsideration or, alternatively, review of staff action of the
Department’s approval of DHL Airways’ corporate structure.
Originally, this docket contained a third-party enforcement complaint by
FedEx against DHL Airways , Inc. which was dismissed by the Office of
Aviation Enforcement and Proceedings on May 11, 2001 (Order 2001-5-11).
That docket is thus closed and is not the appropriate forum in which to
consider FedEx’s petition.
On August 9, 2002, UPS filed a petition to institute a public inquiry
into the citizenship and foreign control of DHL Airways, Inc. UPS filed
this petition in a new docket (OST-2002-13089).
The filings in these two dockets present common issues and are
interrelated. Both FedEx and UPS ask us for relief with regard to
various issues involving the citizenship of DHL Airways, Inc. Both
parties also submit substantially similar information to support their
requests.
We find that consolidation of these filings in Docket OST-2002-13089
will enable the Department and the parties to address these similar
issues and information more efficiently. Thus, we find that the
principle of administrative efficiency supports the consolidation of the
two proceedings into one coordinated docket. The consolidation will not
in any way prejudice any decision, substantive or procedural, made
concerning these filings.
Extension of Time
In a letter of August 13, 2002, DHL Airways requested an extension of
time until September 6, 2002 to respond to the UPS and FedEx petitions.
In this letter, DHL Airways stated that UPS did not object. FedEx filed
a Consent to Extension to Reply on August 14, 2002. For good cause
shown, we believe that DHL Airways’s request is reasonable, and we
will grant it.
ACCORDINGLY,
1. We consolidate the above-captioned proceedings into Docket
OST-2002-13089;
2. We grant the August 13, 2002 request of DHL Airways, Inc. for an
extension of time and give interested parties until September 6, 2002 to
answer the petitions of FedEx and UPS in Docket OST-2002-13089.
By:
READ C. VAN DE WATER
Assistant Secretary for Aviation
and International Affairs
(SEAL)
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov
| dot | 2024-06-07T20:31:39.246656 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13089-0003-0001/content.doc"
} |
DOT-OST-2002-13089-0003-0002 | Notice | "2002-08-16T04:00:00" | Notice Consolidating Proceedings and Granting Extension of Time | UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Served: August 16, 2002
_____________________________________________________________________
In Re: COMPLIANCE WITH U.S. CITIZENSHIP
REQUIREMENTS of DHL AIRWAYS, INC.,
Third Party Complaint pursuant to 14 C.F.R. §302.404
Docket OST-2001-8736
and
PETITION OF UNITED PARCEL SERVICE CO.
TO INSTITUTE A PUBLIC INQUIRY INTO THE CITIZENSHIP
AND FOREIGN CONTROL OF DHL AIRWAYS, INC.
Docket OST-2002-13089
_____________________________________________________________________
NOTICE CONSOLIDATING PROCEEDINGS
AND GRANTING EXTENSION OF TIME
Summary
By this notice, for administrative convenience, we consolidate the
filing by Federal Express Corporation (“FedEx”), dated August 7,
2002, in Docket OST-2001-8736 into Docket OST-2002-13089, a petition by
United Parcel Service (“UPS”) to institute an inquiry into the
citizenship of DHL Airways, Inc. (“DHL Airways”).
We also extend the deadline for answers to both filings to September 6,
2002.
Consolidation of Proceedings
On August 7, 2002, FedEx filed in Docket OST-2001-8736 a petition for
reconsideration or, alternatively, review of staff action of the
Department’s approval of DHL Airways’ corporate structure.
Originally, this docket contained a third-party enforcement complaint by
FedEx against DHL Airways , Inc. which was dismissed by the Office of
Aviation Enforcement and Proceedings on May 11, 2001 (Order 2001-5-11).
That docket is thus closed and is not the appropriate forum in which to
consider FedEx’s petition.
On August 9, 2002, UPS filed a petition to institute a public inquiry
into the citizenship and foreign control of DHL Airways, Inc. UPS filed
this petition in a new docket (OST-2002-13089).
The filings in these two dockets present common issues and are
interrelated. Both FedEx and UPS ask us for relief with regard to
various issues involving the citizenship of DHL Airways, Inc. Both
parties also submit substantially similar information to support their
requests.
We find that consolidation of these filings in Docket OST-2002-13089
will enable the Department and the parties to address these similar
issues and information more efficiently. Thus, we find that the
principle of administrative efficiency supports the consolidation of the
two proceedings into one coordinated docket. The consolidation will not
in any way prejudice any decision, substantive or procedural, made
concerning these filings.
Extension of Time
In a letter of August 13, 2002, DHL Airways requested an extension of
time until September 6, 2002 to respond to the UPS and FedEx petitions.
In this letter, DHL Airways stated that UPS did not object. FedEx filed
a Consent to Extension to Reply on August 14, 2002. For good cause
shown, we believe that DHL Airways’s request is reasonable, and we
will grant it.
ACCORDINGLY,
1. We consolidate the above-captioned proceedings into Docket
OST-2002-13089;
2. We grant the August 13, 2002 request of DHL Airways, Inc. for an
extension of time and give interested parties until September 6, 2002 to
answer the petitions of FedEx and UPS in Docket OST-2002-13089.
By:
READ C. VAN DE WATER
Assistant Secretary for Aviation
and International Affairs
(SEAL)
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov
| dot | 2024-06-07T20:31:39.249408 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13089-0003-0002/content.doc"
} |
DOT-OST-2002-13144-0002 | Notice | "2002-09-12T04:00:00" | Notice of Action Taken re: Air Nippon Co., Ltd. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on September 12, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13144
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applicant: Air Nippon Co., Ltd. Date Filed: August 13, 2002
Relief requested:
Exemption from 49 U.S.C. § 41301 to engage in scheduled foreign air
transportation of persons, property and mail between any point or points
in Japan, and any point or points in the United States; and to perform
charters subject to 14 CFR Part 212 of our rules.
Statement of Authorization to the extent necessary to permit Air Nippon
to wet lease aircraft to All Nippon Airways
Co., Ltd (ANA) for use by ANA on all routes ANA is authorized to serve
under its blanket code-share with United Air Lines, Inc.
Date and citation of last action: Air Nippon previously held exemption
authority during the period October 23, 1998- October 3, 2001. See
Notices of Action Taken, dated October 23, 1998 & October 3, 2000, in
Docket OST-98-4541. Air Nippon’s request for a statement of
authorization to wet lease aircraft to ANA, for use by ANA in its
code-share with United, is new.
Applicant representative: Charles J. Simpson, Jr. (202) 298-8660
Responsive pleadings: None filed
DISPOSITION
Action: Approved Action date: September 12, 2002
Effective dates of the authority granted: September 12, 2002-September
12, 2003
Basis for approval (bilateral agreement/reciprocity): 1998 Memorandum
of Understanding between the United States and Japan (1998 MOU).
Special conditions/Partial grant/Denial basis/Remarks: The authority
granted above is subject to the provisions of the 1998 MOU, and the
further condition that Air Nippon shall not perform any third and fourth
freedom charters unless specific authority in the form of a statement of
authorization for such charter(s) has been granted by the Department.
Air Nippon shall file applications for such statements of authorization
at least 30 calendar days before the charters involved pursuant to the
procedures set forth in § 212.10; provided, that applications involving
all-cargo charters may be filed up to ten calendar days before the
flights. (Under § 212.11(c), we need not submit denials of late-filed
applications for Presidential review).
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated:
X Standard exemption conditions (attached)
X Conditions set forth in the Statements of Authorization granted All
Nippon Airways and United Air Lines, Inc. dated August 7, 1998
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
________________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) the applicant was qualified to perform the
proposed operations; (2) our action was required and was consistent with
Department policy; (3) grant of the authority was consistent with the
public interest; and (4) grant of the authority would not constitute a
major regulatory action under the Energy Policy and Conservation Act of
1975. To the extent not granted/deferred/dismissed, we denied all
requests in the referenced Docket. We may amend, modify, or revoke the
authority granted in this Notice at any time without hearing at our
discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR §
385.30, may file their petitions within seven (7) days after the date of
issuance of this Notice. This action was effective when taken, and the
filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
HYPERLINK "http://dms.dot.gov//reports/reports_aviation.asp"
http://dms.dot.gov//reports/reports_aviation.asp
Attachment A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
9/98
On August 7, 1998, we granted All Nippon Airways and United Air Lines
blanket statements of authorization to engage in code-share services.
See undocketed joint application of United Air Lines, Inc. and All
Nippon Airways Co., Ltd., dated May 1, 1998.
| dot | 2024-06-07T20:31:39.250988 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13144-0002/content.doc"
} |
DOT-OST-2002-13259-0002 | Notice | "2002-09-30T04:00:00" | Notice of Action Taken re: Lineas Aereas Azteca, S.A. de C.V. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on September 30, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST 2002-13259
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applicant: LINEAS AEREAS AZTECA, S.A. de C.V.
Date Filed: August 28, 2002
Relief requested: Exemption from 49 USC section 41301 to permit the
applicant to conduct scheduled, combination service between: 1) Mexico
City, Mexico, and Las Vegas, Nevada; and 2) Mexico City, Mexico, and
Ontario, California.
If renewal, date and citation of last action: New authority.
Applicant representative(s): Pierre Murphy, 202-822-8050
Responsive pleadings: None.
DISPOSITION
Action: Approved. Action date:
September 30, 2002
Effective dates of authority granted: September 30, 2002, through
September 30, 2003.
Basis for approval: United States-Mexico Air Transport Services
Agreement
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated: Standard exemption
conditions.
Special conditions/Remarks:
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
_______________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) the applicant was qualified to perform its proposed
operations; (3) grant of the authority was consistent with the public
interest; and (4) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
| dot | 2024-06-07T20:31:39.256110 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13259-0002/content.doc"
} |
DOT-OST-2002-13371-0002 | Notice | "2002-10-02T04:00:00" | Notice of Action Taken re: Transporte Aereo S.A. d/b/a LanExpress |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 2, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13371
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applicant: Transporte Aéreo S.A. d/b/a LanExpress Date Filed:
September 16, 2002
Relief requested:
Exemption from 49 U.S.C. § 41301 to the extent necessary to engage in
scheduled foreign air transportation of persons, property and mail
between points in Chile and points in the United States, via
intermediate points, in conjunction with a code-share with American
Airlines, Inc.
Statement of Authorization under 14 CFR Part 212 to permit Transporte
Aéreo S.A. to display the designator code of American Airlines, Inc.
(AA) on flights operated by Transporte Aéreo S.A. between points in
Chile, for the carriage of American’s U.S.-Chile traffic.
Date and citation of last action: New authority
Applicant representative: Charles J. Simpson, Jr. (202) 298-8660 & Juan
Carlos Mencio (305) 869-2993
Responsive pleadings: None filed
DISPOSITION
Action: Approved Action date: October 2, 2002
(We acted on this application without awaiting expiration of the 15-day
answer period with the consent of all parties served.)
Effective dates of the exemption authority granted: October 2, 2002
through October 2, 2004
The statement of authorization granted was effective October 2, 2002,
and will remain in effect indefinitely, subject to the conditions listed
below:
Basis for approval (bilateral agreement/reciprocity): The Air Transport
Agreement between the United States and Chile
Special conditions/Partial grant/Denial basis/Remarks: Based on the
record in this case, we found that Transporte Aéreo S.A. is financially
and operationally qualified to perform the services authorized above.
The applicant is substantially owned and effectively controlled by two
Chilean corporations. Specifically, Transporte Aéreo S.A. is owned by
Lan Chile Cargo S.A. (99 shares) and Inversiones Lan S.A. (1 share).
The carrier is properly licensed by the Government of Chile to perform
the proposed services.
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated:
X Standard exemption conditions (attached)
X Conditions set forth in the Statements of Authorization granted Lan
Chile, S.A. and American Airlines, Inc. dated January 7, 2000, in Docket
OST-99-6546
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
________________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) the applicant was qualified to perform the
proposed operations; (2) our action was consistent with Department
policy; (3) grant of the authority was consistent with the public
interest; and (4) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR §
385.30, may file their petitions within seven (7) days after the date of
issuance of this Notice. This action was effective when taken, and the
filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
HYPERLINK "http://dms.dot.gov//reports/reports_aviation.asp"
http://dms.dot.gov//reports/reports_aviation.asp
Attachment A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, comply (except as otherwise
provided in the applicable bilateral agreement) with the Department's
rules governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
9/98
The applicant states that initially, American’s code will be carried
on Transporte Aéreo S.A. flights between Santiago and Concepción,
Puerto Montt, Punta Arenas, Antofagasta and Iquique. American’s
service beyond Santiago will be operated on a blind-sector basis with no
local traffic carried under American’s code between points in Chile.
American holds Department certificate authority to provide service
between the United States and Chile.
See Order 96-5-9.
Lan Chile Cargo S.A. is 99.8% owned by Lan Chile, S.A., a foreign air
carrier of Chile.
Any 30-day notice letter informing the Department of new code-share
services under the blanket code-share authority granted
Lan䌠楨敬愠摮䄠敭楲慣湩䐠捯敫⁴协ⵔ㤹㘭㐵‶桳污
污潳戠楦敬湩䐠捯敫⁴协ⵔ〲㈰ㄭ㌳ㄷമ
ഀ
:
| dot | 2024-06-07T20:31:39.260095 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13371-0002/content.doc"
} |
DOT-OST-2002-13383-0002 | Notice | "2002-10-23T04:00:00" | Notice of Action Taken re: Propair Inc. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 23, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST 2002-13383
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applicant: PROPAIR INC.
Date Filed: September 18, 2002
Relief requested: Exemption from 49 USC section 41301 to permit the
applicant to conduct, using small equipment (see below), passenger and
cargo charter operations between Canada and the United States, and other
charters in accordance with 14 CFR Part 212.
Applicant representative: Ron Tuggey, 819-762-0811 DOT analyst:
Allen F. Brown, 202-366-2405
Responsive pleadings: None.
DISPOSITION
Action: Approved. Action date: October 23,
2002
Effective dates of authority granted: October 23, 2002, through October
23, 2003.
Basis for approval (bilateral agreement/reciprocity): United
States-Canada Air Transport Agreement (Agreement)
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated: Standard exemption
conditions.
Special conditions/Remarks: In the conduct of these operations, the
carrier may only use aircraft designed to have a maximum passenger
capacity of not more than 60 seats or a maximum payload capacity of not
more than 18,000 pounds. The above grant includes authority to conduct
Third and Fourth Freedom charter operations. Charter operations to be
conducted under this authority that would not operate between Canada and
the United States, however, are subject to prior approval under 14 CFR
Part 212.
Action taken by: Paul L. Gretch, Director, Office of International
Aviation
________________________________________________________________________
______________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the authority was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
| dot | 2024-06-07T20:31:39.262267 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13383-0002/content.doc"
} |
DOT-OST-2002-13386-0001 | Notice | "2002-09-18T04:00:00" | Notice of Termination of Service at Lafayette, Indiana | BEFORE THE
DEPARTMENT OF TRANSPORTATION
WASHINGTON, D.C.
Notice of
MESABA AVIATION, INC.
d/b/a MESABA AIRLINES
of intent to terminate service at Lafayette,
Indiana pursuant to 49 U.S.C. § 41734
and 14 C.F.R. § 323
)
)
)
)
)
)
)
)
)
) Docket OST-02-
Dated: September 18, 2002
NOTICE OF TERMINATION OF SERVICE AT
Lafayette, indiana
Mesaba Aviation, Inc. d/b/a Mesaba Airlines (“Mesaba”) hereby
submits notice, pursuant to 49 U.S.C § 41734 and 14 C.F.R. § 323.3, of
its intent to terminate service to Lafayette, Indiana, effective
December 18, 2002. Mesaba provides this service as Northwest Airlink.
In support of this Notice, Mesaba states the following:
1. Mesaba is a certificated air carrier, whose corporate office is
located at:
7501 26th Avenue South
Minneapolis, MN 55450
(612) 726-5151.
2. Communications with respect to this Notice should be directed to:
Robert E. Weil
Vice President and Chief Financial Officer
Mesaba Airlines
7501 26th Avenue South
Minneapolis, MN 55450
(612) 726-5151
FAX: (612) 726-5168
3. No other carrier is currently serving Lafayette, Indiana from a large
or medium hub. (BRAD, CONFIRM TRUE). The Department, however, cannot
require continuation of service to Lafayette beyond the 90-day
termination notice period because Lafayette is located 61 highway miles
from a medium hub airport: Indianapolis International Airport.
4. The routing and schedule of the service that Mesaba is terminating on
December 18, 2002 is as follows:
From Departure To Arrival FrequencyDTW 13:50 YNG 15:42 Daily one
stop via CAK
DTW 19:50 YNG 20:52 Daily one stop via CAK
DTW 1604 LAF 1631 Daily nonstop
DTW 1925 LAF 1951 Daily nonstop except Sat
YNG 16:05 DTW 17:59 Daily one stop via CAK
YNG 07:30 DTW 09:25 Daily one stop via CAK
LAF 0640 DTW 0910 Daily nonstop
LAF 1735 DTW 1955 Daily nonstop except Sat
5. Mesaba operates these flights with Saab SF340 aircraft (30 - 34
passenger seats).
6. Mesaba intends to terminate Lafayette service on December 18, 2002.
7. In 1983, the Department determined that the level of essential air
service for Lafayette, Indiana is two daily nonstop roundtrips to/from
Chicago providing a minimum of 62 seats in each direction. Order 83-6-3
(June 1, 1983). In 1999, however, the Department determined that it
could not subsidize any carrier serving Lafayette because this community
is 61 highway miles from Indianapolis International Airport, a medium
hub. Order 99-6-21 (June 25, 1999). Because the Department is unable
to subsidize service to/from Lafayette, it cannot require any carrier to
continue serving the community beyond the 90-day termination notice
period. Id. The Department, nevertheless, continues to require notice
of service termination, and Mesaba is complying with this notice
requirement.
8. The effective date of this Notice is September 18, 2002. Objections
to this Notice are due within 20 days of this Notice.
9. As required by 14 C.F.R. § 323.7(a), this Notice is being served
upon all persons listed on the attached service list.
Respectfully submitted,
/s/ Robert E. Weil /s/
Robert E. Weil
Vice President and Chief Financial Officer
MESABA AIRLINES
7501 26TH Avenue South
Minneapolis, MS 55450
(612) 726-5151
Dated: September 18, 2002
SERVICE LIST
On this 18th day of September 2002, a copy of this NOTICE OF TERMINATION
was served by first class mail, postage prepaid, upon each of the
persons below:
Dennis DeVany, Chief
EAS and Domestic Analysis, X-53
U.S. Department of Transportation
400 Seventh Street, S.W.
Room 6417I
Washington, D.C. 20590
Robert Stroud
Manager
Lafayette Purdue University Airport
Terminal Building #104
Airport Road W
Lafayette, IN 47906
Mayor David Heath
City of Lafayette
City Hall
Lafayette, IN 47906
(…continued)
(continued…)
NOTICE OF TERMINATION OF
MESABA AIRLINES
Page PAGE \* MERGEFORMAT 2
PAGE 2
| dot | 2024-06-07T20:31:39.264091 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13386-0001/content.doc"
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DOT-OST-2002-13400-0003 | Notice | "2002-10-02T04:00:00" | Notice of Action Taken re: Aerovias de Mexico, S.A. de C.V. and Delta Air Lines, Inc. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Issued by the Department of Transportation on October 2, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13400
________________________________________________________________________
_________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Joint application of AEROVIAS DE MEXICO, S.A. DE C.V. and DELTA AIR
LINES, INC., filed 9/19/02 for:
XX Exemption for Aeromexico for one year under 49 U.S.C. 40109 to
provide the following service:
Scheduled foreign air transportation of persons, property, and mail
between Mazatlan, Mexico, and San Diego, California. Aeromexico intends
to operate this service under a code-share arrangement with Delta on
flights operated by Aeromexico.
XX Exemption for Delta for two years under 49 U.S.C. 40109 to provide
the following service:
Scheduled foreign air transportation of persons, property, and mail
between Mazatlan, Mexico, and San Diego, California. Delta also
requests to integrate this authority with its existing certificate and
exemption authority.
XX Statement of authorization for Aeromexico for indefinite duration
under 14 CFR Part 212 of the Department’s Regulations to:
Display Delta’s “DL” designator code in conjunction with scheduled
foreign air transportation of persons, property, and mail on flights
operated by Aeromexico between Mazatlan, Mexico, and San Diego,
California.
Applicant rep: Robert E.Cohn, 202-663-8060 (Delta)
William C. Evans, 202-371-6030 (Aeromexico)
DOT Analyst: Keith A. Glatz, 202-366-3260
D I S P O S I T I O N
XX Granted (subject to conditions, see below)
The above action, granting new exemption authority to Aeromexico was
effective when taken:
October 2, 2002, through October 2, 2003.
The above action, granting new exemption authority to Delta was
effective when taken:
October 2, 2002, through October 2, 2004.
The above action, granting a statement of authorization to Aeromexico
was effective when taken:
October 2, 2002, and will remain in effect indefinitely, subject to the
conditions listed below.
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the aviation agreement
between the United States and Mexico.
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated:
XX Aeromexico’s foreign air carrier permit
XX Delta’s certificates of public convenience and necessity
XX Standard exemption conditions (attached)
______________
Conditions: The U.S.-Mexico exemption authority granted to Delta is
subject to the dormancy notice requirements set forth in condition 7 of
Appendix A of Order 88-10-2, and is limited to operations conducted on a
code-share basis only.
The route integration authority granted is subject to the condition that
any service provided under this exemption shall be consistent with all
applicable agreements between the United States and the foreign
countries involved. Furthermore, (a) nothing in the award of the route
integration authority granted should be construed as conferring upon
Delta rights (including fifth-freedom intermediate and/or beyond rights)
to serve markets where U.S. carrier entry is limited unless Delta
notifies the Department of its intent to serve such a market and unless
and until the Department has completed any necessary carrier selection
procedures to determine which carrier(s) should be authorized to
exercise such rights; and (b) should there be a request by any carrier
to use the limited-entry route rights that are included in Delta’s
authority by virtue of the route integration exemption granted here, but
that are not then being used by Delta, the holding of such authority by
route integration will not be considered as providing any preference to
Delta in a competitive carrier selection proceeding to determine which
carrier(s) should be entitled to use the authority at issue.
The Statement of Authorization granted Aeromexico is subject to the
following conditions:
The statement of authorization will remain in effect only as long as
Delta and Aeromexico continue to hold the underlying authority to
operate the code-share services at issue, and the code-share agreement
providing for the code-share operations remains in effect.
Delta and/or Aeromexico must promptly notify the Department (Office of
International Aviation) if the code-share agreement is no longer
effective or if the carriers decide to cease operating all of a portion
of the approved code-share services. (Such notice should be filed in
Docket OST-2002-13.)
The code-sharing operations conducted under this authority must comply
with 14 CFR 257 and with any amendment to the Department’s regulations
concerning code-share arrangements that may be adopted. Notwithstanding
any provisions in the contract between the carriers, our approval here
is expressly conditioned upon the requirements that the subject foreign
air transportation be sold in the name of the carrier holding out such
service in computer reservation systems and elsewhere; that the carrier
selling such transportation (i.e., the carrier shown on the ticket)
accept responsibility for the entirety of the code-share journey for all
obligations established in its contract of carriage with the passenger;
and that the passenger liability of the operating carrier be unaffected;
and the operating carrier shall not permit the code of its U.S.
code-sharing partner to be carried on any flight that enters, departs,
or transits the airspace of any area for whose airspace the Federal
Aviation Administration has issued a flight prohibition; and
The authority granted here is specifically conditioned so that neither
Delta nor Aeromexico shall give any force or effect to any contractual
provisions between themselves that are contrary to these conditions.
Remarks: We acted on this application without awaiting expiration of
the 15-day answer period with the consent of all parties served.
________________________________________________________________________
______________
On the basis of data officially noticeable under Rule 24(g) of the
Department's regulations, we found the applicants qualified to provide
the services authorized.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our
action was consistent with Department policy; (2) grant of the
application was consistent with the public interest; and (3) grant of
the authority would not constitute a major regulatory action under the
Energy Policy and Conservation Act of 1975. To the extent not granted,
we denied all requests in the referenced Docket. We may amend, modify,
or revoke the authority granted in this Notice at any time without
hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Attachment
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY In the conduct of the
operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation
(41301/40109) 7/2002 Attachment
U.S. CARRIER Standard Exemption Conditions
In the conduct of operations authorized by the attached notice, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250 (for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying that coverage to the Department, contained in 14 CFR 205;
(5) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration (FAA), and with all U.S. Government requirements
concerning security; and
(7) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department of Transportation, with all applicable orders and regulations
of other U.S. agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
We expect this notification to be received within 10 days of such
non-effectiveness or of such decision.
| dot | 2024-06-07T20:31:39.267309 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13400-0003/content.doc"
} |
DOT-OST-2002-13426-0002 | Notice | "2002-10-01T04:00:00" | Notice of Action Taken re: Volga-Dnepr J.S. Airline |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 1, 2002
NOTICE OF ACTION TAKEN -- DOCKETS OST-2002-13426 & OST-2002-13461
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: Volga-Dnepr J.S. Cargo Airline
Relief requested: Exemptions pursuant to 49 U.S.C. section 40109(g) to
operate the following cargo charter flights using its AN-124 aircraft:
(a) one one-way flight from Philadelphia, PA, to Moffet Field, CA, to
transport outsized cargo consisting of a Rainbow Satellite payload and
associated equipment on/about September 28, 2002, on behalf of Lockheed
Martin Commercial Space Systems (Docket OST-2002-13425, filed September
23, 2002); and (b) three one-way flights from Denver, CO, to Cape
Canaveral/Skid Strip, FL, October 3-10, 2002, to transport outsized
cargo consisting of a Centaur III upper stage payload, an Atlas and
Centaur launch vehicle payload, and an Atlas V booster payload, on
behalf of Lockheed Martin Astronautics (Docket OST-2002-13461, filed
September 26, 2002). The applicant stated that Lockheed Martin needed
urgent delivery of the equipment in order to meet a schedule that
requires final assembly of the Rainbow Satellite payload and subsequent
shipment to Cape Canaveral for scheduled initial launch capability and
in order to complete mission integration activities involving the other
equipment and subsequent launch processing. It also stated that the
cargo is too large for transportation on U.S. carrier aircraft, and that
surface transportation was not feasible because of the time involved,
the delicate nature and high value of the cargo, and conditions
unsuitable to maintaining system integrity compliance.
Applicant representative: Glenn Wicks 202-457-7790
Responsive pleadings: Volga Dnepr served its applications on those U.S.
carriers operating large all-cargo aircraft. Each carrier indicated
that it did not have aircraft available to conduct the proposed
operations and that it had no comment or did not oppose grant of the
requested authority to Volga-Dnepr.
Statutory Standards: Under 49 U.S.C. section 40109(g), we may authorize
a foreign air carrier to carry commercial traffic between U.S. points
(i.e., cabotage traffic) under limited circumstances. Specifically, we
must find that the authority is required in the public interest; that
because of an emergency created by unusual circumstances not arising in
the normal course of business the traffic cannot be accommodated by U.S.
carriers holding certificates under 49 U.S.C. section 41102; that all
possible efforts have been made to place the traffic on U.S. carriers;
and that the transportation is necessary to avoid unreasonable hardship
to the traffic involved (an additional required finding, concerning
emergency transportation during labor disputes, was not relevant here).
For examples of earlier grants of authority of this type, see, e.g.,
Order 2001-5-23.
DISPOSITION
Action: Approved Action date: October 1, 2002
Effective dates of authority granted: October 1-13, 2002
Basis for approval: We found that the applications met all the relevant
criteria of 49 U.S.C. section 40109(g) for the grant of an exemption of
this type and that the grant was required in the public interest.
Specifically, we were persuaded that the need to move the cargo promptly
in order to complete scheduled assembly and mission integration
activities and subsequent launch deadlines; the fact that the cargo
could not be transported by surface either in time to meet that schedule
or without the risk of damage; the potential negative impact of delivery
delays; and the unique, outsized nature of the cargo, constituted an
emergency not arising in the normal course of business. Moreover, based
on the
Page 2 - Dockets OST-2002-13426 & OST-2002-13461
representations of the U.S. carriers, we concluded that no U.S. carrier
had aircraft available which could be used to conduct the operations at
issue here. We also found that grant of Volga-Dnepr’s requests would
prevent undue hardship to the cargo and Lockheed Martin. Finally, we
found that the applicant was qualified to perform its proposed
operations (see, e.g., Order 94-10-13).
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached) and to the condition that
Volga-Dnepr comply with an FAA-approved flight routing for the
authorized flights.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation
and International Affairs
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
7/2002
The applicant subsequently advised us informally that this flight had
been delayed until on/about October 3, 2002.
| dot | 2024-06-07T20:31:39.271628 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-13426-0002/content.doc"
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DOT-OST-2002-13449-0002 | Notice | "2002-09-27T04:00:00" | Notice of Action Taken re: Antonov Design Bureau |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on September 27, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13449
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: Antonov Design Bureau Date Filed: September 24, 2002
Relief requested: Exemption pursuant to 49 U.S.C. section 40109(g) to
operate one one-way cargo charter flight from Wilmington, OH, to
Seattle/Boeing Field, WA, during the period September 27-October 2,
2002, using its AN-124 aircraft to transport one outsized GE90-115
aircraft engine and related tooling and components. Antonov stated that
General Electric Aircraft Engines (GEAE) urgently required delivery of
the first of two GE90-225 flight test certification engines for
installation on a newly designed Boeing-777-300ER airplane that is
scheduled to be completely assembled by November in order to undergo
subsequent FAA certification flight testing, and that timely delivery of
the engine is a critical component of the overall airplane rollout and
certification schedule. It further stated that the size of the engine,
and the distance involved, forecloses the use of surface transportation
for timely delivery; that in order to avoid undue delays, shipment by
air was essential; and that because of the size of the cargo
transportation on U.S. carrier aircraft was not possible.
Applicant representative: Sheryl Israel 202-663-8060
Responsive pleadings: Antonov served its application on those U.S.
carriers operating large all-cargo aircraft. Each carrier indicated
that it did not have aircraft available to conduct the proposed
operation and that it had no comment or did not oppose grant of the
requested authority to Antonov.
Statutory Standards: Under 49 U.S.C. section 40109(g), we may authorize
a foreign air carrier to carry commercial traffic between U.S. points
(i.e., cabotage traffic) under limited circumstances. Specifically, we
must find that the authority is required in the public interest; that
because of an emergency created by unusual circumstances not arising in
the normal course of business the traffic cannot be accommodated by U.S.
carriers holding certificates under 49 U.S.C. section 41102; that all
possible efforts have been made to place the traffic on U.S. carriers;
and that the transportation is necessary to avoid unreasonable hardship
to the traffic involved (an additional required finding, concerning
emergency transportation during labor disputes, was not relevant here).
For examples of earlier grants of authority of this type, see, e.g.,
Order 2001-5-23.
DISPOSITION
Action: Approved Action date: September 27, 2002
Effective dates of authority granted: September 27 - October 4, 2002
Basis for approval: We found that the application met all the relevant
criteria of 49 U.S.C. section 40109(g) for the grant of an exemption of
this type and that the grant was required in the public interest.
Specifically, we were persuaded that GEAE’s need to transport the
engine without delay to in order to meet scheduled assembly and
certification flight testing deadlines, and the fact that the cargo
could not be transported by other modes in time to meet those deadlines,
constituted an emergency not arising in the normal course of business.
Moreover, based on the representations of the U.S. carriers, we
concluded that no U.S. carrier had aircraft available which would be
used to conduct the operation at issue here. Finally, we found that the
applicant was qualified to perform its proposed operations (see, e.g.,
Notice of Action Taken dated August 26, 2002, in Docket OST-96-1454).
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached) and to the condition that
Antonov comply with an FAA-approved flight routing for the authorized
flight.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation
and International Affairs
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
7/2002
| dot | 2024-06-07T20:31:39.274798 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13449-0002/content.doc"
} |
DOT-OST-2002-13450-0004 | Notice | "2002-10-28T05:00:00" | Notice of Action Taken re: Air Canada and El Al Israel Airlines |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 28, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13450
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Joint Applicants: Air Canada & El Al Israel Airlines Date Filed:
September 25, 2002
Relief requested: (1) Exemption from 49 U.S.C. 41301 to permit El Al
to conduct scheduled foreign air transportation of persons, property and
mail between Israel and Boston/San Francisco/Chicago, IL, on a
code-share basis only, via the intermediate point Toronto, Canada. El
Al proposes to conduct these operations via Toronto pursuant to a
code-share arrangement with Air Canada.
(2) Statement of authorization pursuant to 14 CFR 212 of the
Department’s regulations to permit Air Canada to display El Al’s
airline designator on flights operated by Air Canada between Toronto and
Boston/San Francisco/Chicago.
Applicant representatives: Anita Mosner (Air Canada) 703-294-5890;
John Gillick (El Al) 202-775-9870
DOT analyst: Barbara C. Schools 202-366-2401
Responsive pleadings: None
DISPOSITION
Action: Approved Action date: October 28, 2002
Effective dates of exemption authority granted: October 28, 2002 -
October 28, 2003
Effective dates of statement of authorization granted: October 28, 2002
- indefinite, subject to attached conditions
Basis for approval: The authority is consistent with the provisions of
both the U.S.-Canada and U.S.-Israel air service agreements.
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated:
X Standard exemption conditions (attached) X Foreign air
carrier permit conditions (Order 86-3-58)
X Code-share conditions (attached)
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
____________________________________________________________
We found that El Al was qualified to perform its proposed operations.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the authority was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;1
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended). __________________
1 To assure compliance with all applicable U.S. Government requirements
concerning security, the holder should, before commencing any new
service (including charter flights) from a foreign airport that would be
the holder’s last point of departure for the United States, inform its
Principal Security Inspector of its plans.
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
10/2002
Attachment
Air Canada/El Al Israel Airlines Code Share - Docket OST-2002-13450
The code-share operations authorized here are subject to the following
conditions:
(a) The statement of authorization will remain in effect only as long
as (i) Air Canada and El Al continue to hold the necessary underlying
authority to operate the code-share services at issue, and (ii) the
code-share agreement providing for the code-share operations remains in
effect.
(b) Air Canada and/or El Al must promptly notify the Department if the
code-share agreement providing for the code-share operations is no
longer effective or the carriers decide to cease operating any or all of
the approved code-share services. Such notices should be filed in
Docket OST-2002-13450. 1
(c) The code-sharing operations conducted under this authority must
comply with 14 CFR 257 and with any amendments to the Department’s
regulations concerning code-share arrangements that may be adopted.
Notwithstanding any provisions in the contract between the carriers, our
approval here is expressly conditioned upon the requirements that the
subject foreign air transportation be sold in the name of the carrier
holding out such service in computer reservation systems and elsewhere;
that the carrier selling such transportation (i.e., the carrier shown on
the ticket) accept responsibility for the entirety of the code-share
journey for all obligations established in its contract of carriage with
the passenger; and that the passenger liability of the operating carrier
be unaffected.
(d) The authority granted here is specifically conditioned so that
neither carrier shall give any force or effect to any contractual
provisions between themselves that are contrary to these conditions.
______________________
1 We expect this notification to be received within 10 days of such
non-effectiveness or of such decision.
American Airlines, Inc., filed an answer in opposition, which it
subsequently withdrew.
| dot | 2024-06-07T20:31:39.276988 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13450-0004/content.doc"
} |
DOT-OST-2002-13453-0002 | Notice | "2002-09-30T04:00:00" | Notice of Action Taken re: Lineas Aereas Allegro, S.A. de C.V. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on September 30, 2002
NOTICE OF ACTION TAKEN – DOCKET OST 2002-13453
_______________________________________________________________________
____________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applicant: LINEAS AEREAS ALLEGRO, S.A. de C.V.
Date Filed: September 25, 2002
Relief requested: Exemption from 49 USC section 41301 to permit the
applicant to conduct scheduled, combination services between: 1) Leon
(El Bajio), Mexico, and Oakland, California; 2) Puerto Vallarta, Mexico,
and Oakland, California; and 3) Zihuatanejo, Mexico, and Oakland,
California.
If renewal, date and citation of last action(s): New authority.
Applicant representative(s): Moffett B. Roller, 202-331-3300
Responsive pleadings: None.
DISPOSITION
Action: Approved.
Action date: September 30, 2002
Effective dates of authority granted: September 30, 2002, through
September 30, 2003.
Basis for approval (bilateral agreement/reciprocity): United
States-Mexico Air Transport Services Agreement.
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated: Standard exemption
conditions.
Special conditions/Remarks:
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
________________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) the applicant was qualified to perform its proposed
operations; (3) grant of the authority was consistent with the public
interest; and (4) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not
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| dot | 2024-06-07T20:31:39.279639 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13453-0002/content.doc"
} |
DOT-OST-2002-13454-0002 | Notice | "2002-10-01T04:00:00" | Notice of Action Taken re: Lineas Aereas Allegro, S.A. de C.V. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 1, 2002
NOTICE OF ACTION TAKEN – DOCKET OST 2002-13454
_______________________________________________________________________
____________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applicant: LINEAS AEREAS ALLEGRO, S.A. de C.V.
Date Filed: September 25, 2002
Relief requested: Exemption from 49 USC section 41301 to permit the
applicant to conduct scheduled, combination services between: 1)
Guadalajara, Mexico, and Oakland, California; 2) Mexico City, Mexico,
and Austin, Texas; 3) Tijuana, Mexico, and Sacramento, California; 4)
San Jose del Cabo, Mexico, and Oakland, California; and 5) Cancun,
Mexico, and Oakland, California.
If renewal, date and citation of last action(s): New authority.
Applicant representative(s): Moffett B. Roller, 202-331-3300
Responsive pleadings: None.
DISPOSITION
Action: Approved.
Action date: October 1, 2002
Effective dates of authority granted: October 1, 2002, through October
1, 2003.
Basis for approval (bilateral agreement/reciprocity): United
States-Mexico Air Transport Services Agreement.
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated: Standard exemption
conditions.
Special conditions/Remarks:
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
________________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) the applicant was qualified to perform its proposed
operations; (3) grant of the authority was consistent with the public
interest; and (4) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was
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| dot | 2024-06-07T20:31:39.281111 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13454-0002/content.doc"
} |
DOT-OST-2002-13455-0002 | Notice | "2002-10-01T04:00:00" | Notice of Action Taken re: Lineas Aereas Allegro, S.A. de C.V. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 1, 2002
NOTICE OF ACTION TAKEN – DOCKET OST 2002-13455
_______________________________________________________________________
____________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applicant: LINEAS AEREAS ALLEGRO, S.A. de C.V.
Date Filed: September 25, 2002
Relief requested: Exemption from 49 USC section 41301 to permit the
applicant to conduct scheduled, combination services between: 1)
Tijuana, Mexico, and San Jose, California; 2) Leon (El Bajio), Mexico,
and Sacramento, California; 3) Puerto Vallarta, Mexico, and Sacramento,
California; and 4) Zihuatanejo, Mexico, and Sacramento, California.
If renewal, date and citation of last action(s): New authority.
Applicant representative(s): Moffett B. Roller, 202-331-3300
Responsive pleadings: None.
DISPOSITION
Action: Approved.
Action date: October 1, 2002
Effective dates of authority granted: October 1, 2002, through October
1, 2003.
Basis for approval (bilateral agreement/reciprocity): United
States-Mexico Air Transport Services Agreement.
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated: Standard exemption
conditions.
Special conditions/Remarks:
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
________________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) the applicant was qualified to perform its proposed
operations; (3) grant of the authority was consistent with the public
interest; and (4) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
| dot | 2024-06-07T20:31:39.282395 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13455-0002/content.doc"
} |
DOT-OST-2002-13461-0002 | Notice | "2002-10-01T04:00:00" | Notice of Action Taken re: Volga-Dnepr J.S. Airline |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 1, 2002
NOTICE OF ACTION TAKEN -- DOCKETS OST-2002-13426 & OST-2002-13461
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: Volga-Dnepr J.S. Cargo Airline
Relief requested: Exemptions pursuant to 49 U.S.C. section 40109(g) to
operate the following cargo charter flights using its AN-124 aircraft:
(a) one one-way flight from Philadelphia, PA, to Moffet Field, CA, to
transport outsized cargo consisting of a Rainbow Satellite payload and
associated equipment on/about September 28, 2002, on behalf of Lockheed
Martin Commercial Space Systems (Docket OST-2002-13425, filed September
23, 2002); and (b) three one-way flights from Denver, CO, to Cape
Canaveral/Skid Strip, FL, October 3-10, 2002, to transport outsized
cargo consisting of a Centaur III upper stage payload, an Atlas and
Centaur launch vehicle payload, and an Atlas V booster payload, on
behalf of Lockheed Martin Astronautics (Docket OST-2002-13461, filed
September 26, 2002). The applicant stated that Lockheed Martin needed
urgent delivery of the equipment in order to meet a schedule that
requires final assembly of the Rainbow Satellite payload and subsequent
shipment to Cape Canaveral for scheduled initial launch capability and
in order to complete mission integration activities involving the other
equipment and subsequent launch processing. It also stated that the
cargo is too large for transportation on U.S. carrier aircraft, and that
surface transportation was not feasible because of the time involved,
the delicate nature and high value of the cargo, and conditions
unsuitable to maintaining system integrity compliance.
Applicant representative: Glenn Wicks 202-457-7790
Responsive pleadings: Volga Dnepr served its applications on those U.S.
carriers operating large all-cargo aircraft. Each carrier indicated
that it did not have aircraft available to conduct the proposed
operations and that it had no comment or did not oppose grant of the
requested authority to Volga-Dnepr.
Statutory Standards: Under 49 U.S.C. section 40109(g), we may authorize
a foreign air carrier to carry commercial traffic between U.S. points
(i.e., cabotage traffic) under limited circumstances. Specifically, we
must find that the authority is required in the public interest; that
because of an emergency created by unusual circumstances not arising in
the normal course of business the traffic cannot be accommodated by U.S.
carriers holding certificates under 49 U.S.C. section 41102; that all
possible efforts have been made to place the traffic on U.S. carriers;
and that the transportation is necessary to avoid unreasonable hardship
to the traffic involved (an additional required finding, concerning
emergency transportation during labor disputes, was not relevant here).
For examples of earlier grants of authority of this type, see, e.g.,
Order 2001-5-23.
DISPOSITION
Action: Approved Action date: October 1, 2002
Effective dates of authority granted: October 1-13, 2002
Basis for approval: We found that the applications met all the relevant
criteria of 49 U.S.C. section 40109(g) for the grant of an exemption of
this type and that the grant was required in the public interest.
Specifically, we were persuaded that the need to move the cargo promptly
in order to complete scheduled assembly and mission integration
activities and subsequent launch deadlines; the fact that the cargo
could not be transported by surface either in time to meet that schedule
or without the risk of damage; the potential negative impact of delivery
delays; and the unique, outsized nature of the cargo, constituted an
emergency not arising in the normal course of business. Moreover, based
on the
Page 2 - Dockets OST-2002-13426 & OST-2002-13461
representations of the U.S. carriers, we concluded that no U.S. carrier
had aircraft available which could be used to conduct the operations at
issue here. We also found that grant of Volga-Dnepr’s requests would
prevent undue hardship to the cargo and Lockheed Martin. Finally, we
found that the applicant was qualified to perform its proposed
operations (see, e.g., Order 94-10-13).
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached) and to the condition that
Volga-Dnepr comply with an FAA-approved flight routing for the
authorized flights.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation
and International Affairs
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
7/2002
The applicant subsequently advised us informally that this flight had
been delayed until on/about October 3, 2002.
| dot | 2024-06-07T20:31:39.283813 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-13461-0002/content.doc"
} |
DOT-OST-2002-13523-0016 | Notice | "2002-10-23T04:00:00" | Notice of Action Taken re: Antonov Design Bureau |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 23, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13523
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: Antonov Design Bureau Date Filed: 10/18/02, as
supplemented 10/21/02
Relief requested: Seven-day extension of the effective period of the 49
U.S.C. section 40109(g) exemption authority granted to Antonov by Order
2002-10-13, and the flexibility to coterminalize Ontario and/or
Victorville, CA, with Seattle, WA. In support of its request Antonov
stated that West Coast port operations continue to be impaired and the
movement of containers off ships has proceeded more slowly than
predicted; that Honda’s most critically needed parts shipments are now
stalled at its southern California seaport gateways; that, as result of
these circumstances, the the situation at Honda’s production lines is
even more serious; and that this extension and coterminalization
flexibility will be instrumental in helping address Honda’s serious
parts supply crisis and maintain production levels at U.S. plants.
Applicant representative: Alexander Van der Bellen 202-663-8060
DOT analyst: Barbara Schools 202-366-2401
Responsive pleadings: Antonov served its application on those U.S.
carriers operating large all-cargo aircraft. Except as noted below,
each carrier indicated that it did not have aircraft available to
conduct the proposed operation and that it had no comment or did not
oppose grant of the requested authority to Antonov.
Statutory Standards: Under 49 U.S.C. section 40109(g), we may authorize
a foreign air carrier to carry commercial traffic between U.S. points
(i.e., cabotage traffic) under limited circumstances. Specifically, we
must find that the authority is required in the public interest; that
because of an emergency created by unusual circumstances not arising in
the normal course of business the traffic cannot be accommodated by U.S.
carriers holding certificates under 49 U.S.C. section 41102; that all
possible efforts have been made to place the traffic on U.S. carriers;
and that the transportation is necessary to avoid unreasonable hardship
to the traffic involved (an additional required finding, concerning
emergency transportation during labor disputes, was not relevant here).
For examples of earlier grants of authority of this type, see, e.g.,
Order 2001-5-23.
DISPOSITION
Action: Approved Action date: October 23, 2002
Effective dates of authority granted: October 23, 2002 - October 30,
2002
Basis for approval: We found in the circumstances presented that our
previous public interest findings supporting grant of this authority
remained valid and that Antonov’s request for extension and
coterminalization flexibility met all the relevant criteria of 49 U.S.C.
section 40109(g) for the grant of an exemption of this type and that the
grant was required in the public interest. (See Order 2002-10-13 dated
October 9, 2002, in this docket.)
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached) and to the condition that
Antonov comply with an FAA-approved flight routing for the authorized
flights.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation and International Affairs
An electronic version of this document is available on the World Wide
Web at: http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;1
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended). __________________
1 To assure compliance with all applicable U.S. Government requirements
concerning security, the holder should, before commencing any new
service (including charter flights) from a foreign airport that would be
the holder’s last point of departure for the United States, inform its
Principal Security Inspector of its plans.
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
10/2002
By Order 2002-10-13, dated October 9, 2002, the Department granted
Antonov an exemption pursuant to 49 U.S.C. section 40109(g) to permit it
to operate a maximum of 20 one-way cargo charter flights from Seattle,
WA, to Columbus, OH, during the period ending October 20, 2002. In its
original application for this authority, Antonov stated that the flights
were on behalf of Honda Motors Ltd. and Honda of America, which required
urgent delivery of shipping containers holding motor vehicle parts and
components that had been held up by the West Coast port lockout; that
once the lockout ended, Honda needed to move the containers without
further delay to its U.S. manufacturing facilities in order to maintain
production; and that no U.S. carrier was in a position to provide
alternate lift that would meet its requirements.
Arrow Air, Inc., noted its answer filed in response to Antonov’s
original application, but had no further comments.
| dot | 2024-06-07T20:31:39.287574 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-13523-0016/content.doc"
} |
DOT-OST-2002-13554-0002 | Notice | "2002-10-11T04:00:00" | Notice of Action Taken re: Volga-Dnepr J.S. Cargo Airline |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 11, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13554
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: Volga-Dnepr J.S. Cargo Airline Date Filed: October 8,
2002
Relief requested: Exemption pursuant to 49 U.S.C. section 40109(g) to
permit it to operate one one-way cargo charter flight between
Philadelphia, PA, and Moffet Field, CA, on/about October 14, 2002, using
its AN-124 aircraft, to transport outsized cargo consisting of one
Rainbow Satellite Antenna Deck payload and associated equipment, on
behalf of Lockheed Martin Commercial Space Systems. The applicant
stated that Lockheed Martin required urgent delivery of the satellite to
complete final assembly and mission integration activities in order to
meet scheduled shipment deadlines to Cape Canaveral for subsequent
launch processing; that the cargo is too large for transportation on
U.S. carrier aircraft; and that surface transportation is not feasible
because of the time involved, the adverse effect a long road trip could
have on the high-value cargo, and the cargo’s size and highway
oversized load restrictions.
Applicant representative: Glenn Wicks 202-457-7790
Responsive pleadings: Volga-Dnepr served its application on those U.S.
carriers operating large all-cargo aircraft. Each carrier indicated
that it did not have aircraft available to conduct the proposed
operation and that it had no comment or did not oppose grant of the
requested authority to Volga-Dnepr.
Statutory Standards: Under 49 U.S.C. section 40109(g), we may authorize
a foreign air carrier to carry commercial traffic between U.S. points
(i.e., cabotage traffic) under limited circumstances. Specifically, we
must find that the authority is required in the public interest; that
because of an emergency created by unusual circumstances not arising in
the normal course of business the traffic cannot be accommodated by U.S.
carriers holding certificates under 49 U.S.C. section 41102; that all
possible efforts have been made to place the traffic on U.S. carriers;
and that the transportation is necessary to avoid unreasonable hardship
to the traffic involved (an additional required finding, concerning
emergency transportation during labor disputes, was not relevant here).
For examples of earlier grants of authority of this type, see, e.g.,
Order 2001-5-23.
DISPOSITION
Action: Approved Action date: October 11, 2002
Effective dates of authority granted: October 14-21, 2002
Basis for approval: We found that the application met all the relevant
criteria of 49 U.S.C. section 40109(g) for the grant of an exemption of
this type and that the grant was required in the public interest.
Specifically, we were persuaded that the need to move the satellite
promptly in order to complete scheduled assembly and integration
activities and subsequent launch processing deadlines; the fact that the
satellite could not be transported by surface either in time to meet
that schedule or without the risk of damage; the potential negative
impact of delivery delays; and the unique, outsized nature of the cargo,
constituted an emergency not arising in the normal course of business.
Moreover, based on the representations of the U.S. carriers, we
concluded that no U.S. carrier had aircraft available which could be
used to conduct the operation at issue here. We also found that grant
of Volga-Dnepr’s request would prevent undue hardship to the cargo and
Lockheed Martin. Finally, we found that the applicant was qualified to
perform its proposed operations (see, e.g., Order 94-10-13).
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached) and to the condition that
Volga-Dnepr comply with an FAA-approved flight routing for the
authorized flight.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation
and International Affairs
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
6/2002
| dot | 2024-06-07T20:31:39.289783 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-13554-0002/content.doc"
} |
DOT-OST-2002-13572-0002 | Notice | "2002-10-11T04:00:00" | Notice of Action Taken re: Antonov Design Bureau |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on October 11, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13572
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: Antonov Design Bureau Date Filed: October 9, 2002
Relief requested: Exemption pursuant to 49 U.S.C. section 40109(g) to
operate one one-way cargo charter flight from Wilmington, OH, to
Seattle/Boeing Field, WA, during the period October 14-21, 2002, using
its AN-124 aircraft to transport one outsized GE90-115 aircraft engine
and related tooling and components. Antonov stated that General
Electric Aircraft Engines (GEAE) urgently required delivery of the
second of two GE90-225 flight test certification engines for
installation on a newly designed Boeing-777-300ER airplane that is
scheduled to be completely assembled by November in order to undergo
subsequent FAA certification flight testing, and that timely delivery of
the engine is a critical component of the overall airplane rollout and
certification schedule. It further stated that the size of the engine,
and the distance involved, foreclose the use of surface transportation
for timely delivery; that in order to avoid undue delays, shipment by
air was essential; and that because of the size of the cargo
transportation on U.S. carrier aircraft was not possible.
Applicant representative: Sheryl Israel 202-663-8060
Responsive pleadings: Antonov served its application on those U.S.
carriers operating large all-cargo aircraft. Each carrier indicated
that it did not have aircraft available to conduct the proposed
operation and that it had no comment or did not oppose grant of the
requested authority to Antonov.
Statutory Standards: Under 49 U.S.C. section 40109(g), we may authorize
a foreign air carrier to carry commercial traffic between U.S. points
(i.e., cabotage traffic) under limited circumstances. Specifically, we
must find that the authority is required in the public interest; that
because of an emergency created by unusual circumstances not arising in
the normal course of business the traffic cannot be accommodated by U.S.
carriers holding certificates under 49 U.S.C. section 41102; that all
possible efforts have been made to place the traffic on U.S. carriers;
and that the transportation is necessary to avoid unreasonable hardship
to the traffic involved (an additional required finding, concerning
emergency transportation during labor disputes, was not relevant here).
For examples of earlier grants of authority of this type, see, e.g.,
Order 2001-5-23.
DISPOSITION
Action: Approved Action date: October 11, 2002
Effective dates of authority granted: October 14-21, 2002
Basis for approval: We found that the application met all the relevant
criteria of 49 U.S.C. section 40109(g) for the grant of an exemption of
this type and that the grant was required in the public interest.
Specifically, we were persuaded that GEAE’s need to transport the
engine without delay to in order to meet scheduled assembly and
certification flight testing deadlines, and the fact that the cargo
could not be transported by other modes in time to meet those deadlines,
constituted an emergency not arising in the normal course of business.
Moreover, based on the representations of the U.S. carriers, we
concluded that no U.S. carrier had aircraft available which would be
used to conduct the operation at issue here. Finally, we found that the
applicant was qualified to perform its proposed operations (see, e.g.,
Notice of Action Taken dated August 26, 2002, in Docket OST-96-1454).
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached) and to the condition that
Antonov comply with an FAA-approved flight routing for the authorized
flight.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation
and International Affairs
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
7/2002
| dot | 2024-06-07T20:31:39.292280 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-13572-0002/content.doc"
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DOT-OST-2002-13687-0002 | Notice | "2002-12-02T05:00:00" | 2002-12-4 Order Granting Emergency Exemption |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation
on the 2nd day of December, 2002
Application of
Aloha Island Air, Inc. OST Dkt. 2002-13687
(d/b/a Island Air, Inc.)
Emergency Exemption from
the Requirements of 14 CFR 382.40a Served: December 4, 2002
Order Granting Emergency Exemption
By this order, we grant Aloha Island Air, Inc., d/b/a Island Air, Inc.,
(“Island”), a commuter air carrier, a limited emergency exemption
from the requirements of 14 CFR 382.40a from December 4, 2002, through
February 1, 2003. The cited provision requires that air carriers have
in place mechanical lifts for assisting in the embarkation of disabled
passengers at airports which lack level-entry loading bridges or mobile
lounges. The provision applies to points enplaning at least 10,000
passengers a year which are served by aircraft of more than 30 seats and
affects a number of points served by Island.
Although not specifically requested, we are also granting an exemption
to the State of Hawaii from the requirements of 49 CFR 27.72. The
State, as the operator of the airports which are the subject of the
carrier’s request, has joint responsibility with the carrier for
implementing the boarding assistance requirement at issue here. Since
the State of Hawaii’s Department of Transportation filed comments in
support of the carrier’s application, we will consider the carrier’s
and State’s filings as a joint request for relief from 14 CFR 382.40a
and 49 CFR 27.72.
Background
In an application filed October 25, 2002, Island requested that the
mechanical lift requirement, which currently becomes effective December
4, be deferred with respect to the carrier’s operations at five
airports in Hawaii for a period of approximately two months. In support
of its application, the carrier states that additional time to implement
the rule is needed in order to transport the lifts to Honolulu, Kahului,
Kapalua, Lanai, and Molokai, the five airports subject to the request.
The mechanical lifts, the carrier states, have been ordered and were
scheduled for transportation by ocean freight in early October 2002.
The recent extended labor dispute affecting West Coast ports, however,
caused delays in the shipping date. Further, increasing the shipping
time, the mechanical lifts must travel via barge from Honolulu, Oahu to
reach the Kahului, Kapalua, Lanai, and Molokai airports. Given the size
of the mechanical lifts, Island cannot transport them on its aircraft.
Island also asserts that the number of estimated passenger enplanements
at the affected airports during December 2002 and January 2003 should be
small. Specifically, during December 2002 and January 2003 the number
of enplanements at Honolulu, Kahului, Kapalua, Lanai, and Molokai
airports are expected to be 26,719, 3,538, 7,315, 8,027, and 14,612,
respectively. The percentage of these passengers requesting mechanical
lifts should be very small. Island also states that until it receives
the mechanical lifts it will ensure that any disabled travelers at the
five airports affected will be accommodated in a dignified, safe manner
otherwise consistent with the requirements of 14 CFR Part 382.
The State of Hawaii has filed comments in support of the carrier’s
application. According to the State of Hawaii’s Department of
Transportation, it has negotiated and entered into an agreement with
Island allocating the responsibility of regulatory compliance on this
issue. As such, it urges the granting of the temporary exemption.
Decision
Upon review of the carrier’s application, we have decided to grant
Island’s request for an emergency exemption from 14 CFR 382.40a. In
reaching this decision, we note that the carrier already had taken steps
that would have resulted in compliance with the lift requirement, and
only due to circumstances that were unforeseeable and beyond its control
is this exemption necessary. We further note that the number of
passengers affected by the delayed compliance appears to be small. This
small number of enplanements by disabled air travelers will limit the
number of assistance requests made during the two months in which the
exemption will be effective. Moreover, the carrier has assured us that
it will provide dignified, safe boarding of all such passengers. On
these bases, we find that granting the requested emergency exemption
from the provision requiring the availability of mechanical lifts at the
Honolulu, Kahului, Kapalua, Lanai, and Molokai airports is consistent
with the public interest.
As the operator of the airports involved, the State of Hawaii is subject
to the requirements of 49 CFR Part 27, which applies the mandate of
non-discrimination toward disabled persons to recipients of federal
funds under section 504 of the Rehabilitation Act of 1973 (29 U.S.C.
794). Pursuant to 49 CFR 27.72 and 14 CFR 382.40a, air carriers and
airport operators are jointly responsible for compliance with the
boarding assistance requirements, including the provision of mechanical
lifts. In view of the State of Hawaii’s support of the carrier’s
application, we will consider the carrier’s application as requesting
similar relief for the airport operator and will grant the State of
Hawaii an exemption from the requirements of 49 CFR 27.72, to the extent
that it obligates the State to provide mechanical lifts at the Honolulu,
Kahului, Kapalua, Lanai, and Molokai airports, for the same period
stated in the carrier’s application.
ACCORDINGLY, acting under the authority of 49 CFR 5.13,
1. Aloha Island Air, Inc., d/b/a Island Air, Inc., is granted an
exemption from the requirement of 14 CFR 382.40a that it have in place
mechanical lifts to assist in boarding disabled passengers at the
Honolulu, Kahului, Kapalua, Lanai, and Molokai airports for the period
from December 4, 2002, to February 1, 2003;
2. The Hawaii Department of Transportation, as the operator of airports
at Honolulu, Kahului, Kapalua, Lanai, and Molokai, is granted an
exemption from 49 CFR 27.72 to the extent that it requires that the
airport operator have in place mechanical lifts to assist in boarding
disabled passengers at those locations for the period from December 4,
2002, through February 1, 2003; and
3. A copy of this order will be served on Aloha Island Air, Inc., and
the Hawaii Department of Transportation.
The action in this order is effective when taken and the filing of a
petition for review shall not alter its effectiveness.
By:
Norman Y. Mineta
Secretary
(SEAL)
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov
PAGE 2
Order 2002-12-4
| dot | 2024-06-07T20:31:39.297459 | regulations | {
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DOT-OST-2002-13705-0002 | Notice | "2002-12-16T05:00:00" | Notice of Action Taken re US Airways, Inc. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Issued by the Department of Transportation on December 16, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13705
________________________________________________________________________
_________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Application of US Airways, Inc. filed 10/29/02 for:
XX Exemption under 49 U.S.C. 40109 to provide the following service:
Scheduled foreign air transportation of persons, property, and mail
between points in the United States, on the one hand, and Anguilla,
Saba, St. Eustatius, and St. Barthelemy, on the other. US Airways
intends to operate this service pursuant to a code-share arrangement
with Windward Islands Airways International, N.V.
Application of Windward Islands Airways International, N.V. filed
10/29/02 for:
XX Statement of authorization under 14 CFR Part 212 to:
Permit Windward Islands Airways to display the designator code of US
Airways in conjunction with foreign air transportation of persons,
property, and mail on flights operated by Windward between St. Maarten,
on the one hand, and Anguilla, Saba, St. Eustatius, St. Barthelemy, St.
Kitts and Nevis, and Antigua, on the other.
Applicant rep: Joel Stephen Burton (202) 383-5300 DOT Analyst:
Sylvia Moore, (202) 366-6519
D I S P O S I T I O N
XX Granted (subject to conditions, see below)
The exemption authority granted to US Airways was effective when taken:
December 16, 2002, through
December 16, 2004.
The statement of authorization granted was effective when taken:
December 16, 2002, and will remain in effect indefinitely, subject to
the conditions listed below.
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted to serve Saba and St. Eustatius is consistent
with the aviation agreement between the United States and the
Netherlands Antilles; the authority granted to serve St. Barthelemy is
consistent with the aviation agreement between the United States and
France; and the authority granted to serve Anguilla is consistent with
the aviation agreement between the United States and the United Kingdom.
(See Reverse Side)
2
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated: XX Holder’s
certificates of public convenience and necessity (US Airways)
XX Holder’s foreign air carrier permit (Windward Islands Airways)
XX Standard exemption conditions (attached)
The statement of authorization granted is subject to the following
conditions:
(a) The statement of authorization will remain in effect only as long as
(i) US Airways and Windward Islands Airways continue to hold the
necessary underlying authority to operate the code-share services at
issue, and (ii) the code-share agreement providing for the code-share
operations remains in effect.
(b) US Airways and Windward Islands must promptly notify the Department
(Office of International Aviation) if the code-share agreement providing
for the code-share operations is no longer effective or if the carriers
decide to cease operating all or a portion of the approved code-share
services. Such notices should be filed in Docket OST-2002-13609.2
(c) The code-sharing conducted under this authority must comply with
Part 257 and with any amendments to the Department’s regulations
concerning code-share arrangements that may be adopted.
Notwithstanding any provisions in the contract between the carriers, our
approval here is expressly conditioned upon the requirements that the
subject foreign air transportation be sold in the name of the carrier
holding out such service in the computer reservation systems and
elsewhere; that the carrier selling such transportation (i.e., the
carrier shown on the ticket) accept responsibility for the entirety of
the code-share journey for all obligations established in its contract
of carriage with the passenger; and that the passenger liability of the
operating carrier be unaffected. Further, the operating carrier shall
not permit the code of its U.S. air carrier code-sharing partner to be
carried on any flights that enter, depart, or transit the airspace of
any area for whose airspace the Federal Aviation Administration has
issued a flight prohibition.
(d) The authority granted here is specifically conditioned so that
neither US Airways nor Windward Islands Airways shall give any force or
effect to any contractual provisions between themselves that are
contrary to these conditions.
________________________________________________________________________
__________
On the basis of data officially noticeable under Rule 24(g) of the
Department's regulations, we found US Airways, Inc. qualified to provide
the exemption services authorized.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the authority was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy, Policy and Conservation Act of 1975.
To the extent not granted, we denied all requests in the referenced
Docket. We may amend, modify, or revoke the authority granted in this
Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
APPENDIX
U.S. CARRIER
Standard Exemption Conditions
In the conduct of operations authorized by the attached notice, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250 (for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying that coverage to the Department, contained in 14 CFR 205;
(5) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR 203, concerning
waiver of Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration Regulations and with all applicable U.S. Government
requirements concerning security;1 and
(7) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department of Transportation, with all applicable orders and regulations
of other U.S. agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
10/2002
In connection with US Airways’ proposed code share to these points,
the joint applicants state that US Airways already holds authority for
U.S.-St. Kitts and Nevis, U.S.-Antigua, and U.S.-France services. (See
Notices of Action Taken dated January 16, 2002, July 5, 2001, and Order
2002-5-25, respectively.)
2 We expect this notification to be received within 10 days of such
non-effectiveness or of such decision.
1 To assure compliance with all applicable U.S. Government requirements
concerning security, the holder should, before commencing any new
service (including charter flights) to or from a foreign airport, inform
its Principal Security Inspector of its plans.
| dot | 2024-06-07T20:31:39.301240 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13705-0002/content.doc"
} |
DOT-OST-2002-13737-0003 | Notice | "2002-11-13T05:00:00" | Notice Establishing Common Answer and Reply Dates | Posted: 11/13/02
3:10 p.m.
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
_______________________________
In the Matter of
Requests for Interim Authority for U.S.-Hong Kong Fifth-Freedom
All-Cargo Frequencies
Dockets OST-2002-13737, 2002-13795, 2002-13804, 2002-13816
________________________________
Served: November 13, 2002
Notice Establishing Common Answer and Reply Dates
Under the October 19, 2002, Memorandum of Understanding between the
United States and the Hong Kong Special Administrative Region of the
People’s Republic of China (Hong Kong), U.S. carriers may, among other
things, provide a frequency-limited number of additional fifth-freedom
services. By Notice served October 29, 2002, the Department solicited
applications and requests for all of the new U.S. carrier rights set
forth in the MOU that are frequency-limited, with the exception of those
all-cargo frequencies that do not become available until the third year
of the phase-in. These applications were to be filed by November 5,
2002. Eight U.S. carriers filed for all-cargo fifth-freedom
frequencies. The Department is in the process of establishing
procedures for those applications and will issue an order on such
procedures in the near future.
In addition to the requested applications, four U.S. carriers (Federal
Express, Northwest, Polar, and United Parcel Service) have filed
separate applications for immediate, interim allocation of the available
frequencies, and each seeks a different shortened answer period for
responses to the respective applications. Under the Department’s
regulations, the normal answer period for frequency requests is fifteen
days after filing of an application, with replies due seven days after
the last day for filing an answer. In order to facilitate our
consideration of these applications in an expeditious fashion, we have
decided to establish a common date for the filing of answers and for the
filing of replies for the four applications seeking interim authority.
Therefore, acting under authority assigned in 14 CFR 385.3, we will
require that answers to the applications filed in the above-captioned
Dockets be filed no later than Monday, November 18, 2002, and that
replies be filed no later than Wednesday, November 20, 2002. While
these dates will shorten the answer period for three applications and
the reply period for all applications, we believe that the public
interest will best be served by establishing the common dates and will
eliminate any confusion as to filing dates for these related
applications.
We authorize service of documents by facsimile and by electronic mail.
We will serve this notice by facsimile or email on all parties served
with the four requests for immediate interim frequencies.
By:
PAUL L. GRETCH
Director, Office of International Aviation
(SEAL)
Dated: November 13, 2002
An electronic version of this notice is available on the World Wide Web
at
HYPERLINK "http://dms.dot.gov//reports/reports_aviation.asp"
http://dms.dot.gov//reports/reports_aviation.asp
Federal Express, Docket OST-2002-13737, filed November 1, 2002;
Northwest, Docket OST-13804, filed November 7, 2002; Polar Air Cargo,
Docket OST-13795, filed November 7, 2002; and UPS, filed November 12,
2002.
14 CFR 302.307 and 14 CFR 302.308.
| dot | 2024-06-07T20:31:39.305405 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13737-0003/content.doc"
} |
DOT-OST-2002-13795-0002 | Notice | "2002-11-13T05:00:00" | Notice Establishing Common Answer and Reply Dates | Posted: 11/13/02
3:10 p.m.
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
_______________________________
In the Matter of
Requests for Interim Authority for U.S.-Hong Kong Fifth-Freedom
All-Cargo Frequencies
Dockets OST-2002-13737, 2002-13795, 2002-13804, 2002-13816
________________________________
Served: November 13, 2002
Notice Establishing Common Answer and Reply Dates
Under the October 19, 2002, Memorandum of Understanding between the
United States and the Hong Kong Special Administrative Region of the
People’s Republic of China (Hong Kong), U.S. carriers may, among other
things, provide a frequency-limited number of additional fifth-freedom
services. By Notice served October 29, 2002, the Department solicited
applications and requests for all of the new U.S. carrier rights set
forth in the MOU that are frequency-limited, with the exception of those
all-cargo frequencies that do not become available until the third year
of the phase-in. These applications were to be filed by November 5,
2002. Eight U.S. carriers filed for all-cargo fifth-freedom
frequencies. The Department is in the process of establishing
procedures for those applications and will issue an order on such
procedures in the near future.
In addition to the requested applications, four U.S. carriers (Federal
Express, Northwest, Polar, and United Parcel Service) have filed
separate applications for immediate, interim allocation of the available
frequencies, and each seeks a different shortened answer period for
responses to the respective applications. Under the Department’s
regulations, the normal answer period for frequency requests is fifteen
days after filing of an application, with replies due seven days after
the last day for filing an answer. In order to facilitate our
consideration of these applications in an expeditious fashion, we have
decided to establish a common date for the filing of answers and for the
filing of replies for the four applications seeking interim authority.
Therefore, acting under authority assigned in 14 CFR 385.3, we will
require that answers to the applications filed in the above-captioned
Dockets be filed no later than Monday, November 18, 2002, and that
replies be filed no later than Wednesday, November 20, 2002. While
these dates will shorten the answer period for three applications and
the reply period for all applications, we believe that the public
interest will best be served by establishing the common dates and will
eliminate any confusion as to filing dates for these related
applications.
We authorize service of documents by facsimile and by electronic mail.
We will serve this notice by facsimile or email on all parties served
with the four requests for immediate interim frequencies.
By:
PAUL L. GRETCH
Director, Office of International Aviation
(SEAL)
Dated: November 13, 2002
An electronic version of this notice is available on the World Wide Web
at
HYPERLINK "http://dms.dot.gov//reports/reports_aviation.asp"
http://dms.dot.gov//reports/reports_aviation.asp
Federal Express, Docket OST-2002-13737, filed November 1, 2002;
Northwest, Docket OST-13804, filed November 7, 2002; Polar Air Cargo,
Docket OST-13795, filed November 7, 2002; and UPS, filed November 12,
2002.
14 CFR 302.307 and 14 CFR 302.308.
| dot | 2024-06-07T20:31:39.308453 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13795-0002/content.doc"
} |
DOT-OST-2002-13804-0002 | Notice | "2002-11-13T05:00:00" | Notice Establishing Common Answer and Reply Dates | Posted: 11/13/02
3:10 p.m.
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
_______________________________
In the Matter of
Requests for Interim Authority for U.S.-Hong Kong Fifth-Freedom
All-Cargo Frequencies
Dockets OST-2002-13737, 2002-13795, 2002-13804, 2002-13816
________________________________
Served: November 13, 2002
Notice Establishing Common Answer and Reply Dates
Under the October 19, 2002, Memorandum of Understanding between the
United States and the Hong Kong Special Administrative Region of the
People’s Republic of China (Hong Kong), U.S. carriers may, among other
things, provide a frequency-limited number of additional fifth-freedom
services. By Notice served October 29, 2002, the Department solicited
applications and requests for all of the new U.S. carrier rights set
forth in the MOU that are frequency-limited, with the exception of those
all-cargo frequencies that do not become available until the third year
of the phase-in. These applications were to be filed by November 5,
2002. Eight U.S. carriers filed for all-cargo fifth-freedom
frequencies. The Department is in the process of establishing
procedures for those applications and will issue an order on such
procedures in the near future.
In addition to the requested applications, four U.S. carriers (Federal
Express, Northwest, Polar, and United Parcel Service) have filed
separate applications for immediate, interim allocation of the available
frequencies, and each seeks a different shortened answer period for
responses to the respective applications. Under the Department’s
regulations, the normal answer period for frequency requests is fifteen
days after filing of an application, with replies due seven days after
the last day for filing an answer. In order to facilitate our
consideration of these applications in an expeditious fashion, we have
decided to establish a common date for the filing of answers and for the
filing of replies for the four applications seeking interim authority.
Therefore, acting under authority assigned in 14 CFR 385.3, we will
require that answers to the applications filed in the above-captioned
Dockets be filed no later than Monday, November 18, 2002, and that
replies be filed no later than Wednesday, November 20, 2002. While
these dates will shorten the answer period for three applications and
the reply period for all applications, we believe that the public
interest will best be served by establishing the common dates and will
eliminate any confusion as to filing dates for these related
applications.
We authorize service of documents by facsimile and by electronic mail.
We will serve this notice by facsimile or email on all parties served
with the four requests for immediate interim frequencies.
By:
PAUL L. GRETCH
Director, Office of International Aviation
(SEAL)
Dated: November 13, 2002
An electronic version of this notice is available on the World Wide Web
at
HYPERLINK "http://dms.dot.gov//reports/reports_aviation.asp"
http://dms.dot.gov//reports/reports_aviation.asp
Federal Express, Docket OST-2002-13737, filed November 1, 2002;
Northwest, Docket OST-13804, filed November 7, 2002; Polar Air Cargo,
Docket OST-13795, filed November 7, 2002; and UPS, filed November 12,
2002.
14 CFR 302.307 and 14 CFR 302.308.
| dot | 2024-06-07T20:31:39.322999 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13804-0002/content.doc"
} |
DOT-OST-2002-13816-0002 | Notice | "2002-11-13T05:00:00" | Notice Establishing Common Answer and Reply Dates | Posted: 11/13/02
3:10 p.m.
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
_______________________________
In the Matter of
Requests for Interim Authority for U.S.-Hong Kong Fifth-Freedom
All-Cargo Frequencies
Dockets OST-2002-13737, 2002-13795, 2002-13804, 2002-13816
________________________________
Served: November 13, 2002
Notice Establishing Common Answer and Reply Dates
Under the October 19, 2002, Memorandum of Understanding between the
United States and the Hong Kong Special Administrative Region of the
People’s Republic of China (Hong Kong), U.S. carriers may, among other
things, provide a frequency-limited number of additional fifth-freedom
services. By Notice served October 29, 2002, the Department solicited
applications and requests for all of the new U.S. carrier rights set
forth in the MOU that are frequency-limited, with the exception of those
all-cargo frequencies that do not become available until the third year
of the phase-in. These applications were to be filed by November 5,
2002. Eight U.S. carriers filed for all-cargo fifth-freedom
frequencies. The Department is in the process of establishing
procedures for those applications and will issue an order on such
procedures in the near future.
In addition to the requested applications, four U.S. carriers (Federal
Express, Northwest, Polar, and United Parcel Service) have filed
separate applications for immediate, interim allocation of the available
frequencies, and each seeks a different shortened answer period for
responses to the respective applications. Under the Department’s
regulations, the normal answer period for frequency requests is fifteen
days after filing of an application, with replies due seven days after
the last day for filing an answer. In order to facilitate our
consideration of these applications in an expeditious fashion, we have
decided to establish a common date for the filing of answers and for the
filing of replies for the four applications seeking interim authority.
Therefore, acting under authority assigned in 14 CFR 385.3, we will
require that answers to the applications filed in the above-captioned
Dockets be filed no later than Monday, November 18, 2002, and that
replies be filed no later than Wednesday, November 20, 2002. While
these dates will shorten the answer period for three applications and
the reply period for all applications, we believe that the public
interest will best be served by establishing the common dates and will
eliminate any confusion as to filing dates for these related
applications.
We authorize service of documents by facsimile and by electronic mail.
We will serve this notice by facsimile or email on all parties served
with the four requests for immediate interim frequencies.
By:
PAUL L. GRETCH
Director, Office of International Aviation
(SEAL)
Dated: November 13, 2002
An electronic version of this notice is available on the World Wide Web
at
HYPERLINK "http://dms.dot.gov//reports/reports_aviation.asp"
http://dms.dot.gov//reports/reports_aviation.asp
Federal Express, Docket OST-2002-13737, filed November 1, 2002;
Northwest, Docket OST-13804, filed November 7, 2002; Polar Air Cargo,
Docket OST-13795, filed November 7, 2002; and UPS, filed November 12,
2002.
14 CFR 302.307 and 14 CFR 302.308.
| dot | 2024-06-07T20:31:39.325199 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13816-0002/content.doc"
} |
DOT-OST-2002-13979-0002 | Notice | "2002-12-23T05:00:00" | Notice of Action Taken re Laker Airways (Bahamas) Limited |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on December 23, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13979
________________________________________________________________________
________________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no
additional confirming order will be issued in this matter).
Applicant: Laker Airways (Bahamas) Limited Date Filed: December 2,
2002
Relief requested: Exemption from 49 U.S.C. 41301 to conduct scheduled
foreign air transportation of persons, property and mail between
Freeport, Bahamas, and Boston, MA, on a coterminal basis with currently
authorized U.S.-Bahamas services.
If renewal, date and citation of last action: New authority
Applicant representative: Pierre Murphy 202-822-8050 DOT analyst:
Barbara Schools 202-366-2401
Responsive pleadings: None
DISPOSITION
Action: Approved Action date: December 23, 2002
Effective dates of authority granted: December 23, 2002 - December
23, 2003
Basis for approval (bilateral agreement/reciprocity): Reciprocity
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated:
X Standard exemption conditions (attached) X Foreign air
carrier permit conditions (Order 96-6-45)
Special conditions/Partial grant/Denial basis/Remarks:
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
____________________________________________________________
We found that the applicant was qualified to perform its proposed
operations.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the authority was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;1
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended). __________________
1 To assure compliance with all applicable U.S. Government requirements
concerning security, the holder should, before commencing any new
service (including charter flights) from a foreign airport that would be
the holder’s last point of departure for the United States, inform its
Principal Security Inspector of its plans.
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
10/2002
| dot | 2024-06-07T20:31:39.330957 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-13979-0002/content.doc"
} |
DOT-OST-2002-13991-0009 | Notice | "2002-12-20T05:00:00" | Notice of Action Taken re US Airways, Inc. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, DC
Issued by the Department of Transportation on December 20, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-13991
________________________________________________________________________
_________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Application of US Airways, Inc. filed 12/3/02 for:
XX Exemption under 49 U.S.C. 40109 to provide the following service:
Scheduled foreign air transportation of persons, property, and mail
between Philadelphia, Pennsylvania, and Shannon/Dublin, Ireland.
Applicant rep: Joel Stephen Burton (202) 383-5300 DOT Analyst:
Sylvia Moore, (202) 366-6519
D I S P O S I T I O N
XX Granted (see below)
The above action was effective when taken: December 20, 2002, through
December 20, 2004
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the aviation agreement
between the United States and Ireland.
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated: XX Holder’s
certificates of public convenience and necessity
XX Standard exemption conditions (attached)
________________________________________________________________________
__________
On the basis of data officially noticeable under Rule 24(g) of the
Department's regulations, we found US Airways, Inc. qualified to provide
the exemption services authorized.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the authority was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy, Policy and Conservation Act of 1975.
To the extent not granted, we denied all requests in the referenced
Docket. We may amend, modify, or revoke the authority granted in this
Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
APPENDIX
U.S. CARRIER
Standard Exemption Conditions
In the conduct of operations authorized by the attached notice, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250 (for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying that coverage to the Department, contained in 14 CFR 205;
(5) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR 203, concerning
waiver of Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration Regulations and with all applicable U.S. Government
requirements concerning security;1 and
(7) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department of Transportation, with all applicable orders and regulations
of other U.S. agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
10/2002
US Airways will operate this service on a seasonal basis beginning in
or about May 2003.
1 To assure compliance with all applicable U.S. Government requirements
concerning security, the holder should, before commencing any new
service (including charter flights) to or from a foreign airport, inform
its Principal Security Inspector of its plans.
| dot | 2024-06-07T20:31:39.334498 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13991-0009/content.doc"
} |
DOT-OST-2002-13992-0002 | Notice | "2002-12-23T05:00:00" | Notice of Action Taken re Consorcio Aviacsa, S.A. de C.V. |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on December 23, 2002
NOTICE OF ACTION TAKEN – DOCKET OST 2002-13992
_______________________________________________________________________
____________________________________________________
This serves as notice to the public of the action described below, taken
by the Department official indicated (no additional confirming order
will be issued in this matter).
Applicant: CONSORCIO AVIACSA, S.A. de C.V.
Date Filed: December 3, 2002
Relief requested: Exemption from 49 USC section 41301 to permit the
applicant to conduct scheduled, combination service between Monterrey,
Mexico, and Chicago, Illinois.
If renewal, date and citation of last action(s): New authority.
Applicant representative(s): Jim J. Marquez, 703-850-4760 DOT
analyst: Allen F. Brown, 202-366-2405
Responsive pleadings: None.
DISPOSITION
Action: Approved.
Action date: December 23, 2002
Effective dates of authority granted: December 23, 2002, through
December 23, 2003.
Basis for approval (bilateral agreement/reciprocity): United
States-Mexico Air Transport Services Agreement.
Except to the extent exempted/waived, this authority is subject to the
terms, conditions, and limitations indicated: Standard exemption
conditions.
Special conditions/Remarks:
Action taken by: Paul L. Gretch, Director
Office of International Aviation
________________________________________________________________________
________________________________________________________
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) the applicant was qualified to perform its proposed
operations; (3) grant of the authority was consistent with the public
interest; and (4) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted/deferred/dismissed, we denied all requests in
the referenced Docket. We may amend, modify, or revoke the authority
granted in this Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is
avai慬汢湯琠敨圠牯摬圠摩敗瑡ഺ瑨灴⼺搯獭搮
瑯朮癯⼯敲潰瑲⽳敲潰瑲彳癡慩楴湯愮灳
| dot | 2024-06-07T20:31:39.336419 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-13992-0002/content.doc"
} |
DOT-OST-2002-14001-0002 | Notice | "2002-12-19T05:00:00" | Notice of Action Taken re Continental Airlines, Inc. | UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on December 19, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST-2002-14001
________________________________________________________________________
___________________This serves as notice to the public of the action
described below, taken by the Department official indicated (no
additional confirming order will be issued in this matter).
Application of CONTINENTAL AIRLINES, INC., filed 12/3/02, for:
XX Exemption for two years under 49 U.S.C. 40109 to provide the
following service:
Scheduled foreign air transportation of persons, property, and mail
between Memphis, Tennessee, and Mexico City, Mexico. Continental also
seeks to combine this exemption authority with Continental’s other
exemption and certificate authority. Continental states that it intends
to provide this service pursuant to a code-share arrangement with
Northwest Airlines, Inc.
Applicant rep: R. Bruce Keiner, Jr. (202) 624-2500 DOT Analyst: Linda
Lundell (202) 366-2336
D I S P O S I T I O N
XX Granted (See Conditions below)
The authority granted was effective when taken: December 19, 2002 ,
through December 19, 2004 .
Action taken by: Paul L. Gretch, Director
Office of International Aviation
XX The authority granted is consistent with the aviation agreement
between the United States and Mexico.
Except to the extent exempted or waived, this authority is subject to
the terms, conditions, and limitations indicated: XX Holder’s
certificates of public convenience and necessity
XX Standard Exemption Conditions (attached)
________________________________________________________________________
___________
Special Conditions: The U.S.-Mexico exemption authority granted is
subject to the dormancy notice requirements set forth in condition 7 of
Appendix A of Order 88-10-2 and is limited to operations conducted on a
code-share basis only. Consistent with our standard practice, the
dormancy notice period will begin on Continental’s proposed startup
date of February 13, 2003.
The route integration authority granted to Continental is subject to the
condition that any service provided under this exemption shall be
consistent with all applicable agreements between the United States and
the foreign countries involved. Furthermore, (a) nothing in the award
of the route integration authority granted should be construed as
conferring upon Continental rights (including fifth-freedom intermediate
and/or beyond rights) to serve markets where U.S. carrier entry is
limited unless Continental notifies the Department of its intent to
serve such a market and unless and until the Department has completed
any necessary carrier selection procedures to determine which carrier(s)
should be authorized to exercise such rights); (b) should there be a
request by any carrier to use the limited-entry route rights that are
included in Continental’s authority by virtue of the route integration
exemption granted here, but that are not then being used by Continental,
the holding of such authority by route integration will not be
considered as providing any preference for Continental in a competitive
carrier selection proceeding to determine which carrier(s) should be
entitled to use the authority at issue.
________________________________________________________________________
________________________________________
On the basis of data officially noticeable under Rule 24(g) of the
Department’s regulations, we found the applicant qualified to provide
the services authorized.
Under authority assigned by the Department in its regulations, 14 CFR
Part 385, we found that (1) our action was consistent with Department
policy; (2) grant of the application was consistent with the public
interest; and (3) grant of the authority would not constitute a major
regulatory action under the Energy Policy and Conservation Act of 1975.
To the extent not granted, we denied all requests in the referenced
Docket. We may amend, modify, or revoke the authority granted in this
Notice at any time without hearing at our discretion.
Persons entitled to petition the Department for review of the action set
forth in this Notice under the Department’s regulations, 14 CFR
§385.30, may file their petitions within seven (7) days after the date
of issuance of this Notice. This action was effective when taken, and
the filing of a petition for review will not alter such effectiveness.
An electronic version of this document is available on the World Wide
Web at:
http://dms.dot.gov//reports/reports_aviation.asp
APPENDIX A
U.S. CARRIER
Standard Exemption Conditions
In the conduct of operations authorized by the attached notice, the
applicant(s) shall:
(1) Hold at all times effective operating authority from the government
of each country served;
(2) Comply with applicable requirements concerning oversales contained
in 14 CFR 250 (for scheduled operations, if authorized);
(3) Comply with the requirements for reporting data contained in 14 CFR
241;
(4) Comply with requirements for minimum insurance coverage, and for
certifying that coverage to the Department, contained in 14 CFR 205;
(5) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(6) Comply with the applicable requirements of the Federal Aviation
Administration Regulations and with all U.S. Government requirements
concerning security; and
(7) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department of Transportation, with all applicable orders and regulations
of other U.S. agencies and courts, and with all applicable laws of the
United States.
The authority granted shall be effective only during the period when the
holder is in compliance with the conditions imposed above.
10/2002
To assure compliance with all applicable U.S. Government requirements
concerning security, the holder should, before commencing any new
service (including charter flights) to or from a foreign airport, inform
its Principal Security Inspector of its plans.
| dot | 2024-06-07T20:31:39.338599 | regulations | {
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DOT-OST-2002-14049-0011 | Notice | "2002-12-18T05:00:00" | Notice Establishing Response Dates | UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
_______________________________
In the Matter of
Petitions for Reconsideration of Order 2002-12-11
(2002/2003 Hong Kong Fifth-Freedom All-Cargo Frequency Proceeding)
Docket OST-2002-14049
________________________________
Served: December 18, 2002
NOTICE ESTABLISHING RESPONSE DATES
On December 10, 2002, the Department issued Order 2002-12-11,
instituting the 2002/2003 Hong Kong Fifth-Freedom All-Cargo Frequency
Proceeding, Docket OST-2002-14049, establishing a procedural schedule
for the proceeding and attaching an evidence request for the use of the
parties in the case. Under the established procedures, petitions for
reconsideration of Order 2002-12-11 were to be filed December 17, 2002,
and Direct Exhibits are to be filed January 7, 2003.
The Department received three petitions for reconsideration of its
instituting order on December 17, 2002. Polar Air Cargo, Inc. requests
reconsideration of certain portions of the evidence request attached as
Appendix A to Order 2002-12-11, and also requests that December 19,
2002, be established as an answer date for its petition. Federal
Express filed two separate petitions, one seeking reconsideration of
technical issues in the instituting order and another requesting that
the Secretary of Transportation reconsider the Department’s
interpretation of the U.S.-Hong Kong Memorandum of Understanding.
Under the Department’s regulations, 14 CFR 302.14, answers to each of
the petitions filed December 17, 2002, would be due on December 27,
2002. In order to establish more expeditiously a record to resolve the
issues raised, we have decided to establish Monday, December 23, 2002,
as the due date for answers to the petitions, and Friday, December 27,
2002, as the due date for replies.
In view of the above, answers to the petitions for reconsideration of
Order 2002-12-11 shall be filed by December 23, 2002, and replies shall
be filed by December 27, 2002.
2
We will serve this Notice on all parties to this proceeding by email or
facsimile and will authorize the parties to serve their responses by
facsimile or email.
By:
READ C. VAN DE WATER
Assistant Secretary for Aviation
and International Affairs
(SEAL)
Dated: December 18, 2002
An electronic version of this notice is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_aviation.asp
| dot | 2024-06-07T20:31:39.341318 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-14049-0011/content.doc"
} |
DOT-OST-2002-14049-0012 | Notice | "2002-12-23T05:00:00" | Extension of Procedural Dates | Posted 12/23/02
9:32 am
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
_______________________________
2002/2003 Hong Kong Fifth-Freedom All-Cargo Frequency Proceeding
Docket OST-2002-14049
________________________________
Served: December 23, 2002
EXTENSION OF PROCEDURAL DATES
By Order 2002-12-11, the Department instituted the 2002/2003 Hong Kong
Fifth-Freedom All-Cargo Frequency Proceeding, Docket OST-2002-14049, and
established a procedural schedule for the proceeding. Under the
established procedural schedule Direct Exhibits are due January 7, 2003;
Rebuttal Exhibits, January 24, 2003; and Briefs, February 7, 2003.
By Joint Motion, filed December 18, 2002, six of the seven applicants to
the proceeding request (and state expressly that the seventh applicant
does not oppose) the amendment of the procedural timetable as follows:
Direct Exhibits, January 28, 2003; Rebuttal Exhibits, February 14, 2003;
and Briefs, February 28, 2003. The Joint Movants state that the brief
extension is necessary to enable them to prepare their exhibits and to
develop an adequate evidentiary record, especially given the holiday
season, and that the short extension should not affect the
Department’s ability to make a timely decision awarding the
frequencies.
We will grant the motion. In the circumstances presented, we find that
the Joint Movants have presented adequate justification for their
request and that no applicant’s interests will be prejudiced by a
grant.
Accordingly, Direct Exhibits in the above-captioned proceeding shall be
due January 28, 2003; Rebuttal Exhibits, February 14, 2003; and Briefs,
February 28, 2003.
We will serve this Notice on all parties to this proceeding by email or
facsimile and will authorize the parties to serve their responses by
facsimile or email.
By:
SUSAN MCDERMOTT
Deputy Assistant Secretary for Aviation
and International Affairs
(SEAL)
Dated: December 23, 2002
An electronic version of this notice is available on the World Wide Web
at
http://dms.dot.gov//reports/reports_aviation.asp
The Joint Motion was signed by counsel for Polar Air Cargo, Inc.,
Federal Express Corporation, Evergreen International Airlines, Inc.,
Northwest Airlines, Inc., Atlas Air, Inc., and Kalitta Air, Inc. The
Joint Applicants state that they are authorized to state that UPS does
not oppose the motion.
Given that all the applicants in this proceeding have already
registered support for, or non-opposition to, the Joint Motion, we are
acting on the Joint Motion without awaiting completion of the answer
period.
| dot | 2024-06-07T20:31:39.343665 | regulations | {
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"url": "https://downloads.regulations.gov/DOT-OST-2002-14049-0012/content.doc"
} |
DOT-OST-2002-14077-0002 | Notice | "2002-12-16T05:00:00" | Notice of Action Taken re Volga-Dnepr J.S. Cargo Airline |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on December 16, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST 2002-14077
This serves as interim notice to the public of the action described
below, taken orally by the Department official indicated; the confirming
order or other decision document will be issued as soon as possible.
Applicant: Volga-Dnepr J.S. Cargo Airline Date Filed: December 16,
2002
Relief requested: Exemption from 49 U.S.C. 40109(g) to operate three
one-way emergency cabotage cargo flights from Jackson, Mississippi or
Houston, Texas, as required, to Anderson AFB, Guam, to transport
outsized cargo consisting of high voltage line machinery, equipment and
materials on behalf of Kellogg Brown & Root (KBR), during the period
December 17-26, 2002. The applicant stated that the cargo is urgently
needed to allow KBR to restore electrical power to U.S. Navy facilities
on Guam following severe damage inflicted by a recent typhoon; that the
cargo is too large for transportation on U.S.-carrier aircraft, and that
surface transportation is not feasible because of the need to restore
power to these U.S. military facilities as soon as possible.
Applicant representative: Glenn Wicks, (202) 457-7790 DOT Analyst:
George Wellington, (202) 366-2391
Responsive pleadings: The applicant served its application on those U.S.
carriers operating large all-cargo aircraft. Each carrier indicated
that it did not have aircraft available to conduct the proposed
operation, and that it had no comment or did not oppose grant of the
requested authority.
Statutory Standards: Under 49 U.S.C. §40109(g), we may authorize a
foreign air carrier to transport commercial traffic between U.S. points
(i.e., cabotage traffic) only under limited circumstances.
Specifically, we must find that the authority is in the public interest;
that because of an emergency created by unusual circumstances not
arising in the normal course of business, U.S. air carriers holding
certificates under 49 U.S.C. §41102 cannot accommodate the traffic
involved; that all possible efforts have been made to accommodate the
traffic by using the resources of U.S. carriers; and that the authority
is necessary to avoid unreasonable hardship to the traffic involved (an
additional required finding, concerning emergency transportation during
labor disputes, was not relevant here). For examples of earlier grants
of authority of this type, see, e.g., Order 2001-5-23.
DISPOSITION
Action: Approved Action date: December 16, 2002
Effective dates of authority granted: December 17 - 28, 2002
Basis for approval: We found that our action was consistent with all
the relevant criteria of 49 U.S.C. 40109(g) for the grant of an
exemption of this type, and that the grant of this authority was
required in the public interest. Specifically, we were persuaded that
the damage inflicted on the U.S. Navy power generating facilities on
Guam by recent, extraordinary weather conditions; the need to restore
those facilities promptly and ensure U.S. military readiness; and the
unique, outsized nature of the cargo; constituted an emergency not
arising in the normal course of business.
Moreover, based on the representations of the U.S. carriers, we
concluded that no U.S. carrier had aircraft available which could be
used to conduct the operations at issue here. We also found that grant
of this authority would prevent unreasonable hardship to KBR and the
U.S. Navy. Finally, we found that the applicant was qualified to
perform its proposed operations (see, e.g., Order 94-10-13).
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached), and to the condition that
VolgaDnepr comply with an FAA-approved flight routing for the authorized
flights, and with any requisite Department of Defense authorizations.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation
and International Affairs
An electronic version of this document is available on the World Wide
Web at: http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;1
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
__________________
1 To assure compliance with all applicable U.S. Government requirements
concerning security, the holder should, before commencing any new
service (including charter flights) from a foreign airport that would be
the holder’s last point of departure for the United States, inform its
Principal Security Inspector of its plans.
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
10/2002
| dot | 2024-06-07T20:31:39.346233 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-14077-0002/content.doc"
} |
DOT-OST-2002-14100-0003 | Notice | "2002-12-19T05:00:00" | Notice of Action Taken re Antonov Design Bureau |
UNITED STATES OF AMERICA
DEPARTMENT OF TRANSPORTATION
OFFICE OF THE SECRETARY
WASHINGTON, D.C.
Issued by the Department of Transportation on December 19, 2002
NOTICE OF ACTION TAKEN -- DOCKET OST 2002-14100
This serves as interim notice to the public of the action described
below, taken orally by the Department official indicated; the confirming
order or other decision document will be issued as soon as possible.
Applicant: Antonov Design Bureau Date Filed: December 17, 2002
Relief requested: Exemption from 49 U.S.C. 40109(g) to operate one
one-way emergency cabotage cargo flight from Ontario or San Bernadino,
California, to Andersen AFB, Guam, to transport outsized cargo
consisting of two power generator units and ancillary relief supplies,
on behalf of IAP Worldwide Services, during the period December 19-23,
2002. The applicant stated that the cargo is urgently needed to allow
the Army Corps of Engineers to provide emergency power to affected
communities on Guam following severe damage inflicted by a recent
typhoon; that the cargo is too large for transportation on U.S.-carrier
aircraft, and that surface transportation is not feasible because of the
need to restore power to these communities as soon as possible.
Applicant representative: Robert Cohn, Sheryl Israel, (202) 663-8060
DOT Analyst: George Wellington, (202) 366-2391
Responsive pleadings: The applicant served its application on those U.S.
carriers operating large all-cargo aircraft. Each carrier indicated
that it did not have aircraft available to conduct the proposed
operation, and that it had no comment or did not oppose grant of the
requested authority.
Statutory Standards: Under 49 U.S.C. §40109(g), we may authorize a
foreign air carrier to transport commercial traffic between U.S. points
(i.e., cabotage traffic) only under limited circumstances.
Specifically, we must find that the authority is in the public interest;
that because of an emergency created by unusual circumstances not
arising in the normal course of business, U.S. air carriers holding
certificates under 49 U.S.C. §41102 cannot accommodate the traffic
involved; that all possible efforts have been made to accommodate the
traffic by using the resources of U.S. carriers; and that the authority
is necessary to avoid unreasonable hardship to the traffic involved (an
additional required finding, concerning emergency transportation during
labor disputes, was not relevant here). For examples of earlier grants
of authority of this type, see, e.g., Order 2001-5-23.
DISPOSITION
Action: Approved Action date: December 19, 2002
Effective dates of authority granted: December 19 - 25, 2002
Basis for approval: We found that our action was consistent with all
the relevant criteria of 49 U.S.C. 40109(g) for the grant of an
exemption of this type, and that the grant of this authority was
required in the public interest. Specifically, we were persuaded that
the damage inflicted on Guam by recent, extraordinary weather
conditions; the need to restore electrical power to affected communities
promptly; and the unique, outsized nature of the cargo; constituted an
emergency not arising in the normal course of business.
Moreover, based on the representations of the U.S. carriers, we
concluded that no U.S. carrier had aircraft available which could be
used to conduct the operation at issue here. We also found that grant
of this authority would prevent unreasonable hardship to IAP Worldwide
Services, the Army Corps of Engineers, and the affected communities on
Guam. Finally, we found that the applicant was qualified to perform its
proposed operation (see, e.g., Notice of Action Taken dated August 7,
2001, in Docket OST 1996-1454).
Except to the extent exempted/waived, this authority is subject to our
standard exemption conditions (attached), and to the condition that
Antonov Design Bureau comply with an FAA-approved flight routing for the
authorized flight, and with any requisite Department of Defense
authorizations.
Action taken by: Read C. Van de Water
Assistant Secretary for Aviation
and International Affairs
An electronic version of this document is available on the World Wide
Web at: http://dms.dot.gov//reports/reports_aviation.asp
Appendix A
FOREIGN AIR CARRIER CONDITIONS OF AUTHORITY
In the conduct of the operations authorized, the holder shall:
(1) Not conduct any operations unless it holds a currently effective
authorization from its homeland for such operations, and it has filed a
copy of such authorization with the Department;
(2) Comply with all applicable requirements of the Federal Aviation
Administration, including, but not limited to, 14 CFR Parts 129, 91, and
36, and with all applicable U.S. Government requirements concerning
security;1
(3) Comply with the requirements for minimum insurance coverage
contained in 14 CFR Part 205, and, prior to the commencement of any
operations under this authority, file evidence of such coverage, in the
form of a completed OST Form 6411, with the Federal Aviation
Administration’s Program Management Branch (AFS-260), Flight Standards
Service (any changes to, or termination of, insurance also shall be
filed with that office);
(4) Not operate aircraft under this authority unless it complies with
operational safety requirements at least equivalent to Annex 6 of the
Chicago Convention;
(5) Conform to the airworthiness and airman competency requirements of
its Government for international air services;
(6) Except as specifically exempted or otherwise provided for in a
Department Order, comply with the requirements of 14 CFR Part 203,
concerning waiver of Warsaw Convention liability limits and defenses;
(7) Agree that operations under this authority constitute a waiver of
sovereign immunity, for the purposes of 28 U.S.C. 1605(a), but only with
respect to those actions or proceedings instituted against it in any
court or other tribunal in the United States that are:
(a) based on its operations in international air transportation
that, according to the contract of carriage, include a point in the
United States as a point of origin, point of destination, or agreed
stopping place, or for which the contract of carriage was purchased in
the United States; or
(b) based on a claim under any international agreement or treaty
cognizable in any court or other tribunal of the United States.
In this condition, the term "international air transportation" means
"international transportation" as defined by the Warsaw Convention,
except that all States shall be considered to be High Contracting
Parties for the purpose of this definition;
(8) Except as specifically authorized by the Department, originate or
terminate all flights to/from the United States in its homeland;
(9) Comply with the requirements of 14 CFR Part 217, concerning the
reporting of scheduled, nonscheduled, and charter data;
(10) If charter operations are authorized, except as otherwise provided
in the applicable aviation agreement, comply with the Department's rules
governing charters (including 14 CFR Parts 212 and 380); and
(11) Comply with such other reasonable terms, conditions, and
limitations required by the public interest as may be prescribed by the
Department, with all applicable orders or regulations of other U.S.
agencies and courts, and with all applicable laws of the United States.
This authority shall not be effective during any period when the holder
is not in compliance with the conditions imposed above. Moreover, this
authority cannot be sold or otherwise transferred without explicit
Department approval under Title 49 of the U.S. Code (formerly the
Federal Aviation Act of 1958, as amended).
__________________
1 To assure compliance with all applicable U.S. Government requirements
concerning security, the holder should, before commencing any new
service (including charter flights) from a foreign airport that would be
the holder’s last point of departure for the United States, inform its
Principal Security Inspector of its plans.
U.S. Department of Transportation
Office of the Secretary of Transportation (41301/40109)
10/2002
| dot | 2024-06-07T20:31:39.348837 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/DOT-OST-2002-14100-0003/content.doc"
} |
EPA-HQ-OAR-2001-0001-0044 | Supporting & Related Material | "2002-03-19T05:00:00" | null | UNITED
STATES
ENVIRONMENTAL
PROTECTION
AGENCY
zz4/
WASHINGTON,
D.
C.
20460
Ms.
Maude
Grantham
Richards
Director,
Farmington
Electric
Utility
System
10
1
N.
Browning
Parkway
Farmington,
NM
87401
7995
OFFICE
OF
AIR
AN0
RADIATION
1
.....
EPAAIR
DOCKET
1
I
Dear
Ms.
Grantham
Richards:
Thank
you
for
your
August
20,2001,
letter
to
Senator
Pete
Domenici
in
which
you
enclose
comments
about
the
new
source
review
(
NSR)
program.
Senator
Domenici
forwarded
your
letter
to
the
Environmental
Protection
Agency
(
EPA)
requesting
that
I
respond
directly
to
you.
In
responding,
I
want
to
briefly
describe
some
of
the
ways
my
Office
is
working
to
improve
the
NSR
program
by
promoting
greater
certainty
and
flexibility
while
assuring
that
environmental
protection
is
maintained.
I
am
optimistic
that
these
efforts
will
appropriately
address
the
issues
you
raise.
First,
Administrator
Whitman
is
expected
to
announce
soon
a
comprehensive
strategy
to
significantly
reduce
power
plant
pollution.
As
part
of
this
strategy,
EPA
is
looking
at
ways
to
promote
regulatory
certainty
at
power
plants
including
certainty
regarding
how
NSR
applies
when
power
plants
construct
or
modify
equipment.
Second,
we
are
currently
following
through
on
a
recommendation
in
the
President's
National
Energy
Policy
that
EPA,
in
consultation
with
the
Secretary
of
Energy
and
other
relevant
agencies,
review
NSR
regulations
and
report
to
the
President
on
the
impact
of
the
regulations
on
investment
in
new
utility
and
refinery
generation
capacity,
energy
efficiency,
and
environmental
protection.
Once
we
release
our
comprehensive
strategy,
we
will
report
to
the
President
on
whether
additional
improvements
to
the
NSR
program
are
needed.
Third,
we
continue
to
develop
improvements
to
the
NSR
program
that
build
upon
our
1996
NSR
improvement
proposal
and
the
substantial
stakeholder
feedback
we
have
received
since
then.
Together
these
efforts
should
result
in
a
much
more
effective
NSR
program.
As
we
move
forward,
we
are
fully
considering
stakeholder
comments
like
those
you
made.
Since
May,
we
have
met
with
over
100
stakeholder
groups,
have
held
four
public
meetings,
and
have
received
comment
letters
from
over
130,000
individuals
and
organizations.
Several
groups
have
expressed
concerns
similar
to
yours
about
the
Detroit
Edison
determination
and
EPA's
interpretation
of
the
"
routine
maintenance"
exemption
from
NSR,
and
we
are
currently
evaluating
how
best
to
proceed
on
this
and
other
issues.
lntemet
Address
(
URL)
e
http:
Nw.
epa.
gov
RecycledFlecyclable
*
Printed
with
Vegetable
Oil
Based
Inks
on
Recycled
Paper
(
Minimum
25%
Postconsumer)
2
Thank
you
for
your
interest
in
this
issue.
I
hope
you
will
continue
to
stay
involved
in
our
efforts
to
improve
the
NSR
program.
I
appreciate
the
opportunity
to
be
of
service
and
trust
that
the
information
provided
is
helpful
to
you.
Sincerely,
4)
Jeffrey
R.
Holmstead
Assistant
Administrator
cc:
Senator
Pete
V.
Domenici
| epa | 2024-06-07T20:31:39.460850 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0001-0044/content.txt"
} |
EPA-HQ-OAR-2001-0001-0045 | Supporting & Related Material | "2002-03-19T05:00:00" | null | The
Honorable
Mary
L.
Landrieu
United
States
Senate
Washington,
DC
205
10
1
804
Dear
Senator
Landrieu:
THE
.
ADMINISTRATOR
Thank
you
for
your
letter
of
August
10,200
1,
in
which
you
describe
concerns
raised
by
many
of
your
constituents
about
the
.
impact
of
the
New
Source
Review
(
NSR)
program
on
energy
production
and
use
at
industrial
facilities.
You
dcscribe
particular
concerns
about
the
potential
for
delays
and
uncertainty
associated
with
NSR
to
discourage
efficiency
and
reliability
improvements
and
needed
maintenance.
I
have
heard
similar
concerns,
and
I
believe
that
we
must
examine
them
in
an
effort
to
streamline
NSR
and
promote
greater
flexibility
and
certainty
while
preserving
the
environmental
benefits
that
the
NSR
program
achieves.
As
you
note,
the
Environmental
Protection
Agency
(
EPA)
has
been
engaged
in
just
such
an
examination,
consistent
with
the
National
Energy
Policy
Report,
which
recobended
that
I,
in
consultation
with
the
Secretary
of
Energy
and
other
relevant
agencies,
review
NSR
regulations,
including
administrative
interpretation
and
implementation
and
report
to
the
President
on
the
impact
of
NSR
on
investment
in
new
utility
and
refinery
generation
capacity,
energy
efficiency,
and
environmental
protection.
During
this
review,
the
EPA
has
received
over
130,000
mitten
comments,
met
with
over
100
stakeholder
groups,
and
heard
from
over
250
witnesses
at
four
hearings
around
the
country,
including
one
in
Baton
Rouge.
We
are
now
in
the
process
of
reviewing
those
comments
and
determining
what
improvements
to
NSR
are
needed
to
address
concerns
l
i
e
those
raised
by
your
constituents.
I
expect
to
issue
my
fmd
report
on
NSR
shortly
after
I
propose
a
comprehensive
strategy
that
will
significantly
reduce
air
pollution
at
power
plants.
Again,
thank
you
for
writing.
I
appreciate
your
interest
in
this
issue
and
look
forward
to
sharing
our
recommendations
with
you
when
our
review
is
completed.
If
you
have
further
questions,
please
do
not
hesitate
to
contact
me
or
your
staff
may
contact
Diann
Frantz
of
our
Congressional
and
Intergovernmental
Relations
office
at
(
202)
564
3668.
Sincerely
yours,
L
T
M
Christine
Todd
Whitman
internet
Address
(
URL)
http://
w.
epa.
gov
Rw;
ycled/
Recyclable
Printed
with
Vegetable
Oil
Eased
inks
on
Recycled
Paper
{
Minimum
50%
Postconsumer
content)
| epa | 2024-06-07T20:31:39.467833 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0001-0045/content.txt"
} |
EPA-HQ-OAR-2001-0004-0291 | Rule | "2002-12-31T05:00:00" | Prevention of Significant Deterioration
(PSD) and Nonattainment New Source
Review (NSR): Baseline Emissions Determination,
Actual-to-Future-Actual Methodology, Plantwide
Applicability Limitations, Clean Units, Pollution
Control Projects | Tuesday,
December
31,
2002
Part
III
Environmental
Protection
Agency
40
CFR
Parts
51
and
52
Prevention
of
Significant
Deterioration
(
PSD)
and
Nonattainment
New
Source
Review
(
NSR);
Final
Rule
and
Proposed
Rule
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
51
and
52
[
AD
FRL
7414
5]
RIN
2060
AE11
Prevention
of
Significant
Deterioration
(
PSD)
and
Nonattainment
New
Source
Review
(
NSR):
Baseline
Emissions
Determination,
Actual
to
Future
Actual
Methodology,
Plantwide
Applicability
Limitations,
Clean
Units,
Pollution
Control
Projects
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Final
rule.
SUMMARY:
The
EPA
is
revising
regulations
governing
the
New
Source
Review
(
NSR)
programs
mandated
by
parts
C
and
D
of
title
I
of
the
Clean
Air
Act
(
CAA
or
Act).
These
revisions
include
changes
in
NSR
applicability
requirements
for
modifications
to
allow
sources
more
flexibility
to
respond
to
rapidly
changing
markets
and
to
plan
for
future
investments
in
pollution
control
and
prevention
technologies.
Today's
changes
reflect
EPA's
consideration
of
discussions
and
recommendations
of
the
Clean
Air
Act
Advisory
Committee's
(
CAAAC)
Subcommittee
on
NSR,
Permits
and
Toxics,
comments
filed
by
the
public,
and
meetings
and
discussions
with
interested
stakeholders.
The
changes
are
intended
to
provide
greater
regulatory
certainty,
administrative
flexibility,
and
permit
streamlining,
while
ensuring
the
current
level
of
environmental
protection
and
benefit
derived
from
the
program
and,
in
certain
respects,
resulting
in
greater
environmental
protection.
EFFECTIVE
DATE:
This
final
rule
is
effective
on
March
3,
2003.
ADDRESSES:
Docket.
Docket
No.
A
90
37,
containing
supporting
information
used
to
develop
the
proposed
rule
and
the
final
rule,
is
available
for
public
inspection
and
copying
between
8
a.
m.
and
4:
30
p.
m.,
Monday
through
Friday
(
except
government
holidays)
at
the
Air
and
Radiation
Docket
and
Information
Center
(
6102T),
Room
B
108,
EPA
West
Building,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20460;
telephone
(
202)
566
1742,
fax
(
202)
566
1741.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
Worldwide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
this
final
rule
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature,
a
copy
of
the
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules:
http://
www.
epa.
gov/
ttn/
oarpg.
FOR
FURTHER
INFORMATION
CONTACT:
Ms.
Lynn
Hutchinson,
Information
Transfer
and
Program
Integration
Division
(
C339
03),
U.
S.
EPA
Office
of
Air
Quality
Planning
and
Standards,
Research
Triangle
Park,
North
Carolina
27711,
telephone
919
541
5795,
or
electronic
mail
at
hutchinson.
lynn@
epa.
gov,
for
general
questions
on
this
rule.
For
questions
on
baseline
emissions
determination
or
the
actual
to
projected
actual
applicability
test,
contact
Mr.
Dan
DeRoeck,
at
the
same
address,
telephone
919
541
5593,
or
electronic
mail
at
deroeck.
dan@
epa.
gov.
For
questions
on
Plantwide
Applicability
Limitations
(
PALs),
contact
Mr.
Raj
Rao,
at
the
same
address,
telephone
919
541
5344,
or
electronic
mail
at
rao.
raj@
epa.
gov.
For
questions
on
Clean
Units,
contact
Mr.
Juan
Santiago,
at
the
same
address,
telephone
919
541
1084,
or
electronic
mail
at
santiago.
juan@
epa.
gov.
For
questions
on
Pollution
Control
Projects
(
PCPs),
contact
Mr.
Dave
Svendsgaard,
at
the
same
address,
telephone
919
541
2380,
or
electronic
mail
at
svendsgaard.
dave@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Regulated
Entities
Entities
potentially
affected
by
this
final
action
include
sources
in
all
industry
groups.
The
majority
of
sources
potentially
affected
are
expected
to
be
in
the
following
groups.
Industry
group
SIC
a
NAICSb
Electric
Services
............................................................................
491
221111,
221112,
221113,
221119,
221121,
221122
Petroleum
Refining
........................................................................
291
32411
Chemical
Processes
.....................................................................
281
325181,
32512,
325131,
325182,
211112,
325998,
331311,
325188
Natural
Gas
Transport
..................................................................
492
48621,
22121
Pulp
and
Paper
Mills
.....................................................................
261
32211,
322121,
322122,
32213
Paper
Mills
....................................................................................
262
322121,
322122
Automobile
Manufacturing
............................................................
371
336111,
336112,
336712,
336211,
336992,
336322,
336312,
33633,
33634,
33635,
336399,
336212,
336213
Pharmaceuticals
............................................................................
283
325411,
325412,
325413,
325414
a
Standard
Industrial
Classification
b
North
American
Industry
Classification
System.
Entities
potentially
affected
by
this
final
action
also
include
State,
local,
and
tribal
governments
that
are
delegated
authority
to
implement
these
regulations.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Overview
of
Today's
Final
Action
A.
Background
B.
Introduction
C.
Overview
of
Final
Actions
1.
Determining
Whether
a
Proposed
Modification
Results
in
a
Significant
Emissions
Increase
2.
CMA
Exhibit
B
3.
Plantwide
Applicability
Limitations
(
PALs)
4.
Clean
Units
5.
Pollution
Control
Projects
(
PCPs)
6.
Major
NSR
Applicability
7.
Enforcement
8.
Enforceability
II.
Revisions
to
the
Method
for
Determining
Whether
a
Proposed
Modification
Results
in
a
Significant
Emissions
Increase
A.
Introduction
B.
What
We
Proposed
and
How
Today's
Action
Compares
C.
Baseline
Actual
Emissions
For
Existing
Emissions
Units
Other
than
EUSGUs
D.
The
Actual
to
projected
actual
Applicability
Test
E.
Clarifying
Changes
to
WEPCO
Provisions
for
EUSGUs
F.
The
``
Hybrid''
Applicability
Test
G.
Legal
Basis
for
Today's
Action
H.
Response
to
Comments
and
Rationale
for
Today's
Actions
III.
CMA
Exhibit
B
IV.
Plantwide
Applicability
Limitations
(
PALs)
A.
Introduction
B.
Relevant
Background
C.
Final
Regulations
for
Actuals
PALs
D.
Rationale
for
Today's
Final
Action
on
Actuals
PALs
V.
Clean
Units
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251
/
Tuesday,
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31,
2002
/
Rules
and
Regulations
1
In
this
preamble
the
term
``
we''
refers
to
EPA
and
the
term
``
you''
refers
to
major
stationary
sources
of
air
pollution
and
their
owners
and
operators.
All
other
entities
are
referred
to
by
their
respective
names
(
for
example,
reviewing
authorities.)
A.
Introduction
B.
Summary
of
1996
Clean
Unit
Proposal
C.
Final
Regulations
for
Clean
Units
D.
Legal
Basis
for
the
Clean
Unit
Test
E.
Summary
of
Major
Comments
and
Responses
VI.
Pollution
Control
Projects
(
PCPs)
A.
Description
and
Purpose
of
This
Action
B.
What
We
Proposed
and
How
Today's
Action
Compares
To
It
C.
Legal
Basis
for
PCP
D.
Implementation
VII.
Listed
Hazardous
Air
Pollutants
VIII.
Effective
Date
for
Today's
Requirements
IX.
Administrative
Requirements
A.
Executive
Order
12866
Regulatory
Planning
and
Review
B.
Executive
Order
13132
Federalism
C.
Executive
Order
13175
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Unfunded
Mandates
Reform
Act
of
1995
F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
G.
Paperwork
Reduction
Act
H.
National
Technology
Transfer
and
Advancement
Act
of
1995
I.
Congressional
Review
Act
J.
Executive
Order
13211
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
X.
Statutory
Authority
XI.
Judicial
Review
I.
Overview
of
Today's
Final
Action
A.
Background
We1
proposed
revisions
to
the
NSR
rules
in
a
notice
published
in
the
Federal
Register
on
July
23,
1996
(
61
FR
38250).
On
July
24,
1998,
we
published
a
notice
(
63
FR
39857)
to
solicit
further
comment
on
two
specific
aspects
of
the
proposed
revisions.
Today's
Federal
Register
action
announces
EPA's
final
action
on
the
proposed
revisions
for
baseline
emissions
determinations,
the
actual
to
future
actual
methodology,
actuals
PALs,
Clean
Units,
and
PCPs.
We
have
not
made
final
determinations
on
any
other
proposed
changes
to
the
regulations.
Today's
actions
finalize
these
changes
to
the
regulations
for
both
the
approval
and
promulgation
of
implementation
plans
and
requirements
for
preparation,
adoption,
and
submittal
of
implementation
plans
governing
the
NSR
programs
mandated
by
parts
C
and
D
of
title
I
of
the
Act.
We
also
proposed
conforming
changes
to
40
CFR
(
Code
of
Federal
Regulations)
part
51,
appendix
S,
and
part
52.24.
Today
we
have
not
included
the
final
regulatory
language
for
these
regulations.
It
is
our
intention
to
include
regulatory
changes
that
conform
appendix
S
and
40
CFR
52.24
to
today's
final
rules
in
any
final
regulations
that
set
forth
an
interim
implementation
strategy
for
the
8
hour
ozone
standard.
We
intend
to
finalize
changes
to
these
sections
precisely
as
we
have
finalized
requirements
for
other
parts
of
the
program.
Because
these
are
conforming
changes
and
the
public
has
had
an
opportunity
for
review
and
comment,
we
will
not
be
soliciting
additional
comments
before
we
finalize
them.
The
major
NSR
program
contained
in
parts
C
and
D
of
title
I
of
the
Act
is
a
preconstruction
review
and
permitting
program
applicable
to
new
or
modified
major
stationary
sources
of
air
pollutants
regulated
under
the
Act.
In
areas
not
meeting
health
based
National
Ambient
Air
Quality
Standards
(
NAAQS)
and
in
ozone
transport
regions
(
OTR),
the
program
is
implemented
under
the
requirements
of
part
D
of
title
I
of
the
Act.
We
call
this
program
the
``
nonattainment''
NSR
program.
In
areas
meeting
NAAQS
(``
attainment''
areas)
or
for
which
there
is
insufficient
information
to
determine
whether
they
meet
the
NAAQS
(``
unclassifiable''
areas),
the
NSR
requirements
under
part
C
of
title
I
of
the
Act
apply.
We
call
this
program
the
Prevention
of
Significant
Deterioration
(
PSD)
program.
Collectively,
we
also
commonly
refer
to
these
programs
as
the
major
NSR
program.
These
regulations
are
contained
in
40
CFR
51.165,
51.166,
52.21,
52.24,
and
part
51,
appendix
S.
The
NSR
provisions
of
the
Act
are
a
combination
of
air
quality
planning
and
air
pollution
control
technology
program
requirements
for
new
and
modified
stationary
sources
of
air
pollution.
In
brief,
section
109
of
the
Act
requires
us
to
promulgate
primary
NAAQS
to
protect
public
health
and
secondary
NAAQS
to
protect
public
welfare.
Once
we
have
set
these
standards,
States
must
develop,
adopt,
and
submit
to
us
for
approval
a
State
Implementation
Plan
(
SIP)
that
contains
emission
limitations
and
other
control
measures
to
attain
and
maintain
the
NAAQS
and
to
meet
the
other
requirements
of
section
110(
a)
of
the
Act.
Each
SIP
is
required
to
contain
a
preconstruction
review
program
for
the
construction
and
modification
of
any
stationary
source
of
air
pollution
to
assure
that
the
NAAQS
are
achieved
and
maintained;
to
protect
areas
of
clean
air;
to
protect
Air
Quality
Related
Values
(
AQRVs)
(
including
visibility)
in
national
parks
and
other
natural
areas
of
special
concern;
to
assure
that
appropriate
emissions
controls
are
applied;
to
maximize
opportunities
for
economic
development
consistent
with
the
preservation
of
clean
air
resources;
and
to
ensure
that
any
decision
to
increase
air
pollution
is
made
only
after
full
public
consideration
of
all
the
consequences
of
such
a
decision.
For
newly
constructed,
``
greenfield''
sources,
the
determination
of
whether
an
activity
is
subject
to
the
major
NSR
program
is
fairly
straightforward.
The
Act,
as
implemented
by
our
regulations,
sets
applicability
thresholds
for
major
sources
in
nonattainment
areas
[
potential
to
emit
(
PTE)
above
100
tons
per
year
(
tpy)
of
any
pollutant
subject
to
regulation
under
the
Act,
or
smaller
amounts,
depending
on
the
nonattainment
classification]
and
attainment
areas
(
100
or
250
tpy,
depending
on
the
source
type).
A
new
source
with
a
PTE
at
or
above
the
applicable
threshold
amount
``
triggers,''
or
is
subject
to,
major
NSR.
The
determination
of
what
should
be
classified
as
a
modification
subject
to
major
NSR
presents
more
difficult
issues.
The
modification
provisions
of
the
NSR
program
in
parts
C
and
D
are
based
on
the
definition
of
modification
in
section
111(
a)(
4)
of
the
Act:
the
term
``
modification''
means
``
any
physical
change
in,
or
change
in
the
method
of
operation
of,
a
stationary
source
which
increases
the
amount
of
any
air
pollutant
emitted
by
such
source
or
which
results
in
the
emission
of
any
air
pollutant
not
previously
emitted.''
That
definition
contemplates
that,
first,
you
will
determine
whether
a
physical
or
operational
change
will
occur.
If
so,
then
you
will
proceed
to
determine
whether
the
physical
or
operational
change
will
result
in
an
emissions
increase
over
baseline
levels.
The
expression
``
any
physical
change
*
*
*
or
change
in
the
method
of
operation''
in
section
111(
a)(
4)
of
the
Act
is
not
defined.
We
have
recognized
that
Congress
did
not
intend
to
make
every
activity
at
a
source
subject
to
the
major
NSR
program.
As
a
result,
we
have
previously
adopted
several
exclusions
from
what
may
constitute
a
``
physical
or
operational
change.''
For
instance,
we
have
specifically
recognized
that
routine
maintenance,
repair
and
replacement,
and
changes
in
hours
of
operation
or
in
the
production
rate
are
not
considered
a
physical
change
or
change
in
the
method
of
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and
Regulations
2
See
40
CFR
52.21(
b)(
2).
3
See
40
CFR
52.21(
b)(
23).
4
In
approximate
terms,
``
contemporaneous''
emissions
increases
or
decreases
are
those
that
have
occurred
between
the
date
5
years
immediately
preceding
the
proposed
physical
or
operational
change
and
the
date
that
the
increase
from
the
change
occurs.
See,
for
example,
§
52.21(
b)(
3)(
ii).
5
Once
a
modification
is
determined
to
be
major,
the
PSD
requirements
apply
only
to
those
specific
pollutants
for
which
there
would
be
a
significant
net
emissions
increase.
See,
for
example,
§
52.21(
j)(
3)
(
BACT)
and
§
52.21(
m)(
1)(
b)
(
air
quality
analysis).
6
The
regulations
define
``
electric
utility
steam
generating
units''
as
any
steam
electric
generating
unit
that
is
constructed
for
the
purpose
of
supplying
more
than
one
third
of
its
potential
electric
output
capacity
and
more
than
25
megawatts
(
MW)
of
electrical
output
to
any
utility
power
distribution
system
for
sale.
See,
for
example,
§
51.166(
b)(
30).
operation
within
the
definition
of
major
modification.
2
We
have
likewise
addressed
the
scope
of
the
statutory
definition
of
modification
by
excluding
all
changes
that
do
not
result
in
a
``
significant''
emissions
increase
from
a
major
source.
3
This
regulatory
framework
applies
the
major
NSR
program
at
existing
sources
to
only
``
major
modifications''
at
major
stationary
sources.
One
key
attribute
of
the
major
NSR
program
in
general
is
that
you
may
``
net''
modifications
out
of
review
by
coupling
proposed
emissions
increases
at
your
source
with
contemporaneous
emissions
reductions.
Thus,
under
regulations
we
promulgated
in
1980,
you
may
modify,
or
even
completely
replace,
or
add,
emissions
units
without
obtaining
a
major
NSR
permit,
so
long
as
``
actual
emissions''
do
not
increase
by
a
significant
amount
over
baseline
levels
at
the
plant
as
a
whole.
Applicability
of
the
major
NSR
program
must
be
determined
in
advance
of
construction
and
is
pollutant
specific.
In
cases
involving
existing
sources,
this
requires
a
pollutant
by
pollutant
determination
of
the
emissions
change,
if
any,
that
will
result
from
the
physical
or
operational
change.
Our
1980
regulations
implementing
the
PSD
and
nonattainment
major
NSR
programs
thus
inquire
whether
the
proposed
change
constitutes
a
``
major
modification,''
that
is,
a
physical
change
or
change
in
the
method
of
operation
``
that
would
result
in
a
significant
net
emissions
increase
of
any
pollutant
subject
to
regulation
under
the
Act.''
A
``
net
emissions
increase''
is
defined
as
the
increase
in
``
actual
emissions''
from
the
particular
physical
or
operational
change
(
taking
into
account
the
use
of
emissions
control
technology
and
restrictions
on
hours
of
operation
or
rates
of
production
where
such
controls
and
restrictions
are
enforceable),
together
with
your
other
contemporaneous
increases
or
decreases
in
actual
emissions.
4
In
order
to
trigger
applicability
of
the
major
NSR
program,
the
net
emissions
increase
must
be
``
significant.''
5
Before
today's
changes,
our
regulations
generally
defined
actual
emissions
as
``
the
average
rate,
in
tpy,
at
which
the
unit
actually
emitted
the
pollutant
during
a
2
year
period
which
precedes
the
particular
date
and
which
is
representative
of
normal
source
operation.''
The
reviewing
authorities
will
allow
use
of
a
different
time
period
``
upon
a
determination
that
it
is
more
representative
of
normal
source
operation.''
We
have
historically
used
the
2
years
immediately
preceding
the
proposed
change
to
establish
a
source's
actual
emissions.
However,
in
some
cases
we
have
allowed
use
of
an
earlier
period.
With
respect
to
changes
at
existing
sources,
a
prediction
of
whether
the
physical
or
operational
change
would
result
in
a
significant
net
increase
in
your
actual
emissions
following
the
change
was
thus
necessary.
In
part,
this
involved
a
straightforward
and
readily
predictable
engineering
judgment
how
would
the
change
affect
the
emission
factor
or
emissions
rate
of
the
emissions
units
that
are
to
be
changed.
Before
today's
changes,
the
regulations
provided
that
when
your
emissions
unit,
other
than
an
electric
utility
steam
generating
unit
(
EUSGU),
``
has
not
begun
normal
operations,''
actual
emissions
equal
the
PTE
of
the
unit.
When
you
have
not
begun
normal
operations
following
a
change,
you
must
assume
that
your
source
will
operate
at
its
full
capacity
year
round,
that
is,
at
its
full
emissions
potential.
This
is
referred
to
as
the
actual
to
potential
test.
You
may
avoid
the
need
for
an
NSR
permit
by
reducing
your
source's
potential
emissions
through
the
use
of
enforceable
restrictions
to
premodification
actual
emissions
levels
plus
an
amount
that
is
less
than
``
significant''.
In
1992,
we
promulgated
revisions
to
our
applicability
regulations
creating
special
rules
for
physical
and
operational
changes
at
EUSGUs.
See
57
FR
32314
(
July
21,
1992).
6
In
this
rule,
prompted
by
litigation
involving
the
Wisconsin
Electric
Power
Company
(
WEPCO)
and
commonly
referred
to
as
the
``
WEPCO
rule,''
we
adopted
an
actual
to
future
actual
methodology
for
all
changes
at
EUSGUs
except
the
construction
of
a
new
electric
generating
unit
or
the
replacement
of
an
existing
emissions
unit.
Under
this
methodology,
the
actual
annual
emissions
before
the
change
are
compared
with
the
projected
actual
emissions
after
the
change
to
determine
if
a
physical
or
operational
change
would
result
in
a
significant
increase
in
emissions.
To
ensure
that
the
projection
is
valid,
the
rule
requires
the
utility
to
track
its
emissions
for
the
next
5
years
and
provide
to
the
reviewing
authority
information
demonstrating
that
the
physical
or
operational
change
did
not
result
in
an
emissions
increase.
In
promulgating
the
WEPCO
rule,
we
also
adopted
a
presumption
that
utilities
may
use
as
baseline
emissions
the
actual
annual
emissions
from
any
2
consecutive
years
within
the
5
years
immediately
preceding
the
change.
In
attainment
areas,
once
major
NSR
is
triggered,
you
must,
among
other
things,
install
best
available
control
technology
(
BACT)
and
conduct
modeling
and
monitoring
as
necessary.
If
your
source
is
located
in
a
nonattainment
area,
you
must
install
technology
that
meets
the
lowest
achievable
emissions
rate
(
LAER),
secure
emissions
reductions
to
offset
any
increases
above
baseline
emission
levels,
and
perform
other
analyses.
B.
Introduction
Today's
final
regulations
were
proposed
as
part
of
a
larger
regulatory
package
on
July
23,
1996
(
61
FR
38250).
That
package
proposed
a
number
of
changes
to
our
existing
major
NSR
requirements.
(
Please
refer
to
the
outline
of
that
proposed
rulemaking
for
a
complete
list
of
changes
that
were
proposed
to
our
existing
regulations.)
On
July
24,
1998,
we
published
a
Federal
Register
Notice
of
Availability
(
NOA)
that
requested
additional
comment
on
three
of
the
proposed
changes:
determining
baseline
emissions,
actual
to
future
actual
methodology,
and
PALs.
Following
the
1996
proposals,
we
held
two
public
hearings
and
more
than
50
stakeholder
meetings.
Environmental
groups,
industry,
and
State,
local,
and
Federal
agency
representatives
participated
in
these
many
discussions.
In
May
2001,
President
Bush's
National
Energy
Policy
Development
Group
issued
findings
and
key
recommendations
for
a
National
Energy
Policy.
This
document
included
numerous
recommendations
for
action,
including
a
recommendation
that
the
EPA
Administrator,
in
consultation
with
the
Secretary
of
Energy
and
other
relevant
agencies,
review
NSR
regulations,
including
administrative
interpretation
and
implementation.
The
recommendation
requested
that
we
issue
a
report
to
the
President
on
the
impact
of
the
regulations
on
investment
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31,
2002
/
Rules
and
Regulations
in
new
utility
and
refinery
generation
capacity,
energy
efficiency,
and
environmental
protection.
In
response,
in
June
2001,
we
issued
a
background
paper
giving
an
overview
of
the
NSR
program.
This
paper
is
available
on
the
Internet
at
http://
www.
epa.
gov/
air/
nsr
review/
background.
html.
We
solicited
public
comments
on
the
background
paper
and
other
information
relevant
to
the
New
Source
Review
90
day
Review
and
Report
to
the
President.
During
our
review
of
the
NSR
program,
we
met
with
more
than
100
groups,
held
four
public
meetings
around
the
country,
and
received
more
than
130,000
written
comments.
Our
report
to
the
President
and
our
recommendations
in
response
to
the
energy
policy
were
issued
on
June
13,
2002.
A
copy
of
this
information
is
available
at
http://
www.
epa.
gov/
air/
nsrreview
We
expect
that
our
recommendations
in
response
to
the
energy
policy
will
be
reflected
in
the
future
in
various
programs
and
regulatory
actions.
Today's
actions
implement
several
of
those
recommendations.
Today,
we
are
finalizing
five
actions
that
we
previously
proposed
in
1996
(
three
of
which
were
re
noticed
in
the
1998
NOA).
We
are
not
taking
final
action
on
any
of
the
remaining
issues
in
the
1996
proposal
at
this
time.
We
have
not
decided
what
final
action
we
will
take
on
those
issues.
C.
Overview
of
Final
Actions
Today
we
are
taking
final
action
on
five
changes
to
the
NSR
program
that
will
reduce
burden,
maximize
operating
flexibility,
improve
environmental
quality,
provide
additional
certainty,
and
promote
administrative
efficiency.
These
elements
include
baseline
actual
emissions,
actual
to
projected
actual
emissions
methodology,
PALs,
Clean
Units,
and
PCPs.
We
are
also
codifying
our
longstanding
policy
regarding
the
calculation
of
baseline
emissions
for
EUSGUs.
In
addition,
we
are
responding
to
comments
we
received
on
a
proposal
to
adopt
a
methodology,
developed
by
the
American
Chemistry
Council
(
formerly
known
as
the
Chemical
Manufacturers
Association
(
CMA))
and
other
industry
petitioners,
to
determine
whether
a
source
has
undertaken
a
modification
based
on
its
potential
emissions.
We
are
including
a
new
section
in
today's
final
rules
that
outlines
how
a
major
modification
is
determined
under
the
various
major
NSR
applicability
options
and
clarifies
where
you
will
find
the
provisions
in
our
revised
rules.
Finally,
we
have
codified
a
new
definition
of
``
regulated
NSR
pollutant''
that
clarifies
which
pollutants
are
regulated
under
the
Act
for
purposes
of
major
NSR.
This
section
briefly
introduces
each
improvement.
Detailed
discussions
of
the
improvements
are
found
in
sections
II
through
VII
of
this
preamble.
1.
Determining
Whether
a
Proposed
Modification
Results
in
a
Significant
Emissions
Increase
Today
we
are
finalizing
two
changes
to
our
existing
major
NSR
regulations
that
will
affect
how
you
calculate
emissions
increases
to
determine
whether
physical
changes
or
changes
in
the
method
of
operation
trigger
the
major
NSR
requirements.
First,
we
have
a
new
procedure
for
determining
``
baseline
actual
emissions.''
That
is,
the
relevant
terminology
for
calculating
prechange
emissions
for
most
applications
is
now
``
baseline
actual
emissions''
rather
than
``
actual
emissions.''
You
may
use
any
consecutive
24
month
period
in
the
past
10
years
to
determine
your
baseline
actual
emissions.
Second,
we
are
supplementing
the
existing
actual
to
potential
applicability
test
with
an
actual
to
projected
actual
applicability
test
for
determining
if
a
physical
or
operational
change
at
an
existing
emissions
unit
will
result
in
an
emissions
increase.
Notwithstanding
the
new
test,
you
will
still
have
the
ability
to
conduct
an
actual
to
potential
type
test
within
the
new
actual
to
projectedactual
applicability
test.
In
this
case,
you
will
not
be
subject
to
recordkeeping
requirements
that
are
being
established
and
would
otherwise
apply
as
part
of
the
new
actual
to
projected
actual
applicability
test.
For
EUSGUs,
we
are
making
several
changes
to
the
existing
procedures
and
are
codifying
our
current
policy
for
calculating
the
baseline
actual
emissions.
That
is,
the
baseline
actual
emissions
for
EUSGUs
is
the
average
rate,
in
tpy,
at
which
that
unit
actually
emitted
the
pollutant
during
a
2
year
(
consecutive
24
month)
period
within
the
5
year
period
immediately
preceding
when
the
owner
or
operator
begins
actual
construction.
We
are
also
retaining
the
option
that
allows
the
use
of
a
different
time
period
if
the
reviewing
authority
determines
it
is
more
representative
of
normal
source
operation.
2.
CMA
Exhibit
B
As
described
in
section
I.
C.
1
above,
we
have
decided
to
adopt
an
actual
toprojected
actual
methodology,
combined
with
a
revised
process
to
determine
baseline
emissions,
to
use
in
determining
when
sources
are
considered
to
have
made
a
modification
and
are
thereby
subject
to
NSR.
We
are
not
adopting
the
methodology
based
on
potential
emissions
as
discussed
in
the
CMA
Exhibit
B
proposal.
See
section
III
of
this
preamble
for
a
discussion
of
the
comments
we
received
on
this
proposal
and
our
responses.
3.
Plantwide
Applicability
Limitations
A
PAL
is
a
voluntary
option
that
will
provide
you
with
the
ability
to
manage
facility
wide
emissions
without
triggering
major
NSR
review.
We
believe
that
the
added
flexibility
provided
under
a
PAL
will
facilitate
your
ability
to
respond
rapidly
to
changing
market
conditions
while
enhancing
the
environmental
protection
afforded
under
the
program.
Today
we
are
promulgating
a
PAL
based
on
plantwide
actual
emissions.
If
you
keep
the
emissions
from
your
facility
below
a
plantwide
actual
emissions
cap
(
that
is,
an
actuals
PAL),
then
these
regulations
will
allow
you
to
avoid
the
major
NSR
permitting
process
when
you
make
alterations
to
the
facility
or
individual
emissions
units.
In
return
for
this
flexibility,
you
must
monitor
emissions
from
all
of
your
emissions
units
under
the
PAL.
The
benefit
to
you
is
that
you
can
alter
your
facility
without
first
obtaining
a
Federal
NSR
permit
or
going
through
a
netting
review.
A
PAL
will
allow
you
to
make
changes
quickly
at
your
facility.
If
you
are
willing
to
undertake
the
necessary
recordkeeping,
monitoring,
and
reporting,
a
PAL
offers
you
flexibility
and
regulatory
certainty.
4.
Clean
Units
We
are
promulgating
a
new
type
of
applicability
test
for
emissions
units
that
are
designated
as
Clean
Units.
The
new
applicability
test
recognizes
that
when
you
go
through
major
NSR
review
and
install
BACT
or
LAER,
you
may
make
any
changes
to
the
Clean
Unit
without
triggering
an
additional
major
NSR
review,
if
the
project
at
a
Clean
Unit
does
not
cause
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
were
adopted
in
conjunction
with
BACT
or
LAER
and
the
project
would
not
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT
or
LAER
determination.
If
the
project
causes
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
adopted
in
conjunction
with
BACT
or
LAER
or
would
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT
or
LAER
determination,
you
lose
Clean
Unit
status.
You
may
still
proceed
with
the
project
without
triggering
major
NSR
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Rules
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Regulations
review,
if
the
increase
is
not
a
significant
net
emissions
increase.
Emissions
units
that
have
not
been
through
major
NSR
may
still
qualify
for
Clean
Unit
status
if
they
demonstrate
that
the
emissions
control
level
is
comparable
to
BACT
or
LAER.
Clean
Unit
status
will
be
valid
for
up
to
a
10
year
period.
The
new
applicability
test
does
not
exclude
consideration
of
physical
changes
or
changes
in
the
method
of
operation
of
Clean
Units
from
major
NSR,
but
rather
changes
the
way
emissions
increases
are
calculated
for
these
changes.
This
new
applicability
test
therefore
protects
air
quality,
creates
incentives
for
sources
to
install
state
ofthe
art
controls,
provides
flexibility
for
sources,
and
promotes
administrative
efficiency.
5.
Pollution
Control
Projects
Today's
rule
contains
a
new
list
of
environmentally
beneficial
technologies
that
qualify
as
PCPs
for
all
types
of
sources.
Installation
of
a
PCP
is
not
subject
to
the
major
modification
provisions.
An
owner
or
operator
installing
a
listed
PCP
automatically
qualifies
for
the
exclusion
if
there
is
no
adverse
air
quality
impact
that
is,
if
it
will
not
cause
or
contribute
to
a
violation
of
NAAQS
or
PSD
increment,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
(
FLM)
and
for
which
information
is
available
to
the
general
public.
The
PCPs
that
are
not
listed
in
today's
rules
may
also
qualify
for
the
PCP
Exclusion
if
the
reviewing
authority
determines
on
a
case
specific
basis
that
a
non
listed
PCP
is
environmentally
beneficial
when
used
for
a
particular
application.
Also,
in
the
future,
we
may
add
to
the
listed
PCPs
through
a
rulemaking
that
provides
for
public
notice
and
opportunity
for
comment.
The
PCP
Exclusion
allows
sources
to
install
emissions
controls
that
are
known
to
be
environmentally
beneficial.
These
provisions
thus
offer
flexibility
while
improving
air
quality.
6.
Major
NSR
Applicability
We
have
briefly
described
the
new
provisions
for
baseline
actual
emissions,
actual
to
projected
actual
methodology,
PALs,
and
Clean
Units.
Sections
II,
IV,
and
V
describe
the
new
provisions
in
detail.
These
provisions
offer
major
new
changes
to
NSR
applicability,
especially
regarding
how
a
major
modification
is
determined.
The
major
NSR
applicability
provisions
have
developed
over
time
and
therefore
have
been
added
to
the
NSR
rules
in
a
piecemeal
fashion.
In
today's
final
rules
we
are
including
a
new
section
that
outlines
how
a
major
modification
is
determined
under
the
various
major
NSR
applicability
options
and
clarifies
where
you
will
find
the
provisions
in
our
revised
rules.
For
each
applicability
option,
we
describe
how
a
major
modification
is
determined
in
detail.
You'll
find
this
new
applicability
``
roadmap''
in
§
§
51.165(
a)(
2),
51.166(
a)(
7),
and
52.21(
a)(
2).
To
summarize,
the
various
provisions
for
major
modifications
are
now
as
follows.
Actual
to
projected
actual
applicability
test
for
all
existing
emissions
units.
(
Including
an
actual
topotential
option)
Actual
to
potential
test
for
any
new
unit,
including
EUSGUs.
The
Clean
Unit
Test
for
existing
emissions
units
with
Clean
Unit
status.
The
hybrid
test
for
modifications
with
multiple
types
of
emissions
units.
(
Used
when
a
physical
or
operational
change
affects
a
combination
of
more
than
one
type
of
unit.)
We
describe
actuals
PALs,
which
are
an
alternative
way
of
complying
with
major
NSR,
in
section
IV
of
this
preamble.
If
you
have
a
PAL,
as
long
as
you
are
complying
with
the
PAL
requirements,
any
physical
or
operational
changes
are
not
major
modifications.
We
have
revised
the
definition
of
major
modification
to
clarify
what
has
always
been
our
policy
that
determining
whether
a
major
modification
has
occurred
is
a
two
step
process.
The
new
definition
of
major
modification
is
``
any
physical
change
in
or
change
in
the
method
of
operation
of
a
major
stationary
source
that
would
result
in:
(
1)
A
significant
emissions
increase
of
a
regulated
NSR
pollutant;
and
(
2)
a
significant
net
emissions
increase
of
that
pollutant
from
the
major
stationary
source.''
We
have
also
revised
the
definitions
of
actual
emissions,
emissions
unit,
net
emissions
increase,
and
construction.
We
have
deleted
the
word
``
actual''
as
related
to
emissions
from
the
definition
of
``
construction.''
This
change
was
necessary
because
of
how
the
definition
of
``
actual
emissions''
is
used
in
the
final
rule,
but
the
deletion
is
not
intended
to
change
any
meaning
in
the
term
``
construction.''
We
have
added
new
definitions
for
baseline
actual
emissions,
projected
actual
emissions,
project,
and
significant
emissions
increase.
These
revisions
and
additions
implement
our
new
provisions
for
major
modifications
under
the
actual
to
projected
actual
applicability
test,
actual
to
potential
test,
Clean
Unit
Test,
and
hybrid
test.
You
will
find
a
complete
discussion
of
the
Clean
Unit
Test,
including
how
modifications
to
Clean
Units
are
treated,
in
section
V
of
this
preamble.
The
other
tests
are
discussed
in
section
II.
``
Actual
emissions,''
as
the
term
has
been
historically
applied,
will
still
be
used
to
determine
air
quality
impacts
(
for
example,
compliance
with
NAAQS,
PSD
increments,
and
AQRVs)
and
to
compute
the
required
amount
of
emissions
offsets.
To
further
clarify
major
NSR
applicability
in
one
location,
we
have
moved
§
51.166(
i)(
1)
through
(
3)
and
§
52.21(
i)(
1)
through
(
3)
into
the
new
applicability
sections
at
§
51.166(
a)(
7)
and
§
52.21(
a)(
2).
These
provisions
clarify
that
you
must
obtain
a
permit
before
you
begin
construction
(
including
for
major
modifications),
that
the
provisions
apply
for
each
regulated
NSR
pollutant
that
your
source
emits,
and
that
the
provisions
apply
to
any
source
located
in
the
area
designated
as
attainment
or
unclassifiable
(
for
§
§
51.166
and
52.21).
We
have
also
added
a
new
definition
for
reviewing
authority
that
clarifies
who
has
authority
to
implement
major
NSR
programs.
Reviewing
authority
means
the
State
air
pollution
control
agency,
local
agency,
other
State
agency,
Indian
tribe,
or
other
agency
authorized
by
the
Administrator
to
carry
out
a
permit
program
under
§
§
51.165
and
51.166,
or
the
Administrator
in
the
case
of
EPA
implemented
permit
programs
under
§
52.21.
7.
Enforcement
As
noted
above,
today
we
are
taking
final
action
on
five
changes
to
the
NSR
program
that
create
alternative
means
of
determining
NSR
applicability
for
projects
that
begin
actual
construction
after
these
provisions
become
effective
in
your
jurisdiction.
If
you
are
subsequently
determined
not
to
have
met
any
of
the
obligations
of
these
new
alternatives
(
for
example,
failure
to
meet
emissions
or
applicability
limits,
properly
project
emissions,
and/
or
properly
implement
the
PCP
Exclusion
or
Clean
Unit
Test),
you
will
be
subject
to
any
applicable
enforcement
provisions
(
including
the
possibility
of
citizens'
suits)
under
the
applicable
sections
of
the
Act.
Sanctions
for
violations
of
these
provisions
may
include
monetary
penalties
of
up
to
$
27,500
per
day
of
violation,
as
well
as
the
possibility
of
injunctive
relief,
which
may
include
the
requirement
to
install
air
pollution
controls.
8.
Enforceability
This
rule
uses
several
terms
related
to
enforceability
of
particular
provisions.
A
requirement
is
``
legally
enforceable''
if
some
authority
has
the
right
to
enforce
the
restriction.
Practical
enforceability
for
a
source
specific
permit
will
be
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7
See
memorandum,
``
Release
of
Interim
Policy
on
Federal
Enforceability
of
Limitations
on
Potential
to
Emit,''
signed
by
John
Seitz
and
Robert
Van
Heuvelen,
Jan.
22,
1996
at
5
6
and
Attachment
4,
available
on
the
Web
as
http://
www.
epa.
gov/
rgytgrnj/
programs/
artd/
air/
title5/
t5memos/
pottoemi.
pdf.
More
detailed
guidance
on
practical
enforceability
is
contained
in
the
memorandum.
8
The
Agency
has
frequently
used
the
term
``
practicably
enforceable''
and
``
practical
enforceability,''
interchangeably.
There
is
no
difference
in
the
meaning
of
these
terms.
9
See
generally
memorandum,
``
Options
for
Limiting
the
Potential
to
Emit
(
PTE)
of
a
Stationary
Source
Under
Section
112
and
Title
V
of
the
Clean
Air
Act,''
signed
by
John
Seitz
and
Robert
Van
Heuvelen,
Jan.
25,
1995,
at
2
3.
10
By
definition,
the
modification
of
an
existing
source
is
potentially
subject
to
major
NSR
only
if
that
existing
source
is
``
major.''
In
addition,
when
an
existing
``
minor''
source
makes
a
physical
or
operational
change
that
by
itself
is
major,
that
change
constitutes
a
major
stationary
source
that
is
subject
to
major
NSR.
See,
for
example,
§
52.21(
b)(
1)(
c).
11
For
NSR
purposes,
the
definition
of
``
electric
utility
steam
generating
unit''
means
any
steam
electric
generating
unit
that
is
constructed
for
the
purpose
of
supplying
more
than
one
third
of
its
potential
electric
output
capacity
and
more
than
25
MW
electrical
output
to
any
utility
power
distribution
system
for
sale.
Any
steam
supplied
to
a
steam
distribution
system
for
the
purpose
of
providing
steam
to
a
steam
electric
generator
that
would
produce
electrical
energy
for
sale
is
also
considered
in
determining
the
electrical
energy
output
capacity
of
the
affected
facility.
See,
for
example,
§
52.21(
b)(
31).
Reference
in
this
notice
to
utility
units
is
meant
to
include
all
emissions
units
covered
by
this
definition.
12
We
promulgated
special
applicability
rules
for
physical
and
operational
changes
at
EUSGUs
in
1992.
See
57
FR
32314
(
July
21,
1992).
achieved
if
the
permit's
provisions
specify:
(
1)
A
technically
accurate
limitation
and
the
portions
of
the
source
subject
to
the
limitation;
(
2)
the
time
period
for
the
limitation
(
hourly,
daily,
monthly,
and
annual
limits
such
as
rolling
annual
limits);
and
(
3)
the
method
to
determine
compliance,
including
appropriate
monitoring,
recordkeeping,
and
reporting.
For
rules
and
general
permits
that
apply
to
categories
of
sources,
practicable
enforceability
additionally
requires
that
the
provisions:
(
1)
Identify
the
types
or
categories
of
sources
that
are
covered
by
the
rule;
(
2)
where
coverage
is
optional,
provide
for
notice
to
the
permitting
authority
of
the
source's
election
to
be
covered
by
the
rule;
and
(
3)
specify
the
enforcement
consequences
relevant
to
the
rule.
7,
8
``
Enforceable
as
a
practical
matter''
will
be
achieved
if
a
requirement
is
both
legally
and
practically
enforceable.
Note
that
we
continue
to
require
offsets
to
be
federally
enforceable.
``
Federal
enforceability''
means
that
not
only
is
a
requirement
practically
enforceable,
as
described
above,
but
in
addition,
``
EPA
must
have
a
direct
right
to
enforce
restrictions
and
limitations
imposed
on
a
source
to
limit
its
exposure
to
Act
programs.''
9
Also
note
that,
for
computing
baseline
actual
emissions
for
use
in
determining
major
NSR
applicability
or
for
establishing
a
PAL,
you
must
consider
``
legally
enforceable''
requirements.
A
requirement
will
be
legally
enforceable
if
the
Administrator,
State,
local
or
tribal
air
pollution
control
agency
has
the
authority
to
enforce
the
requirement
irrespective
of
its
practical
enforceability.
In
our
existing
regulations
that
are
unamended
by
today's
action,
the
term
``
federally
enforceability''
still
appears.
In
1995,
the
court
in
Chemical
Manufacturers
Ass'n
v.
EPA
remanded
the
definition
of
PTE
in
the
major
NSR
program
to
EPA.
No.
89
1514
(
D.
C.
Cir.
Sept.
150
1995).
Because
the
court
vacated
the
requirements
in
the
nationwide
rules,
the
term
federal
enforceability
as
it
relates
to
PTE
is
not
in
effect
(
pending
final
rule
making
by
the
Agency)
in
the
Federal
rules.
The
decision,
however,
did
not
address
the
term
``
federally
enforceable''
as
used
in
SIPs,
because
that
issue
was
not
before
the
court.
II.
Revisions
to
the
Method
for
Determining
Whether
a
Proposed
Modification
Results
in
a
Significant
Emissions
Increase
A.
Introduction
Today
we
are
finalizing
two
sets
of
amendments
to
our
existing
major
NSR
regulations
that
provide
another
way
in
which
you
may
calculate
emissions
increases
to
determine
whether
certain
types
of
physical
changes
or
changes
in
the
method
of
operation
(
physical
or
operational
changes)
of
an
existing
emissions
unit
trigger
the
major
NSR
requirements.
10
The
first
set
of
amendments
relates
to
the
way
in
which
you
will
determine
your
baseline
actual
emissions
for
such
emissions
units
in
accordance
with
a
new
definition
of
``
baseline
actual
emissions.''
See,
for
example,
new
§
52.21(
b)(
48).
We
will
be
allowing
you
to
use
any
consecutive
24
month
period
during
the
10
year
period
prior
to
the
change
to
determine
your
baseline
actual
emissions
for
existing
emissions
units
(
other
than
EUSGUs).
The
second
set
of
amendments
replaces
the
existing
actual
to
potential
and
actual
to
representative
actual
annual
emissions
applicability
tests
for
existing
emissions
units
(
including
EUSGUs)
with
an
actual
to
projected
actual
applicability
test
for
determining
if
a
physical
or
operational
change
will
result
in
an
emissions
increase
at
such
units.
(
Notwithstanding
this
new
test,
the
actual
to
potential
methodology
is
still
available
at
your
option
under
the
new
applicability
tests.)
The
new
procedure
for
determining
your
prechange
baseline
actual
emissions
will
not
apply
to
EUSGUs.
11
Instead,
for
EUSGUs
we
are
retaining
the
existing
procedures
for
determining
the
baseline
actual
emissions.
12
See,
for
example,
existing
§
52.21(
b)(
33).
We
are
also
affirming
our
current
method
used
for
calculating
the
baseline
actual
emissions
for
EUSGUs
(
allowing
any
consecutive
2
years
in
the
past
5
years,
or
another
more
representative
period)
by
codifying
it
in
the
NSR
regulations.
See,
for
example,
new
§
52.21(
b)(
48).
For
existing
emissions
units
other
than
EUSGUs,
the
changes
we
are
making
to
the
method
for
calculating
a
unit's
baseline
actual
emissions
will
apply
only
for
the
following
three
purposes.
For
modifications,
to
determine
a
modified
unit's
pre
change
baseline
actual
emissions
as
part
of
the
new
actual
to
projected
actual
applicability
test.
For
netting,
to
determine
the
prechange
baseline
actual
emissions
of
an
emissions
unit
that
underwent
a
physical
or
operational
change
within
the
contemporaneous
period.
For
PALs,
to
establish
the
PAL
emissions
cap.
Today's
new
procedures
for
calculating
baseline
actual
emissions
and
for
the
actual
to
projected
actual
applicability
test
should
not
be
used
when
determining
a
source's
actual
emissions
on
a
particular
date
as
may
be
used
for
other
NSR
related
requirements.
Such
requirements
include,
but
are
not
limited
to,
air
quality
impacts
analyses
(
for
example,
compliance
with
NAAQS,
PSD
increments,
and
AQRVs)
and
computing
the
required
amount
of
emissions
offsets.
For
each
of
these
requirements,
the
existing
definition
of
``
actual
emissions''
continues
to
apply.
This
is
discussed
in
greater
detail
in
section
II.
D.
9.
We
believe
that
these
changes
will
greatly
improve
the
major
NSR
program
by
responding
to
industry
concerns
with
our
existing
methodology
without
compromising
air
quality.
One
common
complaint
about
the
current
emissions
baseline
process
is
that
you
have
a
limited
ability
to
consider
the
operational
fluctuations
associated
with
normal
business
cycles
when
establishing
baseline
actual
emissions
unless
your
reviewing
authority
agrees
that
another
period
is
``
more
representative
of
normal
source
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13
The
definition
of
``
actual
emissions''
requires
that
a
unit's
actual
emissions
be
based
on
a
consecutive
24
month
period
immediately
preceding
the
particular
change.
Also,
however,
it
directs
the
reviewing
authority
to
allow
the
use
of
another
time
period
upon
a
determination
that
it
is
more
representative.
This
procedure
continues
to
be
appropriate
under
the
pre
existing
regulation
and
for
other
NSR
purposes,
such
as
determining
a
source's
ambient
impact
against
the
PSD
increments,
and
we
continue
to
require
its
use
for
such
purposes.
14
Note
that
we
plan,
in
the
near
future,
to
issue
a
Notice
of
Proposed
Rulemaking
that
will
address
the
issue
of
``
debottlenecking.''
In
today's
rulemaking,
we
do
not
intend
to
change
current
requirements
related
to
``
debottlenecking.''
Use
of
the
term
``
changed
unit''
should
not
be
interpreted
as
a
change
to
those
requirements.
operation.''
13
By
extending
the
time
period
from
which
you
may
establish
your
baseline
actual
emissions,
the
new
procedures
should
reflect
the
emissions
levels
that
occur
during
a
normal
business
cycle,
without
requiring
you
to
demonstrate
to
your
reviewing
authority
that
another
period
is
``
more
representative
of
normal
source
operations.''
Commenters
also
believe
that
the
current
methodology
requires
many
changes
made
to
existing
equipment
to
go
through
major
NSR,
without
taking
into
account
operating
history,
even
when
such
changes
will
not
result
in
increased
pollution
to
the
environment.
Our
new
applicability
requirements
address
these
commenters'
concerns
and
will
focus
limited
resources
more
effectively.
We
are
also
modifying
the
way
you
may
determine
whether
emissions
at
existing
units
(
including
EUSGUs)
will
increase,
by
allowing
you
to
use
projected
actual
emissions
for
purposes
of
this
determination.
Under
this
approach,
in
circumstances
where
there
is
a
reasonable
possibility
that
a
project
that
is
not
part
of
a
major
modification
may
result
in
a
significant
increase
of
a
regulated
NSR
pollutant,
before
beginning
actual
construction,
you
may
choose
to
make
and
record
a
projection
of
post
change
emissions
of
that
pollutant
from
changed
units.
14
To
make
this
projection,
you
must
use
the
maximum
annual
rate
at
which
the
changed
units
are
projected
to
emit
the
pollutant
in
any
of
the
5
calendar
years
following
the
time
the
unit
resumes
regular
operations
after
the
project
(
or
10
years
if
the
project
increases
the
unit's
design
capacity
or
potential
to
emit
the
regulated
NSR
pollutant).
You
then
use
these
projections
to
calculate
whether
the
project
will
result
in
a
significant
emissions
increase.
In
making
this
calculation,
you
could
exclude
any
emissions
that
the
unit
could
have
accommodated
before
the
change
and
that
are
unrelated
to
the
project.
You
could
also
exclude
emissions
resulting
from
increased
utilization
due
to
demand
growth
that
the
unit
could
have
accommodated
before
the
change.
With
respect
to
the
covered
changes,
if
you
use
this
procedure,
you
are
required
to
track
post
change
annual
emissions
of
the
units
in
tpy
for
the
next
5
years
(
or
10
years
if
the
project
increases
the
unit's
design
capacity
or
potential
to
emit
the
regulated
NSR
pollutant).
At
the
end
of
each
year,
if
post
change
annual
emissions
exceed
the
baseline
actual
emissions
by
a
significant
amount,
and
differ
from
your
projections,
you
must
submit
a
report
to
the
reviewing
authority
with
that
information
within
60
days
after
the
end
of
the
year.
Instead
of
relying
on
projected
actual
emissions,
you
may
instead
elect
to
use
the
unit's
PTE,
in
tpy.
In
that
case,
you
need
not
track
or
report
post
change
emissions.
We
are
also
revising
the
procedures
for
projecting
future
emissions
for
EUSGUs
to
conform
with
these
new
procedures
and
consolidate
the
EUSGU
and
non
EUSGU
procedures
into
a
single
set
of
provisions.
As
a
result
of
our
1992
rulemaking,
EUSGUs
have
available
to
them
a
similar
set
of
procedures.
We
believe
the
procedures
we
are
implementing
for
other
units
represent
a
sensible
refinement
of
the
rules
we
promulgated
in
1992
and
that
we
should
make
these
procedures
available
to
all
existing
units.
We
do,
however,
impose
two
requirements
on
EUSGUs
beyond
those
we
impose
on
other
units.
First,
with
respect
to
covered
projects,
EUSGUs
that
project
post
change
emissions
will
have
to
submit
a
copy
of
their
projections
to
their
reviewing
authority
before
beginning
actual
construction.
You
will
not
be
required
to
obtain
any
kind
of
determination
from
the
reviewing
authority
before
proceeding
with
construction.
Second,
we
are
requiring
that
if
you
project
post
change
emissions
for
your
EUSGUs,
you
must
send
a
copy
of
your
tracked
emissions
to
your
reviewing
authority,
without
regard
to
whether
these
emissions
have
increased
by
a
significant
amount
or
exceed
your
projections.
The
effect
of
this
consolidation
is
that
we
make
minor
changes
to
the
existing
procedures
for
EUSGUs.
For
example,
you
must
project
emissions
for
EUSGUs
on
a
12
month
basis,
rather
than
the
current
approach
of
projecting
average
annual
emissions
for
the
2
years
immediately
following
the
change.
Also,
you
need
only
make
and
report
a
projection
for
EUSGUs
when
there
is
a
reasonable
possibility
that
the
given
project
may
result
in
a
significant
emissions
increase.
By
allowing
you
to
use
today's
new
version
of
the
actual
to
projected
actual
applicability
test
to
evaluate
modified
existing
emissions
units,
we
expect
that
fewer
projects
will
trigger
the
major
NSR
permitting
requirements.
Nonetheless,
we
believe
that
the
environment
will
not
be
adversely
affected
by
these
changes
and
in
some
respects
will
benefit
from
these
changes.
The
new
test
will
remove
disincentives
that
discourage
sources
from
making
the
types
of
changes
that
improve
operating
efficiency,
implement
pollution
prevention
projects,
and
result
in
other
environmentally
beneficial
changes.
Moreover,
the
end
result
is
that
State
and
local
reviewing
authorities
can
appropriately
focus
their
limited
resources
on
those
activities
that
could
cause
real
and
significant
increases
in
pollution.
In
addition,
today's
changes
provide
benefits
to
the
public
and
the
environment
through
the
improved
recordkeeping
and
reporting
requirements
as
discussed
above.
We
believe
that
these
added
recordkeeping
and
reporting
measures
will
provide
the
information
necessary
for
reviewing
authorities
to
assure
that
such
changes
are
made
consistent
with
the
CAA
requirements.
The
new
rule
also
does
not
affect
the
way
in
which
a
source's
ambient
air
quality
impacts
are
evaluated.
Altogether,
we
believe
that
today's
regulatory
amendments
focus
on
the
types
of
changes
occurring
at
existing
emissions
units
that
are
more
likely
to
result
in
significant
contributions
to
air
pollution.
B.
What
We
Proposed
and
How
Today's
Action
Compares
1.
July
23,
1996
Notice
of
Proposed
Rulemaking
(
NPRM)
In
1996,
we
proposed
to
amend
the
NSR
rules
to
allow
States
to
use,
among
other
things,
a
new
test
as
an
alternative
to
the
actual
to
potential
test
for
determining
the
applicability
of
the
NSR
requirements
when
you
wish
to
make
modifications
at
an
existing
major
stationary
source.
The
proposed
test
was
intended
to
apply
exclusively
to
modifications
of
existing
emissions
units
at
major
stationary
sources
not
to
new
emissions
units.
As
described
more
completely
below,
the
proposed
test
involved
changes
to
the
procedures
for
calculating
an
emissions
unit's
prechange
(
baseline)
actual
emissions
and
post
change
(
future)
actual
emissions.
The
method
would
have
also
required
you
to
monitor
and
report
future
emissions
from
certain
modified
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15
This
method,
as
well
as
the
WEPCO
amendments
as
a
whole,
was
limited
to
modifications
of
existing
EUSGUs
and
did
not
apply
to
the
addition
of
a
new
emissions
unit
or
the
replacement
of
an
existing
unit.
emissions
units,
based
on
the
monitoring
and
reporting
requirements
adopted
under
the
WEPCO
amendments.
Baseline
actual
emissions.
In
our
1996
NPRM,
we
proposed
to
change
the
definition
of
baseline
emissions
from
the
average
annual
rate
of
actual
emissions
during
the
2
year
period
preceding
the
date
of
the
modification
to
the
annual
rate
associated
with
the
highest
level
of
utilization
from
any
consecutive
12
month
period
during
the
10
year
period
preceding
the
date
of
the
modification,
adjusted
for
any
more
stringent
limits
that
may
have
been
imposed
since
the
end
of
the
12
month
period
selected.
The
proposed
method
was
intended
to
be
used
for
calculating
baseline
actual
emissions
for
any
existing
emissions
unit,
including
EUSGUs,
by
replacing
both
the
original
method
(
that
was
part
of
the
actual
topotential
test)
and
the
2
in
5
years
method
(
as
adopted
under
the
WEPCO
for
modified
EUSGUs).
As
indicated
above,
the
proposed
procedure
also
would
have
required
you
to
take
into
account
any
legally
enforceable
constraints
imposed
on
the
facility
since
the
selected
12
month
time
frame,
and
currently
in
effect.
Thus,
you
would
generally
have
been
required
to
calculate
the
modified
emissions
unit's
baseline
actual
emissions
by
using
the
appropriate
utilization
level
from
the
selected
12
month
period,
in
combination
with
the
emissions
unit's
current
enforceable
emission
factors.
Such
enforceable
emission
factors
would
have
included
current
Federal
and
State
limits,
such
as
RACT
(
Reasonably
Available
Control
Technology),
MACT
(
Maximum
Achievable
Control
Technology),
BACT,
LAER,
and
New
Source
Performance
Standards
(
NSPS),
as
well
as
enforceable
limits
resulting
from
any
voluntary
reductions
you
may
have
taken
(
for
example,
for
netting,
offsets,
or
Emission
Reduction
Credits
(
ERCs)).
Also,
you
would
have
had
to
consider
any
operational
constraints
that
are
enforceable,
such
as
production
limits,
fuel
use
limits,
or
limits
to
the
number
of
hours
per
day
or
days
per
year
at
which
the
unit
modified,
or
affected
by
such
modification,
could
operate.
Finally,
we
indicated
that
it
was
not
our
intent
to
extend
the
5
year
contemporaneous
period
(
for
considering
creditable
emissions
increases
and
decreases
as
part
of
the
netting
calculus),
even
if
we
established
a
10
year
baseline
look
back
period.
Post
change
actual
emissions.
In
the
1996
proposal,
we
proposed
to
extend
the
availability
of
the
actual
to
futureactual
emissions
method,
established
under
the
WEPCO
amendments
exclusively
for
EUSGUs,
to
predict
the
future
actual
emissions
from
any
emissions
unit
undergoing
a
physical
or
operational
change.
Thus,
we
proposed
extending
availability
of
the
definition
of
``
representative
actual
annual
emissions''
to
all
emissions
units
undergoing
a
physical
or
operational
change.
This
definition
would
have
provided
the
basis
for
you
to
project
an
emissions
unit's
future
actual
emissions,
excluding
any
emissions
increases
caused
by
demand
growth
or
other
independent
factors,
when
determining
whether
the
change
at
issue
will
increase
emissions
over
the
baseline
levels.
15
The
proposal
also
retained
the
WEPCO
provision
requiring
that,
for
any
modified
emissions
unit
using
the
actual
to
future
actual
test,
you
must
submit
annually
for
5
years
after
the
change
sufficient
records
to
demonstrate
that
the
change
has
not
resulted
in
a
significant
emissions
increase
over
the
baseline
levels.
As
a
safeguard,
the
WEPCO
rule
also
provides
that
this
tracking
period
could
be
extended
to
10
years
when
the
reviewing
authority
is
concerned
that
the
first
5
years
will
not
be
representative
of
normal
source
operation.
We
sought
comments
on
numerous
issues,
including
whether
any
changes
should
be
made
to
the
5
year
tracking
requirement
or
to
the
demand
growth
exclusion
in
the
event
that
we
decided
to
broaden
use
of
the
actual
tofuture
actual
test
for
modifications
to
any
existing
emissions
unit.
2.
July
24,
1998
Notice
of
Availability
In
1998,
we
announced
that
comments
received
on
the
1996
proposal
and
changed
circumstances
had
caused
us
to
ask
whether
we
should
reconsider
some
of
the
aspects
of
the
proposed
changes
to
the
``
major
modification''
applicability
test.
The
1998
NOA
set
forth
for
public
comment
an
additional
applicability
test.
In
brief,
the
alternative
presented
for
additional
comment
would
have:
(
1)
Retained
the
actual
to
future
actual
test
for
EUSGUs
and
applied
it
to
all
source
categories;
(
2)
made
binding
for
a
10
year
period
the
emissions
levels
used
in
projecting
future
actual
emissions
following
the
modification
for
all
source
categories;
and
(
3)
eliminated
the
demand
growth
exclusion
for
calculating
a
modified
emissions
unit's
future
actual
emissions.
Consistent
with
the
1996
NPRM,
this
alternative
methodology
would
have
applied
to
any
existing
emissions
unit
at
a
major
stationary
source
for
which
you
might
plan
a
non
routine
physical
or
operational
change.
The
methodology
would
have
required
you
first
to
determine
which
emissions
units
were
being
changed,
or
were
affected
by
the
change,
then
to
calculate
those
units'
baseline
actual
emissions
based
on
the
highest
consecutive
12
months
of
source
operation
during
the
past
10
years,
adjusted
to
reflect
current
emission
factors.
The
second
step
involved
the
forecast
of
future
emissions
resulting
from
the
physical
or
operational
change.
Under
this
calculation
of
future
actual
emissions,
one
would
not
have
been
allowed
to
exclude
predicted
capacity
utilization
increases
that
were
due
to
demand
growth.
If
the
difference
between
the
pre
change
and
post
change
actual
emissions
equaled
or
exceeded
the
significant
emissions
rate
defined
for
a
particular
pollutant,
major
NSR
would
have
been
triggered
(
unless
you
took
enforceable
limits
to
keep
the
increase
below
significant
levels
or
were
otherwise
able
to
net
out
of
review
using
creditable,
contemporaneous
emissions
increases
and
decreases
occurring
at
your
facility).
If
the
difference
between
baseline
and
future
actual
emissions
did
not
exceed
the
applicable
significant
emissions
rate,
your
facility
would
not
be
subject
to
major
NSR,
but
you
would
have
been
required
to
accept
a
temporary
emissions
cap
based
on
the
predicted
future
actual
emissions
for
each
affected
pollutant
at
the
emissions
units
being
modified
or
affected
by
the
modification.
The
temporary
cap
would
have
become
an
enforceable
condition
of
a
preconstruction
permit.
Also,
the
sole
purpose
of
the
temporary
cap
would
have
been
to
make
sure
that
the
physical
or
operational
change
did
not
result
in
a
significant
emissions
increase,
and
the
cap
would
have
applied
to
those
emissions
units
for
at
least
10
years
after
the
changes
were
completed.
You
would
also
have
been
required
to
supply
information
annually
to
demonstrate
that
the
future
actual
emissions
did
not
exceed
the
applicable
emissions
caps
during
the
10
year
period
following
the
modification.
3.
Summary
of
Major
Changes
in
the
Final
Rule
Today's
action
amends
the
existing
NSR
regulations
to
provide
you
with
a
common
applicability
test
for
all
existing
emissions
units
the
actual
toprojected
actual
applicability
test.
This
test
has
changed
in
some
ways
from
both
the
1996
NPRM
and
the
1998
NOA.
As
described
in
greater
detail
in
sections
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Rules
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Regulations
16
We
do
make
use
of
the
term
``
resumes
regular
operations''
(
as
opposed
to
``
normal
operations'')
in
the
final
rule,
but
that
term
has
a
very
different
meaning
and
we
are
using
it
for
an
entirely
different
purpose.
Specifically,
we
are
not
using
the
term
for
purposes
of
determining
whether
a
change
results
in
a
significant
emissions
increase.
Rather,
we
use
it
only
to
identify
the
date
on
which
the
owner
or
operator
must
begin
tracking
emissions
of
changed
units
when
using
the
actual
to
projected
actual
method.
17
The
1980
rulemaking
also
discussed
that
``
reconstruction''
would
have
only
been
applied
on
a
plantwide
basis
and
EPA
believed
that
there
would
be
few
instances
of
plantwide
reconstructions.
18
For
simplicity,
we
state
this
rule
without
addressing
whether
the
replacement
or
reconstruction
has
resulted
in
a
significant
net
emissions
increase,
but
under
our
two
step
approach
for
evaluating
whether
a
change
constitutes
a
major
modification,
a
significant
net
emissions
increase
would
of
course
also
be
required.
We
have
also
retained
the
term
``
representative
of
normal
operations''
in
the
context
of
an
EUSGU's
option
to
seek
use
of
a
different
baseline
period,
but
there
the
question
whether
to
seek
such
use
is
at
the
source's
option,
obviating
many
of
the
difficulties
with
it
in
other
contexts.
II.
C
and
II.
D
below,
the
key
features
of
the
methodology
are
as
follows.
If
you
are
an
existing
emissions
unit
(
other
than
an
EUSGU),
you
will
determine
the
pre
change
(
baseline)
actual
emissions
by
calculating
an
average
annual
emissions
rate,
in
tpy,
using
any
consecutive
24
months
during
the
10
year
period
immediately
preceding
the
change.
This
rate
must
be
adjusted
downward
to
reflect
any
legally
enforceable
emission
limitations
imposed
after
the
selected
baseline
period.
We
are
codifying
the
``
2
in
5
years''
presumption
for
calculating
the
baseline
actual
emissions
for
EUSGUs.
If
you
are
an
existing
emissions
unit
(
including
EUSGUs),
you
will
estimate
post
change
emissions
(
projected
actual
emissions),
in
tpy,
to
reflect
any
increase
in
annual
emissions
that
may
result
from
the
proposed
change.
You
should
exclude,
in
calculating
any
increase
in
emissions
that
results
from
the
particular
project,
that
portion
of
the
unit's
emissions
following
the
project
that
an
existing
unit
could
have
accommodated
during
the
baseline
period
and
that
is
also
unrelated
to
the
particular
project,
including
any
increased
utilization
due
to
product
demand
growth.
You
must
make
the
projection
before
you
begin
actual
construction.
When
using
this
method,
you
must
record
the
projection
and
certain
other
information
in
circumstances
where
there
is
a
reasonable
possibility
that
a
change
may
result
in
a
significant
emissions
increase.
In
addition,
EUSGUs
must
send
a
copy
of
the
projections
and
other
information
to
your
reviewing
authority
before
beginning
actual
construction.
If,
for
a
project
at
an
existing
emissions
unit
(
other
than
an
EUSGU)
at
a
major
stationary
source,
you
elect
to
project
your
post
change
emissions,
we
are
also
requiring
you
to
maintain
information
on
these
emissions,
for
5
years
following
a
physical
or
operational
change,
or
in
some
cases
for
10
years
depending
on
the
nature
of
the
change.
If
your
annual
emissions
exceed
the
baseline
actual
emissions
by
a
significant
amount
and
also
exceed
your
projection,
you
must
report
this
information
to
your
reviewing
authority
within
60
days
after
the
end
of
the
year.
If
you
project
post
change
emissions
for
EUSGUs,
you
must
report
these
emissions
to
your
reviewing
authority
within
60
days
after
the
end
of
the
year
without
regard
to
whether
such
emissions
exceed
the
baseline
actual
emissions
or
projected
actual
emissions
for
a
period
of
5
years
(
or
in
some
cases
10
years,
depending
on
the
nature
of
the
change).
Instead
of
projecting
your
postchange
emissions,
for
all
existing
emissions
units
you
may
instead
project
post
change
emissions
on
the
basis
of
each
unit's
post
change
PTE.
If
you
use
this
method,
you
need
not
record
your
projections
or
track
or
report
postchange
emissions.
As
discussed
earlier,
our
prior
regulations
provide
that
when
your
emissions
unit,
other
than
an
EUSGU,
``
has
not
begun
normal
operations,
``
actual
emissions
equal
the
PTE
of
the
unit.
There
have
been
considerable
number
issues
raised
with
this
approach.
For
example,
using
PTE
as
a
measure
of
post
change
emissions
automatically
attributes
all
possible
emissions
increases
to
the
change.
There
are
many
cases,
however,
where
this
simply
is
not
true.
Moreover,
when
the
actual
to
potential
test
is
applied,
it
is
automatically
assumed
that
the
emissions
unit
has
not
begun
normal
operations
after
the
change
period.
In
many
such
cases,
however,
the
changed
unit
as
a
practical
matter
will
function
essentially
as
it
did
before
the
change.
We
are,
therefore,
allowing
all
existing
emissions
units
to
use
an
actual
toprojected
actual
applicability
test.
Accordingly,
we
are
generally
eliminating
the
term
``
begun
normal
operations''
from
the
determination
of
whether
a
change
results
in
a
significant
emissions
increase.
16
For
essentially
the
same
reasons,
while
our
1992
rules
did
not
authorize
use
of
projections
in
evaluating
whether
replacement
of
an
existing
emissions
unit
(
which
we
understood
to
require
application
of
the
NSPS
50
percent
cost
threshold)
constitutes
a
major
modification,
upon
reflection
we
have
decided
this
exception
to
the
availability
of
the
actual
to
projectedactual
applicability
test
is
also
unnecessary.
In
our
1980
rulemaking,
we
decided
against
applying
PSD
to
``
reconstruction,''
even
of
entire
sources,
on
the
grounds
that,
as
to
existing
sources
that
would
not
otherwise
be
subjected
to
PSD
review
as
a
major
modification
(
i.
e.,
such
source
would
not
cause
a
significant
net
emissions
increase),
changes
that
had
no
emission
consequences
should
not
be
subject
to
PSD
regardless
of
their
magnitude.
17
In
addition,
we
now
believe
that,
as
with
modified
units,
the
fact
that
replacement
units
are
replacing
similar
units
with
a
record
of
historical
operational
data
provides
sufficient
reasons
to
believe
that
a
projection
of
future
actual
emissions
can
be
sufficiently
reliable
that
an
up
front
emissions
cap
based
on
PTE
is
unnecessary.
In
other
words,
a
source
replacing
a
unit
should
be
able
to
adequately
project
and
track
emissions
for
the
replacement
unit
based,
in
part,
on
the
operating
history
of
the
replaced
unit.
In
contrast,
sources
adding
``
new''
units
that
do
not
qualify
as
replacement
units
must
project
that
the
future
emissions
of
the
new
unit
equal
its
PTE,
effectively
applying
the
``
actual
topotential
test
because
there
is
no
relevant
historical
data
that
could
be
used
to
establish
an
actual
emissions
baseline
or
projection
of
future
actual
emissions
for
such
new
units.
For
these
reasons,
we
have
eliminated
the
requirement
that
replaced
or
reconstructed
units
be
evaluated
as
to
whether
they
constitute
major
modifications
on
an
actual
to
potential
basis.
Instead,
you
may
compare
an
emission
unit's
baseline
actual
emissions
with
your
projected
actual
emission
in
measuring
whether
the
replacement
or
reconstruction
has
resulted
in
a
significant
emissions
increase.
You
must
treat
these
emissions
units
as
modifications
only
if
the
replacement
or
reconstruction
of
the
unit
results
in
a
signficant
increase
so
measured.
18
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251
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December
31,
2002
/
Rules
and
Regulations
C.
Changes
to
the
Procedures
for
Calculating
the
Pre
Change
Baseline
Actual
Emissions
for
Existing
Emissions
Units
Other
Than
EUSGUs
1.
Under
Today's
New
Requirements,
How
Should
I
Calculate
the
Pre
Change
Baseline
Actual
Emissions
for
an
Existing
Emissions
Unit
That
Is
Not
an
EUSGU?
When
you
calculate
the
baseline
actual
emissions
for
an
existing
emissions
unit
(
other
than
an
EUSGU),
you
may
select
any
consecutive
24
months
of
source
operation
within
the
past
10
years.
Using
the
relevant
source
records
for
that
24
month
period,
including
such
information
as
the
utilization
rate
of
the
equipment,
fuels
and
raw
materials
used
in
the
operation
of
the
equipment,
and
applicable
emission
factors,
you
must
be
able
to
calculate
an
average
annual
emissions
rate,
in
tpy,
for
each
pollutant
emitted
by
the
emissions
unit
that
is
modified,
or
is
affected
by
the
modification.
The
new
requirements
prohibit
you
from
counting
as
part
of
the
baseline
actual
emissions
any
pollution
levels
that
are
not
allowed
under
any
legally
enforceable
limitations
and
that
apply
at
the
time
of
the
project.
Therefore,
you
must
identify
the
most
current
legally
enforceable
limits
on
your
emissions
unit.
If
these
legally
enforceable
emission
limitations
and
operating
restrictions
are
more
stringent
than
those
that
applied
during
the
24
month
period,
you
must
adjust
downward
the
average
annual
emissions
rate
that
you
calculated
from
the
consecutive
24
month
period
to
reflect
these
current
restrictions.
(
See
section
II.
C.
5
of
this
preamble
for
further
discussion
of
the
adjustment
that
you
may
need
to
make.)
In
summary,
when
the
average
annual
emissions
rate
that
you
originally
calculated
is
still
legally
achievable
(
see
discussion
below),
then
your
baseline
actual
emissions
will
be
the
same
as
the
average
annual
emissions
rate
calculated
from
the
24
month
period.
If
it
is
not,
you
must
adjust
it
downward
so
that
it
does
not
reflect
emissions
that
are
no
longer
legally
allowed.
2.
Can
Existing
Emissions
Units
(
Other
Than
EUSGUs)
Still
Use
a
``
More
Representative
Time
Period''
for
Selecting
the
Baseline
Actual
Emissions?
No,
under
today's
new
requirements
neither
you
nor
your
reviewing
authority
will
have
the
authority
to
select
another
period
of
time
from
which
to
calculate
your
baseline
actual
emissions.
You
must
select
a
24
month
period
within
the
10
year
period
before
the
physical
or
operational
change.
3.
From
What
Point
in
Time
Is
the
10
Year
Look
Back
Measured?
If
you
believe
that
you
will
need
either
a
major
or
minor
NSR
permit
to
proceed
with
your
proposed
physical
or
operational
change,
then
you
must
use
the
10
year
period
immediately
preceding
the
date
on
which
you
submit
a
complete
permit
application.
If,
however,
you
believe
that
the
physical
or
operational
change(
s)
you
plan
to
make
will
not
result
in
either
a
significant
emissions
increase
from
the
project
or
a
significant
net
emissions
increase
at
your
major
stationary
source
(
that
is,
your
project
will
not
be
a
major
modification),
and
you
are
not
otherwise
required
to
obtain
a
minor
NSR
permit
before
making
such
change,
then
you
must
use
the
10
year
period
that
immediately
precedes
the
date
on
which
you
begin
actual
construction
of
the
physical
or
operational
change.
4.
What
if,
for
an
Existing
Emissions
Unit
(
Other
Than
an
EUSGU),
I
Do
Not
Have
Adequate
Documentation
for
Its
Operation
for
the
Past
10
Years?
Your
ability
to
use
the
full
10
years
of
the
look
back
period
will
depend
upon
the
availability
of
relevant
data
for
the
consecutive
24
month
period
you
wish
to
select.
The
data
must
adequately
describe
the
operation
and
associated
pollution
levels
for
the
emissions
units
being
changed.
If
you
do
not
have
the
data
necessary
to
determine
the
units'
actual
emission
factors,
utilization
rate,
and
other
relevant
information
needed
to
accurately
calculate
your
average
annual
emissions
rate
during
that
period
of
time,
then
you
must
select
another
consecutive
24
month
period
within
the
10
year
look
back
period
for
which
you
have
adequate
data.
5.
For
an
Existing
Unit
(
Other
Than
EUSGUs),
When
Must
I
Adjust
My
Calculation
of
the
Pre
Change
Baseline
Actual
Emissions?
Today's
amendments
require
you
to
adjust
the
average
annual
emissions
rate
derived
from
the
selected
24
month
period
under
certain
circumstances.
Specifically,
you
must
adjust
downward
this
average
annual
rate
if
any
legally
enforceable
emission
limitations,
including
but
not
limited
to
any
State
or
Federal
requirements
such
as
RACT,
BACT,
LAER,
NSPS,
and
National
Emission
Standards
for
Hazardous
Air
Pollutants
(
NESHAP),
restrict
the
emissions
unit's
ability
to
emit
a
particular
pollutant
or
to
operate
at
levels
that
existed
during
the
selected
24
month
period
from
which
you
calculate
the
average
annual
emissions
rate.
For
example,
assume
that
during
the
selected
consecutive
24
month
period
you
burned
fuel
oil
and
you
were
subjected
to
a
sulfur
limit
of
2
percent
sulfur
(
by
weight).
Today,
you
are
only
allowed
to
burn
fuel
oil
with
a
sulfur
content
of
0.5
percent
or
less.
Consequently,
you
would
be
required
to
adjust
your
preliminary
calculation
of
baseline
actual
emissions
for
sulfur
dioxide
(
SO2)
(
that
is,
substitute
the
lower
sulfur
limit
into
the
emissions
calculation,
yielding
a
75
percent
reduction
in
the
emissions
rate
from
the
initial
calculation)
to
reflect
the
current
restriction
allowing
only
0.5
percent
sulfur
in
fuel
oil.
The
original
average
annual
utilization
rate
would
not
be
adjusted
unless
a
more
stringent
legally
enforceable
operational
limitation
has
since
been
imposed
that
restricts
that
rate.
You
must
also
adjust
for
legally
enforceable
emission
limitations
you
may
have
voluntarily
agreed
to,
such
as
limits
you
may
have
taken
in
your
permit
for
netting,
emissions
offsets,
or
the
creation
of
ERCs.
Also,
you
must
adjust
your
emissions
from
the
24
month
period
if
a
raw
material
you
used
during
the
baseline
period
is
now
prohibited.
For
example,
you
may
have
used
a
paint
with
a
high
solvent
concentration
during
a
portion
of
the
consecutive
24
month
period.
Today,
you
are
prohibited
from
using
that
particular
paint.
You
must
then
adjust
your
emissions
rate
to
reflect
the
raw
material
restriction.
6.
How
Should
I
Calculate
the
Baseline
Actual
Emissions
for
Emissions
Units
(
Other
Than
EUSGUs)
That
Use
Multiple
Fuels
or
Raw
Materials?
For
an
emissions
unit
that
is
capable
of
burning
more
than
one
type
of
fuel,
you
must
relate
the
current
emission
factors
to
the
fuel
or
fuels
that
were
actually
used
during
the
selected
24
month
period.
For
example,
when
calculating
the
baseline
actual
emissions
for
an
emissions
unit
that
burned
natural
gas
for
a
portion
of
the
24
month
period
and
fuel
oil
for
the
remainder,
you
must
retain
that
fuel
apportionment
(
for
example,
natural
gas
to
fuel
oil
ratio),
but
you
must
also
use
the
current
legally
enforceable
emission
factors
for
natural
gas
and
fuel
oil,
respectively,
to
calculate
the
baseline
actual
emissions.
If,
however,
you
are
no
longer
allowed
or
able
to
use
one
of
those
fuel
types,
then
you
must
make
your
calculations
assuming
use
of
the
currently
allowed
fuel
for
the
entire
24
month
period.
You
must
use
the
same
approach
for
emissions
units
that
use
multiple
feedstock
or
raw
materials,
which
may
vary
in
use
during
the
unit's
ongoing
production
process.
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31,
2002
/
Rules
and
Regulations
7.
How
Should
I
Calculate
the
Baseline
Actual
Emissions
for
Construction
Projects
That
Involve
Multiple
Units?
Today's
new
requirements
require
that
you
select
the
same
single
consecutive
24
month
period
within
the
10
year
look
back
period
to
calculate
the
baseline
actual
emissions
for
all
existing
emissions
units
that
will
be
changed.
See,
for
example,
new
§
52.21(
b)(
48)(
ii)(
e).
The
result
will
be
that
the
baseline
actual
emissions
for
each
affected
pollutant
will
be
based
on
the
same
consecutive
24
month
period
as
well.
You
will
have
the
option
to
select
the
single
24
month
period
that
best
represents
the
collective
level
of
operation
(
and
emissions)
for
your
existing
emissions
units.
If
a
particular
existing
emissions
unit
did
not
yet
exist
during
the
24
month
period
you
select
to
calculate
the
baseline
actual
emissions,
you
must
count
that
emissions
unit's
emissions
rate
as
zero
for
that
full
period
of
time.
If
an
emissions
unit
operated
for
only
a
portion
of
the
particular
24
month
period
that
you
select,
you
must
calculate
its
average
annual
emissions
rate
using
an
emissions
rate
of
zero
for
that
portion
of
time
when
the
unit
was
not
in
operation.
For
new
emissions
units
(
a
unit
that
has
existed
for
less
than
2
years)
that
will
be
changed
by
the
project,
the
baseline
actual
emissions
rate
is
zero
if
you
have
not
yet
begun
operation
of
the
unit,
and
is
equal
to
the
unit's
PTE
once
it
has
begun
to
operate.
8.
Am
I
Able
To
Apply
Today's
Changes
for
Calculating
the
Baseline
Actual
Emissions
to
Other
Major
NSR
Requirements?
No,
as
stated
in
section
II.
A,
you
are
only
allowed
to
use
the
new
baseline
methodology
in
today's
rule
for
three
specific
purposes
involving
existing
emissions
units
as
follows.
For
modifications,
to
determine
a
modified
unit's
pre
change
baseline
actual
emissions
as
part
of
the
new
actual
to
projected
actual
applicability
test
For
netting,
to
determine
the
prechange
actual
emissions
of
an
emissions
unit
that
underwent
a
physical
or
operational
change
within
the
contemporaneous
period.
You
may
select
separate
baseline
periods
for
each
contemporaneous
increase
or
decrease.
For
PALs,
to
establish
the
PAL
level.
If
you
determine
that
the
modification
of
your
source
is
a
major
modification,
you
must
revert
to
using
the
existing
definition
of
``
actual
emissions''
to
determine
your
source's
actual
emissions
on
a
particular
date
to
satisfy
all
other
NSR
permitting
requirements,
including
any
air
quality
analyses
(
for
example,
compliance
with
NAAQS,
PSD
increments,
AQRVs)
and
the
amount
of
emissions
offsets
required.
For
example,
when
you
must
determine
your
source's
compliance
with
the
PSD
increments
following
a
major
modification,
you
must
still
use
the
allowable
emissions
from
each
emissions
unit
that
is
modified,
or
is
affected
by
the
modification.
An
existing
source's
contribution
to
the
amount
of
increment
consumed
should
be
based
on
that
source's
actual
emissions
rate
from
the
2
years
immediately
preceding
the
date
of
the
change,
although
the
reviewing
authority
shall
allow
the
use
of
another
2
year
period
if
it
determines
that
such
period
is
more
representative
of
that
source's
normal
operation.
See,
for
example,
§
52.21(
b)(
21)(
ii).
Also,
any
determination
of
the
amount
of
emissions
offset
that
must
be
obtained
by
a
major
modification
subject
to
the
nonattainment
NSR
requirements
under
§
51.165(
a)
should
be
based
on
calculations
using
the
existing
definitions
of
``
actual
emissions''
and
``
allowable
emissions.''
See
new
§
51.165(
a)(
3)(
ii)(
H).
D.
The
Actual
to
Projected
Actual
Applicability
Test
for
Physical
or
Operational
Changes
to
Existing
Emissions
Units
Including
EUSGUs
1.
How
are
post
change
actual
emissions
calculated
under
today's
revised
rule?
Today,
we
are
amending
the
major
NSR
rules
to
enable
you
to
use
an
applicability
test
that
is
similar
to
the
applicability
test
that
currently
applies
to
EUSGUs
(
that
is,
the
actual
torepresentative
actual
annual
emissions
test).
The
new
test
allows
you
to
project
the
post
change
emissions
of
all
modified
existing
emissions
units
(
including
EUSGUs)
in
the
same
manner.
That
is,
under
today's
new
provisions
for
non
routine
physical
or
operational
changes
to
existing
emissions
units,
rather
than
basing
a
unit's
post
change
emissions
on
its
PTE,
you
may
project
an
annual
rate,
in
tpy,
that
reflects
the
maximum
annual
emissions
rate
that
will
occur
during
any
one
of
the
5
(
or
in
some
circumstances
10)
years
immediately
after
the
physical
or
operational
change.
The
first
year
begins
on
the
day
the
emissions
unit
resumes
regular
operation
following
the
change
and
includes
the
12
months
after
this
date.
This
projection
of
the
unit's
annual
emissions
rate
following
the
change
is
defined
as
the
``
projected
actual
emissions''
(
see,
for
example,
§
52.21(
b)(
48)),
and
will
be
based
on
your
maximum
annual
rate
in
tons
per
year
at
which
you
are
projected
to
emit
a
regulated
NSR
pollutant,
less
any
amount
of
emissions
that
could
have
been
accommodated
during
the
selected
24
month
baseline
period
and
is
not
related
to
the
change.
Accordingly,
you
will
calculate
the
unit's
projected
actual
emissions
as
the
product
of:
(
1)
The
hourly
emissions
rate,
which
is
based
on
the
emissions
unit's
operational
capabilities
following
the
change(
s),
taking
into
account
legally
enforceable
restrictions
that
could
affect
the
hourly
emissions
rate
following
the
change(
s);
and
(
2)
the
projected
level
of
utilization,
which
is
based
on
both
the
emissions
unit's
historical
annual
utilization
rate
and
available
information
regarding
the
emissions
unit's
likely
post
change
capacity
utilization.
In
calculating
the
projected
actual
emissions,
you
should
consider
both
the
expected
and
the
highest
projections
of
the
business
activity
that
you
expect
could
be
achieved
and
that
are
consistent
with
information
your
company
publishes
for
business
related
purposes
such
as
a
stockholder
prospectus,
or
applications
for
business
loans.
From
the
initial
calculation,
you
may
then
make
the
appropriate
adjustment
to
subtract
out
any
portion
of
the
emissions
increase
that
could
have
been
accommodated
during
the
unit's
24
month
baseline
period
and
is
unrelated
to
the
change.
Once
the
appropriate
subtractions
have
been
made,
the
final
value
for
the
projected
actual
emissions,
in
tpy,
is
the
value
that
you
compare
to
the
baseline
actual
emissions
to
determine
whether
your
project
will
result
in
a
significant
emissions
increase.
The
adjustment
to
the
projected
actual
emissions
allows
you
to
exclude
from
your
projection
only
the
amount
of
the
emissions
increase
that
is
not
related
to
the
physical
or
operational
change(
s).
In
comparing
your
projected
actual
emissions
to
the
units'
baseline
actual
emissions,
you
only
count
emissions
increases
that
will
result
from
the
project.
For
example,
as
with
the
electric
utility
industry,
you
may
be
able
to
attribute
a
portion
of
your
emissions
increase
to
a
growth
in
demand
for
your
product
if
you
were
able
to
achieve
this
higher
level
of
production
during
the
consecutive
24
month
period
you
selected
to
establish
the
baseline
actual
emissions,
and
the
increased
demand
for
the
product
is
unrelated
to
the
change.
For
Clean
Units,
if
a
given
project
can
be
constructed
and
operated
at
a
Clean
Unit
without
causing
the
emissions
unit
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251
/
Tuesday,
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31,
2002
/
Rules
and
Regulations
19
Your
ability
to
use
the
full
10
years
for
calculating
any
contemporaneous
emissions
change
is
contingent
upon
the
availability
of
valid
and
sufficient
source
information
for
the
selected
24
month
period.
See,
for
example,
new
§
52.21(
b)(
48)(
ii)(
f).
to
lose
its
Clean
Unit
status,
then
no
emissions
increase
will
occur.
For
new
units,
however,
you
must
continue
to
calculate
post
change
emissions
on
the
basis
of
a
unit's
PTE.
2.
Will
My
Projection
of
Projected
Actual
Emissions
Become
an
Enforceable
Emission
Limitation
as
Suggested
in
the
1998
NOA?
No,
we
did
not
adopt
such
a
requirement.
If
you
have
an
existing
emissions
unit
and
your
project
results
in
an
increase
in
annual
emissions
that
exceeds
the
baseline
actual
emissions
by
a
significant
amount,
and
differs
from
your
projection
of
post
change
emissions
that
you
were
required
to
calculate
and
maintain
records
of,
then
you
must
report
this
increase
to
your
reviewing
authority
within
60
days
after
the
end
of
the
year.
Since
modified
EUSGUs
are
required
to
report
their
post
change
annual
emissions
to
the
reviewing
authority
annually,
any
occurrence
of
a
significant
increase
will
be
covered
under
that
report
for
the
affected
calendar
year.
See
section
II.
D.
6
of
this
preamble
for
a
more
detailed
discussion
of
the
reporting
requirements.
3.
How
Do
I
Determine
How
Long
My
Post
Change
Emissions
Will
Be
Tracked
To
Ensure
That
My
Project
Is
Not
a
Major
Modification?
Generally,
your
projected
actual
emissions
must
be
tracked
against
your
facility's
post
change
emissions
for
5
years
following
resumption
of
regular
operations
whether
you
are
an
EUSGU
or
other
type
of
existing
emissions
unit.
We
will
presume
that
any
increases
that
occur
after
5
years
are
not
associated
with
the
physical
or
operational
changes.
However,
you
may
be
required
to
track
emissions
for
a
longer
period
of
time
under
the
following
circumstances.
If
you
are
an
existing
emissions
unit
and
one
of
the
effects
of
your
physical
or
operational
change(
s)
is
to
increase
a
unit's
design
capacity
or
PTE,
you
must
track
your
emissions
for
a
period
of
10
years
after
the
completion
of
the
project.
This
extended
period
allows
for
the
possibility
that
you
could
end
up
using
the
increased
capacity
more
than
you
projected
and
such
use
might
lead
to
significant
emissions
increases.
4.
What
Are
the
Reporting
and
Recordkeeping
Requirements
for
Projects?
Reporting
and
recordkeeping
for
a
project
is
required
when
three
criteria
are
met:
(
1)
You
elect
to
project
postchange
emissions
rather
than
use
PTE;
(
2)
there
is
a
reasonable
possibility
that
the
project
will
result
in
a
significant
emissions
increase;
and
(
3)
the
project
will
not
constitute
a
major
modification.
In
such
circumstances,
you
must
document
and
maintain
a
record
of
the
following
information:
a
description
of
the
project;
an
identification
of
emissions
units
whose
emissions
could
increase
as
a
result
of
the
project;
the
baseline
actual
emissions
for
each
emissions
unit;
and
your
projected
actual
emissions,
including
any
emissions
excluded
as
unrelated
to
the
change
and
the
reason
for
the
exclusion.
In
addition,
if
your
project
increase
is
significant,
you
must
record
your
netting
calculations
if
you
use
emissions
reductions
elsewhere
at
your
major
stationary
source
to
conclude
that
the
project
is
not
a
major
modification.
For
covered
projects,
you
must
record
this
information
before
beginning
actual
construction.
If
you
are
an
EUSGU,
you
must
also
send
this
information
to
your
reviewing
authority
before
beginning
actual
construction.
Note,
however,
that
if
you
chose
to
use
potential
emissions
as
your
projection
of
post
change
emissions,
you
are
not
required
to
maintain
a
record
of
this
decision.
In
addition,
today's
final
rules
require
you
to
maintain
emissions
data
for
all
emissions
units
that
are
changed
by
the
project.
You
must
maintain
this
information
for
5
years,
or
10
years
if
applicable.
The
information
you
must
maintain
may
include
continuous
emissions
monitoring
data,
operational
levels,
fuel
usage
data,
source
test
results,
or
any
other
readily
available
information
of
sufficient
accuracy
for
the
purpose
of
determining
an
emissions
unit's
post
change
emissions.
If
you
are
an
EUSGU,
you
must
report
this
information
to
your
reviewing
authority
within
60
days
after
the
end
of
any
year
in
which
you
are
required
to
generate
such
information.
Other
existing
units
must
report
to
the
reviewing
authority
any
increase
in
the
post
change
annual
emissions
rate
when
that
rate:
(
1)
Exceeds
the
baseline
actual
emissions
by
a
significant
amount,
and
(
2)
differs
from
the
projection
that
was
calculated
before
the
change.
See,
for
example,
new
§
52.21(
r)(
6)(
iii).
In
addition
to
the
reporting
requirements
discussed
above,
you
are
also
obligated
to
ensure
that
the
necessary
emissions
information
you
are
required
to
maintain
is
available
for
examination
upon
request
by
the
reviewing
authority
or
the
general
public.
5.
How
Do
Today's
Changes
Affect
the
Netting
Methodology
for
Existing
Emissions
Units
(
Other
Than
EUSGUs)?
If
your
calculations
show
that
a
significant
emissions
increase
will
result
from
a
modification,
you
have
the
option
of
taking
into
consideration
any
contemporaneous
emissions
changes
that
may
enable
you
to
``
net
out''
of
review,
that
is,
show
that
the
net
emissions
increase
at
the
major
stationary
source
will
not
be
significant.
The
contemporaneous
time
period
will
not
change
under
the
Federal
PSD
program
as
a
result
of
today's
action.
That
is,
creditable
increases
and
decreases
in
emissions
that
have
occurred
between
the
date
5
years
before
construction
of
the
particular
change
commences
and
the
date
the
increase
from
that
change
occurs
are
contemporaneous.
See
§
52.21(
b)(
3)(
ii).
States
will
continue
to
have
some
discretion
in
defining
``
contemporaneous''
for
their
own
NSR
programs.
Although
we
are
not
changing
our
definition
of
``
contemporaneous,''
today's
action
allows
existing
emissions
units
(
other
than
EUSGUs)
to
calculate
the
baseline
actual
emissions
for
each
contemporaneous
event
using
the
10
year
look
back
period.
That
is,
you
can
select
any
consecutive
24
month
period
during
the
10
year
period
immediately
preceding
the
change
occurring
in
the
contemporaneous
period
to
determine
the
baseline
actual
emissions
for
each
creditable
emissions
change.
Generally,
for
each
emissions
unit
at
which
a
contemporaneous
emissions
change
has
occurred,
you
should
use
the
10
year
look
back
period
relevant
to
that
change.
19
When
evaluating
emissions
increases
from
multi
unit
modifications,
if
more
than
one
emissions
unit
was
changed
as
part
of
a
single
project
during
the
contemporaneous
period,
you
may
select
a
separate
consecutive
24
month
period
to
represent
each
emissions
unit
that
is
part
of
the
project.
In
any
case,
the
calculated
baseline
actual
emissions
for
each
emissions
unit
must
be
adjusted
to
reflect
the
most
current
emission
limitations
(
including
operational
restrictions)
applying
to
that
unit.
``
Current''
in
the
context
of
a
contemporaneous
emissions
change
refers
to
limitations
on
emissions
and
source
operation
that
existed
just
prior
to
the
date
of
the
contemporaneous
change.
E.
Clarifying
Changes
to
WEPCO
Provisions
for
EUSGUs
The
method
you
use
to
calculate
the
baseline
actual
emissions
for
an
existing
EUSGU
to
determine
whether
there
is
a
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/
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/
Rules
and
Regulations
20
Letter
from
John
S.
Seitz,
Director,
Office
of
Air
Quality
Planning
and
Standards,
to
Patrick
M.
Raher,
August
6,
2001.
significant
emissions
increase
from
a
physical
or
operational
change
at
an
EUSGU,
and
to
determine
whether
a
significant
net
emissions
increase
will
occur
at
the
major
stationary
source,
will
not
change
as
a
result
of
today's
final
rulemaking.
The
rule
provides
that
for
an
existing
EUSGU
you
may
calculate
the
baseline
actual
emissions
as
the
average
annual
emissions
(
tpy)
of
the
emissions
unit
using
any
2
year
period
out
of
the
5
years
immediately
preceding
the
modification.
(
This
was
set
out
as
a
presumption
in
the
preamble
for
the
1992
WEPCO
amendments.)
This
rule
recognizes
the
ordinary
variability
in
demand
for
electricity.
See,
for
example,
new
§
52.21(
b)(
21)(
ii).
For
example,
a
cold
winter
or
hot
summer
will
result
in
high
levels
of
demand
while
a
relatively
mild
year
will
produce
lower
demand.
By
allowing
a
utility
to
use
any
consecutive
2
years
within
the
past
5,
the
rule
recognizes
that
electricity
demand
and
resultant
utility
operations
fluctuate
in
response
to
various
factors
such
as
annual
variability
in
climatic
or
economic
conditions
that
affect
demand,
or
changes
at
other
plants
in
the
utility
system
that
affect
the
dispatch
of
a
particular
plant.
By
allowing
utilities
to
use
as
a
baseline
any
consecutive
2
years
in
the
last
5
years,
these
types
of
fluctuations
in
operations
can
be
more
realistically
considered.
The
reviewing
authority
shall
allow
the
use
of
a
different
time
period
upon
a
determination
that
it
is
more
representative
of
normal
source
operation.
In
an
August
6,
2001
letter,
20
we
addressed
the
issue
of
whether
combined
cycle
gas
turbines
(
the
gas
turbines
and
waste
heat
recovery
components)
came
within
the
definition
of
``
electric
utility
steam
generating
units''
for
the
purpose
of
determining
whether
such
units
are
eligible
to
use
the
WEPCO
``
applicability
test.''
The
letter
concluded
that
``
steam
generating
units''
include
not
only
electric
utility
plants
with
boilers,
but
also
plants
with
combined
cycle
gas
turbines
if
the
combined
cycle
gas
turbine
systems
supply
more
than
one
third
of
their
potential
electric
output
capacity
and
more
than
25
MW
electrical
output
to
any
utility
power
distribution
system
for
sale.
Consequently,
qualifying
combined
cycle
gas
turbines
must
also
use
the
2
in
5
years
baseline
method.
Finally,
today's
rules
provide
the
same
method
for
EUSGUs
that
will
exist
for
all
other
existing
emissions
units
to
project
post
change
emissions
following
a
physical
or
operational
change
to
a
unit.
In
the
1996
proposal,
we
proposed
a
range
of
options
for
addressing
the
applicability
of
changes
that
are
made
to
existing
emissions
units,
including
the
option
of
extending
the
actual
to
futureactual
test,
then
available
only
to
utilities,
to
all
source
categories.
While
we
have
decided
to
leave
the
WEPCO
rules
intact
in
most
respects,
we
believe
that
it
is
reasonable
and
appropriate
to
establish
a
consistent
method
for
sources
to
use
for
projecting
the
postchange
emissions
that
will
result
from
a
physical
or
operational
change
to
an
existing
emissions
unit.
Therefore,
under
today's
new
rules,
the
current
method
of
basing
the
projection
on
the
2
years
following
the
change
to
an
EUSGU
is
being
replaced
with
the
method
available
to
all
other
existing
units,
under
which
you
project
a
unit's
post
change
emissions
as
the
maximum
annual
rate
that
the
unit
will
emit
in
any
one
of
the
5
years
following
resumption
of
regular
operations.
F.
The
``
Hybrid''
Applicability
Test
for
Projects
Affecting
Multiple
Types
of
Emissions
Units
1.
When
Does
the
Hybrid
Applicability
Test
Apply
to
You?
The
hybrid
applicability
test
applies
if
you
plan
a
project
(
or
series
of
related
projects)
that
will
affect
emissions
units
of
two
or
more
of
the
following
types.
Existing
emissions
units
New
emissions
units
Clean
Units
2.
How
Do
I
Determine
Whether
My
Project
Will
Result
in
a
Significant
Emissions
Increase
Under
the
Hybrid
Test?
For
the
first
two
types
of
emissions
units
listed
above
that
are
affected
by
the
project,
calculate
the
emissions
increase
as
we
have
discussed
previously
in
this
preamble.
That
is,
use
the
actual
to
projected
actual
applicability
test
for
existing
units
and
the
actual
to
potential
test
for
new
emissions
units.
Clean
Units
are
discussed
fully
in
section
V
of
this
preamble.
If
a
given
project
can
be
constructed
and
operated
at
a
Clean
Unit
without
causing
the
emissions
unit
to
lose
its
Clean
Unit
status,
no
emissions
increase
shall
be
deemed
to
occur
at
that
Clean
Unit.
If
a
given
project
would
cause
the
emissions
unit
to
lose
its
Clean
Unit
status,
then
the
increase
in
emissions
should
be
calculated
as
if
the
emissions
unit
is
not
a
Clean
Unit.
After
you
calculate
the
emissions
increase
for
each
relevant
unit,
total
the
increases
across
all
the
emissions
units
of
all
types.
If
this
total
emissions
increase
equals
or
exceeds
the
level
defined
as
significant
for
the
regulated
NSR
pollutant
in
question,
the
project
will
result
in
a
significant
emissions
increase
for
that
pollutant.
You'll
find
the
regulatory
language
for
determining
whether
a
project
will
result
in
a
significant
emissions
increase
at
§
§
51.165(
a)(
2)(
vii)(
D),
51.166(
a)(
7)(
vi)(
d),
and
52.21(
a)(
2)(
vi)(
d).
In
section
II.
C.
8
of
this
preamble,
we
indicate
that
the
baseline
actual
emissions
for
all
units
that
are
not
EUSGUs
that
are
changed
by
a
project
must
be
calculated
based
on
the
same
consecutive
24
month
period
within
the
previous
10
years.
The
same
principle
applies
under
the
hybrid
test,
but
it
can
be
slightly
more
complicated
if
both
EUSGUs
and
non
EUSGUs
are
involved.
In
this
case,
you
must
use
the
same
baseline
period
for
all
emissions
units
affected
by
the
project.
This
baseline
period
must
be
selected
so
as
to
meet
the
requirements
for
both
EUSGUs
and
non
EUSGUs.
Thus,
you
must
select
a
2
year
period
out
of
the
previous
5
years
for
your
baseline
period,
as
required
for
EUSGUs
(
and
within
the
requirements
for
non
EUSGUs).
If
you
wish
to
use
another
period
that
you
believe
is
more
representative
(
as
allowed
for
EUSGUs),
the
entire
period
must
fall
within
the
previous
10
years
(
as
required
for
non
EUSGUs).
3.
How
Do
I
Determine
the
Net
Emissions
Increase
From
My
Project
Under
the
Hybrid
Test?
If
you
conclude
that
a
significant
emissions
increase
will
result
from
the
proposed
project,
you
have
the
option
of
taking
into
consideration
any
contemporaneous
emissions
changes
that
may
enable
you
to
``
net
out''
of
review,
that
is,
show
that
the
net
emissions
increase
at
the
major
stationary
source
will
not
be
significant.
The
netting
analysis
is
carried
out
under
the
hybrid
test
just
as
it
is
under
the
other
applicability
tests.
Refer
to
section
II.
D.
7
of
this
preamble
for
a
discussion
of
netting
methodology.
G.
Legal
Basis
for
Today's
Action
The
Act
defines
modification
for
the
purposes
of
PSD
and
nonattainment
NSR
through
cross
reference
to
the
NSPS
definition
of
``
modification.''
The
NSPS
definition
states
that
a
modification
``
means
any
physical
change
in,
or
change
in
the
method
of
operation
of,
a
stationary
source
which
increases
the
amount
of
any
air
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
21
See,
for
example,
WEPCO
Rule,
57
FR
32316
(``
fundamental
distinctions
between
the
technologybased
provisions
of
NSPS
and
the
air
quality
based
provisions
of
NSR'').
See
also
ASARCO
Inc.
v.
EPA,
578
F.
2d
319
(
D.
C.
Cir.
1978).
22
The
explanation
of
the
applicability
test
for
``
Clean
Units''
is
discussed
in
section
V.
23
``
Business
Cycles
in
Major
Emitting
Source
Industries.''
Eastern
Research
Group;
September
25,
1997.
This
study
examined
the
business
fluctuations
for
nine
source
categories
described
as
CAA
major
emitting
sources.
Industry
business
cycles
were
examined
using
industry
output
data
Continued
pollutant
emitted
by
such
source
or
which
results
in
the
emission
of
any
air
pollutant
not
previously
emitted.''
CAA
section
111(
a)(
4),
42
U.
S.
C.
7411(
a)(
4).
The
Act
is
silent,
however,
on
the
issue
of
how
one
is
to
determine
whether
a
physical
or
operational
change
increases
the
amount
of
any
air
pollutant
emitted
by
the
source.
Accordingly,
EPA
is
exercising
its
discretion
in
interpreting
and
providing
clarity
to
this
issue.
We
believe
that
the
rules
set
forth
today
are
``
a
permissible
construction
of
the
statute.''
Chevron
U.
S.
A.,
Inc.
v.
NRDC,
467
U.
S.
843
4
(
1984).
The
reviewing
court
should
defer
to
it.
Id.
at
837.
In
the
NSPS
program,
we
determine
whether
there
has
been
an
``
increase
in
any
air
pollutant
emitted''
by
the
source
by
comparing
its
maximum
hourly
achievable
emissions
before
and
after
the
change.
EPA
and
the
courts
have
recognized,
however,
that
the
NSR
programs
and
the
NSPS
programs
have
different
goals,
21
and
thus,
we
have
utilized
different
emissions
tests
in
the
NSR
programs.
Prior
to
today,
the
regulations
applied
an
actual
to
futureactual
applicability
test
for
EUSGUs
and
an
actual
to
potential
applicability
test
for
all
other
emissions
units.
Today,
we
are
establishing
a
new
applicability
test
for
calculating
emissions
increases
for
``
Clean
Units''
and
an
actual
toprojected
actual
applicability
test
for
all
other
emissions
units.
We
believe
that
establishing
an
actual
to
projectedactual
applicability
test
for
all
emissions
units
is
a
reasonable
interpretation
of
the
phrase
``
increase
of
any
pollutant
emitted.''
22
H.
Response
to
Comments
and
Rationale
for
Today's
Actions
We
received
numerous
comments
on
our
proposed
rule
regarding
the
calculation
of
the
baseline
actual
emissions
and
the
actual
to
futureactual
test.
Some
of
the
significant
comments
and
our
responses
to
them
are
provided
below.
A
complete
set
of
comments
and
our
responses
can
be
found
in
the
Technical
Support
Document
located
in
the
docket
for
this
rulemaking.
1.
Why
Are
We
Extending
the
Look
Back
Period
for
Determining
the
Baseline
Actual
Emissions
to
10
Years?
Most
commenters
generally
support
our
proposal
to
allow
owners
and
operators
to
use
a
10
year
look
back
period
to
determine
the
baseline
actual
emissions
for
modifications
at
any
existing
emissions
unit.
Commenters
have
various
reasons
for
supporting
or
opposing
the
proposed
approach.
Many
supporters
agree
that
extending
the
baseline
look
back
period
to
10
years
would
simplify
current
regulations
and
provide
certainty
to
sources
who
otherwise
would
have
to
demonstrate
to
the
reviewing
authority
that
a
period
other
than
the
2
years
immediately
preceding
the
proposed
change
was
more
representative
of
normal
source
operation.
Some
commenters
support
the
proposal
because
it
would
prevent
the
perceived
confiscation
of
underused
capacity
at
sources
that
have
had
low
utilization
rates
for
an
extended
period.
These
commenters
agree
that
a
10
year
look
back
period
is
more
likely
to
afford
a
source
a
baseline
actual
emissions
calculation
that
best
reflects
representative
source
operating
conditions
and
would
also
account
for
fluctuations
in
the
business
cycle.
Some
commenters
criticize
the
proposed
10
year
look
back
period
as
being
too
long.
These
commenters
recommend
either
a
5
year
or
2
year
look
back
period.
One
of
these
commenters
states
that
the
10
year
look
back
creates
the
opportunity
for
a
source
to
increase
production
to
the
10
year
maximum,
and
prevents
the
State
or
local
air
regulators
from
addressing
the
increase
in
emissions.
Thus,
the
commenter
believes
that
sources
would
be
allowed
to
use
historic
emissions
levels
that
are
higher
than
current
levels
to
establish
the
baseline
actual
emissions.
Some
commenters
add
that
the
proposed
change
would
not
reduce
program
complexity.
Some
commenters
believe
that
instead
of
extending
the
period
for
establishing
baseline
actual
emissions,
the
test
for
establishing
modifications
should
be
changed.
According
to
the
commenters,
the
problem
is
not
that
the
current
system
does
not
go
back
far
enough
to
set
a
fair
actual
emissions
baseline,
but
that
the
methodology
does
not
account
for
the
fact
that
most
emissions
units
are
operating
at
an
activity
level
much
lower
than
the
allowed
activity
level.
The
commenters
believe
that
many
of
the
real
problems
associated
with
the
current
major
modification
applicability
test
would
be
eliminated
if
the
procedure
was
modified
in
an
equitable
manner.
A
commenter
also
adds
that
EPA
may
also
want
to
include
provisions
that
prevent
a
source
from
applying
the
new
definition
of
actual
emissions
in
a
way
that
would
retroactively
enable
the
source
to
reverse
a
previous
major
modification
determination
and
to
eliminate
any
emissions
reduction
previously
required
for
that
major
modification.
We
continue
to
believe
that
it
is
reasonable
and
appropriate
to
adopt
the
new
method
for
establishing
a
modified
unit's
baseline
actual
emissions.
It
is
important
to
understand
the
difference
between
the
purpose
of
the
new
procedure,
which
uses
the
10
year
look
back,
and
the
existing
procedure
under
the
pre
existing
definition
of
``
actual
emissions''
at
§
52.21(
b)(
21(
ii),
which
generally
requires
the
use
of
an
average
annual
emissions
rate
based
on
the
2
year
period
immediately
preceding
a
particular
date.
The
latter
procedure
is
designed
to
estimate
a
source's
actual
emissions
at
a
particular
time
and
continues
to
be
appropriate
for
such
things
as
estimating
a
source's
impact
on
air
quality
for
PSD
increment
consumption.
On
the
other
hand,
the
new
baseline
procedure
is
specifically
designed
to
allow
a
source
to
consider
a
full
business
cycle
in
determining
whether
there
will
be
an
emissions
increase
from
a
physical
or
operational
change.
Generally,
a
source's
operations
over
a
business
cycle
cover
a
range
of
operating
(
and
emissions)
levels
not
simply
a
single
level
of
utilization.
The
new
procedure
recognizes
that
market
fluctuations
are
a
normal
occurrence
in
most
industries,
and
that
a
source's
operating
level
(
and
emissions)
does
not
remain
constant
throughout
a
source's
business
cycle.
The
use
of
a
24
month
period
within
the
past
10
years
to
establish
an
average
annual
rate
is
intended
to
adjust
for
unusually
high
short
term
peaks
in
utilization.
Consequently,
the
new
procedure
ensures
that
a
source
seeking
to
make
changes
at
its
facility
at
a
time
when
utilization
may
not
be
at
its
highest
can
use
a
normal
business
cycle
baseline
by
allowing
the
source
to
identify
capacity
actually
used
in
order
to
determine
an
average
annual
emissions
rate
from
which
to
calculate
any
projected
actual
emissions
resulting
from
the
change.
With
respect
to
the
commenters'
general
concerns
that
a
10
year
look
back
period
is
too
long,
we
sought
to
better
understand
what
time
period
best
represents
an
industry's
normal
business
cycle.
Therefore,
we
contracted
for
a
study
of
several
industries
in
1997.23
This
study
found
that,
for
the
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
for
the
years
1982
to
1994
inclusive,
based
on
the
Office
of
Management
and
Budget's
SIC
codes
for
individual
industries
(
OMB,
1987).
industries
analyzed,
business
cycles
differ
markedly
by
industry,
and
may
vary
greatly
both
in
duration
and
intensity
even
within
a
particular
industry.
Nevertheless,
we
concluded
from
the
study
that
10
years
of
data
is
reasonable
to
capture
an
entire
industry
cycle.
Comments
from
various
industries
support
a
conclusion
that
a
10
year
look
back
period
is
a
fair
and
representative
time
frame
for
encompassing
a
source's
normal
business
cycle.
We
believe
that
the
use
of
a
10
year
look
back
period
will
help
provide
certainty
to
the
process
and
eliminate
the
ambiguity
and
confusion
that
occurred
when
an
applicant
and
the
reviewing
authority
disagreed
on
what
time
frame
provides
the
period
most
representative
of
normal
source
operation.
The
new
requirements
also
provide
certainty
to
the
look
back
period,
since
there
is
no
opportunity
to
select
another
period
of
time
outside
this
10
year
period.
(
See
additional
discussion
in
section
II.
E.
2.)
In
addition,
we
have
placed
certain
restrictions
on
when
the
full
10
year
look
back
period
may
be
used.
(
See
section
II.
E.
3.)
With
regard
to
the
concern
that
industry
may
try
to
apply
the
new
requirements
retroactively
to
undo
current
restrictions
on
existing
sources,
we
want
to
reiterate
that
the
new
procedures
do
not
apply
retroactively
to
existing
NSR
permits
or
changes
that
sources
have
made
in
the
past.
Prior
applicability
determinations
on
major
modifications
and
the
control
requirements
that
currently
apply
to
sources
remain
valid
and
enforceable
and
have
to
be
adjusted
for
in
the
calculation
of
baseline
actual
emissions.
However,
as
part
of
the
transition
process
for
implementing
the
new
provisions,
we
do
intend
to
allow
permit
applicants
to
withdraw
any
permit
applications
submitted
for
review
under
the
part
52
Federal
PSD
permit
program
so
that
they
may
reevaluate
their
projects
in
light
of
the
new
requirements.
States
may
allow
for
the
same
type
of
transition
process
under
their
own
NSR
programs.
Finally,
we
considered
whether
we
should
change
the
length
of
the
look
back
period
for
EUSGUs
for
establishing
the
actual
emissions
baseline
period
to
be
consistent
with
the
10
year
look
back
period
we
are
adopting
for
other
existing
emissions
units.
The
data
we
collected
to
support
the
1992
rule
changes
show
that
allowing
EUSGUs
to
use
any
2
year
period
out
of
the
preceding
5
years
is
a
sufficient
period
of
time
to
capture
normal
business
cycles
at
an
EUSGU.
We
do
not
believe
that
any
information
received
during
the
public
comment
period
for
this
final
rule
adequately
supports
a
different
conclusion.
Thus,
we
have
decided
to
retain
the
2
in
5
years
baseline
period
for
EUSGUs.
However,
for
consistency
with
the
baseline
period
for
other
existing
emissions
units,
we
have
specified
that
the
2
year
period
is
a
consecutive
24
month
period.
2.
Why
Do
the
New
Requirements
Not
Provide
Discretion
for
the
Reviewing
Authority
To
Consider
Another
Time
Period
More
Representative
of
Normal
Operation
for
Non
EUSGUs?
Several
commenters
oppose
our
proposed
elimination
of
the
reviewing
authority's
discretion
to
allow
a
different
representative
period
(
outside
of
the
10
year
period),
because
they
argue
certain
sources
(
for
example,
emissions
units
placed
in
cold
reserve
due
to
reduced
demand)
require
this
flexibility.
Some
commenters
say
the
discretion
should
be
given
to
the
reviewing
authority,
while
other
commenters
wanted
the
discretion
given
directly
to
source
owners
and
operators.
Instead
of
the
discretion
to
use
an
alternate
period,
one
commenter
prefers
that
all
sources
should
be
required
to
show
that
they
have
selected
a
representative
period
that
precedes
the
most
recent
2
year
period.
We
believe
that
use
of
a
fixed
10
year
look
back
period
provides
the
desired
clarity
and
certainty
to
the
process
of
selecting
an
appropriate
utilization/
emissions
level
that
is
representative
of
a
source's
normal
operation.
A
bounded
10
year
look
back
provides
certainty
to
the
regulated
community
that
may
be
undermined
by
an
option
to
allow
an
unbounded
alternative
period
as
well.
3.
Why
Are
We
Placing
Restrictions
on
the
Use
of
a
10
Year
Look
Back
for
Setting
the
Baseline
Actual
Emissions?
Numerous
commenters
responded
to
our
concern
that
many
sources
might
lack
accurate
records
for
the
full
10
year
look
back
period,
and
to
our
request
for
comments
on
the
need
to
condition
the
full
use
of
the
10
year
period
upon
the
accuracy
and
completeness
of
available
data,
as
well
as
the
need
to
establish
specific
criteria
for
accuracy,
completeness,
and
recordkeeping
when
using
older
data.
A
number
of
commenters
generally
support
limiting
full
use
of
the
10
year
look
back
period
to
situations
in
which
adequate
emissions
and/
or
capacity
utilization
data
are
available.
Some
commenters
also
recommend
that
EPA
issue
minimum
criteria
to
reduce
the
number
of
case
by
case
determinations
and
help
reviewing
authorities
avoid
debates
with
sources
on
what
constitutes
sufficient
data.
On
the
other
hand,
one
commenter
recommends
that
we
not
adopt
a
variable
look
back
period
based
on
the
quality
of
the
older
data
because
it
would
``
add
considerable
uncertainty
and
protracted
debate
to
the
process.
.
.
.''
If,
however,
we
choose
to
limit
the
look
back
period
based
on
the
quality
of
older
data,
then
this
commenter
and
several
others
prefer
provisions
allowing
for
case
by
case
decisions
by
State
or
local
reviewing
authorities
over
specific
criteria
established
by
EPA.
Today's
amendments
condition
the
full
use
of
the
new
10
year
look
back
period
on
the
accuracy
and
completeness
of
your
records
of
emissions
and
capacity
utilization,
with
respect
to
the
24
month
period
you
select,
for
any
emissions
unit
that
undergoes
a
physical
or
operational
change.
See,
for
example,
new
§
52.21(
b)(
48)(
f).
As
with
all
emissions
calculations,
accuracy
and
completeness
are
central
elements
for
applicability
determinations.
In
many
cases,
sources
presently
maintain
accurate
records
on
emissions
and
operations
for
only
3
to
5
years.
Thus,
we
think
it
is
appropriate
to
limit
use
of
the
full
10
year
look
back
period
when
you
do
not
have
adequate
data
for
the
time
period
you
wish
to
select.
However,
this
limitation
should
be
alleviated
over
time
as
sources
begin
to
maintain
records
for
longer
periods
to
accommodate
the
10
year
look
back
opportunity.
We
also
agree
that
adequacy
of
any
given
data
should
be
left
to
the
case
bycase
judgment
of
individual
reviewing
authorities.
The
type
of
data
necessary
to
determine
emissions
will
vary
drastically
from
source
category
to
source
category
and
from
process
to
process
within
a
source
category.
At
this
time,
we
are
not
able
to
issue
generic
criteria
that
would
apply
to
all
types
of
industries.
We
are
further
restricting
your
use
of
the
10
year
look
back
for
emissions
units
that
are
located
in
nonattainment
areas
and
OTRs.
In
such
cases,
you
are
precluded
from
using
any
portion
of
the
10
year
look
back
that
precedes
November
15,
1990
the
date
of
the
1990
CAA
Amendments
to
establish
baseline
actual
emissions
for
those
units.
This
limit
on
the
use
of
the
10
year
look
back
is
consistent
the
intent
of
the
1996
NPRM,
which
was
originally
proposed
to
apply
to
the
use
of
the
10
year
look
back
for
any
modification
of
an
existing
facility
in
a
nonattainment
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
area
or
OTR.
See
61
FR
38259
(
July
23,
1996).
However,
because
we
are
now
beyond
the
point
where
the
November
15,
1990
limit
is
relevant
to
modifications,
we
are
only
applying
this
limitation
in
the
netting
context
with
respect
to
emissions
units
changed
within
the
contemporaneous
period.
4.
Why
Were
Changes
Made
to
the
Proposed
Approach
for
Establishing
Baseline
Actual
Emissions
Using
a
10
Year
Look
Back?
Commenters
raise
specific
questions
about
how
to
use
the
10
year
look
back
to
calculate
an
emissions
unit's
baseline
actual
emissions.
Several
commenters
are
concerned
about
how
the
utilization
rate
would
be
considered
in
the
calculation.
For
example,
some
commenters
support
the
proposal
to
allow
sources
to
use
their
highest
capacity
achieved
during
any
consecutive
12
months,
because
it
provides
improved
flexibility
in
establishing
a
capacity
level
that
is
representative
of
normal
operations.
However,
other
commenters
object
to
using
the
12
months
with
the
highest
utilization.
These
commenters
argue
that
the
use
of
production
rates
can
be
unworkable
because
there
is
not
always
a
clear
relationship
between
production
rate
and
emissions.
In
addition,
reliable
records
may
not
be
available
to
determine
the
highest
production
rates.
As
an
alternative,
commenters
suggest
using
emissions
from
any
12
month
period
in
the
preceding
10
years,
adjusted
to
reflect
current
rules,
or
allowing
the
source
to
use
any
12
month
period
of
its
choice.
A
related
issue
raised
by
commenters
is
whether
to
require
any
current
Federal,
State,
or
voluntary
limit
to
be
included
in
the
establishment
of
the
baseline
actual
emissions.
Some
commenters
say
these
provisions
would
penalize
sources
that
complied
with
other
regulatory
requirements
or
chose
to
implement
pollution
prevention
programs.
Commenters
are
particularly
concerned
that
sources
be
given
credit
for
voluntary
reductions.
However,
other
commenters
support
including
all
of
these
factors
in
the
baseline
to
better
represent
actual
emissions
and
avoid
inconsistencies
between
emissions
units
that
have
permits
and
those
that
do
not.
Commenters
also
raise
specific
questions
about
how
the
calculation
would
include
the
effect
of
other
emission
limitations.
As
described
earlier,
we
have
decided
to
require
the
use
of
a
consecutive
24
month
period
within
the
10
year
look
back
instead
of
the
proposed
12
month
period
to
calculate
the
baseline
actual
emissions
for
any
emissions
unit
that
undergoes
a
physical
or
operational
change,
or
is
affected
by
such
change.
The
longer
24
month
period
allows
you
to
reference
levels
of
utilization
achieved
in
the
past,
but
also
eliminates
the
potential
problem
associated
with
short
term
peaks
that
do
not
truly
represent
the
unit's
normal
operation.
In
this
respect,
the
use
of
a
24
month
period
is
consistent
with
the
preexisting
approach
for
calculating
actual
emissions.
With
respect
to
commenters'
concerns
about
being
required
to
use
the
period
of
highest
utilization,
our
reference
in
the
proposal
preamble
to
selecting
the
period
of
highest
utilization
was
based
on
our
general
assumption
that
the
period
of
maximum
utilization
also
represents
the
period
of
highest
pollution
levels
for
the
unit
of
concern.
However,
you
are
not
required
to
select
the
period
of
highest
utilization.
The
choice
of
which
consecutive
24
month
period
within
the
10
year
window
to
use
is
up
to
you.
The
two
restrictions
on
the
selection
of
the
appropriate
consecutive
24
month
period,
as
described
earlier,
are
the
availability
of
adequate
and
complete
source
records
for
the
unit
of
concern
and
the
limit
on
using
dates
earlier
than
November
15,
1990
for
contemporaneous
emissions
changes
in
nonattainment
areas
and
OTRs.
We
agree
with
the
concerns
expressed
by
some
commenters
that
the
baseline
actual
emissions
calculated
from
the
consecutive
24
month
period
selected
could
yield
a
higher
pollution
level
than
a
unit
is
currently
allowed
to
emit.
We
do
not
believe
that
we
should
allow
a
source
to
take
credit
for
baseline
actual
emissions
that
exceed
the
current,
legally
allowable
emissions
rate.
Consequently,
the
new
requirements
require
you
to
determine
whether
any
legally
enforceable
limitations
currently
exist
that
would
prevent
the
affected
unit
from
emitting
a
pollutant
at
the
levels
calculated
from
the
24
month
baseline
period.
The
approach
that
we
have
adopted
allows
you
to
reference
plant
capacity
that
has
actually
been
used,
but
not
pollution
levels
that
are
not
legally
allowed
at
the
time
the
modification
is
to
occur.
You
will
be
required
to
make
adjustments
for
voluntary
reductions
that
you
may
have
taken
only
to
the
extent
that
the
reductions
resulted
from
conditions
that
are
legally
enforceable
limitations.
5.
How
Does
the
Change
in
the
Baseline
Period
Affect
Related
Requirements
Regarding
Protection
of
Air
Quality?
a.
How
Does
the
Extended
Baseline
Period
Conform
With
the
Special
Modification
Provisions
Under
Sections
182(
c)
and
(
e)
of
the
Act?
Most
commenters
feel
the
proposed
extension
of
the
look
back
period
fits
within
the
design
and
intent
of
the
special
modification
procedures
set
forth
in
sections
182(
c)
and
(
e)
of
the
Act,
applicable
in
serious,
severe,
and
extreme
ozone
nonattainment
areas.
However,
one
commenter
representing
State
and
local
air
pollution
control
agencies
considers
the
new
requirements
to
be
in
significant
conflict
with
the
special
modification
procedures
contained
in
those
sections
of
the
Act.
The
commenter
indicates
that
this
conflict
could
be
resolved
by
deferring
to
relevant
requirements
for
modifications
in
serious,
severe,
and
extreme
areas.
The
commenter
adds
that
while
NSR
programs
are
tools
to
attain
and
maintain
compliance
with
the
NAAQS,
they
should
not
be
available
to
undermine
specific
statutory
and
SIP
requirements
designed
to
resolve
nonattainment
problems.
We
disagree
with
the
commenter's
concern
that
the
use
of
a
10
year
look
back
period
to
implement
sections
182(
c)
and
(
e)
of
the
Act
for
purposes
of
establishing
a
modified
unit's
baseline
emissions
will
undermine
any
statutory
or
SIP
requirements
designed
to
address
nonattainment
problems.
The
two
sections
establish
special
procedures
for
determining
whether
a
proposed
modification
of
a
major
stationary
source
of
ozone
in
a
serious,
severe,
or
extreme
ozone
nonattainment
area
will
be
subject
to
major
NSR
under
part
D
of
the
Act.
The
Act
is
silent
on
the
issue
of
how
one
is
to
determine
whether
a
physical
or
operational
change
increases
the
amount
of
a
pollutant
for
a
changed
emissions
unit.
We
believe,
therefore,
that
we
have
the
authority
to
establish
a
regulatory
procedure
for
making
the
required
determinations
concerning
emissions
increases
resulting
from
physical
or
operational
changes.
In
light
of
the
fact
that
the
10
year
look
back
period
may
be
used
for
emissions
units
(
other
than
EUSGUs)
that
are
involved
in
contemporaneous
emissions
changes
(
for
netting
purposes),
it
should
be
noted
that
the
new
requirements
prohibit
the
use
of
the
look
back
period
earlier
than
November
15,
1990.
Consequently,
for
emissions
units
whose
contemporaneous
emissions
changes
occurred
before
November
15,
2000,
the
consecutive
24
month
period
selected
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Federal
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
24
Guidance
for
modeling
NAAQS
compliance
under
the
PSD
program
is
set
forth
in
EPA's
Guideline
on
Air
Quality
Models
contained
in
appendix
W
of
40
CFR
part
51.
This
guidance
is
incorporated
by
reference
both
in
the
Federal
PSD
regulations
and
in
the
minimum
requirements
for
SIPs
under
the
part
51
PSD
regulations.
for
calculating
the
baseline
actual
emissions
relevant
to
the
contemporaneous
emissions
change
cannot
include
a
date
prior
to
November
15,
1990.
It
should
be
pointed
out,
however,
that
for
modifications
involving
emissions
of
volatile
organic
compounds
(
VOC)
in
areas
classified
as
``
extreme,''
the
statutory
language
is
clear
that
the
increase
in
emissions
resulting
from
the
change
is
not
required
to
be
a
significant
increase,
but
rather
that
``
any
increase''
that
is
projected
using
the
new
actual
toprojected
actual
applicability
test
will
trigger
the
applicable
NSR
requirements.
b.
Will
the
Longer
Look
Back
Period
Related
to
the
Baseline
Actual
Emissions
Protect
Short
term
Increments
and
NAAQS?
Some
commenters
express
concerns
that
the
opportunity
to
take
credit
for
older
baseline
actual
emissions
would
result
in
adverse
environmental
consequences.
One
commenter
specifically
indicates
that
the
proposed
baseline
actual
emissions
determination
process,
involving
a
10
year
look
back,
would
allow
significant
increases
in
emissions
to
escape
the
ambient
impact
review
requirements
otherwise
required
by
NSR.
Today's
new
rule
modifies
the
way
your
NSR
applicability
determinations
are
made
for
changes
made
to
existing
emissions
units.
The
new
rule
does
not
affect
the
way
in
which
a
source's
ambient
air
quality
impacts
are
evaluated.
Compliance
with
the
NAAQS
is
accomplished
with
air
quality
dispersion
models
using
maximum
allowable
emission
limitations
(
or
federally
enforceable
permit
limits)
combined
with
operating
factors,
which
consider
either
design
capacity
or
actual
operating
factors
averaged
over
the
most
recent
2
years
of
operation,
from
all
modeled
sources.
24
In
addition,
any
increase
in
actual
emissions,
based
on
the
existing
definition
of
``
actual
emissions,''
consumes
PSD
increment
whether
it
occurs
through
normal
source
operation
or
as
a
result
of
a
physical
or
operational
change.
As
mentioned
earlier,
the
existing
definition
of
``
actual
emissions''
continues
to
apply
with
regard
to
all
NSR
requirements
other
than
the
new
source
applicability
tests.
See,
for
example,
new
§
52.21(
b)(
21)(
i).
Thus,
we
do
not
believe
there
is
a
basis
for
concluding
that
the
use
of
a
longer
look
back
period
for
determining
a
modified
emissions
unit's
baseline
actual
emissions
(
for
purposes
of
determining
whether
a
physical
or
operational
change
will
result
in
a
significant
emissions
increase)
will
cause
any
adverse
environmental
impacts.
6.
Why
Was
the
Contemporaneous
Period
for
Netting
Not
Also
Changed
to
a
10
Year
Look
Back
Period?
In
the
1996
NPRM,
we
indicated
that
we
were
not
proposing
to
extend
the
5
year
contemporaneous
period
along
with
the
proposed
10
year
look
back
period
associated
with
the
establishment
of
baseline
actual
emissions.
See
61
FR
38259
(
July
23,
1996).
We
did,
however,
solicit
comments
on
the
effect
of
the
differing
look
back
periods
and
any
reasons
why
these
periods
should
be
the
same.
Commenters
responded
in
a
variety
of
ways
to
our
request,
with
no
clear
consensus
as
to
whether
it
would
be
appropriate
to
establish
a
uniform
look
back
period.
One
commenter
supports
the
10
year
contemporaneous
period
for
reasons
of
consistency.
Other
commenters
believe
that
it
was
reasonable
to
use
two
different
time
frames.
Some
commenters
support
retaining
the
5
year
contemporaneous
period
because
changing
it
could
have
adverse
effects
on
existing
permit
determinations.
Several
commenters
support
the
selection
of
a
different
contemporaneous
time
frame
than
the
existing
5
year
period,
but
they
differ
in
their
recommendations
for
changing
it.
One
suggests
giving
the
source
the
option
of
choosing
either
a
10
year
or
5
year
contemporaneous
period.
Another
commenter
believes
that
a
1
year
period
would
reduce
confusion.
Finally,
another
commenter
proposes
a
5
year
contemporaneous
period
that
would
not
mandate
that
5
consecutive
years
be
considered.
We
do
not
believe
that
there
is
a
compelling
reason
to
change
the
existing
5
year
contemporaneous
period.
The
look
back
periods
serve
different
purposes
and
need
not
be
the
same
in
order
to
effectively
implement
the
NSR
program
objectives.
States
retain
the
flexibility
in
defining
a
different
contemporaneous
period
under
SIP
approved
NSR
programs,
and
may
use
that
flexibility
to
adjust
the
contemporaneous
period
if
they
believe
that
a
different
period
is
more
appropriate
for
their
purposes
under
the
new
applicability
requirements.
See,
for
example,
§
51.166(
b)(
3)(
ii).
Therefore,
under
today's
new
requirements,
we
have
not
changed
the
5
year
contemporaneous
period
under
the
Federal
PSD
program.
It
should
be
noted
that
for
purposes
of
determining
the
baseline
actual
emissions
of
a
contemporaneous
change
in
emissions
from
an
emissions
unit
that
was
an
existing
unit
at
the
time
of
the
contemporaneous
change,
the
new
requirements
authorize
a
source
to
use
the
10
year
look
back
period.
7.
Why
Was
the
Demand
Growth
Exclusion
Retained?
When
we
proposed
to
expand
the
scope
of
the
WEPCO
rulemaking
to
cover
modifications
at
any
existing
emissions
unit,
we
solicited
comment
on
whether
the
demand
growth
exclusion
(
currently
available
only
to
EUSGUs)
should
also
be
available
to
all
source
categories.
In
1998,
we
noted
that
there
were
problems
that
could
arise
with
the
demand
growth
exclusion.
63
FR
39860
39861
(
July
24,
1998).
Accordingly,
we
solicited
comment
on
this
new
position.
Several
regulatory
agency
and
environmental
commenters
support
the
total
elimination
of
the
demand
growth
exclusion.
These
commenters
maintain
that
a
facility's
post
change
emissions
increases
due
to
demand
growth
could
not
be
disassociated
from
those
that
resulted
directly
from
the
physical
or
operational
change.
These
commenters
believe
the
demand
growth
exclusion
would
be
difficult
to
enforce.
The
demand
growth
exclusion
would,
they
claim,
also
be
burdensome
because
it
would
require
projections,
estimates,
and
post
modification
evaluations
of
increased
emissions
to
determine
whether
the
increases
were
the
result
of
increased
demand.
On
the
other
hand,
numerous
industry
commenters
oppose
eliminating
the
demand
growth
provisions,
stating
that
market
factors
do
independently
cause
emissions
increases
absent
physical
and
operational
changes.
These
commenters
maintain
that
when
projected
increased
capacity
utilization
is
in
response
to
an
independent
factor,
such
as
demand
growth,
the
increased
utilization
cannot
be
said
to
result
from
the
change
and
therefore
may
rightfully
be
excluded
from
the
projection
of
the
emissions
unit's
future
actual
emissions.
They
further
argue
that
such
increases
should
not
be
included
in
post
change
emissions
even
in
the
absence
of
a
demand
growth
exclusion,
as
the
increases
would
not
be
the
result
of
the
physical
or
operational
changes
that
were
made.
Consequently,
these
commenters
state
that
the
proposed
demand
growth
exclusion
simply
makes
that
principle
explicit
and
eliminates
confusion
as
to
how
emissions
should
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
be
calculated.
The
same
commenters
who
support
retaining
demand
growth
provisions
for
utilities
also
believe
these
provisions
should
be
extended
to
nonutilities
Under
today's
new
requirements,
you
will
be
allowed
to
apply
the
causation
provision
as
originally
contained
in
the
WEPCO
amendments.
Both
the
statute
and
implementing
regulations
indicate
that
there
should
be
a
causal
link
between
the
proposed
change
and
any
post
change
increase
in
emissions,
that
is,
``*
*
*
any
physical
change
or
change
in
the
method
of
operation
that
would
result
in
a
significant
net
emissions
increase
*
*
*''
[
emphasis
added].
See,
for
example,
existing
§
52.21(
b)(
2)(
i).
Consequently,
under
today's
new
rules,
when
a
projected
increase
in
equipment
utilization
is
in
response
to
a
factor
such
as
growth
in
market
demand,
you
may
subtract
the
emissions
increases
from
the
unit's
projected
actual
emissions
if:
(
1)
The
unit
could
have
achieved
the
necessary
level
of
utilization
during
the
consecutive
24
month
period
you
selected
to
establish
the
baseline
actual
emissions;
and
(
2)
the
increase
is
not
related
to
the
physical
or
operational
change(
s)
made
to
the
unit.
See
for
example,
new
§
52.21(
b)(
41)(
ii)(
c).
On
the
other
hand,
demand
growth
can
only
be
excluded
to
the
extent
that
the
physical
or
operational
change
is
not
related
to
the
emissions
increase.
Thus,
even
if
the
operation
of
an
emissions
unit
to
meet
a
particular
level
of
demand
could
have
been
accomplished
during
the
representative
baseline
period,
but
the
increase
is
related
to
the
changes
made
to
the
unit,
then
the
emissions
increases
resulting
from
the
increased
operation
must
be
attributed
to
the
project,
and
cannot
be
subtracted
from
the
projection
of
projected
actual
emissions.
8.
Should
Increases
in
Plant
Utilization
Be
Reviewed
as
Potential
Major
Modifications?
Many
commenters
argue
that
emissions
increases
resulting
from
increased
utilization
should
not
be
subjected
to
review
as
major
modifications.
They
insist
that
EPA's
policy
and
rules
have
always
allowed
increases
in
capacity
utilization
without
triggering
a
modification,
and
not
allowing
utilization
increases
will
limit
new
capacity
to
new
emissions
units
instead
of
promoting
increased
efficiency
at
existing
emissions
units.
One
commenter
argues
that
these
sorts
of
changes
do
not
require
any
sort
of
applicability
determination
and
that
Congress
never
anticipated
that
the
NSR
program
would
hamper
a
source's
ability
to
increase
utilization
up
to
the
original
design
capacity.
We
believe
that
an
increase
in
utilization
should
not
trigger
the
major
NSR
requirements
unless
it
is
related
to
a
physical
or
operational
change.
As
explained
earlier,
the
CAA
only
applies
the
major
NSR
requirements
to
emissions
increases
that
are
the
result
of
a
physical
or
operational
change.
Thus,
we
do
not
believe
that
the
major
NSR
requirements
should
apply
to
a
utilization
increase
unless
the
increase
is
related
to
the
modification.
Under
today's
final
rules,
you
may
exclude
emissions
related
to
an
increase
in
utilization
if
you
were
able
to
accommodate
the
increase
in
utilization
during
the
24
month
period
you
select
to
establish
your
baseline
actual
emissions
and
the
increased
utilization
is
not
related
to
the
change.
9.
Why
Must
You
Track
Physical
or
Operational
Changes
That
Increase
a
Unit's
Design
Capacity
or
Potential
To
Emit
Post
Change
Actual
Emissions
for
a
Longer
Period
of
Time?
We
raised
this
issue
in
the
1998
NOA.
Several
commenters
support
applying
what
we
then
termed
the
``
actual
toenforceable
future
actual''
test
to
increases
in
design
capacity
or
PTE
because
it
would
be
inappropriate
to
automatically
assume
that
such
increases
will
affect
normal
operations,
which
would
require
the
actual
topotential
test.
They
say
that
these
types
of
modifications
are
common
and
do
not
generally
increase
emissions
because
they
improve
efficiency
and
add
control
devices.
One
commenter
explains
that
it
is
not
uncommon
for
an
emissions
unit's
capacity
to
be
increased
so
as
to
speed
up
normal
operations
without
increasing
production,
and
that
projected
actual
emissions
could
easily
be
calculated
on
the
basis
of
past
operating
experience.
On
the
other
hand,
another
commenter
indicates
that
it
is
very
expensive
to
increase
design
capacity.
Therefore,
it
can
be
assumed
that
a
company
would
use
the
additional
capacity
as
soon
as
it
becomes
available.
Several
regulatory
agency
commenters
support
the
use
of
the
actual
topotential
test
for
modifications
that
increase
design
capacity
or
PTE.
One
of
these
commenters
stated
that
such
modifications
would
alter
an
emissions
unit's
normal
operation
and
make
previous
actual
emissions
``
unreliable
and
irrelevant.''
We
do
not
believe
that
every
modification
that
includes
added
capacity
or
an
increase
in
the
PTE
is
intended
for
full
use
of
that
new
capacity
or
PTE.
Such
actions
could
well
be
intended
to
enhance
current
operations
without
resulting
in
increased
production
or
operation.
Therefore,
under
today's
new
requirements,
you
are
not
required
to
count
the
emissions
increase
that
would
result
from
full
use
of
new
capacity
or
PTE
if
you
conclude
that:
(
1)
Such
capacity
or
PTE
will
not
be
fully
utilized,
and
(
2)
the
emissions
increase
resulting
from
that
portion
of
the
capacity
that
will
be
used
will
not
result
in
a
significant
emissions
increase
from
the
modification
or
a
significant
net
emissions
increase
at
the
source.
The
new
requirements
include
a
provision
that
requires
you
to
monitor
the
emissions
from
the
project
for
10
years
following
the
resumption
of
regular
operation
of
the
emissions
units
modified.
The
10
year
period
reflects
our
determination
that
this
time
frame
best
captures
the
normal
business
cycle
for
industry
in
general.
Thus,
in
situations
where
your
proposed
project
will
in
fact
add
new
capacity
or
PTE
to
an
existing
emissions
unit,
yet
you
determine
that
the
objective
of
the
physical
or
operational
change
is
not
to
use
the
increased
capacity,
your
calculation
of
representative
projected
actual
emissions
may
reflect
this.
However,
you
must
maintain
adequate
information
for
10
years
following
the
completion
of
the
project
to
track
the
actual
annual
emissions
from
the
units
associated
with
the
project.
This
represents
a
special
condition
that
supersedes
the
normal
5
year
period
for
the
recordkeeping
requirements
being
adopted
today.
During
the
10
year
period,
you
must
report
to
your
reviewing
authority
within
60
days
after
any
year
if
the
annual
emissions,
in
tpy,
from
the
project
exceed
the
baseline
actual
emissions
by
a
significant
amount
for
the
regulated
NSR
pollutant
and
if
such
emissions
differ
from
the
preconstruction
projection.
10.
Does
the
Actual
To
Projected
Actual
Applicability
Test
Apply
to
Netting?
We
did
not
specifically
request
comment
on
this
issue
in
the
1996
proposal.
Nonetheless,
we
received
several
comments
that
assert
that
use
of
different
methods
to
compute
an
emissions
increase
and
determine
a
net
emissions
increase
would
result
in
``
absurd
results''
and
require
two
separate
accounting
records.
Other
commenters
oppose
using
the
actual
tofuture
actual
test
for
netting.
One
commenter
says
that
the
sole
purpose
of
the
actual
to
future
actual
test
was
to
determine
if
an
emissions
increase
will
occur.
One
commenter
says
we
should
go
further
and
revise
the
definition
of
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Regulations
25
Information
supporting
these
values
can
be
found
in
the
docket
for
today's
rulemaking.
``
contemporaneous''
to
limit
it
to
project
activities
(
vs.
plantwide)
and
reduce
credits
for
shutdowns
and
curtailments.
As
stated
previously,
we
did
not
specifically
request
comment
on
this
issue
and
we
are
not
promulgating
amendments
to
the
netting
regulations,
on
this
point,
at
this
time.
11.
Should
We
Impose
an
Enforceable
Projected
Actual
Emissions
Level?
Some
commenters
on
our
1996
proposal
support
the
establishment
of
an
enforceable
limitation
on
the
modified
source's
projected
future
emissions
level.
Other
commenters
support
our
specific
proposal
in
the
1998
NOA
to
use
the
projected
actual
emissions
as
a
temporary
cap
for
the
emissions
units
involved
in
the
project,
that
is,
an
enforceable
10
year
emissions
level.
On
the
other
hand,
many
other
commenters
oppose
the
concept,
citing
various
reasons
for
their
opposition.
These
included
concerns
that
it
would
become
a
de
facto
baseline
for
any
additional
permitting
and
create
additional
enforcement
liability,
usurp
State
prerogatives,
be
inconsistent
with
the
CAA,
and
require
enforceable
restrictions
for
too
long.
A
few
State
and
local
air
reviewing
agencies
indicate
that
they
do
not
have
the
resources
to
adequately
administer
a
program
that
would
require
permits
to
be
issued
for
every
physical
or
operational
change
at
a
major
stationary
source.
Today's
new
requirements
follow
the
1996
proposal.
You
will
not
be
required
to
make
the
projected
actual
emissions
projection
through
a
permitting
action.
After
considering
the
comments
received,
we
are
concerned
that
such
a
requirement
may
place
an
unmanageable
resource
burden
on
reviewing
authorities.
We
also
believe
that
it
is
not
necessary
to
make
your
future
projections
enforceable
in
order
to
adequately
enforce
the
major
NSR
requirements.
The
Act
provides
ample
authority
to
enforce
the
major
NSR
requirements
if
your
physical
or
operational
change
results
in
a
significant
net
emissions
increase
at
your
major
stationary
source.
12.
Why
Are
Modified
Sources
That
Are
Not
Considered
Major
Modifications
Not
Required
To
Submit
Annual
Reports
of
Actual
Emissions
Under
the
New
Requirements?
Several
commenters
support
our
proposal
to
require
sources
to
track
post
change
emissions
for
a
5
year
period
so
that
there
is
a
factual
finding
as
to
whether
emissions
from
the
modified
units
actually
increased.
These
commenters
believe
that
the
requirement
to
track
emissions
is
a
needed
safeguard
and
that
it
should
not
be
too
difficult
to
track
various
operating
parameters.
They
add
that
non
utilities
should
be
able
to
track
emissions
as
well
as
utilities.
Finally,
commenters
who
oppose
the
proposed
10
year
enforceable
limit
support
retaining
the
5
year
tracking
period
in
its
place.
Many
other
commenters
object
to
the
burden
that
tracking
would
impose
in
the
absence
of
any
additional
environmental
benefit.
Some
commenters
suggest
ways
to
reduce
the
burden,
such
as
not
requiring
sources
to
report
emissions
unless
there
is
a
problem
or
reducing
the
tracking
period
to
2
or
3
years.
Another
industry
commenter
suggests
that
we
require
an
up
front
notification
to
the
reviewing
authority
whenever
the
actual
to
futureactual
applicability
test
is
used.
We
agree
with
those
commenters
who
recommend
that
you
should
be
required
to
track
emissions
for
a
period
of
time
following
a
modification.
Thus,
we
have
retained
our
proposed
requirement
to
maintain
annual
emissions
information
for
a
period
of
5
years
following
resumption
of
regular
operations
after
the
change.
As
discussed
previously,
we
expanded
this
requirement
to
10
years
for
changes
that
increase
an
emissions
unit's
capacity
or
its
potential
to
emit
a
regulated
NSR
pollutant.
However,
although
we
proposed
a
requirement
for
annual
emissions
reporting,
we
have
concluded
that
the
combination
of
the
recordkeeping
requirements
of
this
rule,
along
with
a
requirement
to
report
to
the
reviewing
authority
any
annual
emissions
that
exceed
your
baseline
actual
emissions
by
a
significant
amount
for
the
regulated
NSR
pollutant
and
differ
from
your
preconstruction
projection,
is
an
equally
effective
way
to
ensure
that
a
reviewing
authority
can
receive
the
information
necessary
to
enforce
the
major
NSR
requirements.
Moreover,
your
reviewing
authority
has
the
authority
to
request
emissions
information
from
you
at
any
time
to
determine
the
status
of
your
post
change
emissions.
In
response
to
the
concern
that
these
requirements
might
impose
unnecessary
burdens,
we
have
also
included
further
limits.
First,
you
are
only
required
to
keep
records
if
you
elect
to
use
the
actual
to
projected
actual
applicability
test
to
calculate
your
emissions
increase
from
the
project.
Second,
you
are
only
required
to
keep
the
records
if
there
is
a
reasonable
possibility
that
your
project
might
result
in
a
significant
emissions
increase.
Finally,
you
only
need
keep
those
records
for
projects
that
are
not
major
modifications.
We
also
considered
requiring
you
to
submit
an
up
front
notification
to
your
reviewing
authority,
but
concluded
that
this
would
result
in
an
unnecessary
paperwork
burden.
(
EUSGUs,
however,
will
be
required
to
submit
a
copy
of
their
projections
to
reviewing
authorities
before
beginning
actual
construction.)
We
anticipate
that
a
large
majority
of
the
projects
that
are
not
major
modifications
may
nonetheless
be
required
to
undergo
a
permit
action
through
States'
minor
NSR
permit
programs.
In
such
cases,
the
minor
NSR
permitting
procedures
could
provide
an
opportunity
to
ensure
that
your
reviewing
authority
agrees
with
your
emission
projections.
Requiring
a
separate
notification
would
not
provide
the
reviewing
authority
with
any
additional
information
in
such
circumstances.
Accordingly,
we
believe
today's
requirements
provide
reviewing
agencies
with
the
ability
to
obtain
all
the
information
necessary
to
ensure
compliance.
13.
Why
Are
We
Promulgating
Different
Reporting
Requirements
for
Existing
Emissions
Units
Than
for
EUSGUs?
Today
we
are
finalizing
slightly
different
requirements
for
EUSGUs
than
other
industries.
In
2000,
boilers
and
turbines
with
greater
than
25
MWe
or
250
mmBTU/
hr
of
generating
capacity
represented
76
percent
of
this
nation's
emissions
of
nitrogen
oxides
(
NOX)
and
85
percent
of
this
nation's
emissions
of
SO2
from
stationary
sources.
25
In
view
of
the
disproportionate
amount
of
emissions
generated
by
EUSGUs
compared
to
other
industry
sectors,
we
believe
that
it
is
appropriate
for
reviewing
authorities
to
have
information
on
construction
and
modification
activities
at
EUSGUs
readily
available.
Accordingly,
we
are
requiring
EUSGUs
to
provide
a
copy
of
their
emissions
projection
to
the
reviewing
authority
before
beginning
actual
construction
of
a
project.
We
are
also
requiring
them
to
report
their
postchange
annual
emissions
for
every
year
they
are
required
to
generate
them.
This
approach
also
makes
sense
because
it
focuses
the
limited
resources
of
both
sources
and
agencies
on
the
sources
that
matter
most.
III.
CMA
Exhibit
B
In
addition
to
the
proposed
changes
based
on
the
1992
WEPCO
amendments
(
see
section
II
of
this
preamble),
the
1996
proposal
package
included
alternative
regulatory
language
that
would
enable
you
to
determine
whether
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your
facility
has
undertaken
a
modification
based
on
the
facility's
prechange
and
post
change
potential
emissions
instead
of
its
actual
emissions.
This
action
was
part
of
the
settlement
of
a
challenge
to
our
1980
NSR
regulations
by
CMA
and
other
industry
petitioners.
The
exact
language
we
proposed
was
set
forth
in
Exhibit
B
to
the
Settlement
Agreement,
which
is
contained
in
the
docket
for
this
rulemaking.
Under
this
method,
sources
may
calculate
emissions
increases
and
decreases
based
on
the
actual
emissions
method
or
the
unit's
pre
change
and
post
change
potential
emissions,
measured
in
terms
of
hourly
emissions
(
that
is,
pounds
of
pollutant
per
hour).
Sources
could
use
this
potential
topotential
test
for
NSR
applicability,
as
well
as
for
calculating
offsets,
netting
credits,
and
other
ERCs.
We
proposed
to
make
several
changes
to
the
NSR
regulations.
First,
we
proposed
to
add
the
following
exclusion
to
the
definition
of
``
major
modification'':
A
major
modification
shall
be
deemed
not
to
occur
if
one
of
the
following
occurs:
(
a)
there
is
no
significant
net
increase
in
the
source's
PTE
(
as
calculated
in
terms
of
pounds
of
pollutant
emitted
per
hour);
or
(
b)
there
is
no
significant
net
increase
in
the
source's
actual
emissions.
Second,
we
proposed
to
delete
all
references
to
``
actual
emissions''
in
the
definition
of
``
net
emissions
increase''
and
added
language
indicating
that
all
references
to
``
increase
in
emissions''
and
``
decreases
in
emissions''
in
the
definition
of
``
net
emissions
increases''
``
shall
refer
to
changes
in
the
source's
PTE
(
as
calculated
in
terms
of
pounds
of
pollutant
emitted
per
hour)
or
in
its
actual
emissions.''
Third,
we
proposed
to
modify
the
applicability
baseline
by
eliminating
the
reference
to
the
2
year
baseline
period
and
to
a
method
for
determining
actual
emissions
during
the
representative
period.
Finally,
we
proposed
to
provide
express
authorization
for
sources
to
use
potential
emissions
in
calculating
offsets
and
in
creating
ERCs.
We
also
indicated
in
the
preamble
for
the
1996
proposed
rulemaking
that
if
we
promulgated
the
Exhibit
B
settlement
as
a
final
rule,
the
Exhibit
B
rules
would
need
to
be
updated
to
reflect
other
rule
changes
since
1980,
as
well
as
relevant
provisions
of
the
1990
Amendments.
Before
proposing
the
Exhibit
B
language,
we
did
a
preliminary
analysis
of
the
impact
on
the
NSR
program
of
the
Exhibit
B
changes.
These
changes
would
provide
maximum
flexibility
to
existing
facilities
with
respect
to
determining
if
a
significant
net
emissions
increase
would
result
from
a
physical
or
operational
change.
However,
we
also
expressed
concern
about
the
environmental
consequences
associated
with
the
Exhibit
B
provisions.
For
one,
you
could
modernize
your
aging
facilities
(
restoring
lost
efficiency
and
reliability
while
lowering
operating
costs)
without
undergoing
preconstruction
review,
while
increasing
annual
pollution
levels
as
long
as
hourly
potential
emissions
did
not
change.
Also,
Exhibit
B
would
allow
your
facilities
to
generate
netting
credits
and
ERCs
for
offsets
based
on
potential
hourly
emissions,
even
if
never
actually
emitted.
This
could
sanction
greater
actual
emissions
increases
to
the
environment,
often
from
older
facilities,
without
any
preconstruction
review.
In
addition,
actual
emissions
increases
resulting
from
unreviewed
projects
could
go
largely
undocumented
until
a
PSD
review
is
performed
by
a
new
or
modified
facility
that
ultimately
must
undergo
review.
By
that
time,
however,
a
violation
of
an
increment
could
have
unknowingly
occurred.
We
were
also
concerned
that
Exhibit
B
would
ultimately
stymie
major
new
source
growth
by
allowing
unreviewed
increases
of
emissions
from
modifications
of
existing
sources
to
consume
all
available
increment
in
PSD
areas.
In
our
analysis
supporting
the
1996
proposal,
we
were
unable
to
reach
any
conclusions
as
to
the
magnitude
of
any
environmental
impacts
beyond
noting
that
the
effects
would
vary
from
State
to
State
depending
on
how
much
cumulative
difference
exists
between
the
unused
potential
emissions
and
actual
emissions
in
a
given
inventory
of
sources
and
on
the
extent
to
which
any
unused
potential
emissions
have
been
used
in
attainment
demonstrations.
However,
our
analysis
did
show
that
typical
source
operation
frequently
does
result
in
actual
emissions
that
are
below
allowable
emission
levels.
We
received
many
comments
in
response
to
the
1996
proposal
regarding
CMA
Exhibit
B.
Some
commenters
believe
the
potential
to
potential
test
appropriately
focuses
on
the
significant
emissions
changes
that
could
produce
an
adverse
environmental
impact.
Several
other
commenters
believe
that
a
potential
to
potential
test
would
be
environmentally
detrimental.
These
commenters
believe
that
CMA
Exhibit
B
represents
a
substantial
weakening
of
the
PSD
program
with
large
increases
in
actual
emissions,
which
in
itself
could
lead
to
a
significant
deterioration
of
air
quality.
They
also
express
concerns
regarding
the
creation
of
paper
credits
and
other
impacts
on
the
broader
air
quality
planning
process.
One
commenter
states
that
the
potential
topotential
test
would
conflict
with
SIPs
that
are
based
on
actual
emissions,
threaten
a
State's
efforts
to
make
reasonable
further
progress
(
RFP)
demonstrations,
and
interfere
with
emission
credits
relied
on
by
SIPs.
These
commenters
also
cite
the
following
concerns.
The
potential
to
potential
test
would
allow
sources
to
escape
the
major
modification
provisions
and
could
virtually
eliminate
NSR
in
most
modification
cases.
Once
a
facility
has
proceeded
without
NSR
based
on
actual
emissions,
it
would
be
difficult
to
take
an
enforcement
action
years
later
that
would
successfully
require
that
facility
to
retrofit
LAER
and
obtain
offsets
retrospectively.
We
agree
that
a
potential
to
potential
test
for
major
NSR
applicability
could
lead
to
unreviewed
increases
in
emissions
that
would
be
detrimental
to
air
quality
and
could
make
it
difficult
to
implement
the
statutory
requirements
for
state
of
the
art
controls.
After
consideration,
we
believe
some
of
the
comments
in
support
of
Exhibit
B
have
merit.
As
noted
by
commenters
who
supported
the
CMA
Exhibit
B
proposal,
a
potential
to
potential
test
could
simplify
and
improve
the
NSR
process.
According
to
commenters,
the
CMA
Exhibit
B
approach
would
have
the
following
benefits.
Limit
the
scope
of
the
program
to
encompass
only
those
significant
physical
changes
that
Congress
intended
to
cover
Reduce
unnecessary
NSR
costs
and
delays
and
improve
compliance
and
enforcement
Lower
the
cost
of
the
NSR
process
by
reducing
the
complexity
of
the
NSR
applicability
determinations
Facilitate
applicability
decisions
at
the
plant
level
The
commenters
also
say
that
the
CMA
Exhibit
B
approach
is
more
equitable
than
the
existing
actual
topotential
approach,
which
results
in
the
capture
of
a
source's
unused
capacity.
These
commenters
prefer
the
potentialto
potential
test
because
it
would
allow
utilization
increases.
This
provision
is
especially
useful
for
sources
in
cyclical
industries
where
using
existing
capacity
is
critical.
Sources
in
sectors
where
utilization
and
demand
are
closely
related
would
also
benefit.
Our
own
concerns,
coupled
with
the
concerns
expressed
by
some
commenters,
have
caused
us
to
reject
the
use
of
the
Exhibit
B
regulatory
changes
for
general
purposes
of
determining
whether
a
proposed
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26
In
our
1996
proposal
we
used
the
term
``
actual
emissions,''
while
today
we
are
using
the
term
``
baseline
actual
emissions.''
This
change
in
terminology
is
consistent
with
the
regulatory
changes
discussed
in
section
II
of
today's
preamble.
Despite
this
change
in
terminology,
there
may
be
places
in
this
section
of
the
preamble
where
we
still
use
the
phrase
``
actual
emissions.''
In
such
cases
we
are
either
discussing
PALs
established
under
the
old
regulatory
provisions,
or
summarizing
and
responding
to
comments
received
on
the
1996
proposal.
27
Under
our
current
NSR
program,
you
can
make
physical
changes
or
changes
in
the
method
of
operation
without
triggering
major
NSR
applicability,
provided
the
individual
changes
do
not
result
in
significant
net
emissions
increases.
We
have
interpreted
this
requirement
to
permit
you
to
make
unrelated
changes
that,
standing
alone,
do
not
result
in
significant
emissions
increases
and
to
allow
such
changes
to
occur
without
considering
whether
other
contemporaneous
emissions
increases
render
the
change
significant.
Over
time
you
could
undertake
numerous
unrelated
projects
without
triggering
major
NSR,
provided
the
individual
projects
did
not
increase
emissions
by
a
significant
amount,
thus
allowing
source
wide
emissions
to
increase
over
time
without
requiring
any
emissions
controls
for
these
individual
projects.
For
example,
a
large
chemical
plant
that
is
located
in
an
ozone
attainment
area
adds
a
new
product
line
in
2001
and
properly
avoids
PSD
(
including
the
BACT
requirement)
by
limiting
the
VOC
emissions
increase
to
39
tpy.
Later,
in
2003
the
plant
adds
a
different
product
line
and
also
properly
avoids
PSD
by
limiting
VOC
emissions
from
the
new
line
to
39
tpy.
For
this
example,
two
process
lines
at
the
same
plant
with
total
potential
emissions
(
78
tpy)
above
the
40
tpy
VOC
significant
level
under
PSD
were
properly
permitted
over
a
3
year
period
without
BACT
applying
to
either
new
product
line.
physical
or
operational
change
would
result
in
a
major
modification.
For
the
reasons
stated
above,
we
do
not
believe
that
a
potential
to
potential
approach
is
acceptable
for
major
NSR
applicability
as
a
general
matter.
However,
we
agree
with
the
commenters
in
part
some
of
the
benefits
of
a
potential
to
potential
approach
are
desirable.
We
believe
that
in
more
limited
circumstances
a
``
potential
to
potential''
like
approach
would
be
acceptable.
Therefore,
we
are
promulgating
two
new
applicability
provisions
that
capture
the
benefits
of
a
potential
to
potential
approach
but
still
have
the
necessary
safeguards
to
ensure
environmental
protection
PALs,
and
the
Clean
Unit
Test.
Today's
rules
provide
for
a
PAL
based
on
plantwide
actual
emissions.
If
you
keep
the
emissions
from
your
facility
below
a
plantwide
actual
emissions
cap,
then
you
need
not
evaluate
whether
each
change
might
be
subject
to
the
major
NSR
permitting
when
you
make
alterations
to
the
facility
or
individual
emissions
units.
The
cumulative
actual
emissions
become
the
de
facto
potential
emissions
for
the
plant,
and
you
may
emit
up
to
the
permitted
level
without
going
through
major
NSR,
even
if
you
are
making
changes
to
the
facility.
The
PAL
allows
you
to
make
changes
quickly
by
allowing
you
to
alter
your
facility
without
first
going
through
major
NSR
review.
It
thus
limits
the
number
and
complexity
of
NSR
applicability
determinations,
and
reduces
unnecessary
costs
and
delays.
It
also
allows
a
plant
manager
to
authorize
changes,
as
long
as
the
emissions
remain
under
the
permitted
level,
without
first
obtaining
reviewing
authority
review.
Furthermore,
it
provides
an
incentive
to
use
state
of
theart
controls
and
install
new,
lower
emitting
equipment,
which
will
allow
sources
to
increase
utilization.
In
return
for
the
flexibility
a
PAL
allows,
you
must
monitor
emissions
from
all
of
your
emissions
units
under
the
PAL.
Therefore,
the
PAL
ensures
good
controls
and
protection
of
air
quality.
We
believe
there
are
other
mechanisms
for
establishing
PALs
that
would
achieve
beneficial
results.
For
example,
we
believe
PALs
based
on
allowable
emissions
would
produce
flexibility
and
assure
environmental
protection,
provided
affected
sources
had
adequate
safeguards.
Therefore,
we
intend
in
the
near
future
to
propose
a
rule
that
would
adopt
PALs
based
on
allowable
emissions.
Analogous
to
what
the
PAL
does
for
facilities,
the
Clean
Unit
Test
sets
emission
limitations
or
work
practice
requirements
in
conjunction
with
BACT,
LAER,
or
Clean
Unit
determinations
and
identifies
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT,
LAER,
or
Clean
Unit
determination
for
a
particular
unit.
The
Clean
Unit
Test
recognizes
that
if
you
go
through
major
NSR
review
(
including
air
quality
review)
and
install
BACT
or
LAER
or
comparable
technology,
then
you
may
make
any
subsequent
changes
to
the
Clean
Unit
without
triggering
an
additional
major
NSR
review,
as
long
as
there
is
no
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
were
adopted
in
conjunction
with
BACT,
LAER,
or
Clean
Unit
determination
or
to
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT,
LAER,
or
Clean
Unit
determination.
Therefore,
for
Clean
Units,
given
that
the
permit
is
based
on
a
determination
that
is
protective
of
air
quality,
the
new
test
would
deem
there
is
no
emissions
increase
as
a
result
of
any
physical
change
or
change
in
the
method
of
operation.
With
these
provisions,
sources
will
have
improved
certainty
and
flexibility,
reduced
burden,
and
opportunity
for
utilization
increases
without
compromising
air
quality.
Like
the
PAL,
the
Clean
Unit
includes
necessary
safeguards
by
requiring
enforceable
permit
terms
and
conditions
to
ensure
environmental
protection.
IV.
Plantwide
Applicability
Limitations
A.
Introduction
Today
we
are
adopting
a
final
rule
for
a
PAL
option
that
is
based
on
the
baseline
actual
emissions
26
from
major
stationary
sources.
A
PAL
is
an
optional
approach
that
will
provide
you,
the
owners
or
operators
of
major
stationary
sources,
with
the
ability
to
manage
facility
wide
emissions
without
triggering
major
NSR.
We
believe
the
added
flexibility
of
a
PAL
allows
you
to
respond
rapidly
to
market
changes
consistent
with
the
goals
of
the
NSR
program.
The
final
rules
we
are
adopting
today
also
benefit
the
public
and
the
environment.
Reviewing
authorities,
usually
States,
can
only
establish
a
PAL
by
using
a
public
process
that
affords
citizens
the
opportunity
to
comment
upon
the
proposed
PAL.
This
process
is
designed
to
assure
local
communities
that
air
emissions
from
your
major
stationary
source
will
not
exceed
the
facility
wide
cap
set
forth
in
the
permit
unless
you
first
meet
the
major
NSR
requirements.
We
believe
that
a
PAL
provides
a
more
complete
perspective
to
the
public
because
in
setting
a
PAL,
your
reviewing
authority
accounts
for
all
current
processes
and
all
emissions
units
together
and
reflects
the
long
term
maximum
amount
of
emissions
it
would
allow
from
your
source.
Moreover,
to
comply
with
a
PAL
you
must
meet
monitoring
requirements
prescribed
in
the
rules
that
ensure
that
both
your
reviewing
authority
and
the
public
have
sufficient
information
from
which
to
determine
plantwide
compliance.
Additionally,
through
the
final
PAL
regulations,
we
are
promoting
voluntary
improvements
in
pollution
controls
by
creating
an
incentive
for
you
to
control
existing
and
new
emissions
units
to
maintain
a
maximum
amount
of
operational
flexibility
under
the
PAL.
Most
importantly,
for
pollutants
subject
to
a
PAL,
we
are
prohibiting
serial,
small,
unrelated
emissions
increases,
27
which
otherwise
can
occur
under
our
existing
regulations.
If
you
choose
to
use
it,
we
believe
you
will
benefit
from
the
PAL
option
because
you
will
have
increased
operational
flexibility
and
regulatory
certainty,
a
simpler
NSR
applicability
approach,
and
fewer
administrative
burdens.
To
comply
with
a
PAL,
you
need
to
ensure
that
there
are
no
emissions
increases
from
your
major
stationary
source,
as
measured
against
the
PAL.
For
you
to
do
that,
there
is
no
need
for
you
to
quantify
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Rules
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28
The
term
``
voluntary''
means
that
you
have
the
option
of
entering
into
a
PAL,
rather
than
voluntary
compliance
with
a
PAL
that
is
in
place.
Once
you
have
a
permit
with
PAL
requirements,
you
must
comply
with
the
requirements.
29
Results
of
our
study
are
reported
in
``
Evaluation
of
the
Implementation
Experience
with
Innovative
Air
Permits.''
A
complete
copy
of
this
report
is
located
in
the
docket
for
today's
rulemaking.
contemporaneous
emissions
increases
and
decreases
for
individual
emissions
units.
Through
the
PAL
we
are
allowing
you
to
make
timely
changes
to
react
to
market
demand
and
providing
you
additional
certainty
regarding
the
level
of
emissions
at
which
your
source
will
be
required
to
undergo
major
NSR.
The
benefit
to
you
is
that
you
will
not
have
to
make
numerous
applicability
decisions
using
different
baselines.
Also,
in
some
situations
where
you
would
have
been
unable
to
``
net
out''
a
new
project
in
the
major
NSR
program,
under
a
PAL
you
can
begin
construction
on
your
new
project
without
obtaining
a
major
NSR
permit,
which
can
take
from
a
few
months
up
to
2
years.
In
addition,
because
you
may
make
emissions
reductions
at
emissions
units
under
the
PAL
to
create
room
for
growth
at
other
units,
through
the
PAL
we
are
providing
a
strong
incentive
for
you
to
employ
innovative
control
technologies
and
pollution
prevention
measures,
to
create
voluntary
emissions
reductions
to
facilitate
economic
expansion.
B.
Relevant
Background
1.
What
Is
a
PAL
and
How
Does
a
PAL
Compare
to
Other
Major
NSR
Requirements
and
Netting?
The
concept
of
a
PAL
is
simple.
Under
the
Act,
you
are
not
subject
to
major
NSR
unless
you
make
a
``
modification,''
which
by
definition
cannot
occur
without
an
emissions
increase.
CAA
section
111(
a)(
4).
A
PAL
is
a
source
wide
cap
on
emissions
and
is
one
way
of
making
sure
that
emissions
increases
from
your
major
stationary
source
do
not
occur.
The
existing
regulations
require
``
major
modifications''
to
undergo
NSR,
and
the
existence
of
a
``
significant
net
emissions
increase''
at
the
facility
is
a
necessary
prerequisite
to
a
``
major
modification.''
See,
for
example,
§
§
52.21(
b)(
2)
&
(
3);
see
also
Chevron
v.
Natural
Resources
Defense
Council,
467
U.
S.
837,
863
64
(
1984).
Under
our
current
system,
we
determine
whether
a
``
significant
net
emissions
increase''
occurs
at
your
major
stationary
source
by
focusing
initially
on
the
change
to
the
emissions
unit(
s)
and
then
broadening
the
analysis
to
include
other
changes
within
the
source.
In
order
to
determine
whether
there
is
a
``
significant
net
emissions
increase''
under
major
NSR
as
revised
today,
you
must
establish
a
pre
change
baseline
for
each
change,
project
the
actual
level
of
emissions
after
the
change,
calculate
the
creditable
emissions
increases
and
decreases
that
have
occurred
that
are
contemporaneous
with
the
change,
and
determine
whether
the
change
would
result
in
a
significant
net
emissions
increase.
We
refer
to
this
applicability
process
as
``
netting''
under
the
major
NSR
regulations.
Both
you
and
reviewing
authorities
have
maintained
that
the
netting
rules
are
unnecessarily
complex
and
burdensome,
and
have
urged
us
to
craft
rules
that
link
NSR
applicability
to
compliance
with
a
predictable
source
wide
emissions
cap.
We
are
responding
to
that
request
with
the
PAL
concept.
A
PAL
is
a
voluntary,
28
source
specific,
straightforward,
flexible
approach
to
account
for
changes,
including
alterations
to
existing
emissions
units
and
the
addition
of
new
emissions
units,
at
your
existing
major
stationary
sources.
Complying
with
the
PAL
ensures
that
there
are
no
emissions
increases
that
trigger
major
NSR.
If
your
emissions
of
the
PAL
pollutant
remain
below
the
PAL,
and
you
comply
with
all
other
PAL
requirements,
whatever
changes
occur
at
your
plant
will
not
be
subject
to
major
NSR
for
the
PAL
pollutant.
Our
July
23,
1996
proposal
contains
a
thorough
discussion
of
the
proposed
PAL
concept
and
the
background
information
used
to
develop
the
proposal.
2.
Why
Does
EPA
Believe
That
PALs
Will
Benefit
the
Environment?
Over
the
past
several
years,
we
have
allowed
use
of
major
stationary
sourcewide
emissions
caps
to
demonstrate
compliance
with
major
NSR
in
a
select
number
of
pilot
projects.
We
recently
reviewed
six
of
these
innovative
air
permitting
efforts
and
found
substantial
benefits
associated
with
the
implementation
of
permits
containing
emissions
caps
(
among
other
types
of
permit
terms
offering
greater
flexibility
than
major
NSR
permitting
programs).
29
Specifically,
we
reviewed
on
site
records
to
track
utilization
of
these
flexible
permit
provisions,
to
assess
how
well
the
permits
are
working
and
any
emissions
reductions
achieved,
and
to
determine
if
there
were
any
economic
benefits
of
the
permits.
Overall,
we
found
that
significant
environmental
benefits
occurred
for
each
of
the
permits
reviewed.
In
particular,
the
six
flexible
permits
established
emissions
cap
based
frameworks
that
encouraged
emissions
reductions
and
pollution
prevention,
even
though
such
environmental
improvements
were
not
an
explicit
requirement
of
the
permits.
We
found
that
in
a
cap
based
program,
sources
strive
to
create
enough
headroom
for
future
expansions
by
voluntarily
controlling
emissions.
For
instance,
one
company
lowered
its
actual
VOC
emissions
over
threefold
in
becoming
a
synthetic
minor
source
(
that
is,
190
tpy
to
56
tpy).
Other
companies
lowered
their
actual
VOC
emissions
by
as
much
as
3600
tpy
by
increasing
capture,
by
using
voluntary
pollution
prevention
and
other
voluntary
emissions
control
measures,
and
by
reducing
production
rates.
Participants
reported
that
having
the
ability
to
make
rapid,
iterative
changes
to
optimize
process
performance
in
ways
that
minimize
emissions,
and
that
reduce
the
administrative
``
friction''
(
time
delays
and
uncertainty)
associated
with
making
operational
and
equipment
changes,
encourages
facilities
to
make
changes
that
improve
yields
and
reduce
per
unit
emissions.
It
is
also
critical
for
responding
to
product
development
needs
and
market
demand,
and
for
maintaining
overall
competitiveness.
Reviewing
authorities
consistently
reported
that
the
permits
worked
well
and
proved
beneficial,
and
that
there
was
a
reduction
in
the
number
of
caseby
case
permitting
actions
they
needed
to
undertake.
Specifically,
we
found
that
flexible
permit
provisions
(
for
example,
emissions
caps)
are
enforceable
as
a
practical
matter
by
using
a
mixture
of
mass
balance
based
equations,
CEMS,
and
parameter
monitoring.
No
emissions
cap
exceedances
or
violations
of
the
monitoring
provisions
were
experienced
by
any
of
the
pilot
sources.
In
addition,
the
monitoring
and
reporting
approaches
worked
well
and
were
generally
of
higher
quality
and
of
more
extensive
scope
than
those
directly
required
by
individual
applicable
requirements.
Based
on
the
results
of
these
pilot
projects,
we
believe
that
PALs
will
over
time
tend
to
shift
growth
in
emissions
to
cleaner
units,
because
the
growth
will
have
to
be
accommodated
under
the
PAL
cap.
Specifically,
we
expect
that
PALs
will
encourage
you
to
undertake
such
projects
as:
replacing
outdated,
dirty
emissions
units
with
new,
more
efficient
models;
installing
voluntary
emissions
controls;
and
researching
and
implementing
improvements
in
process
efficiency
and
use
of
pollution
prevention
technologies,
so
that
you
can
maintain
maximum
operational
flexibility.
We
also
expect
that
you
and
the
reviewing
authority
will
need
to
devote
substantially
fewer
resources
to
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Vol.
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/
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31,
2002
/
Rules
and
Regulations
30
The
key
determination
to
be
made
is
whether
an
emissions
unit
is
``
permanently
shut
down.''
This
issue
is
discussed
in
the
Administrator's
response
to
a
petition
objecting
to
an
operating
permit
for
a
facility
in
Monroe,
Louisiana.
See
Monroe
Electric
Generating
Plant,
Petition
No.
6
99
2
(
Adm'r
1999).
A
copy
of
this
decision
is
in
the
docket.
In
general,
we
explained
in
our
``
reactivation
policy''
that
whether
or
not
a
discussing
and
reviewing
whether
major
NSR
applies
to
individual
changes.
Thus,
overall,
we
believe
that
PALs
will
prove
to
be
as
beneficial
to
the
environment
as
they
are
to
you
and
your
reviewing
authority.
3.
What
Did
We
Propose
for
PALs?
On
July
23,
1996,
we
proposed
to
amend
the
NSR
regulations
to
specifically
authorize
PALs
and
to
clarify
the
methodology
under
which
you
can
obtain
a
PAL.
Under
the
proposal,
your
reviewing
authority
could
have
elected
to
include
provisions
in
its
SIP
to
allow
you
to
apply
for
a
permit
that
based
your
source's
major
NSR
applicability
on
compliance
with
a
pollutant
specific,
source
wide
emissions
cap.
We
proposed
that
a
facility's
PAL
would
generally
be
based
on
source
wide
``
actual
emissions''
plus
an
operating
margin
of
emissions
less
than
a
significant
emissions
increase.
We
also
sought
comment
on
the
circumstances
under
which
it
would
be
appropriate
to
use
something
other
than
actual
(
for
example,
``
allowable'')
emissions
to
set
the
PAL.
On
July
24,
1998,
we
published
a
notice
in
the
Federal
Register
seeking
further
comment
on
how
the
PAL
regulations
could
be
reconciled
with
several
environmental
and
legal
concerns.
The
notice
discussed
how
the
PAL
alternative
fits
within
the
Act's
requirements
for
determining
if
changes
at
existing
sources
are
subject
to
major
NSR.
Today
we
are
adopting
final
regulations
that
address
the
issues
and
comments
raised
in
the
1998
notice
and
the
1996
proposal.
C.
Final
Regulations
for
Actuals
PALs
Today's
action
establishes
final
regulatory
provisions
for
actuals
PALs.
We
are
placing
these
requirements
in
the
major
NSR
rules
for
nonattainment
areas
at
§
51.165(
f),
and
in
the
PSD
regulations
(
applicable
in
attainment
and
unclassifiable
areas)
at
§
§
51.166(
w)
and
52.21(
aa).
The
PAL
option
adopted
today
provides
you
with
a
voluntary
alternative
for
determining
NSR
applicability.
Actuals
PALs
are
rolling
12
month
emissions
caps
(
that
is,
tpy
limits)
that
include
all
conditions
necessary
to
make
the
limitation
enforceable
as
a
practical
matter.
Through
the
regulations,
we
are
allowing
PALs
on
a
pollutant
specific
basis
and
are
also
allowing
you
to
opt
for
actuals
PALs
for
more
than
one
pollutant
at
your
existing
major
stationary
sources.
You
must
continue
to
apply
the
major
NSR
applicability
provisions
to
air
pollutants
at
your
source
for
which
you
have
no
PAL.
This
section
sets
forth
the
specific
requirements
for
actuals
PALs.
The
section
addresses
the
following
items:
(
1)
The
process
used
to
establish
a
PAL
and
the
public
participation
requirements;
(
2)
how
the
PAL
level
is
determined;
(
3)
how
long
a
PAL
is
effective
and
what
happens
when
a
PAL
expires;
(
4)
can
a
PAL
be
terminated
before
the
end
of
its
effective
period;
(
5)
how
a
PAL
is
renewed;
(
6)
how
a
PAL
can
be
increased
during
the
effective
period;
(
7)
circumstances
that
would
cause
your
PAL
to
be
adjusted
during
the
PAL
effective
period;
(
8)
whether
a
PAL
can
eliminate
enforceable
emission
limitations
previously
taken
to
avoid
major
NSR;
(
9)
the
compliance
requirements
and
monitoring,
recordkeeping,
reporting,
and
testing
(
MRRT)
requirements
that
the
permit
must
contain
for
emissions
units
under
your
PAL;
(
10)
the
process
for
incorporating
conditions
of
the
PAL
into
your
title
V
operating
permit;
and
(
11)
an
example
of
how
an
actuals
PAL
would
work
under
the
regulations
finalized
today.
1.
What
Are
the
Permit
Application
Requirements,
What
Is
the
Process
Used
To
Establish
a
PAL,
and
What
Are
the
Public
Participation
Requirements?
Under
today's
final
rules,
you
must
submit
a
complete
application
to
your
reviewing
authority
requesting
a
PAL.
The
application,
at
a
minimum,
must
include
a
list
of
all
emissions
units,
their
size
(
major,
significant,
or
small);
the
Federal
and
State
applicable
requirements,
emission
limitations
and
work
practice
requirements
that
each
emissions
unit
is
subject
to;
and
the
baseline
actual
emissions
for
the
emissions
units
at
the
source
(
with
supporting
documentation).
The
calculation
of
baseline
actual
emissions
must
include
fugitive
emissions
to
the
extent
they
are
quantifiable.
The
reviewing
authority
must
establish
a
PAL
in
a
federally
enforceable
permit
(
for
example,
a
``
minor''
NSR
construction
permit,
a
major
NSR
permit,
or
a
SIP
approved
operating
permit
program).
To
comply
with
our
final
regulations,
the
reviewing
authority
must
provide
an
opportunity
for
public
participation
when
issuing
a
PAL
permit.
This
process
must
be
consistent
with
the
requirements
at
§
51.161
and
include
a
minimum
of
a
30
day
period
for
public
notice
and
opportunity
for
public
comment
on
the
proposed
permit.
Where
the
PAL
is
established
in
a
major
NSR
permit,
major
NSR
public
participation
procedures
apply.
When
establishing
a
PAL,
you
must
comply
with
all
applicable
requirements
of
the
reviewing
authority's
minor
NSR
program,
including
modeling
to
ensure
the
protection
of
the
ambient
air
quality.
Additionally,
you
must
meet
all
applicable
title
V
operating
permit
requirements.
When
adding
new
emissions
units
under
a
PAL,
you
must
comply
with
the
reviewing
authority's
minor
NSR
permit
requirements
for
public
notice,
review,
and
comment.
In
contrast,
when
adding
new
emissions
units
that
will
require
an
increase
in
a
PAL,
you
must
comply
with
the
reviewing
authority's
major
NSR
permit
requirements
for
public
notice,
review,
and
comment.
2.
How
Is
the
Level
of
the
PAL
Determined?
We
calculate
the
PAL
level
for
a
specific
pollutant
by
summing
the
baseline
actual
emissions
of
the
PAL
pollutant
for
each
emissions
unit
at
your
existing
major
stationary
source,
and
then
adding
an
amount
equal
to
the
applicable
significant
level
for
the
PAL
pollutant
under
§
52.21(
b)(
23)
or
under
the
CAA,
whichever
is
lower.
You
must
first
identify
all
your
existing
emissions
units
(
greater
than
2
years
of
operating
history)
and
new
emissions
units
(
less
than
2
years
of
operating
history
since
construction).
When
establishing
the
actuals
PAL
level,
you
must
calculate
the
baseline
actual
emissions
from
existing
emissions
units
that
existed
during
the
24
month
period
as
described
below.
The
baseline
actual
emissions
will
equal
the
average
rate,
in
tpy,
at
which
your
emissions
units
emitted
the
PAL
pollutant
during
a
consecutive
24
month
period,
within
the
10
year
period
immediately
preceding
the
application
for
a
PAL.
Consistent
with
today's
final
rules,
you
will
have
broad
discretion
to
select
any
consecutive
24
month
period
in
the
last
10
years
to
determine
the
baseline
actual
emissions.
Only
one
consecutive
24
month
period
may
be
used
to
determine
the
baseline
actual
emissions
for
such
existing
emissions
units.
For
any
emissions
unit
(
currently
classified
as
existing
or
new)
that
is
constructed
after
the
24
month
period,
emissions
equal
to
its
PTE
must
be
added
to
the
PAL
level.
Additionally,
for
any
emissions
unit
that
is
permanently
shut
down
or
dismantled
30
since
the
24
month
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Vol.
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251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
shutdown
should
be
treated
as
permanent
depends
on
the
intention
of
the
owner
or
operator
at
the
time
of
shutdown
based
on
all
facts
and
circumstances.
Shutdowns
of
more
than
2
years,
or
that
have
resulted
in
the
removal
of
the
source
from
the
State's
emissions
inventory,
are
presumed
to
be
permanent.
In
such
cases
it
is
up
to
the
facility
owner
or
operator
to
rebut
the
presumption.
period,
its
emissions
must
be
subtracted
from
the
PAL
level.
Different
rules
apply
for
determining
baseline
actual
emissions
for
EUSGUs.
You
should
refer
to
the
definition
of
baseline
actual
emissions
to
determine
the
specific
method
for
calculating
baseline
actual
emissions
for
your
emissions
units.
Consistent
with
today's
final
rules
for
determining
baseline
actual
emissions,
your
baseline
actual
emissions
for
an
emissions
unit
cannot
exceed
the
emission
limitation
allowed
by
your
permit
or
newly
applicable
State
or
Federal
rules
(
RACT,
NSPS,
etc.)
in
effect
at
the
time
the
reviewing
authority
sets
the
PAL.
This
means
that
for
the
purpose
of
setting
the
PAL,
your
baseline
actual
emissions
for
an
emissions
unit
will
include
an
adjustment
downward
to
reflect
currently
applicable
requirements.
Additionally,
your
reviewing
authority
shall
specify
a
reduced
PAL
level(
s)
(
in
tpy)
in
the
PAL
permit
to
become
effective
on
the
future
compliance
date(
s)
of
any
applicable
Federal
or
State
regulatory
requirement(
s)
that
the
reviewing
authority
is
aware
of
prior
to
issuance
of
the
PAL
permit.
See
section
II
of
today's
preamble
for
additional
information
on
determining
the
baseline
actual
emissions
for
your
emissions
units.
3.
How
Long
Can
a
PAL
Be
Effective
and
What
Happens
When
a
PAL
Expires?
Through
the
final
rules,
we
are
requiring
that
the
term
of
an
actual
PAL
be
10
years.
At
least
6
months
prior
to,
but
not
earlier
than
18
months
from,
the
expiration
date
of
your
PAL,
you
must
submit
a
complete
application
either
to
request
renewal
or
expiration
of
the
PAL.
If
you
meet
this
application
deadline
for
a
permit
renewal,
the
existing
PAL
will
continue
as
an
enforceable
requirement
until
the
reviewing
authority
renews
your
PAL,
even
if
the
reviewing
authority
fails
to
issue
a
PAL
renewal
within
the
specified
period
of
time.
As
part
of
an
application
to
request
expiration
of
the
PAL,
you
must
submit
a
proposed
approach
for
allocating
the
PAL
among
your
existing
emissions
units.
The
reviewing
authority
will
retain
the
ultimate
discretion
to
decide
whether
and
how
the
allowable
emission
limitations
will
be
allocated,
including
whether
to
establish
limits
on
individual
emissions
units
or
groups
of
emissions
units.
As
under
the
PAL,
your
emissions
units
must
comply
with
their
allowable
emission
limitations
on
a
12
month
rolling
basis.
However,
the
reviewing
authority
retains
the
discretion
to
accept
monitoring
systems
other
than
CEMS,
CPMS,
PEMS,
etc.,
from
you
to
demonstrate
compliance
with
these
unit
specific
limits.
Until
the
reviewing
authority
issues
the
revised
permit
with
allowable
emission
limitations
covering
each
of
your
emissions
units,
your
source
must
comply
with
a
source
wide
multi
unit
emissions
cap
equivalent
to
the
PAL
level.
After
a
PAL
expires,
physical
or
operational
changes
will
no
longer
be
evaluated
under
the
PAL
applicability
provisions.
Notwithstanding
the
expiration
of
the
PAL,
you
must
continue
to
comply
with
any
State
or
Federal
applicable
requirements
for
a
specific
emissions
unit.
(
BACT,
RACT,
NSPS,
etc.)
When
the
PAL
expires,
none
of
the
limits
established
pursuant
to
§
§
51.166(
r)(
2),
51.165(
a)(
5)(
ii),
or
52.21(
r)(
4),
which
the
PAL
originally
eliminated,
would
return
under
today's
final
rules.
4.
Can
a
PAL
Be
Terminated
Before
the
End
of
Its
Effective
Period?
Today's
final
rules
do
not
contain
specific
provisions
related
to
the
issue
of
terminating
a
PAL.
Decisions
about
whether
a
PAL
can
or
should
be
terminated
will
be
handled
between
you
and
your
reviewing
authority
in
accordance
with
the
requirements
of
the
applicable
permitting
program.
5.
How
Is
a
PAL
Renewed?
As
previously
discussed,
you
must
submit
a
complete
application
to
renew
a
PAL
at
least
6
months
prior
to,
but
not
earlier
than
18
months
from,
the
expiration
date
of
your
PAL.
If
you
submit
a
complete
application
to
renew
the
PAL
by
this
deadline,
the
existing
PAL
will
continue
as
an
enforceable
requirement
until
the
reviewing
authority
issues
the
permit
with
the
renewed
PAL.
As
part
of
your
renewal
application,
you
must
recalculate
and
propose
your
maximum
PAL
level,
taking
into
account
newly
applicable
requirements
and
the
factors
described
below.
Your
reviewing
authority
must
review
the
complete
application
and
issue
a
proposed
permit
for
public
comment
consistent
with
the
permitting
procedures
for
issuing
the
initial
PAL.
As
part
of
this
public
process,
the
reviewing
authority
must
provide
a
written
rationale
for
its
proposed
PAL
level.
If
your
source's
PTE
has
declined
below
the
PAL
level,
the
reviewing
authority
must
adjust
the
PAL
downward
so
that
it
does
not
exceed
your
source's
PTE.
In
addition,
the
reviewing
authority
may
renew
the
PAL
at
the
same
level
without
consideration
of
other
factors,
if
the
sum
of
the
baseline
actual
emissions
for
all
emissions
units
at
your
source
(
as
calculated
using
the
definition
of
``
baseline
actual
emissions''
at
§
§
51.165(
a)(
1)(
xii)(
B),
51.166(
b)(
21),
and
52.21(
b)(
21)
as
amended
by
today's
final
rules)
plus
an
amount
equal
to
the
significant
level
is
equal
to
or
greater
than
80
percent
of
the
PAL
level
(
unless
greater
than
the
current
PTE
of
the
major
stationary
source).
However,
if
the
baseline
actual
emissions
plus
an
amount
equal
to
the
significant
level
is
less
than
80
percent
of
the
PAL
level,
the
reviewing
authority
may
set
the
PAL
at
a
level
that
it
determines
to
be
more
representative
of
the
source's
baseline
actual
emissions,
or
that
it
determines
to
be
appropriate
considering
air
quality
needs,
advances
in
control
technology,
anticipated
economic
growth
in
the
area,
desire
to
reward
or
encourage
the
source's
voluntary
emissions
reductions,
cost
effective
emissions
control
alternatives,
or
other
factors
as
specifically
identified
by
the
reviewing
authority
in
its
written
rationale.
For
instance,
a
reviewing
authority
may
determine
that
PAL
levels
are
inconsistent
with
the
levels
necessary
to
achieve
the
NAAQS,
or
a
State
may
determine
that
PAL
levels
need
to
be
reduced
to
provide
room
for
new
economic
growth
in
the
area.
In
some
circumstances,
such
as
in
the
example
cited
below,
the
reviewing
authority
may
exercise
its
discretion
in
deciding
that
an
adjustment
is
not
warranted.
We
believe
that
such
discretion
is
appropriate,
based
in
part
on
our
experience
with
the
pilot
projects
previously
mentioned.
In
one
instance,
a
participant
voluntarily
agreed
to
reduce
its
actual
emissions
by
54
percent
in
exchange
for
obtaining
a
source
wide
emissions
cap.
After
agreeing
to
this
emissions
reduction,
the
participant
further
reduced
emissions
by
increasing
capture
efficiency
and
incorporating
pollution
prevention
strategies
into
its
operations.
Unexpectedly,
the
participant
also
suffered
an
unusual
economic
downturn
that
caused
a
decrease
in
the
rate
of
production
and
a
corresponding
decrease
in
actual
emissions.
At
the
time
of
renewal
of
the
source
wide
emissions
cap,
the
participant's
actual
emissions
were
10
percent
of
its
actual
emissions
before
committing
to
the
emissions
cap.
The
participant
chose
not
to
renew
its
emissions
caps,
because
renewal
required
an
automatic
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
adjustment
to
its
current
actual
emissions
level.
Clearly,
such
a
result
contravenes
the
mutual
benefits
that
operating
under
a
PAL
provides,
and
discourages
you
from
undertaking
voluntary
reductions.
If
your
source
would
ordinarily
be
subject
to
a
downward
adjustment,
but
you
believe
such
an
adjustment
is
not
appropriate,
you
may
propose
another
level.
The
reviewing
authority
may
approve
the
level
that
you
propose
if
it
determines,
in
writing,
that
the
level
is
reasonably
representative
of
the
source's
baseline
actual
emissions.
Similarly,
the
reviewing
authority
may
determine
that
a
lower
level
best
represents
the
baseline
actual
emissions
from
the
source.
Consistent
with
the
effective
period
for
the
initial
PAL,
all
renewed
PALs
will
have
a
10
year
effective
period.
6.
How
Can
a
PAL
Be
Increased
During
the
Effective
Period?
The
reviewing
authority
may
allow
you
to
increase
a
PAL
during
the
effective
period
if
you
are
adding
new
emissions
units
or
changing
existing
emissions
units
in
a
way
that
would
cause
you
to
exceed
your
PAL.
However,
today's
rule
only
authorizes
your
reviewing
authority
to
allow
such
an
increase
if
you
would
not
be
able
to
maintain
emissions
below
the
PAL
level
even
if
you
assumed
application
of
BACT
equivalent
controls
on
all
existing
major
and
significant
units
(
emissions
units
that
have
a
PTE
greater
than
a
significant
amount
(
as
defined
by
§
52.21(
b)(
23)
or
the
CAA,
whichever
is
lower).
Such
units
must
be
adjusted
for
current
BACT
levels
of
control
unless
they
are
currently
subject
to
a
BACT
or
LAER
requirement
that
has
been
determined
within
the
preceding
10
years,
in
which
case
the
assumed
control
level
shall
be
equal
to
the
emissions
unit's
existing
BACT
or
LAER
control
level.
The
PAL
permit
must
require
that
the
increased
PAL
level
will
be
effective
on
the
day
any
emissions
unit
that
is
part
of
the
PAL
major
modification
becomes
operational
and
begins
to
emit
the
PAL
pollutant.
Your
proposed
new
emissions
unit(
s)
and
your
existing
emissions
units
undergoing
a
change
must
go
through
major
NSR
permitting,
regardless
of
the
magnitude
of
the
proposed
emissions
increase
that
would
result
(
for
example,
no
significant
level
applies).
This
is
because
the
significant
level
for
the
pollutant
is
incorporated
into
the
PAL.
These
emissions
units
must
comply
with
any
emissions
requirements
resulting
from
the
major
NSR
process
(
for
example,
LAER),
even
though
they
have
also
become
subject
to
the
PAL
program
or
remain
subject
to
the
PAL.
To
request
a
PAL
increase,
you
must
submit
a
complete
major
NSR
permit
application.
As
part
of
this
application,
you
must
demonstrate
that
the
sum
of
the
baseline
actual
emissions
of
your
small
emissions
units,
plus
the
sum
of
the
baseline
actual
emissions
from
your
significant
and
major
emissions
units
(
adjusted
for
a
current
BACT
level
of
control
unless
the
emissions
units
are
currently
subject
to
a
BACT
or
LAER
requirement
that
has
been
determined
within
the
preceding
10
years,
in
which
case
the
assumed
control
level
shall
be
equal
to
the
emissions
unit's
existing
BACT
or
LAER
control
level),
plus
the
sum
of
the
allowable
emissions
of
the
new
or
modified
existing
emissions
unit(
s),
exceeds
the
PAL.
After
the
reviewing
authority
has
completed
the
major
NSR
process,
and
thereby
determined
the
allowable
emissions
for
the
new
or
modified
emissions
unit(
s),
the
reviewing
authority
will
calculate
the
new
PAL
as
the
sum
of
the
allowable
emissions
of
the
new
or
modified
emissions
unit(
s),
plus
the
sum
of
the
baseline
actual
emissions
of
your
small
emissions
units,
plus
the
sum
of
the
baseline
actual
emissions
from
significant
and
major
emissions
units
adjusted
for
the
appropriate
BACT
level
of
control
as
described
above.
Your
reviewing
authority
must
modify
the
PAL
permit
to
reflect
the
increased
PAL
level
pursuant
to
the
public
notice
requirements
of
§
§
51.166(
w)(
5),
51.165(
f)(
5),
or
52.21(
aa)(
5)
of
today's
final
rule.
7.
Are
There
Any
Circumstances
That
Would
Cause
Your
PAL
To
Be
Adjusted
During
the
PAL
Effective
Period?
During
the
term
of
the
PAL,
at
PAL
renewal
or
at
title
V
permit
renewal,
your
reviewing
authority
may
reopen
your
PAL
permit
and
adjust
the
PAL
level,
either
upward
or
downward,
as
needed
by
the
reviewing
authority.
While
certain
activities
require
mandatory
reopening,
for
others
the
reviewing
authority
may
reopen
at
its
discretion.
The
reviewing
authority
must
reopen
the
permit
for
the
following
reasons:
(
1)
To
correct
typographical/
calculation
errors
made
in
setting
the
PAL
or
to
reflect
a
more
accurate
determination
of
emissions
used
to
establish
the
PAL;
(
2)
to
reduce
the
PAL
if
the
owner
or
operator
of
the
major
stationary
source
creates
creditable
emissions
reductions
for
use
as
offsets;
or
(
3)
to
revise
a
PAL
to
reflect
an
increase
in
the
PAL.
The
reviewing
authority
may
reopen
the
permit
to:
(
1)
Reduce
the
PAL
to
reflect
newly
applicable
Federal
requirements
(
for
example,
NSPS)
with
compliance
dates
after
the
PAL
effective
date;
(
2)
reduce
the
PAL
consistent
with
any
other
requirement
that
is
enforceable
as
a
practical
matter,
and
that
the
State
may
impose
on
the
major
stationary
source
under
the
SIP;
or
(
3)
reduce
the
PAL
if
the
reviewing
authority
determines
that
a
reduction
is
necessary
to
avoid
causing
or
contributing
to
a
NAAQS
or
PSD
increment
violation,
or
to
an
adverse
impact
on
an
AQRV
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
While
the
final
rule
does
not
require
your
reviewing
authority
to
immediately
reopen
the
PAL
permit
to
reflect
newly
applicable
Federal
or
State
regulatory
requirements
(
for
example,
NSPS,
RACT)
that
become
effective
during
the
PAL
effective
period,
it
does
require
the
PAL
to
be
adjusted
at
the
time
of
your
title
V
permit
renewal
or
PAL
permit
renewal,
whichever
occurs
first.
Notwithstanding
this
requirement,
today's
final
rule
provides
your
reviewing
authority
discretion
to
reopen
the
PAL
permit
to
reduce
the
PAL
to
reflect
newly
applicable
Federal
or
State
regulatory
requirements
before
the
time
we
otherwise
require.
8.
Can
a
PAL
Eliminate
Existing
Emission
Limitations?
An
actuals
PAL
may
eliminate
enforceable
permit
limits
you
may
have
previously
taken
to
avoid
the
applicability
of
major
NSR
to
new
or
modified
emissions
units.
Under
the
major
NSR
regulations
at
§
§
52.21(
r)(
4),
51.166(
r)(
2),
and
51.165(
a)(
5)(
ii),
if
you
relax
these
limits,
the
units
become
subject
to
major
NSR
as
if
construction
had
not
yet
commenced
on
the
source
or
modification.
Should
you
request
a
PAL,
today's
revised
regulations
allow
the
PAL
to
eliminate
annual
emissions
or
operational
limits
that
you
previously
took
at
your
stationary
source
to
avoid
major
NSR
for
the
PAL
pollutant.
This
means
that
you
may
relax
or
remove
these
limits
without
triggering
major
NSR
when
the
PAL
becomes
effective.
Before
removing
the
limits,
your
reviewing
authority
should
make
sure
that
you
are
meeting
all
other
regulatory
requirements
and
that
the
removal
of
the
limits
does
not
adversely
impact
the
NAAQS
or
PSD
increments.
We
are
not
taking
a
position
on
whether
compliance
with
requirements
contained
in
a
PAL
permit
could
serve
to
demonstrate
compliance
with
certain
pre
existing
requirements
on
individual
units.
The
reviewing
authority
may
assess
on
a
case
by
case
basis
whether
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Rules
and
Regulations
any
streamlining
would
be
appropriate
in
the
title
V
permit
consistent
with
part
70
procedures
and
our
existing
policies
and
guidance
on
permit
streamlining.
9.
What
MRRT
(
Collectively
Referred
to
as
``
Monitoring'')
Requirements
Must
the
Permit
Contain
for
Emissions
Units
Under
Your
PAL?
Each
permit
must
contain
enforceable
requirements
that
accurately
determine
plantwide
emissions.
A
PAL
monitoring
system
must
be
comprised
of
one
or
more
of
the
four
general
approaches
that
meet
the
minimum
requirements
discussed
below,
and
such
monitoring
systems
must
be
approved
by
the
reviewing
authority.
You
may
also
employ
an
alternative
approach
if
approved
by
the
reviewing
authority.
Use
of
monitoring
systems
that
do
not
meet
the
minimum
requirements
approved
by
the
reviewing
authority
renders
the
PAL
invalid.
Any
monitoring
system
authorized
for
use
in
the
PAL
permit
must
be
based
on
sound
science
and
must
conform
to
generally
acceptable
scientific
procedures
for
data
quality
and
manipulation.
In
return
for
the
increased
operational
flexibility
of
a
PAL,
your
permit
must
include
sufficient
data
collection
requirements
to
ensure
compliance
with
the
PAL
at
all
times.
In
addition,
the
PAL
permit
must
contain
enforceable
provisions
that
ensure
that
the
monitoring
data
meet
the
minimum
legal
requirements
for
admissibility
in
a
judicial
proceeding
to
enforce
the
PAL
permit.
This
section
addresses
a
number
of
issues
associated
with
the
practical
enforceability
of
PALs
and
describes
concepts
that
you
and
reviewing
authorities
must
follow
when
establishing
your
PAL.
The
issues
addressed
include
the
following.
How
do
monitoring
requirements
for
emissions
units
under
a
PAL
differ
from
those
for
emissions
units
that
are
not
under
a
PAL?
What
are
the
testing
requirements
for
your
emissions
units
under
a
PAL?
What
monitoring
systems
are
appropriate
to
demonstrate
compliance
with
your
PAL?
What
information
about
your
proposed
data
collection
systems
must
be
submitted
to
your
reviewing
authority
for
approval?
What
recordkeeping
requirements
must
your
permit
contain
to
demonstrate
compliance
with
your
PAL?
What
reporting
requirements
for
your
PAL
must
your
permit
contain?
a.
How
Do
Monitoring
Requirements
for
Emissions
Units
Under
a
PAL
Differ
From
Those
for
Emissions
Units
That
Are
Not
Under
a
PAL?
Typically,
when
an
emission
limitation
applies
on
a
unit
by
unit
basis,
the
monitoring
must
be
sufficient
to
provide
data
that
demonstrate
that
emissions
do
not
exceed
the
applicable
limit
for
a
particular
unit.
Under
this
approach,
if
an
emissions
unit
has
to
meet
an
NSPS
VOC
limit
of
9
ppm,
the
monitoring
need
only
demonstrate
that
VOC
emissions
are
no
higher
than
9
ppm
but
not
measure
VOC
emissions
at
any
precise
level
below
9
ppm
(
for
example,
7
ppm,
8
ppm).
In
contrast,
under
a
VOC
emissions
actual
PAL,
the
VOC
emissions
from
each
emissions
unit
must
be
quantified
(
in
tpy),
generally
each
month
as
the
sum
of
the
previous
12
months
of
VOC
emissions.
Thus,
it
becomes
necessary
to
require
monitoring
that
quantifies
the
emissions
from
each
emissions
unit
to
ensure
that
the
annual
limit
is
enforceable
as
a
practical
matter.
As
a
result,
the
monitoring
requirements
for
emissions
units
under
a
PAL
may
be
more
stringent
than
for
those
emissions
units
not
under
a
PAL.
In
many
instances,
your
emissions
units
may
have
monitoring
suitable
for
determining
compliance
with
a
unitspecific
emission
limitation
on
a
periodic
basis,
in
accordance
with
title
V
requirements,
but
that
monitoring
frequency
of
data
collection
may
not
be
appropriate
for
ongoing
emissions
quantification
for
a
12
month
rolling
total.
Thus,
even
if
your
emissions
unit's
monitoring
meets
the
title
V
requirements
in
§
§
70.6(
a)(
3)(
i)(
B)
or
70.6(
c)(
1),
you
must
upgrade
that
monitoring
if
you
request
a
PAL
and
the
existing
monitoring
does
not
meet
the
minimum
requirements
of
the
PAL
regulations.
All
units
operating
under
a
PAL
must
have
sufficient
monitoring
to
accurately
determine
plantwide
emissions
for
a
12
month
rolling
total.
For
example,
a
source
owner
or
operator
with
five
units
must
be
able,
at
any
time,
to
quantify
the
baseline
actual
emissions
for
the
past
12
months
for
each
of
the
five
units.
That
source
should,
in
advance,
outline
how
it
plans
to
monitor
each
of
the
units
in
order
to
quantify
the
emissions.
If
one
of
the
five
units
cannot
accommodate
one
of
the
monitoring
options
provided
in
the
rule
in
order
to
quantify
the
emissions,
then
the
source
owner
or
operator
would
be
incapable
of
demonstrating
ongoing
compliance
with
the
source's
PAL.
b.
What
Are
the
Testing
Requirements
for
Your
Emissions
Units
Under
a
PAL?
As
part
of
your
PAL
application
and
as
directed
by
your
reviewing
authority,
you
must
use
current
emissions
or
other
current
direct
measurement
data
to
demonstrate
that
your
monitoring
systems
accurately
determine
emissions
from
each
unit
subject
to
a
PAL.
You
will
need
to
collect
such
data
from
all
units
subject
to
the
PAL,
including
those
that
are
unregulated
at
the
present
time.
If
you
do
not
have
current
emissions
data,
or
if
your
emissions
unit's
operation
and
equipment
have
changed
since
collection
of
that
data,
you
will
need
to
obtain
current,
accurate
data,
typically
by
conducting
performance
tests
or
other
direct
measurements
before
submission
of
your
complete
permit
application
to
obtain
a
PAL.
In
addition,
you
will
need
to
revalidate
the
data
and
any
correlation
to
demonstrate
that
your
monitoring
systems
continue
to
accurately
determine
emissions
from
each
unit
subject
to
a
PAL.
This
re
validation
must
occur
at
least
once
every
5
years
for
the
life
of
the
PAL.
Data
must
be
revalidated
through
a
performance
evaluation
test
or
other
scientifically
valid
means
that
is
approved
by
the
reviewing
authority.
You
must
conduct
all
testing
in
accordance
with
test
methods
appropriate
to
your
emissions
unit
and
applicable
requirements.
For
example,
among
the
test
methods
for
measuring
organic
emissions
are
Methods
18,
25,
25A,
and
25B,
which
can
be
found
in
40
CFR
part
60,
appendix
A.
During
testing,
your
emissions
unit
must
operate
within
the
range
you
wish
to
operate,
so
as
to
provide
an
accurate
quantification
of
emissions
across
the
entire
range.
This
may
require
you
to
perform
more
than
one
performance
test.
c.
What
Monitoring
Systems
Are
Appropriate
To
Demonstrate
Compliance
With
Your
PAL?
The
PAL
monitoring
system
must
be
comprised
of
one
or
more
of
four
general
approaches:
(
1)
Mass
balance
for
processes,
work
practices,
or
emissions
sources
using
coatings
or
solvents;
(
2)
Continuous
Emissions
Monitoring
System
(
CEMS);
(
3)
Continuous
Parameter
Monitoring
System
(
CPMS)
or
Predictive
Emissions
Monitoring
System
(
PEMS)
with
Continuous
Emissions
Rate
Monitoring
System
(
CERMS)
or
automated
data
acquisition
and
handling
system
(
ADHS),
as
needed;
or
(
4)
emission
factors.
Alternatively,
another
monitoring
approach
may
be
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67,
No.
251
/
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December
31,
2002
/
Rules
and
Regulations
used
if
approved
in
advance
by
the
reviewing
authority.
The
monitoring
approaches
mentioned
above
must
meet
minimum
requirements
established
by
today's
rule.
In
the
mass
balance
approach,
you
would
consider
all
of
the
PAL
pollutant
contained
in
or
created
by
any
raw
material
or
fuel
used
in
or
at
your
emissions
unit
to
be
emitted.
Currently,
we
are
limiting
this
approach
to
monitoring
for
processes,
work
practices,
or
emissions
sources
using
coatings
or
solvents.
In
order
to
use
the
mass
balance
approach,
you
must
validate
the
content
of
the
PAL
pollutant
that
is
contained
in
or
created
by
any
raw
material
or
fuel
used
on
site.
This
validation
may
be
accomplished
by
a
regular
testing
program
conducted
by
the
vendor
of
the
materials
or
by
an
independent
laboratory.
In
addition,
you
are
required
to
use
the
upper
limit
of
any
content
range
in
the
calculations,
unless
the
reviewing
authority
determines
that
there
is
a
site
specific
data
monitoring
system
in
place
at
the
unit
or
that
there
are
data
to
support
the
use
of
another
content
within
the
range.
If
your
reviewing
authority
allows
you
to
use
a
mass
balance
approach,
then
the
PAL
permit
must
require
you
to
account
for
all
material
containing
the
PAL
pollutant
or
use
of
all
materials
that
could
create
PAL
pollutant
emissions
(
through
chemical
decomposition,
by
product
formation,
etc.).
For
instance,
if
you
are
subject
to
a
VOC
PAL
and
your
emissions
units
do
not
utilize
add
on
control
devices,
you
may
use
a
mass
balance
approach
to
determine
compliance.
For
example,
suppose
over
1
month
you
were
using
8
tons
of
solvent
with
25
percent
VOCs
(
as
demonstrated
using
Method
311).
You
would
be
required
to
report
and
include
2
tons
of
VOC
emissions
(
since
8
×
0.25
=
2)
for
that
month
to
compare
with
the
PAL,
even
though
some
of
the
VOCs
may
not
ultimately
be
emitted.
(
For
example,
they
could
be
retained
in
your
emissions
unit's
product
or
in
a
process
waste.)
A
CEMS,
coupled
with
a
CERMS
as
well
as
an
ADHS
(
collectively
known
as
a
CEMS),
may
be
used
to
measure
and
verify
the
PAL
pollutant
concentration,
volumetric
gas
flow
(
if
applicable),
and
PAL
pollutant
mass
emissions
discharged
to
the
atmosphere
from
each
emissions
unit
emitting
the
PAL
pollutant.
If
your
source
utilize
a
CEMS
approach,
you
must
ensure
that
the
CEMS
meets
the
applicable
Performance
Specifications
in
40
CFR
part
60,
appendix
B.
The
CEMS
must
be
capable
of
data
sampling
at
least
once
every
15
minutes.
In
addition,
you
must
be
able
to
convert
the
data
obtained
from
the
CEMS
system
to
a
mass
emissions
rate.
These
types
of
monitoring
systems
are
appropriate
for
emissions
sources
subject
to
respective
SO2,
NOX,
carbon
monoxide,
particulate
matter
(
PM),
VOC,
total
reduced
sulfur
(
TRS),
or
hydrogen
sulfide
(
H2S)
regulations.
A
CPMS
or
PEMS
coupled
with
CERMS
and
ADHS
(
collectively
known
as
parameter
monitoring),
may
be
used
for
emissions
units
as
reviewed
and
approved
by
your
reviewing
authority.
To
determine
emissions,
parameter
monitoring
relies
on:
(
1)
Use
of
physical
principles;
(
2)
parameters
such
as
temperature,
mass
flow,
or
pressure
differential;
and
(
3)
performance
testing
results.
Users
of
parameter
monitoring
must
show
a
correlation
between
predicted
and
actual
emissions
across
the
anticipated
operating
range
of
the
unit.
An
example
is
a
source
owner
or
operator
who
determines
VOC
emissions
from
an
incinerator
by
multiplying
the
incinerator
efficiency
by
the
amount
of
VOC
containing
material
used.
Three
assumptions
are
built
into
the
emissions
algorithm:
(
1)
The
VOC
content
remains
constant;
(
2)
the
control
device
reduction
efficiency
remains
constant
over
the
temperature
range
established
during
performance
testing;
and
(
3)
the
unit
load
remains
constant.
Checks
on
these
assumptions
are
established
by:
ongoing
monitoring
requirements
(
for
example,
combustion
chamber
temperature
and
control
device
load);
ongoing
emissions
testing
requirements
(
for
example,
periodic
reevaluation
of
the
correlation
between
combustion
chamber
temperature
and
control
device
efficiency);
and
ongoing
testing
of
the
VOC
content
of
the
material.
Another
example
of
parameter
monitoring
is
an
organic
emissions
condenser.
The
parameter
monitoring
design
in
this
case
is
based
on
the
laws
of
physics
and
the
physical
properties
of
the
material
(
for
example,
the
lowest
condensation
temperature
of
the
VOC
constituent),
the
temperature
of
the
condenser,
and
the
maximum
material
feed
rate.
Some
parameter
monitoring
works
by
calculating
emissions
using
data
from
monitored
parameters
and
a
neural
network
system
to
optimize
performance
of
a
unit.
By
measuring
numerous
parameters,
the
network
can
then
automatically
analyze
current
operations,
as
well
as
emissions,
and
make
adjustments
to
optimize
performance.
Establishing
parameter
monitoring
is
a
resource
intensive
effort,
requiring
extensive
up
front
testing,
analysis,
and
development.
Recently,
we
have
developed
draft
performance
specifications
for
evaluating
appropriate,
acceptable
parameter
monitoring
accuracy,
repeatability,
and
reproducibility
(
e.
g.,
Performance
Specification
16).
You
and
your
reviewing
authority
should
review
these
performance
specifications
in
developing
an
interim
protocol
for
using
parameter
monitoring
to
demonstrate
continuous
compliance
with
a
PAL.
Your
approved
protocol
may
require
revision
as
we
finalize
performance
specifications.
Today's
rule
requires
you
to
revalidate
your
monitoring
systems,
including
parameter
re
certification
emissions
testing,
at
least
once
every
5
years
during
the
PAL
permit
term.
You
may
conduct
such
re
validation
as
part
of
any
other
testing
required
by
other
non
PAL
program
requirements,
such
as
title
V
program
requirements.
If
a
parameter
monitoring
approach
is
taken,
the
owner
or
operator
must
use
current
site
specific
data
to
establish
the
emissions
correlations
between
the
monitored
parameter
and
the
PAL
pollutant
emissions
across
the
entire
range
of
the
operation
of
the
emissions
unit.
If
the
owner
or
operator
cannot
establish
a
correlation
for
the
entire
operation
range,
the
reviewing
authority
shall,
at
the
time
of
the
permit
issuance,
establish
a
default
value(
s)
for
determining
compliance
with
the
PAL
based
on
the
highest
potential
emissions
reasonably
estimated
during
the
operational
times
when
an
emissions
correlation
is
not
available.
Alternatively,
the
reviewing
authority
may
decide
that
operation
of
the
emissions
unit
during
periods
where
there
is
no
emissions
correlation
is
a
violation
of
the
PAL.
The
PAL
permit
must
include
enforceable
requirements
if
either
of
these
alternatives
to
the
required
correlation
for
parameter
monitoring
are
used.
Emission
factors
may
be
used
for
demonstrating
compliance
with
PALs,
so
long
as
the
factors
are
adjusted
for
the
degree
of
uncertainty
or
limitations
in
the
factors'
development.
In
ascertaining
whether
an
emission
factor
is
appropriate,
you
and
your
reviewing
authority
should
consider
the
contribution
of
emissions
from
the
emissions
unit
in
relation
to
the
PAL,
the
size
of
the
emissions
unit,
and
the
margin
of
compliance
of
the
emissions
unit.
In
addition,
if
the
emission
factor
approach
is
taken,
the
emissions
unit
shall
operate
within
the
designated
range
of
use
for
the
emission
factor.
The
owner
or
operator
of
a
significant
emissions
unit
that
relies
on
an
emission
factor
to
calculate
PAL
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
pollutant
emissions
shall
conduct
validation
testing
using
other
monitoring
approaches
(
if
technically
practicable)
to
determine
a
site
specific
emission
factor
within
6
months
of
PAL
permit
issuance,
unless
the
reviewing
authority
determines
that
testing
is
not
required.
For
example,
should
you
demonstrate
to
your
reviewing
authority's
satisfaction
that
the
use
of
your
emission
factor
would
yield
a
result
that
is
protective
of
the
environment,
then
you
may
not
need
to
conduct
site
specific
performance
testing.
An
emissions
unit
is
considered
significant
if
the
emissions
unit
has
the
potential
to
emit
the
PAL
pollutant
in
amounts
greater
than
those
listed
in
§
51.165(
a)(
1)(
x).
In
the
event
you
choose
to
use
one
or
more
emission
factors
for
your
significant
or
small
emissions
units,
you
bear
the
burden
to
prove
to
the
reviewing
authority
that
the
emission
factors
are
appropriate
and
adjusted
for
any
uncertainty
in
the
factors'
development.
By
way
of
example,
the
sulfur
dioxide
emission
factor
for
2
stroke,
lean
burn,
natural
gas
fired
reciprocating
engines,
5.88
*
10
4
pounds
of
sulfur
dioxide
emitted
per
million
British
Thermal
Unit
(
mmBTU)
of
natural
gas
combusted,
as
published
in
our
Compilation
of
Air
Pollutant
Emission
Factors
AP
42,
Fifth
Edition
Volume
1:
Stationary
Point
and
Area
Sources,
which
is
found
on
our
Internet
Web
site
at
http://
www.
epa.
gov/
ttn/
chief/
ap42/
index.
html,
represents
an
appropriate
emission
factor.
The
reviewing
authority
may
approve
other
types
of
monitoring
systems
that
quantify
emissions
to
demonstrate
compliance
with
PALs.
Other
types
of
monitoring
that
may
be
approved
include
a
Gas
Chromatographic
(
GC)
or
a
Fourier
Transform
Infrared
Spectroscopy
(
FTIR)
CEMS
that
relies
on
extractive
techniques,
coupled
with
a
CERMS
as
well
as
an
ADHS,
to
measure
and
verify
the
VOC
concentration,
volumetric
gas
flow
(
if
applicable),
and
VOC
mass
emissions
(
in
lb/
hr)
discharged
from
stacks
(
that
is,
non
fugitive
emissions)
to
the
atmosphere.
For
processes,
work
practices,
or
emissions
sources
subject
to
VOC
or
organic
hazardous
air
pollutant
(
HAP)
regulations,
these
types
of
monitoring
systems
may
be
used
for
each
emissions
unit
emitting
VOC.
d.
What
information
about
your
monitoring
system
must
be
submitted
to
your
reviewing
authority
for
approval?
You
need
to
propose
a
monitoring
system
as
part
of
your
PAL
permit
application
submission
to
your
reviewing
authority.
The
monitoring
system
proposed
must
accurately
determine
plantwide
emissions.
In
your
permit
application,
you
must
describe
how
you
will
collect
and
transform
data
from
each
emissions
unit
subject
to
a
PAL
permit,
so
that
the
emissions
from
each
unit
can
be
quantified
as
a
12
month
rolling
total.
In
addition,
you
need
to
demonstrate
how
you
can
be
assured
the
data
are
and
remain
accurate
by
describing
how
you
will
install,
operate,
certify,
test,
calibrate,
and
maintain
the
performance
of
your
monitoring
system(
s)
on
each
emissions
unit
that
will
be
subject
to
the
PAL.
You
will
also
need
to
provide
calculations
for
the
maximum
potential
emissions
without
considering
enforceable
emission
limitations
or
operational
restrictions
for
each
unit
in
order
to
determine
emissions
during
periods
when
the
monitoring
system
is
not
in
operation
or
fails
to
provide
data.
In
lieu
of
the
permit
requiring
maximum
potential
emissions
during
periods
when
there
is
no
monitoring
data,
you
may
propose
another
alternate
monitoring
approach
as
a
backup.
This
backup
monitoring,
however,
must
still
meet
the
minimum
requirements
for
the
monitoring
approaches
prescribed
in
the
regulation.
Note
that
each
monitoring
system
with
applicable
requirements
contained
in
appendix
B
of
40
CFR
part
60
must
be
installed,
operated,
and
maintained
according
to
the
applicable
Performance
Specification
of
40
CFR
part
60,
appendix
B.
For
purposes
of
determining
emissions
from
an
emissions
unit,
a
unit
is
considered
operational
not
only
during
periods
of
normal
operation,
but
also
during
periods
of
startup,
shutdown,
maintenance,
and
malfunction'even
if
compliance
with
a
non
PAL
emission
limitation
is
excused
during
these
latter
periods.
Your
reviewing
authority
may
approve
different
monitoring
for
various
operating
conditions
(
for
example,
startup,
shutdown,
low
load,
or
high
load
conditions
as
demonstrated
through
multiple
performance
tests)
for
each
emissions
unit.
You
must,
however,
use
one
of
the
accepted
monitoring
approaches,
including
alternative
monitoring
approved
by
the
reviewing
authority,
for
these
periods
or
calculate
the
emissions
during
these
periods
by
assuming
the
highest
PTE
without
considering
enforceable
emission
limitations
or
operational
restrictions.
In
addition,
the
rule
permits
the
reviewing
authority
to
use
the
reasonably
estimated
highest
potential
emissions
for
periods
when
your
emissions
unit
operates
outside
its
parameter
range(
s)
established
in
the
performance
test,
unless
another
method
is
specified
in
the
permit,
and
include
those
emissions
in
the
12
month
rolling
total
in
order
to
demonstrate
compliance
with
the
PAL.
Alternatively,
the
reviewing
authority
may
decide
that
operation
outside
the
range(
s)
established
in
the
performance
test
is
a
violation
of
the
PAL.
The
reviewing
authority
must
decide
how
to
handle
emissions
when
the
unit
is
operating
outside
the
ranges
established
in
the
performance
tests
prior
to
the
issuance
of
the
PAL
permit
and
must
include
appropriate
enforceable
conditions
in
the
PAL
permit.
For
parameter
monitoring
to
be
approved
by
your
reviewing
authority,
your
proposed
monitoring
system
must
measure
the
operational
parameter
value(
s)
within
the
established
sitespecific
range(
s)
of
operating
parameter
values
demonstrated
in
recent
performance
testing.
The
monitoring
system
must
then
record
the
associated
PAL
pollutant
mass
emissions
rate
for
that
period
based
on
the
correlations
demonstrated
with
the
current
test
data.
e.
What
Recordkeeping
Requirements
Must
Your
Permit
Contain
To
Demonstrate
Compliance
With
Your
PAL?
Your
permit
must
require
you
to
maintain
records
of
your
monitoring
and
testing
data
that
support
any
compliance
certifications,
reports,
or
other
compliance
demonstrations.
This
information
should
contain,
but
is
not
necessarily
limited
to,
the
following
data.
The
date,
place
(
specific
location),
and
time
that
testing
or
measuring
occurs
The
date(
s)
sample
analysis
or
analyses
occur
The
entity
that
performs
the
analysis
or
analyses
The
analytical
techniques
or
methods
used
The
results
of
the
analyses
Each
emissions
unit's
operating
conditions
during
the
testing
or
monitoring
A
summary
of
total
monthly
emissions
for
each
emissions
unit
at
the
major
stationary
source
for
each
calendar
month
A
copy
of
any
report
submitted
to
the
reviewing
authority
A
list
of
the
allowable
emissions
and
the
date
operation
began
for
any
new
emissions
units
added
to
the
major
stationary
source.
You
must
also
record
all
periods
of
deviation,
including
the
date
and
time
that
a
deviation
started
and
stopped
and
whether
the
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction.
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Federal
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
You
must
retain
records
of
all
required
testing
and
monitoring
data,
as
well
as
supporting
information,
for
at
least
5
years
from
the
date
of
the
monitoring
sample,
measurement,
report,
or
application.
Supporting
information
includes
all
calibration
and
maintenance
records
and
all
original
strip
chart
recordings
for
continuous
monitoring
instrumentation,
and
copies
of
all
required
reports.
Instead
of
paper
records,
you
may
maintain
records
on
alternative
media,
such
as
microfilm,
computer
files,
magnetic
tape
disks,
or
microfiche,
provided
that
the
use
of
such
alternative
media
allows
for
expeditious
inspection
and
review
and
does
not
conflict
with
other
recordkeeping
requirements.
You
must
also
retain
a
copy
of
the
following
records
for
the
duration
of
the
PAL
effective
period
plus
5
years:
(
1)
A
copy
of
the
PAL
permit
application
and
any
applications
for
revisions
to
the
PAL;
and
(
2)
each
annual
certification
of
compliance
pursuant
to
title
V
and
the
data
relied
on
in
certifying
the
compliance.
f.
What
reporting
requirements
for
your
PAL
must
your
permit
contain?
You
must
provide
semi
annual
monitoring
and
prompt
deviation
reports.
The
terms
and
conditions
of
an
approved
PAL
become
title
V
applicable
requirements
that
will
be
placed
in
your
title
V
permit.
Therefore,
the
reports
required
under
title
V
may
meet
the
requirements
of
the
PAL
rule,
so
long
as
the
minimum
reporting
requirements
listed
in
the
regulations
are
met.
You
must
submit
a
semi
annual
emissions
report
to
the
reviewing
authority
within
30
days
after
the
end
of
each
reporting
period.
The
reviewing
authority
will
use
this
report
to
determine
compliance
with
the
conditions
of
the
PAL,
including
the
PAL
level.
The
compliance
period
for
an
actuals
PAL
emissions
level
is
a
consecutive
12
month
period,
rolled
monthly.
Block
12
month
periods
are
not
allowed
(
for
example,
Jan.
Dec.
of
each
year).
The
emissions
report
must
include
the
total
baseline
actual
emissions
of
the
PAL
pollutant
for
the
previous
12
months
and
compare
the
previous
12
months'
total
emissions
with
the
PAL
level
to
determine
compliance.
Additionally,
the
emissions
report
must
identify:
the
site;
the
owner
or
operator;
the
applicable
PAL;
the
monitored
parameters,
the
method
of
calculation
with
appropriate
formulas,
any
emission
factors
used,
the
capture
and
control
efficiencies
used
and
the
calculated
emissions;
total
monthly
emissions
(
tons)
and
the
equations
used
to
compute
this
value
for
each
of
the
12
months
before
submission
of
the
emissions
report
(
or
for
all
prior
months
if
the
PAL
has
not
been
effective
for
1
year);
total
annual
emissions
(
tpy);
a
PAL
compliance
statement;
a
list
of
any
emissions
units
added
or
modified
to
the
site;
and
information
concerning
shutdown
of
any
monitoring
system,
including
the
method
that
was
used
to
measure
emissions
during
that
period.
Finally,
in
accordance
with
title
V
requirements,
your
permit
will
require
all
reports
to
be
certified
by
your
responsible
official
as
true,
accurate,
and
complete.
10.
What
is
the
process
for
incorporating
conditions
of
the
PAL
into
your
title
V
operating
permit?
As
discussed
previously,
the
reviewing
authority
establishes
a
PAL
in
a
federally
enforceable
permit
using
its
minor
NSR
construction
permit
process
or
the
major
NSR
permit
construction
process
and
eventually
rolling
these
requirements
into
its
title
V
operating
permit.
The
reviewing
authorities'
rules
for
establishing
or
renewing
PALs
must
include
a
public
participation
process
prior
to
permit
approval
of
the
PAL.
The
process
must
be
consistent
with
the
requirements
at
§
51.161
and
include
a
minimum
30
day
period
for
public
notice
and
opportunity
for
public
comment
on
the
proposed
permit.
PALs
established
through
the
major
NSR
process
are
subject
to
major
NSR
public
participation
requirements.
When
adding
a
new
emissions
unit
under
an
established
PAL,
you
must
comply
with
the
reviewing
authority's
minor
NSR
permit
requirements
for
public
notice,
review,
and
comment.
The
process
for
incorporating
the
conditions
of
a
PAL
into
the
title
V
operating
permit
depends
on
whether
the
initial
title
V
permit
has
already
been
issued
for
the
source.
If
the
initial
title
V
permit
has
not
been
issued,
a
PAL
created
in
a
minor
or
major
NSR
permit
would
be
incorporated
during
initial
issuance
of
the
title
V
permit.
If
the
initial
title
V
permit
has
already
been
issued,
the
PAL
would
be
incorporated
through
the
appropriate
part
70
modification
procedures.
As
discussed
later
in
this
preamble,
we
suggest
that
you
request
that
your
reviewing
authority
renew
your
title
V
permit
concurrently
with
issuance
of
your
PAL
in
order
to
align
the
two
processes
together
and
decrease
the
administrative
burden
on
you
and
your
reviewing
authority.
Once
a
PAL
is
established,
a
change
at
a
facility
is
exempt
from
major
NSR
and
netting
calculations,
but
could
require
a
title
V
permit
modification,
as
could
any
other
change.
Whether
a
title
V
permit
modification
would
be
required,
and
which
permit
modification
process
would
be
used,
is
governed
by
the
current
part
70
rule
as
implemented
by
the
reviewing
authority.
11.
What
is
an
example
of
an
actuals
PAL?
The
following
example
is
based
upon
a
hypothetical
source
that
wishes
to
obtain
an
actuals
PAL
under
the
final
regulations
adopted
today.
A
manufacturing
plant
(
a
major
stationary
source)
located
in
a
serious
ozone
nonattainment
area
seeks
an
actuals
PAL
for
VOC
in
January
2002.
The
major
source
threshold
for
VOC
in
a
serious
ozone
nonattainment
area
is
50
tpy
and
the
significant
level
for
VOC
modifications
is
25
tpy.
The
plant
has
5
emissions
units
with
a
total
PTE
of
640
tpy
of
VOC.
The
PTE
for
VOC
for
each
of
the
emissions
units
at
the
plant
is
as
follows:
(
1)
Unit
A
is
335
tpy;
(
2)
unit
B
is
20
tpy;
(
3)
Unit
C
is
125
tpy;
(
4)
unit
D
is
60
tpy;
and
(
5)
unit
E
is
100
tpy.
Units
A,
B,
C,
and
D
are
existing
emissions
units
with
more
than
2
years
of
operating
history.
Unit
E
has
been
in
operation
for
only
a
year.
Unit
D
was
dismantled
in
year
2000
and
is
considered
permanently
shutdown.
For
units
A,
B,
C,
and
D,
the
source
has
selected
July
1,
1996
to
June
30,
1998
(
a
consecutive
24
month
period)
to
determine
baseline
actual
emissions.
Unit
A
is
subject
to
a
RACT
requirement
that
became
effective
in
year
2000.
The
baseline
actual
emissions
for
each
emissions
unit
during
this
period
are
as
follows:
unit
A,
140
tpy
(
including
RACT
adjustment);
unit
B,
10
tpy;
unit
C,
90
tpy;
and
unit
D,
20
tpy.
The
actuals
PAL
level
for
VOC
is
=
260
+
100
¥
20
+
25
=
365
tpy
WHERE
260
tpy
=
the
sum
of
the
baseline
actual
emissions
for
emissions
units
A
D
(
with
2
or
more
years
of
operation)
100
tpy
=
the
allowable
emissions
(
PTE)
of
unit
E,
which
was
constructed
after
the
24
month
period;
20
tpy
=
baseline
actual
emissions
of
unit
D,
which
is
permanently
shut
down
since
the
24
month
period;
and
25
tpy
=
significant
level
for
VOC
in
a
serious
nonattainment
area.
D.
Rationale
for
Today's
Final
Action
on
Actuals
PALs
We
received
voluminous
comments
and
suggestions
in
response
to
the
1996
NSR
proposal,
the
1998
NOA,
and
numerous
meetings
with
interested
stakeholders.
This
section
addresses
the
more
significant
comments
we
received.
For
a
more
detailed
discussion
of
the
comments
received
and
our
responses,
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
please
refer
to
the
Technical
Support
Document
included
in
the
docket
for
this
rulemaking.
The
comment
areas
addressed
in
this
section
include:
(
1)
How
do
the
PAL
regulations
meet
the
major
NSR
requirements
of
the
Act?
(
2)
Are
PALs
consistent
with
the
concept
of
``
contemporaneity'?
(
3)
Are
PALs
permissible
in
serious
and
severe
nonattainment
areas?
(
4)
Is
it
appropriate
for
a
PAL
to
be
based
on
actual
emissions?
(
5)
How
should
actual
emissions
be
determined
in
setting
the
PAL
level?
(
6)
Should
emissions
from
shut
down
or
dismantled
units
be
excluded
from
a
PAL?
(
7)
Should
a
PAL
include
a
margin
for
growth?
(
8)
Should
PALs
be
required
to
expire?
(
9)
Should
we
require
PALs
to
be
adjusted
at
the
time
of
PAL
renewal?
(
10)
Should
certain
new
emissions
units
that
are
added
under
a
PAL
be
required
to
meet
some
level
of
emissions
control?
(
11)
Under
what
circumstances
should
you
be
allowed
to
increase
your
PAL
and
how
should
we
apply
the
major
NSR
requirements
to
that
increase?
(
12)
What
monitoring
requirements
are
necessary
to
ensure
the
enforceability
of
PALs
as
a
practical
matter?
(
13)
Is
EPA
adopting
an
approach
that
allows
area
wide
PALs?
and
(
14)
When
should
modeling
or
other
types
of
ambient
impact
assessments
be
required
for
changes
occurring
under
a
PAL?
1.
How
do
the
PAL
regulations
meet
the
major
NSR
requirements
of
the
Act?
The
PAL
regulations
adopted
today
meet
the
requirements
of
the
CAA
and
are
consistent
with
the
Congressional
purpose
and
intent
underlying
NSR.
We
believe
the
PAL
regulations
constitute
a
reasonable
interpretation
of
the
Act's
definition
of
``
modification''
and
are
permissible
under
current
law.
The
definition
of
``
modification''
set
forth
in
section
111(
a)(
4)
of
the
Act
is
fundamental
to
determining
major
NSR
applicability.
Pursuant
to
the
Act,
the
term
modification
means
``
any
physical
change
in
or
change
in
the
method
of
operation
of
a
stationary
source
which
increases
the
amount
of
any
air
pollutant
emitted
by
such
source
or
which
results
in
the
emission
of
any
air
pollutant
not
previously
emitted.''
The
statute,
however,
does
not
prescribe
the
methodology
for
establishing
a
stationary
source's
emissions
baseline
from
which
emissions
increases
are
measured.
When
a
statute
is
silent
or
ambiguous
with
respect
to
specific
issues,
the
relevant
inquiry
is
whether
the
agency's
interpretation
of
the
statutory
provisions
is
permissible.
Chevron
U.
S.
A.,
Inc.
v.
NRDC,
Inc.,
467
U.
S.
837,
865
(
1984).
Accordingly,
EPA
is
exercising
its
discretion
to
develop
reasonable
alternatives
to
determine
NSR
applicability
that
are
consistent
with
the
statutory
provisions
and
Congressional
intent
underlying
the
NSR
requirements.
We
believe
that
the
PAL
regulations
adopted
today
represent
a
permissible
construction
of
the
Act.
2.
Are
PALs
consistent
with
the
concept
of
``
contemporaneity''?
In
the
1998
NOA,
we
solicited
comment
on
whether
and
how
a
program
that
recognizes
PALs
as
an
alternate
method
for
determining
NSR
applicability
should
address
a
particular
legal
concern:
the
need
to
have
some
``
contemporaneity''
between
an
emissions
increase
and
any
decrease
relied
upon
to
net
the
increase
out
of
review.
As
we
discussed
in
the
1998
notice,
the
current
regulations
specify
that,
to
be
creditable,
emissions
increases
and
decreases
must
have
occurred
within
a
``
contemporaneous''
period.
Our
current
regulations
governing
SIP
approved
programs
do
not
specify
a
precise
time
frame.
However,
the
Federal
PSD
rules
generally
only
credit
those
emissions
increases
and
decreases
that
occur
within
the
5
years
preceding
a
given
change.
We
established
these
regulatory
requirements
after
the
court's
decision
in
Alabama
Power,
in
which
the
court
interpreted
the
Act
as
requiring
plantwide
bubbling
in
the
PSD
program,
but
stated
that
``
any
offset
changes
claimed
by
industry
must
be
substantially
contemporaneous.''
636
F.
2d
402.
In
the
1998
notice,
we
sought
comment
on
whether
a
PAL
program
that
never
required
PALs
to
be
periodically
updated
to
reflect
current
emissions
at
the
source
would
allow
sources
to
make
emissions
reductions
and
hold
them
indefinitely,
only
to
use
them
several
decades
later
to
offset
new
increases,
and
whether
such
a
system
would
contravene
the
contemporaneity
principle
the
court
announced.
Many
commenters,
including
several
regulatory
agencies,
maintain
that
PALs
are
consistent
with
the
NSR
requirements
under
the
Act.
These
commenters
contend
that
the
court
gave
EPA
the
discretion
to
define
contemporaneity.
See
636
F.
2d
402
(``
The
Agency
has
discretion,
within
reason,
to
define
which
changes
are
substantially
contemporaneous.'').
Others
contend
that
changes
made
under
a
PAL
are
not
subject
to
the
Alabama
Power
``
contemporaneity''
requirement
because
a
change
made
under
the
PAL
is
either
excluded
from
NSR
or
alternatively
does
not
exceed
the
applicable
NSR
significance
threshold.
Therefore,
they
contend
that
netting
is
not
implicated
by
such
changes.
On
the
other
hand,
a
few
commenters
assert
that
PALs
conflict
with
the
purpose
of
the
Act.
We
believe
that
the
concept
of
contemporaneity,
as
articulated
in
Alabama
Power
and
as
set
forth
in
the
regulations
governing
the
major
NSR
program,
does
not
apply
to
PALs.
The
PAL
program
differs
in
certain
important
respects
from
our
current
regulations
and
from
the
1978
regulations
at
issue
in
Alabama
Power.
The
Alabama
Power
court
was
not
presented
with
the
PAL
approach
for
determining
whether
there
was
an
increase
in
emissions
and
did
not
consider
whether
the
principles
it
set
forth
in
its
opinion
would
apply
to
such
an
approach.
Under
the
1978
PSD
regulations
(
43
FR
26380),
a
source
was
subject
to
BACT
review
only
if
``
no
net
increase
in
emissions
of
an
applicable
pollutant
would
occur
at
the
source,
taking
into
account
all
emissions
increases
and
decreases
at
the
source
which
would
accompany
the
modification.''
43
FR
26385.
The
test
for
whether
a
``
major
modification''
had
occurred
required
the
source
to
sum
all
accumulated
increases
in
potential
emissions
that
had
occurred
at
the
source
since
issuance
of
the
regulations,
or
since
issuance
of
the
last
construction
permit,
whichever
was
more
recent.
Reductions
achieved
elsewhere
in
the
source
could
not
be
taken
into
account.
In
Alabama
Power,
the
D.
C.
Circuit
held
that
EPA
was
correct
in
excluding
from
BACT
review
any
changes
that
did
not
result
in
a
net
increase
of
a
pollutant.
636
F.
2d
401.
It
concluded,
however,
that
EPA
had
incorrectly
excluded
contemporaneous
decreases
from
the
calculation
of
whether
a
``
major
modification''
had
occurred.
Id.
at
402
03.
The
current
regulations
take
contemporaneous
decreases
into
account
for
all
PSD
review
purposes.
Under
the
current
regulations,
you
look
initially
at
the
emissions
unit
undergoing
the
change
and
determine
whether
there
will
be
a
significant
increase
at
that
unit.
If
there
is
no
significant
increase
at
the
unit,
the
inquiry
ends
there.
While
we
continue
to
believe
that
this
is
a
permissible
approach,
one
drawback
to
this
approach
is
that
it
allows
a
series
of
small,
unrelated
emissions
increases
to
occur,
which
is
discussed
elsewhere
in
this
preamble.
If
there
will
be
a
significant
increase
at
the
unit,
then
you
expand
the
inquiry
to
other
units
at
the
source.
You
take
into
account
contemporaneous
increases
and
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251
/
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31,
2002
/
Rules
and
Regulations
31
Eastern
Research
Group
Inc.
report
on
``
Business
Cycles
in
Major
Emitting
Source
Industries''
dated
September
25,
1997.
decreases
at
the
source
in
determining
whether
there
will
be
an
increase
for
the
source
as
a
whole.
Thus,
you
must
calculate
increases
and
decreases
at
individual
units
in
order
to
arrive
at
a
net
figure
for
the
entire
source.
In
contrast,
under
today's
PAL
regulations,
the
inquiry
begins
and
ends
with
the
source.
Your
PAL
represents
source
wide
baseline
actual
emissions.
As
such,
it
is
the
reference
point
for
calculating
increases
in
baseline
actual
emissions.
If
your
source's
emissions
will
equal
or
exceed
the
PAL,
then
there
will
be
an
emissions
increase
at
your
source.
There
is
no
need
to
calculate
increases
and
decreases
at
individual
units.
Today's
PAL
regulations
constitute
a
reasonable,
though
not
the
only,
approach
to
determining
whether
there
is
an
emissions
increase
at
your
source.
While
we
believe
that
the
principle
of
contemporaneity
continues
to
be
important
for
purposes
of
major
NSR
netting
calculations,
we
do
not
believe
that
it
is
a
necessary
concept
for
purposes
of
PALs.
This
is
because
if
your
source
has
a
PAL,
you
have
accepted
a
different
means
of
calculating
an
emissions
increase
for
the
PAL
pollutant.
The
only
relevant
question
is
whether
your
source
has
reached
or
exceeded
the
PAL
level.
Even
though
PALs
are
a
new
approach,
they
do
not
alter
the
fundamental
question,
which
is
whether
there
will
be
an
increase
in
emissions
from
your
source.
For
actuals
PALs,
we
consider
whether
there
will
be
an
increase
in
baseline
actual
emissions.
Because
the
PAL
serves
as
the
baseline
for
measuring
an
increase,
we
have
taken
steps
to
ensure
that
the
PAL
is
reasonably
representative
of
baseline
actual
emissions.
In
taking
these
steps,
we
have
also
ensured
that
actuals
PALs
as
finalized
today
are
consistent
with
the
concept
of
contemporaneity,
to
the
extent
such
a
concept
has
any
application
in
this
context.
One
way
of
viewing
a
PAL
is
to
focus
on
the
increases
and
decreases
at
individual
emissions
units
that,
taken
together,
result
in
the
net
emissions
from
your
source
as
a
whole.
As
long
as
the
decreases
that
have
occurred
during
the
term
of
the
PAL
are
sufficient
to
offset
any
increase
that
occurs,
total
emissions
for
your
source
will
remain
below
the
PAL,
and
your
source
will
not
experience
a
``
significant
net
emissions
increase.''
Viewed
from
this
perspective,
the
term
of
the
PAL
constitutes
the
``
contemporaneous''
period.
We
believe
that
10
years
is
a
reasonable
contemporaneous
period
for
PALs
for
the
following
two
reasons.
First,
we
believe
that
a
10
year
period
is
practical
and
reasonable
both
for
you
and
for
the
reviewing
authority.
While
a
logical
stopping
point
may
seem
to
be
5
years
in
line
with
the
title
V
permit
period,
setting
a
PAL
can
be
a
complex
and
time
consuming
process,
so
a
5
year
period
would
be
too
short
and
hence
not
beneficial
either
to
you
or
to
the
reviewing
authority.
Second,
a
study
conducted
by
Eastern
Research
Group,
Inc.
31
supported
a
10
year
look
back
to
ensure
that
the
normal
business
cycle
would
be
captured
generally
for
any
industry.
In
addition,
we
believe
that
the
PAL
renewal
provisions
ensure
that
each
10
year
term
represents
a
distinct
``
contemporaneous''
period.
The
renewal
process
is
designed
to
prevent
decreases
that
occurred
outside
of
the
current
10
year
PAL
term
from
being
used
to
offset
increases
during
that
term.
At
renewal,
the
reviewing
authority
must
consider
whether
decreases
have
occurred
at
your
source
because
of
compliance
with
newly
applicable
requirements.
Thus,
for
example,
if
the
compliance
date
for
a
new
RACT
requirement
occurred
during
the
initial
term
of
the
PAL,
and
the
reviewing
authority
has
not
already
adjusted
the
PAL
downward
to
account
for
that
requirement,
it
must
do
so
at
renewal.
More
generally,
the
reviewing
authority
is
required
to
evaluate
baseline
actual
emissions
and
provide
a
written
rationale
for
public
comment
if
it
determines
that
an
adjustment
to
the
PAL
is
warranted.
As
part
of
this
process,
the
reviewing
authority
must
adjust
the
PAL
downward
if
your
source's
current
PTE
is
below
the
PAL
level.
We
believe
that
this
adjustment
is
important
for
air
quality
planning
purposes.
Additionally,
the
reviewing
authority
may
renew
the
PAL
at
the
same
level
if
your
source's
baseline
actual
emissions
plus
the
significant
level
are
equal
to
or
greater
than
80
percent
of
the
PAL
level
without
consideration
of
other
factors.
We
believe
that
this
level
is
reasonably
representative
of
the
source's
baseline
actual
emissions.
If
your
source's
baseline
actual
emissions
plus
the
significant
level
are
less
than
80
percent
of
the
PAL
level,
the
reviewing
authority
may
set
the
PAL
at
a
level
that
it
determines
to
be
more
representative
of
the
source's
baseline
actual
emissions,
or
that
it
determines
to
be
appropriate
considering
air
quality
needs,
advances
in
control
technology,
anticipated
economic
growth
in
the
area,
desire
to
reward
or
encourage
the
source's
voluntary
emissions
reductions,
or
other
factors
as
specifically
identified
by
the
reviewing
authority
in
its
written
rationale.
We
recognize
that
fluctuations
in
baseline
actual
emissions
will
occur
at
most
sources
as
part
of
the
normal
business
cycle.
We
also
recognize
that
requiring
the
reviewing
authority
to
adjust
the
PAL
downward
if
your
source's
baseline
actual
emissions
do
not
equal
100
percent
of
the
PAL
level
could
create
an
incentive
for
you
to
maximize
your
baseline
actual
emissions.
In
addition,
most
sources
do
not
emit
at
a
level
just
below
the
maximum
allowable
level
but
rather
build
in
a
margin
to
prevent
accidental
exceedances.
However,
the
PAL
should
be
reasonably
representative
of
baseline
actual
emissions
so
that
it
can
continue
to
serve
as
the
baseline
for
calculating
an
emissions
increase.
We
have
balanced
these
competing
concerns
in
adopting
a
requirement,
subject
to
the
provisions
noted
below,
to
provide
discretion
to
the
reviewing
authority
to
adjust
the
PAL
level
if
baseline
actual
emissions
plus
the
significant
level
do
not
equal
at
least
80
percent
of
the
PAL
level.
To
maintain
flexibility,
today's
actuals
PAL
regulations
allow
the
reviewing
authority
to
determine
representativeness
on
a
case
by
case
basis.
If
you
believe
that
the
new
PAL
level
that
the
reviewing
authority
proposes
for
your
source
is
not
representative
of
your
source's
baseline
actual
emissions,
you
may
propose
a
different
level.
In
addition,
any
person
may
propose
a
different
level
as
being
more
representative
of
your
source's
baseline
actual
emissions.
The
reviewing
authority
may
approve
a
higher
or
lower
level
if
it
determines
that
it
is
reasonably
representative
of
your
source's
baseline
actual
emissions.
For
example,
assume
that
your
source
was
designed
to
burn
either
fuel
oil
or
natural
gas,
and
that
your
source's
permit
allowed
the
use
of
either
fuel.
During
the
initial
term
of
the
PAL,
you
used
only
natural
gas
at
the
source
and
your
source
wide
emissions
were
consistently
less
than
80
percent
of
the
PAL
level.
However,
due
to
shifting
market
conditions,
you
expected
to
use
fuel
oil
for
a
period
beginning
after
PAL
renewal.
Under
these
circumstances,
the
reviewing
authority
could
reasonably
determine
that
a
higher
level
would
be
more
representative
of
your
source's
baseline
actual
emissions.
Similarly,
your
source
might
be
designed
to
manufacture
several
different
products,
and
your
permit
might
allow
you
to
switch
from
one
product
to
another.
During
the
initial
term
of
the
PAL,
you
might
produce
a
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product
associated
with
low
emissions,
resulting
in
source
wide
emissions
that
were
consistently
less
than
80
percent
of
the
PAL
level.
However,
you
might
be
planning
to
produce
a
product
that
would
cause
the
source
to
emit
at
a
higher
level
following
PAL
renewal.
This
is
another
example
of
a
circumstance
in
which
the
reviewing
authority
could
reasonably
determine
that
a
higher
level
was
more
representative
of
your
source's
baseline
actual
emissions.
In
addition,
for
SIP
planning
purposes,
the
reviewing
authority
may
adjust
the
PAL
level
at
its
discretion
based
on
air
quality
needs,
advances
in
control
technology,
anticipated
economic
growth
in
the
area,
or
other
relevant
factors.
Because
of
the
safeguards
described
above,
we
believe
that
the
actuals
PAL
program
as
finalized
today
ensures
that
the
PAL
will
serve
as
an
appropriate
baseline
for
determining
whether
there
is
a
significant
net
``
increase''
in
overall
emissions
from
the
source,
and
thus
whether
the
source
is
undergoing
a
``
modification.''
Moreover,
we
believe
that
a
PAL
approach
satisfies
Congressional
intent
to
only
apply
the
NSR
permit
process
when
industrial
changes
cause
significant
net
emissions
increases
to
an
area
and
not
when
changes
in
plant
operations
result
in
no
emissions
increase
from
the
major
stationary
source.
See
Alabama
Power,
636
F.
2d
401.
3.
Are
PALs
Permissible
in
Serious,
Severe,
and
Extreme
Ozone
Nonattainment
Areas?
In
our
1996
proposal,
we
requested
comment
on
whether
PALs
could
be
implemented
in
serious
and
severe
ozone
nonattainment
areas
in
a
manner
that
was
consistent
with
section
182(
c)(
6)
of
the
Act.
Section
182(
c)(
6)
contains
special
provisions
for
major
stationary
sources
that
increase
VOC
emissions
in
serious
or
severe
ozone
nonattainment
areas
as
a
result
of
a
physical
change
or
a
change
in
the
method
of
operation.
In
some
of
these
areas,
the
provisions
also
apply
if
you
increase
NOX
emissions.
In
general,
these
special
provisions
change
the
significant
level
for
VOC
emissions
in
serious
and
severe
nonattainment
areas
from
40
tpy
to
greater
than
25
tpy.
They
also
specify
that
you
must
go
through
a
major
NSR
permitting
review
if
you
have
a
net
emissions
increase
in
the
aggregate
of
more
than
25
tpy
over
a
period
of
5
years.
In
addition,
we
requested
comment
on
whether
PALs
could
be
implemented
in
extreme
ozone
nonattainment
areas.
Section
182(
e)(
2),
which
applies
in
such
areas,
provides
that
any
physical
change
or
change
in
the
method
of
operation
at
the
source
that
results
in
``
any
increase''
from
any
discrete
operation,
unit,
or
other
pollutant
emitting
activity
at
the
source,
generally
must
be
considered
a
modification
subject
to
major
NSR
permit
requirements,
regardless
of
any
decreases
elsewhere
at
the
source.
A
few
industry
commenters
believe
that
the
``
accumulation''
provisions
of
CAA
section
182(
c)(
6)
should
make
no
difference
to
the
acceptability
of
a
PAL
in
``
serious''
and
``
severe''
ozone
nonattainment
areas.
They
contend
that
we
have
correctly
concluded
that
CAA
section
182(
c)(
6)
only
applies
when
net
emissions
at
the
source
as
a
whole
increase
above
the
25
ton
level.
Accordingly,
any
change
that
triggered
CAA
section
182(
c)(
6)
would
already
have
breached
the
PAL
limits.
On
the
other
hand,
an
environmental
commenter
states
that
a
PAL
in
a
serious,
severe,
or
extreme
ozone
nonattainment
area
could
be
problematic
because
it
could
allow
for
an
increase
at
an
emissions
unit
in
situations
where
source
wide
emissions
would
not
exceed
the
PAL.
We
agree
with
commenters
who
believe
that
the
PAL
approach
does
not
conflict
with
the
provisions
of
CAA
section
182(
c)(
6).
We
do
not
interpret
section
182(
c)(
6)
to
be
a
limitation
on
our
ability
to
authorize
PALs
in
serious
and
severe
nonattainment
areas.
This
section
directs
that
when
there
is
an
increase
meeting
certain
criteria,
it
may
not
be
considered
de
minimis,
but
it
does
not
specify
the
methodology
by
which
an
emissions
increase
must
be
calculated.
Accordingly,
we
exercise
our
discretion
in
establishing
the
methodology,
and
we
are
doing
so
today
by
having
the
PAL
serve
as
the
actuals
emissions
baseline
against
which
future
emissions
increases
are
measured.
Chevron
U.
S.
A.,
Inc.
v.
NRDC,
Inc.,
467
U.
S.
837,
865
(
1984).
If
your
source's
emissions
equal
or
exceed
the
PAL,
it
will
trigger
NSR,
whereas
maintaining
plant
emissions
below
the
PAL
ensures
that
there
is
no
emissions
increase.
We
believe
that
our
interpretation
reasonably
implements
the
statutory
purpose
of
the
section,
given
that
PAL
sources
agree
to
be
subject
to
a
plantwide
cap
that
serves
as
the
reference
point
for
determining
whether
there
has
been
an
increase
and
given
that
the
appropriateness
of
the
PAL
level
is
reviewed
at
10
year
intervals.
Actuals
PALs
effectively
prevent
the
uncontrolled,
unrelated,
small,
serial
emissions
increases
section
182(
c)(
6)
is
designed
to
address.
Because
CAA
section
182(
e)(
2)
clearly
requires
consideration
of
increases
at
individual
emissions
units
in
extreme
ozone
nonattainment
areas,
PALs
are
not
allowed
in
such
areas,
since
any
increase
in
emissions
from
any
unit
in
those
areas
constitutes
a
modification.
4.
Is
It
Appropriate
for
a
PAL
to
Be
Based
on
Actual
Emissions?
In
1996,
we
proposed
and
sought
comment
on
a
broad
range
of
alternative
approaches
for
setting
PAL
emission
limitations,
including
a
PAL
based
on
the
following:
(
1)
Actual
emissions
as
defined
under
the
current
and
then
proposed
regulations
at
§
51.166(
b)(
21)(
ii);
(
2)
actual
emissions
with
the
addition
of
an
operating
margin
greater
than
the
applicable
significance
rate;
(
3)
for
new
stationary
sources,
limits
established
pursuant
to
a
review
of
the
entire
facility
under
PSD;
and
(
4)
for
nonattainment
pollutants
(
in
nonattainment
areas),
any
emissions
level
completely
offset
and
relied
upon
in
an
EPA
approved
State
attainment
demonstration
plan.
61
FR
38250,
38256
(
July
23,
1996).
We
received
general
support
for
the
PAL
concept
and
for
the
different
approaches
we
proposed.
Some
comments
express
support
for
a
PAL
approach
based
on
allowable
emissions,
and
others
indicate
support
for
a
PAL
approach
based
on
actual
emissions.
Some
commenters
generally
believe
that
an
allowables
approach
is
necessary
to
ensure
increased
operating
flexibility
and
capacity
utilization.
They
also
assert
that
an
allowables
approach
would
protect
air
quality
management
goals,
because
they
claim
that
air
quality
planning
historically
has
been
based
on
permitted
emissions
levels.
Other
commenters
believe
that
an
actuals
approach
is
preferable
because
it
facilitates
more
accurate
air
quality
planning
and
provides
a
more
reliable
basis
for
determining
the
availability
of
offsets.
We
have
concluded
that
a
major
stationary
source's
compliance
with
an
actuals
based
PAL
system
is
a
permissible
means
of
assuring
that
a
major
stationary
source
does
not
have
a
significant
emissions
increase.
We
also
conclude
that
this
approach
can
be
implemented
in
a
manner
that
is
consistent
with
the
Act.
Thus,
in
today's
action,
we
are
adopting
regulations
that
authorize
States
to
issue
actuals
PALs.
We
plan
to
address
allowables
PALs
in
an
upcoming
rulemaking.
5.
How
Should
Actual
Emissions
Be
Determined
in
Setting
the
PAL
Level?
In
the
1996
proposal,
we
requested
comment
on
whether
the
definition
of
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Regulations
actual
emissions
for
the
purpose
of
determining
the
level
of
the
PAL
should
be
based
on
the
definition
of
actual
emissions
in
the
current
major
NSR
regulations,
or
whether
it
should
be
based
on
the
proposed
revisions
to
the
actual
emissions
definition
contained
in
that
1996
proposal.
The
fundamental
difference
between
these
two
approaches
is
that
the
current
NSR
regulations
would
only
allow
you
to
look
back
5
years
to
determine
the
actual
emissions
(
the
sum
of
actual
emissions
for
all
emissions
units
at
your
major
stationary
source).
The
1996
proposed
changes
to
this
definition
would
allow
you
to
look
back
10
years
to
determine
the
actual
emissions.
Several
commenters
prefer
a
10
year
baseline
period
for
setting
PALs
based
on
actual
emissions.
A
few
commenters
prefer
a
5
year
baseline
period.
One
commenter
advocates
use
of
an
actual
emissions
level
that
is
initially
based
on
the
previous
2
years
but
that
would
decline
over
time.
In
a
separate
section
of
today's
final
rules,
we
are
finalizing
changes
to
our
definition
of
baseline
actual
emissions.
Among
other
changes
to
the
definition,
you
will
be
allowed
to
look
back
for
a
period
of
10
years
to
establish
the
baseline
actual
emissions
(
except
for
EUSGUs).
For
program
consistency
and
ease
of
implementation,
we
believe
that
the
procedure
for
determining
the
baseline
actual
emissions
for
establishing
your
PAL
should
be
the
same
as
the
baseline
actual
emissions
that
you
will
be
required
to
use
under
the
other
major
NSR
program
requirements.
Accordingly,
we
are
adopting
an
approach
for
establishing
your
actuals
PAL
that
is
consistent
with
how
the
baseline
actual
emissions
are
determined
for
an
emissions
unit
under
other
requirements
of
the
major
NSR
program.
We
are,
however,
including
a
special
allowance
for
emissions
units
that
have
operated
for
less
than
2
years.
Under
such
circumstances,
the
emissions
unit
has
not
operated
long
enough
to
establish
a
reliable
baseline
actual
emissions
calculation.
Therefore,
today's
rule
allows
your
reviewing
authority
to
consider
the
allowable
emissions
of
such
emissions
units
when
establishing
or
renewing
the
PAL.
The
baseline
actual
emissions
of
such
emissions
units
would
be
adjusted
to
reflect
a
more
representative
level
of
baseline
actual
emissions
at
the
time
of
the
next
PAL
renewal.
6.
Are
Emissions
From
Shut
Down
or
Dismantled
Units
Excluded
From
a
PAL?
We
proposed
several
options
to
adjust
PAL
levels
to
account
for
emissions
units
that
are
shut
down
or
dismantled
before
setting
a
PAL.
Several
commenters
support
adjusting
the
PAL
level
for
permanently
shut
down
or
dismantled
units.
A
few
commenters
maintain
that
PAL
adjustments
are
only
appropriate
for
long
term
shutdowns.
Other
commenters
oppose
allowing
adjustments
for
shutdowns.
They
indicate
that
it
would
be
difficult
to
implement
and
that
it
could
penalize
sources
that
were
meeting
environmental
goals.
We
agree
with
commenters
that
the
baseline
actual
emissions
used
in
establishing
the
PAL
should
exclude
emissions
from
units
that
are
permanently
shut
down
or
dismantled
after
the
24
month
period
selected
for
establishment
of
baseline
emissions.
We
believe
that
excluding
such
emissions
from
your
PAL
level
is
appropriate
for
air
quality
planning
purposes.
Moreover,
the
environment
has
already
seen
the
benefit
of
the
reduced
emissions.
We
also
do
not
agree
with
those
commenters
who
advocate
adjusting
the
PAL
only
for
long
term
shutdowns,
because
it
is
too
difficult
to
define
and
enforce
``
long
term.''
As
described
in
section
IV.
C.
2
of
this
preamble,
the
PAL
level
includes
baseline
actual
emissions
from
each
existing
emissions
unit
and
new
emissions
unit
at
the
source.
For
any
emissions
unit
that
has
been
permanently
shut
down
since
the
24
month
period,
its
emissions
should
not
be
included
in
calculating
the
PAL
level.
Conversely,
for
an
emissions
unit
that
began
construction
after
the
24
month
period,
the
emissions
(
equal
to
the
potential
emissions
of
that
emissions
unit)
must
be
included
in
setting
the
PAL
level.
One
shutdown
option
we
considered,
but
did
not
adopt,
is
to
exclude
emissions
from
PALs
only
for
units
that
did
not
operate
at
all
during
the
10
year
life
of
the
PAL.
Under
this
option,
the
PAL
would
not
be
adjusted
downward
if
you
utilized
those
emissions
from
the
shut
down
or
dismantled
units
elsewhere
at
your
source
during
the
period
since
the
shutdown
(
for
example,
by
adding
new
emissions
units
or
capacity,
or
by
increasing
capacity
utilization
at
existing
emissions
units).
As
we
indicated
in
our
proposal,
we
believe
it
would
be
too
difficult
to
determine
whether
you
have
actually
relied
on
these
emissions
decreases
in
undertaking
other
activities
at
your
source.
We
did
not
receive
any
comments
suggesting
ways
to
overcome
this
identified
problem.
7.
Does
a
PAL
Include
a
Reasonable
Operating
Margin?
In
the
July
23,
1996
action,
we
proposed
that
a
PAL
for
existing
sources
be
based
on
source
wide
actual
emissions,
including
a
reasonable
operating
margin
less
than
the
applicable
significant
emissions
rate.
We
also
requested
comment
on
several
other
options
for
establishing
a
PAL.
Several
commenters
support
the
option
of
basing
the
PAL
on
source
wide
actual
emissions
plus
a
reasonable
operating
margin
less
than
the
applicable
significance
amount.
Other
commenters
believe
an
operating
margin
tied
to
significant
levels
would
be
too
restrictive.
Today
we
are
finalizing
an
option
that
allows
you
to
include,
when
setting
the
initial
PAL,
an
amount
that
corresponds
to
the
significant
level
for
modifications
of
the
PAL
pollutant
as
specified
in
the
major
NSR
rules
[
for
example,
in
the
PSD
regulations
at
§
52.21(
b)(
23)(
i)],
or
as
specified
in
the
CAA,
whichever
is
lower.
For
example,
for
SO2
PALs
you
may
add
to
the
PAL
baseline
level
the
40
tpy
significant
level;
for
CO
PALs
you
may
add
100
tpy
to
the
PAL
baseline
level.
Also,
for
serious
and
severe
ozone
nonattainment
areas
the
VOC
significant
level
added
to
the
PAL
level
is
25
tpy.
For
major
sources
of
NOX
located
in
serious
and
severe
ozone
nonattainment
areas,
where
NOX
is
regulated
as
an
ozone
precursor,
you
may
add
to
the
NOX
PAL
baseline
the
NOX
significant
level
of
25
tpy,
and
not
the
40
tpy
NOX
significant
level
specified
under
PSD.
In
extreme
ozone
nonattainment
areas,
PALs
are
not
allowed
since
any
increase
in
emissions
in
these
areas
constitutes
a
modification.
While
other
approaches
to
providing
a
reasonable
operating
margin
may
be
consistent
with
the
CAA,
we
believe
that
the
approach
we
are
adopting
today
comports
most
closely
with
existing
regulatory
provisions
for
major
NSR
applicability.
That
is,
it
assures
that
the
environment
sees
no
significant
increases
in
emissions
compared
to
the
baseline
actual
emissions
existing
before
the
PAL
is
established.
In
our
1998
NOA,
we
also
requested
comment
on
whether
we
should
provide
for
an
operating
margin
when
renewing
a
PAL.
We
proposed
four
possible
approaches
for
maintaining
a
reasonable
operating
margin,
including
an
option
that
would
include
in
the
adjusted
PAL
level
an
operating
cushion
equal
to
20
percent
of
the
current
PAL.
In
a
separate
section
of
the
NOA,
we
also
requested
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251
/
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December
31,
2002
/
Rules
and
Regulations
comment
on
how
PALs
should
be
adjusted
for
emissions
units
that
have
installed
good
emissions
controls.
Many
commenters
indicate
that
we
must
provide
for
a
reasonable
operating
margin.
However,
we
generally
received
unfavorable
comments
on
all
the
approaches
we
suggested.
Several
commenters
believe
that
our
suggested
approaches
do
not
provide
an
adequate
operating
margin.
In
responding
to
our
request
for
comment
on
how
to
adjust
PALs
for
emissions
units
that
have
installed
good
emissions
controls,
many
commenters
indicate
that
it
would
be
inappropriate
for
EPA
to
``
confiscate''
such
emissions
reductions.
Such
an
approach
would
encourage
sources
to
pollute
to
maintain
higher
baseline
emissions,
and
would
penalize
those
sources
who
would
voluntarily
reduce
emissions.
At
least
one
commenter
maintains
that
both
you
and
the
environment
should
benefit
from
these
reductions,
and
thus,
you
should
be
allowed
to
retain
a
portion
of
your
voluntary
emissions
reductions.
We
agree
with
some
commenters
that
mandating
an
adjustment
at
renewal,
based
solely
on
current
operations
and
emissions
levels,
would
discourage
the
voluntary
emissions
reductions
the
PAL
is
specifically
designed
to
encourage.
We
agree
with
commenters
that
both
you
and
the
environment
should
benefit
from
your
commitment
to
comply
with
a
PAL.
Should
you
engage
in
voluntary
emissions
reductions,
we
believe
you
should
be
able
to
retain
the
accompanying
flexibility
that
encouraged
you
to
make
these
reductions.
At
the
time
of
renewal,
it
may
be
very
difficult
for
a
reviewing
authority
to
distinguish
the
reason
for
a
decrease
in
your
baseline
actual
emissions
level.
It
could
be
because
you
have
aggressively
applied
emissions
controls,
or
because
of
a
decrease
in
utilization,
a
loss
of
capacity,
a
desire
to
maintain
a
compliance
margin,
or
any
of
a
number
of
other
reasons.
Accordingly,
we
believe
that
it
would
be
difficult
to
advise
a
reviewing
authority
to
only
retain
a
certain
percentage
of
your
emissions
reductions
that
resulted
from
applying
emissions
controls.
Therefore,
for
simplicity,
and
for
what
we
believe
to
be
a
reasonable
policy
position
to
encourage
you
to
voluntarily
reduce
emissions
without
a
fear
of
a
complete
loss
of
operational
flexibility,
we
are
allowing
your
reviewing
authority
discretion
to
renew
the
PAL
at
an
appropriate
level.
Hence,
your
reviewing
authority
may
renew
the
PAL
at
the
same
level
without
consideration
of
other
factors,
if
the
baseline
actual
emissions
plus
the
significant
level
is
equal
to
or
greater
than
80
percent
of
the
PAL
level.
If
not,
today's
rules
also
allow
your
reviewing
authority
to
renew
the
PAL
at
a
different
level
if
it
determines
that
level
is
more
representative
of
baseline
actual
emissions.
See
section
II.
D.
9,
``
Should
we
require
PALs
to
be
adjusted
at
the
time
of
PAL
renewal,''
for
more
information
on
our
rationale
for
allowing
this
discretion.
8.
Are
PALs
Required
to
Expire?
In
our
1998
NOA,
we
announced
that
we
were
considering,
and
requested
comment
on,
an
approach
that
would
require
PALs
to
expire
after
10
years
unless
you
choose
to
renew
the
PAL.
We
proposed
that
the
PAL
term
would
be
10
years.
Several
commenters
agree
with
our
suggested
time
frame
of
10
years
for
the
term
of
a
PAL.
Others
support
a
5
year
period,
which
would
fit
with
the
title
V
permit
review
period.
Some
commenters
support
a
period
longer
than
10
years.
Today,
we
are
finalizing
rules
that
require
a
PAL
to
be
effective
for
a
period
of
10
years.
We
believe
that
a
fixed
term
PAL
provides
you
with
an
appropriate
time
of
regulatory
certainty
and
allows
a
sufficient
period
of
time
for
planning
long
term
capital
improvements.
We
also
agree
with
those
commenters
who
think
it
is
beneficial
to
align
the
PAL
renewal
process
with
the
title
V
permitting
process
for
your
major
stationary
source.
Similar
to
a
PAL
permit
process,
the
title
V
permit
process
provides
the
public
with
a
comprehensive
review
of
your
source.
We
believe
that
aligning
the
PAL
permit
with
the
title
V
process
will
allow
you
and
your
reviewing
authority
to
consolidate
the
administrative
process
for
the
two
permitting
actions.
It
also
provides
the
public
with
a
better
understanding
of
your
emissions
characteristics
relative
to
the
surrounding
community.
However,
we
do
not
believe
that
requiring
PALS
to
be
reviewed
every
5
years,
consistent
with
the
title
V
renewal
period,
provides
industry
with
a
sufficient
period
of
regulatory
certainty.
We
also
believe
that
while
the
overall
administrative
burden
for
you
and
the
reviewing
authority
is
reduced
if
you
are
complying
with
a
PAL,
the
establishment
of
a
PAL
requires
an
initial
commitment
of
substantial
resources.
Given
this
initial
resource
investment,
we
do
not
believe
that
a
5
year
fixed
term
for
a
PAL
provides
you
or
your
reviewing
authority
with
an
adequate
incentive
to
participate
in
the
PAL
system.
Thus,
in
an
effort
to
balance
the
need
for
regulatory
certainty,
the
administrative
burden,
and
a
desire
to
align
the
PAL
renewal
with
the
title
V
permit
renewal,
we
believe
a
fixed
term
of
10
years,
the
equivalent
of
two
title
V
effective
periods
(
10
years),
is
most
appropriate.
You
may
elect
to
renew
your
PAL
after
10
years,
for
a
subsequent
10
year
period,
rather
than
allow
the
PAL
to
expire.
In
order
to
align
the
PAL
renewal
process
with
the
title
V
permitting
process,
we
suggest
that
you
request
that
the
reviewing
authorities
renew
title
V
permits
concurrent
with
issuance
of
the
initial
PAL
permit,
regardless
of
how
many
years
are
actually
left
on
your
title
V
permit.
9.
Are
PALs
Required
To
Be
Adjusted
at
the
Time
of
PAL
Renewal?
In
1996,
we
requested
comment
on
``
why,
how,
and
when
a
PAL
should
be
lowered
or
increased
without
being
subject
to
major
NSR.''
In
1998,
we
announced
that
we
were
considering
an
option
that
required
PALs
to
be
renewed
to
reflect
new
current
baseline
actual
emissions.
We
were
also
considering
requiring
a
PAL
to
be
adjusted
for
unused
capacity.
Under
this
approach,
we
would
adjust
a
PAL
downward
when
an
emissions
unit
operates
below
the
capacity
level
that
was
used
to
establish
the
PAL.
In
our
1998
NOA,
we
expressed
three
reasons
why
it
might
be
appropriate
to
require
PALs
to
be
periodically
adjusted.
First,
we
expressed
concern
that
the
allowable
toallowable
applicability
system
of
the
PAL
would
allow
you
to
indefinitely
retain
the
right
to
pollute
at
an
historical
level
of
actual
emissions.
Second,
we
were
concerned
that
a
PAL
may
allow
you
to
retain
unused
emissions
credits
that
would
otherwise
be
available
for
economic
growth
in
the
area.
And
third,
we
were
concerned
that
a
PAL
may
interfere
with
a
State's
ability
to
plan
for
attainment
if
your
actual
emissions
to
the
atmosphere
are
lower
during
a
SIP
planning
year
than
in
a
subsequent
year.
Some
commenters
generally
oppose
any
periodic
reviewing
or
adjustment
of
a
PAL.
They
believe
that
such
an
approach
would
limit
operational
flexibility,
discourage
efficiency
improvements,
and
create
disincentives
for
voluntary
reductions.
However,
other
commenters
generally
support
an
approach
that
would
require
a
periodic
adjustment
to
PALs.
We
continue
to
have
concerns
with
an
approach
that
would
allow
a
PAL
to
be
renewed
without
any
evaluation
of
the
appropriateness
of
the
current
PAL
level.
We
believe
such
an
approach
would
be
contrary
to
the
Act,
and
contrary
to
the
court's
decision
in
WEPCO
v.
Reilly,
893
F.
2d
901,
908
(
7th
Circ.
1990).
In
WEPCO,
the
court
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Federal
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
determined
that
one
statutory
purpose
of
the
NSR
requirements
is
``
to
stimulate
the
advancement
of
pollution
control
technology,''
and
that
``
allowing
increased
production
(
and
pollution)
through
the
extensive
replacement
of
deteriorated
generating
system''
without
triggering
NSR
review
would
create
``
vistas
of
indefinite
immunity
from
the
provisions
of
*
*
*
PSD.''
We
believe
today's
rules
avoid
this
inappropriate
outcome,
by
requiring
the
reviewing
authority
to
evaluate
your
baseline
actual
emissions
at
the
time
of
PAL
permit
renewal.
Although
we
believe
that
a
periodic
review
of
the
level
of
the
PAL
may
be
necessary,
and
that
this
may
result
in
an
adjustment
in
your
PAL
to
a
level
that
is
representative
of
your
baseline
actual
emissions,
we
do
not
believe
that
we
should
mandate
an
adjustment
to
the
PAL
based
on
only
one
prescribed
methodology.
Such
an
approach
could
lead
to
inappropriate
results,
as
discussed
below.
Instead,
we
believe
that
our
concerns
can
be
appropriately
addressed
by
providing
the
States
the
authority
to
adjust
the
PAL
based
on
what
is
representative
of
your
baseline
actual
emissions.
We
believe
that
some
discretion
in
determining
what
is
representative
of
actual
emissions
is
appropriate,
based
in
part
on
our
experience
with
the
pilot
projects
previously
mentioned.
In
one
instance,
a
participant
voluntarily
agreed
to
reduce
its
actual
emissions
by
54
percent
in
exchange
for
obtaining
a
source
wide
emissions
cap.
After
agreeing
to
this
emissions
reduction,
the
participant
further
reduced
emissions
by
increasing
capture
efficiency
and
incorporating
pollution
prevention
strategies
into
its
operations.
Unexpectedly,
the
participant
also
suffered
an
unusual
economic
downturn
that
caused
a
decrease
in
the
rate
of
production
and
a
corresponding
decrease
in
actual
emissions.
At
the
time
of
renewal
of
the
source
wide
emissions
cap,
the
participant's
actual
emissions
were
10
percent
of
its
actual
emissions
before
committing
to
the
emissions
cap.
The
participant
chose
not
to
renew
its
emissions
caps,
because
renewal
required
an
automatic
adjustment
to
its
current
actual
emissions
level.
Clearly,
such
a
result
contravenes
the
mutual
benefits
operating
under
a
PAL
provides,
and
discourages
you
from
undertaking
voluntary
reductions.
Accordingly,
although
today's
final
rules
require
the
reviewing
authority
to
consider
the
need
for
adjusting
the
PAL
when
your
current
baseline
actual
emissions
plus
the
significant
level
are
less
than
80
percent
of
your
PAL
level,
it
also
provides
the
reviewing
authority
discretion
to
consider
a
variety
of
factors
in
determining
whether
the
PAL
should
be
adjusted.
We
are
also
providing
your
reviewing
authority
discretion
to
take
into
account
measures
necessary
to
prevent
a
violation
of
a
NAAQS
or
PSD
increment,
and
to
prevent
an
adverse
impact
on
an
AQRV
in
a
Federal
Class
I
area.
For
example,
although
we
remain
concerned
that
a
PAL
may
allow
you
to
retain
unused
emissions
credits
that
would
otherwise
be
available
for
economic
growth
in
your
area,
we
believe
that
managing
an
area's
economic
growth
is
the
primary
responsibility
of
the
State.
As
such,
the
State,
through
your
reviewing
authority,
should
have
discretion
to
manage
the
growth
increment
for
your
area.
If
your
State
wishes
to
encourage
economic
growth,
then
it
may,
at
its
discretion,
reduce
your
PAL
for
that
reason.
Conversely,
it
may
decide
that
encouraging
economic
growth
is
not
a
priority
for
the
area
and
concurrently
find
no
other
concerns
that
warrant
a
downward
adjustment
in
your
PAL.
After
further
reflection,
we
also
believe
that
it
is
inappropriate
for
us
to
mandate
in
all
cases
a
prescribed
methodology
for
adjusting
PALs
based
on
our
concern
that
a
PAL
system
may
interfere
with
a
State's
ability
to
plan
for
attainment.
We
believe
that
the
concern
regarding
planning
for
attainment
is
not
unique
to
a
PAL
system.
Most
importantly,
nothing
in
this
rule
reduces
the
State's
discretion
in
developing
plans
to
attain
and
maintain
NAAQS.
Under
our
major
NSR
applicability
system,
you
could
increase
your
emissions
over
your
historical
actual
emissions
by
increasing
utilization
or
hours
of
operation.
If
this
occurs,
there
may
be
a
discrepancy
between
the
amount
the
State
carries
in
the
emissions
inventory
and
the
amount
that
you
emit
to
the
atmosphere.
States
should
be
cognizant
of
these
issues
and
take
appropriate
measures
in
their
SIP
planning
procedures
to
assure
that
emissions
from
any
major
stationary
source,
including
a
PAL
participant,
are
properly
characterized
in
the
emissions
inventory.
And
finally,
we
agree
with
industry
commenters
that
if
we
were
to
mandate
an
adjustment
because
your
baseline
actual
emissions
did
not
equal
100
percent
of
the
PAL
level,
it
would
encourage
you
to
increase
production
and
emissions,
and
such
an
outcome
would
be
counterproductive.
We
have
accordingly
provided
your
reviewing
authority
the
ability
to
add
a
reasonable
operating
margin
to
your
baseline
actual
emissions
at
the
time
of
renewal.
This
operating
margin
was
discussed
previously
in
section
II.
D.
7
above
`
`
Should
a
PAL
include
a
reasonable
operating
margin?''
10.
Are
Certain
New
Emissions
Units
That
Are
Added
Under
a
PAL
Required
To
Meet
Some
Level
of
Emissions
Control?
We
solicited
comments
on
whether
we
should
require
you
to
control
emissions
from
new
emissions
units
that
are
added
under
an
established
PAL.
Several
commenters
believe
that
BACT
or
LAER
should
not
be
required
for
these
emissions
units.
A
few
commenters
favor
adding
a
requirement
that
BACT
or
LAER
be
required
on
new
emissions
units.
We
believe
that
it
is
unnecessary
to
mandate
a
specific
control
level
on
new
emissions
units
that
you
add
under
an
established
PAL.
After
reviewing
the
performance
of
a
limited
number
of
facilities
that
are
participating
in
PAL
pilot
projects,
we
have
concluded
that
these
facilities'
desire
to
maintain
a
large
degree
of
operational
flexibility
under
a
PAL
system
has
encouraged
them
to
voluntarily
install
state
of
theart
controls
on
new
emissions
units.
(
See
footnote
26
regarding
our
study,
``
Evaluation
of
the
Implementation
Experience
with
Innovative
Air
Permits.'')
We
anticipate
similar
results
as
we
extend
the
PAL
program
more
broadly.
Alternatively,
we
believe
that
you
will
add
emissions
controls
to
existing
emissions
units
if
this
is
a
more
cost
effective
approach
to
controlling
your
emissions.
This
is
precisely
the
type
of
flexibility
you
should
have
for
managing
your
total
source
wide
emissions
under
a
PAL
system.
Furthermore,
this
cost
effective
approach
was
contemplated
and
supported
by
the
statements
of
the
court
in
Alabama
Power.
The
court
concluded
that
you
should
be
allowed
to
add
new
emissions
units
if
the
new
emissions
from
this
unit
could
be
``
set
off
against
decreases''
from
other
emissions
units
at
the
major
stationary
source.
Accordingly,
we
do
not
believe
that
it
is
necessary
to
mandate
the
installation
of
emissions
controls
on
new
emissions
units
if
you
are
able
to
continue
to
comply
with
your
PAL
even
after
installing
the
new
emissions
unit.
If
our
projections
on
this
matter
prove
to
be
incorrect
in
practice,
we
will
consider
revising
our
regulations
in
the
future
to
require
a
specific
control
level
on
new
and/
or
existing
emissions
units.
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
11.
Under
What
Circumstances
Are
You
Allowed
To
Increase
Your
PAL
and
How
Are
the
Major
NSR
Requirements
Applied
To
That
Increase?
We
proposed
that
whenever
a
PAL
is
increased
due
to
the
addition
of
a
new
unit,
or
due
to
a
physical
or
operational
change
to
an
existing
emissions
unit,
the
units
associated
with
the
increase
would
be
reviewed
for
current
BACT
or
current
LAER,
air
quality
impacts
modeling,
and
emissions
offsets,
if
applicable.
We
noted
that
it
may
be
difficult
for
a
reviewing
authority
to
determine
which
emissions
units
are
associated
with
a
physical
change
or
change
in
method
of
operation
when
the
emissions
increase
is
the
result
of
a
source
wide
production
increase.
We
requested
comment
on
five
possible
ways
to
apply
the
major
NSR
requirements
when
emissions
increases
are
not
directly
associated
with
a
particular
change.
Commenters
offered
various
suggestions
for
addressing
emissions
increases
above
the
PAL.
Several
commenters
believe
that
major
NSR
should
only
be
applied
to
the
emissions
unit
primarily
responsible
for
the
increase.
Among
the
various
commenters,
there
are
a
few
supporters
for
each
one
of
the
options
we
proposed.
In
addition,
one
commenter
suggests
that
we
add
de
minimis
increase
levels;
another
suggests
that
we
require
offsets
for
each
increase.
Several
industry
commenters
believe
that
we
should
not
apply
major
NSR
when
an
increase
above
the
PAL
is
solely
due
to
a
production
increase.
One
commenter
believes
all
increases
should
be
subject
to
BACT.
After
considering
the
comments
received,
we
agree
with
the
commenters
who
believe
that
major
NSR
should
only
be
applied
to
the
emissions
units
(
either
new
or
modifications
of
existing
units)
primarily
causing
the
increase.
Accordingly,
in
the
final
regulations,
we
are
confirming
our
proposed
requirement
that
only
those
emissions
units
that
are
part
of
a
PAL
major
modification
would
be
subject
to
major
NSR.
As
discussed
earlier,
we
believe
that
a
PAL
provides
you
with
an
incentive
to
control
existing
and
new
emissions
units
to
maximize
your
operational
flexibility
under
your
PAL.
We
also
recognize
that
there
may
be
valid
economic
reasons
for
requesting
an
upward
adjustment
in
a
PAL.
We
are,
however,
concerned
that
if
there
were
no
restrictions
on
your
ability
to
request
a
PAL
increase,
you
would
not
have
an
incentive
to
control
emissions.
Therefore,
under
today's
final
rules,
before
the
reviewing
authority
may
approve
a
mid
term
increase
in
your
PAL,
you
must
demonstrate
that
you
are
unable
to
maintain
emissions
below
your
current
PAL
even
with
a
good
faith
effort
to
control
emissions
from
existing
emissions
units.
To
make
this
demonstration,
you
must
show
that
even
if
BACT
equivalent
control
(
adjusted
for
a
current
BACT
level
of
control
unless
the
emissions
units
are
currently
subject
to
a
BACT
or
LAER
requirement
that
has
been
determined
within
the
preceding
10
years,
in
which
case
the
assumed
control
level
shall
be
equal
to
the
emissions
unit's
existing
BACT
or
LAER
control
level)
were
to
be
applied
to
all
of
your
significant
and
major
emissions
units,
the
resulting
emissions
level
will
exceed
your
current
PAL
when
combined
with
the
emissions
from
both
your
small
emissions
units
and
your
new
emissions
unit's
allowable
emissions.
12.
What
Compliance
Monitoring,
Reporting,
Recordkeeping,
and
Testing
(
MRRT)
Requirements
Are
Necessary
to
Ensure
the
Enforceability
of
PALs
as
a
Practical
Matter?
The
MRRT
requirements
for
PALs
are
addressed
below.
Numerous
commenters,
generally
State
agencies
and
environmental
groups,
state
that
adequate
monitoring,
reporting,
and
recordkeeping
requirements
would
be
necessary
to
ensure
that
the
PAL
limits
were
enforceable.
Some
commenters
hold
that
the
monitoring,
recordkeeping,
and
reporting
provisions
would
be
too
burdensome
and
restrictive.
Some
believe
that
PALs
would
not
be
viable
because
of
these
requirements.
Several
commenters
request
that
we
clarify
the
monitoring
that
is
necessary
to
show
compliance
with
a
PAL,
especially
in
relation
to
the
CAM
and
title
V
programs.
Several
commenters
prefer
that
the
monitoring
requirements
be
flexible
and
simple.
These
commenters
urge
us
not
to
use
CAM,
require
CEMS,
or
establish
stringent
protocols.
A
few
commenters
prefer
that
we
not
define
what
would
be
enforceable
as
a
practical
matter
for
PAL
limits.
Others
insisted
that
the
PAL
limits
must
be
federally
enforceable.
We
believe
that
the
PAL
must
assure
that
the
source
maintains
emissions
below
the
PAL
level
to
assure
that
major
NSR
does
not
apply.
Therefore,
we
agree
with
the
commenters
who
stated
that
adequate
data
collection
requirements
through
means
such
as
monitoring,
reporting,
and
recordkeeping
requirements
are
necessary
to
ensure
that
the
PAL
limits
are
enforceable
as
a
practical
matter.
In
fact,
we
find
that
not
only
monitoring,
recordkeeping,
and
reporting
requirements,
but
also
emissions
testing
requirements,
for
emissions
units
subject
to
a
PAL
differ
from
other
MRRT
in
one
important
aspect:
actual
unit
emissions
must
be
measured
to
provide
a
12
month
rolling
total,
and
compared
against
a
limit.
Currently,
many
emissions
units
are
required
only
to
have
MRRT
suitable
for
initial
or
spot
checks
on
emissions
concentrations,
not
emissions
quantification.
Even
emissions
units
whose
MRRT
meets
the
title
V
requirements
in
§
§
70.6(
a)(
3)(
i)(
B)
or
70.6(
c)(
1),
including
those
imposed
by
part
64
(
the
CAM
rule),
may
need
to
be
upgraded
when
those
units
are
proposed
to
become
subject
to
a
PAL,
because
the
approved
title
V
MRRT
may
not
be
able
to
count
emissions
against
a
cap.
While
we
believe
you
can
obtain
data
for
emissions
quantification
best
through
the
use
of
CEMS
or
PEMS,
in
today's
final
rule
we
are
allowing
you
to
propose
other
types
of
emissions
monitoring
quantification
systems,
depending
upon
such
factors
as
the
size
category
of
the
emissions
unit
and
its
margin
of
compliance.
13.
Is
EPA
Adopting
an
Approach
That
Allows
Area
Wide
PALs?
In
1996,
we
proposed
an
option
that
would
allow
a
State
to
adopt
an
areawide
PAL
approach.
Under
such
an
approach,
all
major
stationary
sources
within
a
given
geographic
area
would
have
a
PAL.
Our
1996
proposal
contained
little
detail
on
how
this
would
be
implemented.
While
a
few
commenters
support
area
wide
PALs,
many
more
oppose
them.
State
agency
commenters
generally
believe
they
would
need
time
to
develop
PALs
consistent
with
the
approaches
provided
in
the
final
NSR
rule,
as
well
as
to
develop
data
management
and
compliance
assurance
approaches
that
would
accommodate
the
PAL
approach.
Thus,
adding
the
area
wide
PAL
at
the
same
time
as
the
source
specific
PAL
may
create
several
administrative
headaches.
Industry
commenters
maintain
that
area
wide
PALs
would
ratchet
down
emissions
and
reduce
flexibility.
We
agree
with
the
many
commenters
who
opposed
an
area
wide
PAL
system,
believing
that
the
approach
would
be
complex
and
resource
and
time
intensive.
We
also
perceived
little
interest
in
such
an
approach
from
the
various
stakeholders
with
whom
we
have
met.
Accordingly,
we
are
not
including
any
provisions
in
our
final
rules
to
implement
an
area
wide
PAL
system.
However,
we
are
not
precluding
such
a
program
either.
If
a
State
currently
has
or
wants
to
pursue
an
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
area
wide
PAL
program,
then
it
must
demonstrate
that
its
program
is
equivalent
to
or
more
stringent
than
our
final
rules.
14.
When
Should
Modeling
or
Other
Types
of
Ambient
Impact
Assessments
Be
Required
for
Changes
Occurring
Under
a
PAL?
In
our
1996
proposal,
we
requested
comment
on
when
modeling
or
other
air
quality
impacts
analysis
is
needed
for
changes
occurring
under
a
PAL
to
demonstrate
protection
of
NAAQS,
increments,
and
AQRVs.
One
environmental
commenter
recommends
modeling
or
other
types
of
ambient
impacts
assessment
whenever
a
change
in
emissions
occurred
under
the
PAL.
One
commenter
recommends
that
FLMs
be
consulted
whenever
changes
under
the
PAL
are
proposed,
to
determine
whether
an
impact
analysis
for
adverse
impact
on
AQRVs
would
be
necessary.
Several
commenters
recommend
modeling
whenever
a
significant
change
occurred,
but
also
recommend
that
EPA
define
significant
change
and
how
the
modeling
would
be
conducted.
A
facility
could
report
the
modeled
effects
of
a
minor
change
after
the
change
is
made
(
in
a
quarterly,
semiannual
or
perhaps
annual
modeling
summary),
while
more
significant
changes
should
be
modeled
prior
to
construction.
The
facility
could
be
given
a
lot
of
responsibility
in
these
cases
and
then
held
accountable
(
that
is,
required
to
mitigate)
should
an
air
quality
increment
or
NAAQS
be
exceeded.
These
commenters
also
recommend
that
the
impacts
evaluation
should
be
conducted
at
the
time
the
PAL
is
established
and
that
the
PAL
should
clearly
define
what
flexibility
the
source
is
allowed
without
further
review
and
the
types
of
changes
for
which
additional
review
will
be
required.
Some
commenters
generally
believe
that
the
proposed
regulatory
language
concerning
changes
to
PALs
for
air
quality
reasons
was
too
vague
and
broad,
but
only
a
few
of
these
commenters
directly
oppose
modeling
for
changes
under
the
PAL.
One
commenter
states
that
if
many
changes
were
to
require
ambient
air
quality
analysis,
the
PAL
approach
would
have
little
if
any
benefit.
The
commenter
believes
that
sources
ought
to
discuss
up
front
with
permit
authorities
which
emissions
shifts
might
have
consequences
that
would
later
require
additional
modeling/
monitoring.
If
questions
existed
about
certain
emissions
sources
under
a
PAL,
PALs
could
be
approved
with
conditions
assuring
that
certain
post
approval
modeling
analysis
be
submitted.
In
today's
final
rules,
we
believe
we
can
rely
on
the
reviewing
authority's
existing
programs
for
addressing
air
quality
issues.
Certain
changes
in
effective
stack
parameters
under
the
PAL
would
generally
be
covered
by
the
reviewing
authority's
minor
NSR
construction
permit
program.
The
reviewing
authority
would
ordinarily
request
air
quality
modeling
for
any
changes
if
it
believes
that
the
changes
under
the
PAL
may
affect
the
NAAQS
and
PSD
increments.
V.
Clean
Units
A.
Introduction
In
today's
final
rulemaking,
we
are
promulgating
a
new
type
of
applicability
test
for
emissions
units
that
are
designated
as
Clean
Units.
This
new
applicability
test
will
measure
whether
an
emissions
increase
occurs,
based
on
whether
the
physical
change
or
change
in
the
method
of
operation
affects
the
Clean
Unit
status
of
the
unit.
This
new
applicability
test
provides
that
when
you
meet
emission
limitations
based
on
installing
state
of
the
art
emissions
control
technologies
(
add
on
control
technology,
pollution
prevention
techniques,
or
work
practices)
that
are
determined
to
be
BACT
or
LAER,
you
may
make
any
physical
or
operational
changes
to
the
Clean
Unit
without
triggering
major
NSR,
unless
the
change
causes
the
need
for
a
revision
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
adopted
in
conjunction
with
BACT,
LAER,
or
Clean
Unit
determinations,
or
would
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT,
LAER,
or
Clean
Unit
determination
for
a
particular
unit.
Emissions
units
that
have
not
been
through
major
NSR
may
also
qualify
for
the
Clean
Unit
applicability
test
if
you
demonstrate
that
their
emission
limitations
based
on
their
emissions
control
technology
(
that
is,
add
on
control
technology,
pollution
prevention
technique,
or
work
practice)
is
comparable
to
BACT
or
LAER
and
you
demonstrate
that
the
allowable
emissions
will
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
To
be
comparable
to
BACT/
LAER,
the
controls
must
meet
the
specific
comparability
test
that
we
describe
in
section
V.
C.
3
of
this
preamble.
That
is,
you
must
show
that
the
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
is
comparable
to
BACT/
LAER
in
one
of
two
ways:
(
1)
By
comparing
your
emissions
unit's
control
level
to
BACT/
LAER
determinations
for
other
similar
sources
in
the
RACT/
BACT/
LAER
Clearinghouse
(
RBLC);
or
(
2)
by
making
a
case
by
case
demonstration
that
your
emissions
control
is
``
substantially
as
effective''
as
BACT
or
LAER.
The
Clean
Unit
applicability
test
benefits
the
public
and
the
environment
by
providing
you
with
an
incentive
to
install
state
of
the
art
emissions
controls,
even
if
you
would
not
otherwise
be
required
to
control
emissions
to
this
level.
You
will
benefit
from
these
final
rules
because
they
provide
you
with
increased
operational
flexibility.
Once
you
have
installed
state
of
the
art
emissions
controls
on
an
emissions
unit
and
it
is
considered
a
Clean
Unit,
you
may
make
changes
to
respond
rapidly
to
market
demands
without
having
to
obtain
a
preconstruction
major
NSR
permit.
Moreover,
you
and
your
reviewing
authority
will
benefit
from
increased
administrative
efficiency.
We
believe
that
once
you
have
installed
state
of
theart
emissions
control,
an
additional
major
NSR
review
will
generally
not
result
in
any
additional
emissions
controls
for
a
period
of
years
after
the
original
control
technology
determination
is
made.
In
such
cases,
the
major
NSR
permitting
requirements
impose
a
paperwork
burden
with
little
to
no
additional
environmental
benefit.
The
Clean
Unit
applicability
test
eliminates
this
unnecessary
administrative
action.
B.
Summary
of
1996
Clean
Unit
Proposal
In
the
1996
NSR
Reform
package,
we
proposed
an
innovative
approach
to
NSR
applicability
called
the
Clean
Unit
Exclusion.
The
proposed
Clean
Unit
Exclusion
would
allow
you
to
modify
qualifying
emissions
units
without
being
subject
to
the
NSR
permitting
process
for
a
period
of
10
years,
as
long
as
your
maximum
hourly
emissions
rates
would
not
increase.
We
proposed
that
your
pre
change
hourly
potential
emissions
rate
must
be
established
at
any
time
up
to
6
months
prior
to
the
proposed
activity
or
project.
We
proposed
three
methods
by
which
an
emissions
unit
could
qualify
for
the
Clean
Unit
Exclusion.
One
was
that
the
emissions
unit
went
through
a
major
NSR
action
within
the
last
10
years
and
had
an
enforceable
limit
based
on
BACT
or
LAER.
The
second
was
if
the
emissions
unit
was
permitted
under
a
State
or
local
agency
minor
NSR
program
within
the
last
10
years
and
the
minor
NSR
control
technology
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and
Regulations
requirements
were
comparable
to
BACT
or
LAER.
As
part
of
this
second
method,
we
proposed
that
State
and
local
agencies
would
submit
their
minor
NSR
programs
for
certification
so
that
caseby
case
determinations
for
emissions
units
permitted
under
a
minor
NSR
program
would
not
be
necessary.
The
third
method
was
a
case
by
case
determination
that
an
emission
limitation
was
comparable
to
BACT
or
LAER
for
that
emissions
unit.
For
these
units,
we
proposed
that
the
Clean
Unit
Exclusion
would
last
for
5
years.
We
proposed
that
a
determination
that
a
limit
was
comparable
to
BACT
or
LAER
could
be
based
on
one
of
two
methods:
(
1)
the
average
of
the
BACT
or
LAER
for
equivalent
sources
over
a
recent
period
of
time
(
such
as
3
years);
or
(
2)
the
unit's
control
level
is
within
some
percentage
(
such
as
5
or
10)
of
the
most
recent,
or
average
of
the
most
recent,
BACT
or
LAER
levels
for
equivalent
or
similar
sources.
In
addition,
we
asked
for
public
comment
on
whether
Clean
Unit
status
should
apply
to
emissions
units
with
limits
based
on
MACT
or
RACT.
Although
we
did
not
propose
accompanying
regulatory
language,
we
suggested
that
reviewing
authorities
use
the
title
V
permitting
process
to
designate
Clean
Units.
C.
Final
Regulations
for
Clean
Units
1.
Summary
of
Final
Action
Today's
rule
provides
that
your
emissions
unit
qualifies
as
a
Clean
Unit,
and
qualifies
to
use
the
Clean
Unit
applicability
test,
if
it
has
gone
through
a
major
NSR
permitting
review
and
is
complying
with
BACT
or
LAER.
Conversely,
if
your
emissions
unit
has
not
gone
through
a
major
NSR
permitting
review,
you
do
not
automatically
qualify
for
Clean
Unit
status.
These
emissions
units
must
first
go
through
a
SIP
approved
permitting
process
that
includes
a
process
for
determining
whether
the
emissions
unit
meets
the
criteria
to
be
designated
as
a
Clean
Unit.
This
process
must
include
public
notice
and
opportunity
for
public
comment.
To
obtain
Clean
Unit
status
and
qualify
for
the
Clean
Unit
applicability
test
using
a
SIP
approved
permitting
process,
you
must
pass
a
two
part
test:
(
1)
The
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
must
be
comparable
to
BACT
or
LAER;
and
(
2)
you
must
demonstrate
that
the
allowable
emissions
will
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
You
may
make
a
showing
that
the
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
is
comparable
to
BACT/
LAER
in
two
ways:
(
1)
By
comparing
your
emissions
unit's
control
level
to
BACT/
LAER
determinations
for
similar
sources
in
the
RBLC;
or
(
2)
by
making
a
case
by
case
demonstration
that
your
emissions
control
is
``
substantially
as
effective''
as
BACT
or
LAER.
If
your
emissions
unit
automatically
qualifies
as
a
Clean
Unit
because
it
has
been
through
major
NSR
permitting,
you
may
use
the
Clean
Unit
applicability
test
for
up
to
10
years.
Today's
rules
allow
you
to
apply
for
Clean
Unit
status
for
control
technologies
you
have
installed
in
the
past
if
you
go
through
a
SIP
approved
permitting
program
that
authorizes
Clean
Units
and
you
qualify
as
a
Clean
Unit.
The
Clean
Unit
effective
period
for
emissions
units
that
must
go
through
a
SIP
approved
permitting
process
to
obtain
Clean
Unit
status
is
consistent
with
the
time
frame
for
emissions
units
that
automatically
qualify
as
Clean
Units.
That
is,
you
may
only
use
the
Clean
Unit
applicability
test
for
a
period
of
10
years.
If
you
meet
the
requirements
that
we
describe
in
section
V.
C.
9
of
this
preamble,
you
may
re
qualify
for
Clean
Unit
status.
Upon
expiration
of
Clean
Unit
status,
the
Clean
Unit
applicability
test
no
longer
applies
to
changes
at
the
emissions
unit.
It
is
worth
noting
that
in
1996,
we
proposed
the
provisions
for
Clean
Units
as
a
``
Clean
Unit
Exclusion,''
although
we
discussed
the
provisions
as
a
new
applicability
test.
We
received
criticism
from
at
least
one
commenter
that
our
characterization
of
the
test
as
an
exclusion
was
inappropriate.
We
agree
with
this
commenter,
and
have
thus
renamed
the
test
as
the
Clean
Unit
applicability
test.
We
believe
that
this
title
more
appropriately
reflects
that
the
test
is
not
whether
you
are
excluded
from
review
under
major
NSR,
but
whether
using
a
more
appropriate
emissions
test
you
trigger
major
NSR
review.
2.
Is
Clean
Unit
Status
Available
in
Both
Attainment
and
Nonattainment
Areas?
You
may
obtain
Clean
Unit
status
regardless
of
whether
you
are
located
in
an
attainment
area
or
in
a
nonattainment
area.
Our
proposed
Clean
Unit
provisions
were
unclear
on
how
emissions
offsets
and
other
nonattainment
area
requirements
are
affected
by
Clean
Unit
status.
We
want
to
clarify
this
issue.
For
sources
in
nonattainment
areas
which
went
through
major
NSR
permitting
while
the
area
was
nonattainment
or
which
have
qualified
for
Clean
Unit
status
showing
they
are
comparable
to
LAER,
the
permitted
emissions
level
for
the
Clean
Unit
must
have
been
offset.
The
emissions
reductions
resulting
from
installation
of
the
control
technology
that
is
the
basis
of
an
emissions
unit's
status
as
a
Clean
Unit
may
not
be
used
as
offsets;
however,
emissions
reductions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit
may
be
used
as
offsets
if
they
are
surplus,
quantifiable,
permanent,
and
federally
enforceable.
Furthermore,
for
emissions
units
that
are
designated
as
Clean
Units
and
that
are
located
in
nonattainment
areas,
RACT
and
any
other
requirements
for
nonattainment
area
sources
under
the
SIP
will
still
apply.
The
only
exception
to
this
is
that
the
specific
major
NSR
requirements
related
to
calculating
emissions
increases
from
a
physical
change
or
change
in
the
method
of
operation
for
all
other
existing
sources
that
we
describe
in
this
preamble
and
codify
in
today's
rules
are
not
applicable
to
Clean
Units,
because
the
Clean
Units
are
subject
to
an
alternative
major
NSR
applicability
requirement
for
calculating
emissions
increases
when
changes
are
made.
As
we
discuss
in
detail
in
section
V.
C.
3
of
this
preamble,
the
``
substantially
as
effective''
test
for
sources
in
nonattainment
areas
must
consider
only
LAER
determinations,
except
that
emissions
units
in
nonattainment
areas
that
went
through
major
NSR
permitting
while
the
area
was
designated
an
attainment
area
for
that
regulated
NSR
pollutant,
and
that
received
a
permit
based
on
a
qualifying
air
pollution
control
technology,
automatically
qualify
as
Clean
Units.
If
your
emissions
unit
received
Clean
Unit
status
while
the
unit
was
located
in
an
attainment
area
and
the
area's
attainment
status
subsequently
changes
to
nonattainment,
your
emissions
unit
retains
Clean
Unit
status
until
expiration.
However,
to
re
qualify
as
a
Clean
Unit
(
see
section
V.
C.
9),
the
unit
will
have
to
meet
the
requirements
that
apply
in
nonattainment
areas.
3.
How
Do
You
Qualify
As
A
Clean
Unit?
Any
emissions
unit
permitted
through
major
NSR
automatically
qualifies
as
a
Clean
Unit,
provided
the
BACT/
LAER
determination
results
in
some
degree
of
emissions
control.
(
We
discuss
the
specific
requirements
for
qualifying
controls
in
section
V.
C.
4
of
this
preamble.)
These
units
already
meet
both
the
control
technology
and
air
quality
criteria
of
the
CAA
and
the
NSR
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Vol.
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251
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December
31,
2002
/
Rules
and
Regulations
regulations.
We
believe
that
the
emission
limitations
(
based
on
the
BACT/
LAER
determination)
and
other
permit
terms
and
conditions
(
such
as
any
limits
on
hours
of
operation,
raw
materials,
etc.,
that
were
used
to
determine
BACT/
LAER)
are
protective
of
air
quality.
Although
emissions
units
that
have
been
through
major
NSR
automatically
qualify
for
Clean
Unit
status,
there
are
specific
procedures
for
establishing
and
maintaining
Clean
Unit
status.
We
discuss
these
procedures
in
detail
in
sections
V.
C.
6
through
9
of
this
preamble.
Your
emissions
units
that
have
not
gone
through
a
major
NSR
permitting
action
that
resulted
in
a
requirement
to
comply
with
BACT
or
LAER
may
qualify
for
Clean
Unit
status
if
they
are
permitted
under
a
SIP
approved
permitting
program
that
provides
for
public
notice
of
the
proposed
determination
and
opportunity
for
public
comment.
You
must
pass
a
twopart
test
to
obtain
Clean
Unit
status:
(
1)
The
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
must
be
comparable
to
BACT
or
LAER;
and
(
2)
the
allowable
emissions
will
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
You
may
show
that
the
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
is
comparable
to
BACT/
LAER
in
one
of
two
ways:
(
1)
By
comparing
your
emissions
unit's
control
level
to
BACT/
LAER
determinations
for
other
similar
sources
in
the
RBLC;
or
(
2)
by
making
a
case
by
case
demonstration
that
your
emissions
control
is
``
substantially
as
effective''
as
BACT
or
LAER.
To
make
a
demonstration
using
the
first
methodology
in
a
nonattainment
area,
you
must
compare
your
control
technology
to
the
best
performing
5
similar
sources
in
the
RBLC
for
which
LAER
has
been
determined
within
the
past
5
years.
If
the
emission
limitation
that
is
achieved
by
your
control
technology
is
at
least
as
stringent
as
any
one
of
the
5
best
performing
units,
and
the
emissions
unit
also
passes
the
air
quality
test,
then
the
reviewing
authority
shall
presume
that
it
qualifies
as
a
Clean
Unit.
In
attainment
areas,
you
must
compare
your
control
technology
to
all
BACT
and
LAER
decisions
that
have
been
entered
into
the
RBLC
in
the
past
5
years,
and
for
which
it
is
technically
feasible
to
apply
the
BACT
or
LAER
control
to
your
emissions
unit
type.
If
your
control
technology
achieves
a
level
of
control
that
is
equal
to
or
better
than
the
average
of
these
determinations,
and
the
emissions
unit
also
passes
the
air
quality
test,
then
the
reviewing
authority
shall
presume
that
your
emissions
unit
qualifies
as
a
Clean
Unit.
After
you
have
submitted
your
demonstration,
the
reviewing
authority
will
also
consider
other
BACT/
LAER
determinations
that
are
not
included
in
the
RBLC
to
determine
whether
the
proposed
emissions
rate
is
comparable
to
BACT/
LAER,
and
incorporate
this
information
into
its
determination
as
appropriate.
In
addition,
the
public
will
have
an
opportunity
to
review
and
comment
on
the
reviewing
authority's
decision
to
designate
an
emissions
unit
as
a
Clean
Unit.
This
approach
ensures
that
you
are
meeting
an
emissions
level
comparable
to
that
of
BACT
or
LAER,
while
providing
you
flexibility
to
use
the
controls
that
are
best
suited
to
your
processes.
We
are
providing
this
first
methodology
as
a
streamlined
methodology
for
identifying
Clean
Units.
Any
unit
that
meets
these
qualifications
shall
be
presumed
to
be
a
Clean
Unit.
Conversely,
the
opposite
is
not
true.
The
reviewing
authority
shall
not
presume
that
a
unit
that
does
not
meet
the
test
is
not
a
Clean
Unit.
The
quality
and
number
of
determinations
in
the
RBLC
vary
by
different
type
of
sources.
The
RBLC
may
not
always
identify
all
the
types
of
control
technology
strategies
that
should
qualify
an
emissions
unit
as
a
Clean
Unit,
or
it
may
not
provide
a
representative
sample
for
making
an
appropriate
determination.
Therefore,
even
if
you
are
unable
to
demonstrate
that
your
emissions
unit
is
a
Clean
Unit
using
this
methodology,
your
reviewing
authority
shall
not
allow
this
outcome
to
prejudice
its
decision
making.
Accordingly,
we
are
providing
a
second
option
for
determining
whether
you
qualify
as
a
Clean
Unit.
If
your
emissions
unit
does
not
meet
the
emission
limitation
determined
from
the
analysis
of
the
RBLC
described
above
(
as
appropriate
for
the
area
in
which
it
is
located),
or
if
there
is
insufficient
information
in
the
RBLC
to
conduct
the
analysis,
then
you
may
still
show,
on
a
case
by
case
basis,
that
your
emissions
unit
will
achieve
a
level
of
control
that
is
``
substantially
as
effective''
as
BACT
or
LAER,
depending
whether
your
emissions
unit
is
in
an
attainment
area
or
a
nonattainment
area.
In
an
attainment
area,
your
emissions
unit
must
achieve
a
level
of
control
that
is
``
substantially
as
effective''
as
BACT.
In
a
nonattainment
area,
your
emissions
unit
must
achieve
a
level
of
control
that
is
``
substantially
as
effective''
as
LAER.
The
reviewing
authority
will
make
a
decision
on
whether
a
particular
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
is
``
substantially
as
effective''
as
the
BACT/
LAER
technology
for
a
specific
source
on
a
case
by
case
basis.
We
are
not
promulgating
specific
requirements
or
performance
criteria
for
satisfying
the
``
substantially
as
effective''
test,
because
we
believe
reviewing
authorities
are
in
the
best
position
to
determine
whether
in
fact
a
particular
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
is
``
substantially
as
effective''
as
the
BACT/
LAER
technology
for
a
specific
source.
The
case
by
case
determinations
must
meet
the
same
air
quality
test
as
those
units
going
through
a
BACT/
LAER
determination.
Moreover,
the
public
has
opportunity
for
public
review
and
comment
on
the
``
substantially
as
effective''
decision.
With
these
safeguards,
we
believe
the
``
substantially
as
effective''
test
will
ensure
determinations
that
meet
both
the
control
technology
and
air
quality
tests,
as
well
as
allow
sources
to
implement
the
controls
that
are
best
suited
to
their
individual
processes.
Under
the
second
part
of
the
test
to
determine
whether
your
unit
qualifies
for
Clean
Unit
status,
you
must
demonstrate
that
the
allowable
emissions
will
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
If
your
emissions
unit
has
already
been
permitted
under
minor
NSR
or
another
SIP
approved
permitting
program,
you
may
have
already
satisfied
the
second
part
of
this
test.
If
not,
consistent
with
the
requirements
in
sections
165(
a)(
3)
and
173(
a)
of
the
CAA,
you
will
be
required
to
show
that
the
allowable
emissions
will
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
For
areas
that
do
not
already
attain
the
NAAQS,
the
source
would
be
required
to
show
that
the
emissions
for
the
unit
have
been
previously
offset.
4.
Can
an
Emissions
Unit
That
Applies
No
Emissions
Control
Technology
Qualify
as
a
Clean
Unit?
In
most
cases,
BACT/
LAER
will
result
in
significant
emissions
decreases
(
such
as
90
percent
control
for
many
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32
It
is
possible
that
a
BACT/
LAER
analysis
will
not
always
result
in
the
requirement
of
add
on
controls
at
a
source.
In
some
situations,
a
reviewing
authority
may
appropriately
determine
that
the
control
technology
that
best
represents
BACT/
LAER
is
a
work
practice,
or
a
combination
of
work
practices
and
add
on
controls.
As
a
result,
a
requirement
to
use
work
practices,
or
a
combination
of
add
on
controls
and
work
practices,
as
an
emissions
control
technology,
could
qualify
an
emissions
unit
for
Clean
Unit
status,
provided
it
meets
the
criteria
established.
coating
sources).
32
In
some
circumstances,
however,
the
outcome
of
a
reviewing
authority's
BACT
or
LAER
determination
may
result
in
an
emission
limitation
that
you
will
meet
without
using
a
control
technology
(
add
on
control,
pollution
prevention
technique,
or
work
practice).
Under
today's
rules,
you
will
not
qualify
as
a
Clean
Unit
in
such
circumstances.
More
specifically,
today's
rules
also
require
you
to
make
an
investment
to
qualify
initially
as
a
Clean
Unit.
An
investment
includes
any
cost
which
would
ordinarily
qualify
as
a
capital
expense
under
the
Internal
Revenue
Service's
filing
guidelines
whether
or
not
you
actually
choose
to
capitalize
that
cost.
An
investment
also
includes
any
cost
you
incur
to
change
your
emissions
unit
or
process
to
implement
a
pollution
prevention
approach,
including
research
expenses,
or
costs
to
retool
or
reformulate
your
emissions
unit
or
process
to
accommodate
an
add
on
control,
pollution
prevention
approach,
or
work
practice.
5.
When
Do
the
Major
NSR
Requirements
Apply
to
Clean
Units?
Once
an
emissions
unit
qualifies
as
a
Clean
Unit,
it
is
subject
to
an
alternative
major
NSR
applicability
test
for
calculating
emissions
increases
for
subsequent
changes.
As
we
discussed
in
section
II
of
this
preamble,
we
have
codified
our
longstanding
policy
(
for
emissions
units
that
are
not
Clean
Units)
that
a
major
modification
occurs
if
both
of
the
following
result
from
the
modification:
(
1)
A
significant
emissions
increase
following
the
physical
or
operational
change;
and
(
2)
a
significant
net
emissions
increase
from
the
major
stationary
source.
The
major
NSR
applicability
test
for
Clean
Units
is
a
different
process.
For
Clean
Units,
you
must
first
determine
whether
a
project
causes
the
need
to
change
the
emission
limitations
or
work
practice
requirements
in
the
permit
which
were
established
in
conjunction
with
BACT,
LAER,
or
Clean
Unit
determinations
and
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT,
LAER,
or
Clean
Unit
determination
for
a
particular
unit.
If
it
does,
you
lose
Clean
Unit
status,
and
the
project
is
subject
to
the
applicability
requirements
as
if
the
emissions
unit
were
never
a
Clean
Unit.
If
the
project
does
not
cause
the
need
to
change
the
emission
limitations
or
work
practice
requirements
in
the
permit
which
were
established
in
conjunction
with
BACT,
LAER,
or
Clean
Unit
determinations
and
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT,
LAER,
or
Clean
Unit
determination
for
a
particular
unit,
then
you
maintain
Clean
Unit
status,
and
no
emissions
increase
is
deemed
to
occur
from
the
project
for
the
purposes
of
major
NSR.
Once
you
have
lost
Clean
Unit
status,
you
can
only
re
qualify
for
Clean
Unit
status
by
going
through
the
process
that
we
describe
in
section
V.
C.
9
of
this
preamble.
6.
Can
You
Get
Clean
Unit
Status
for
Controls
That
Have
Already
Been
Installed?
As
discussed
in
section
V.
C.
3,
emissions
units
that
have
been
through
major
NSR
permitting
automatically
qualify
for
Clean
Unit
status.
This
includes
those
emissions
units
that
went
through
major
NSR
before
promulgation
of
today's
final
rules.
If
an
emissions
unit
automatically
qualifies
for
Clean
Unit
status
because
it
went
through
major
NSR,
its
Clean
Unit
status
is
based
on
the
BACT/
LAER
controls
that
went
into
service
as
a
result
of
the
major
NSR
review.
That
is,
Clean
Unit
status
is
based
on
the
BACT/
LAER
controls
regardless
of
whether
the
actual
process
for
designating
Clean
Unit
status
through
title
V
occurs
at
some
time
after
the
controls
went
into
service.
However,
Clean
Unit
status,
and
the
ability
to
use
the
applicability
process
for
Clean
Units,
does
not
begin
until
the
Clean
Unit
effective
date.
We
discuss
the
specific
procedures
for
when
Clean
Unit
status
starts,
when
it
ends,
and
how
it
is
designated
in
sections
V.
C.
7
through
9.
For
emissions
units
that
have
not
been
through
major
NSR,
our
rules
allow
your
reviewing
authority
to
provide
you
with
Clean
Unit
status
for
emissions
control
that
you
have
already
installed
and
operated.
However,
our
final
rules
also
limit
the
time
frame
under
which
your
reviewing
authority
is
allowed
to
make
such
determinations
for
Clean
Unit
status
that
is
granted
through
a
SIP
approved
permitting
process
other
than
major
NSR.
Your
reviewing
authority
will
only
be
able
to
grant
Clean
Unit
status
for
previously
installed
emissions
controls
if
they
were
installed
before
the
effective
date
of
the
program
in
your
area.
If
the
emissions
unit's
control
technology
is
installed
on
or
after
the
date
that
provisions
for
the
Clean
Unit
applicability
test
are
effective
in
your
area,
you
must
apply
for
Clean
Unit
status
from
your
reviewing
authority
at
the
time
the
control
technology
is
installed.
As
for
emissions
units
that
went
through
major
NSR
review,
Clean
Unit
status
for
emissions
units
permitted
through
SIPapproved
programs
other
than
major
NSR
does
not
begin
until
the
Clean
Unit
effective
date.
If
you
are
applying
for
retroactive
Clean
Unit
status,
today's
final
rules
allow
your
reviewing
authority
to
compare
your
emissions
control
level
to
the
BACT
or
LAER
level
that
would
have
applied
at
the
time
you
began
construction
of
your
emissions
unit.
However,
in
some
cases,
such
a
comparability
analysis
may
be
difficult
for
you
to
demonstrate
because
of
lack
of
sufficient
information
from
which
your
reviewing
authority
can
make
a
reasoned
determination.
If
this
is
the
case,
then
you
will
have
to
demonstrate
that
your
emissions
controls
are
comparable
to
a
BACT
or
LAER
limit
from
a
subsequent
or
current
date.
7.
When
Can
I
Begin
To
Use
the
Clean
Unit
Test?
The
exact
effective
date
depends
on
the
circumstances
of
the
individual
emissions
unit,
as
explained
further
below.
As
a
general
principle,
however,
the
effective
date
for
Clean
Unit
status
can
never
be
before
the
Clean
Unit
provision
becomes
effective
in
the
relevant
jurisdiction.
For
emissions
units
that
automatically
qualify
for
their
original
Clean
Unit
status
because
they
have
been
through
major
NSR
review,
and
for
units
that
requalify
for
Clean
Unit
status
(
see
section
V.
C.
9)
by
going
through
major
NSR
review
and
implementing
new
control
technology
to
meet
current
day
BACT/
LAER,
the
effective
date
is
the
date
the
emissions
unit's
air
pollution
control
technology
is
placed
into
service,
or
3
years
after
the
issuance
date
of
the
major
NSR
permit,
whichever
is
earlier.
However,
the
effective
date
can
be
no
sooner
than
the
date
that
provisions
for
the
Clean
Unit
applicability
test
are
approved
by
the
Administrator
for
incorporation
into
the
SIP
and
become
effective
for
the
State
in
which
the
unit
is
located.
That
is,
if
the
source
had
a
major
NSR
permit
and
began
operating
before
the
Clean
Unit
provision
becomes
effective
in
the
relevant
jurisdiction,
the
effective
date
is
the
date
the
State
or
local
agency
begins
authorizing
Clean
Unit
status.
As
we
noted
earlier,
if
the
emissions
unit
previously
went
through
major
NSR,
it
automatically
qualifies
as
a
Clean
Unit.
The
original
Clean
Unit
status
would
be
based
on
the
controls
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33
As
discussed
in
section
III.
E
of
today's
preamble,
we
believe
that
15
years
represents
a
reasonable
time
period
for
designating
a
Clean
Unit.
However,
we
proposed
and
took
comment
on
a
10
year
period;
therefore,
we
are
finalizing
today's
rule
with
a
10
year
duration.
In
a
separate
Federal
Register
notice
we
will
be
proposing
to
change
this
duration
to
15
years.
that
were
installed
to
meet
major
NSR.
An
additional
investment
at
the
time
the
original
Clean
Unit
status
becomes
effective
is
not
required.
For
emissions
units
that
re
qualify
for
Clean
Unit
status
(
see
section
V.
C.
9)
by
going
through
major
NSR
using
an
existing
control
technology
that
continues
to
meet
current
day
BACT/
LAER,
the
effective
date
is
the
date
the
new
major
NSR
permit
is
issued.
If
you
obtain
Clean
Unit
status
from
your
State
or
local
reviewing
authority
using
a
SIP
approved
permitting
process
other
than
major
NSR,
the
Clean
Unit
effective
date
is
the
later
of
the
following
dates:
(
1)
The
date
that
the
State
or
local
agency
permit
that
designates
the
emissions
unit
as
a
Clean
Unit
is
issued;
and
(
2)
the
date
that
the
emissions
unit's
air
pollution
control
measures
went
into
service.
That
is,
if
the
controls
went
into
service
before
the
issuance
date
of
the
State
or
local
agency
permit
that
designates
the
unit
as
a
Clean
Unit,
the
Clean
Unit
effective
date
is
the
date
that
the
permit
is
issued.
As
with
units
that
have
been
through
major
NSR,
additional
investment
is
not
required
for
the
limited
cases
where
there
is
a
retroactive
designation.
If
the
issuance
date
of
the
State
or
local
agency
permit
that
designates
the
emissions
unit
as
a
Clean
Unit
is
before
the
date
the
controls
went
into
service
(
as
would
likely
be
the
case
for
a
unit
that
is
new
or
modified
after
the
State
or
local
agency
begins
to
authorize
Clean
Unit
status),
then
the
effective
date
of
Clean
Unit
status
is
the
date
the
controls
went
into
service.
8.
How
Long
Does
Clean
Unit
Status
Last?
In
most
cases,
you
may
use
the
Clean
Unit
applicability
test
for
a
period
of
10
years.
33
As
a
general
principle,
the
Clean
Unit
expiration
date
can
never
be
later
than
the
date
that
is
10
years
after
the
controls
are
brought
into
service.
For
emissions
units
that
automatically
qualify
for
their
original
Clean
Unit
status
because
they
have
been
through
major
NSR
review,
and
for
units
that
requalify
for
Clean
Unit
status
(
see
section
V.
C.
9)
by
going
through
major
NSR
review
and
implementing
new
control
technology
to
meet
current
day
BACT/
LAER,
Clean
Unit
status
expires
10
years
after
the
effective
date,
or
the
date
the
equipment
went
into
service,
whichever
is
earlier.
However,
Clean
Unit
status
expires
sooner
if,
at
any
time,
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
Clean
Unit
status
that
are
included
in
the
final
rules.
For
emissions
units
that
re
qualify
for
Clean
Unit
status
(
see
section
V.
C.
9)
by
going
through
major
NSR
using
an
existing
control
technology
that
continues
to
meet
current
day
BACT/
LAER,
Clean
Unit
status
expires
10
years
after
the
effective
date.
However,
as
noted
above,
Clean
Unit
status
expires
sooner
if,
at
any
time,
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
Clean
Unit
status
that
are
included
in
the
final
rules.
The
expiration
date
for
Clean
Units
that
have
not
been
through
major
NSR
permitting
depends
on
whether
the
owner
or
operator
qualifies
for
Clean
Unit
status
based
on
current
BACT/
LAER,
or
on
BACT/
LAER
at
the
time
the
control
technology
was
installed.
If
the
owner
or
operator
of
a
previously
installed
unit
demonstrates
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
the
BACT/
LAER
requirements
that
applied
at
the
time
the
control
technology
was
installed,
then
Clean
Unit
status
expires
10
years
from
the
date
that
the
control
technology
was
installed.
For
all
other
emissions
units
(
that
is,
previously
installed
units
that
are
demonstrated
to
be
comparable
to
current
BACT/
LAER,
new
units,
and
units
that
re
qualify
as
Clean
Units),
Clean
Unit
status
expires
10
years
from
the
effective
date
of
the
Clean
Unit
status.
In
addition,
for
all
emissions
units,
Clean
Unit
status
expires
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
Clean
Unit
status
that
are
included
in
the
final
rules.
When
your
Clean
Unit
status
expires,
you
are
subject
to
the
major
NSR
applicability
test
as
if
your
emissions
unit
is
not
a
Clean
Unit.
The
permitted
emissions
levels
established
for
the
Clean
Unit
do
not
expire.
9.
Can
I
Re
qualify
for
Clean
Unit
Status?
You
may
re
qualify
for
Clean
Unit
status
after
the
status
has
expired
or
you
have
otherwise
lost
Clean
Unit
status,
if
you
meet
the
conditions
in
our
final
regulations.
As
we
stated
before,
we
believe
that
once
you
have
installed
state
of
the
art
emissions
control,
an
additional
major
NSR
review
will
generally
not
result
in
any
additional
emissions
controls
for
a
period
of
years
after
the
original
control
technology
determination
is
made.
Also,
the
period
for
which
any
specific
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
will
continue
to
achieve
the
same
level
of
control
depends
on
many
factors.
As
a
practical
matter,
we
have
established
a
single
time
frame
of
10
years
for
Clean
Unit
status,
to
provide
simplicity
in
our
final
rules.
However,
for
reasons
we
discuss
in
detail
in
section
V.
E.
1
of
this
preamble,
we
determined
that
a
reasonable
average
equipment
life
for
a
control
technology
is
generally
longer
than
10
years.
Certainly
we
want
to
encourage
source
owner/
operators
to
install
and
maintain
state
of
the
art
control.
We
believe
this
is
more
likely
when
you
can
be
assured
that
you
can
retain
Clean
Unit
status
for
the
useful
life
of
the
equipment,
as
long
as
air
quality
continues
to
be
assured.
The
useful
life
of
the
equipment
may
extend
beyond
the
original
Clean
Unit
expiration
date.
Therefore,
we
are
promulgating
final
regulations
that
allow
you
to
apply
to
re
qualify
for
Clean
Unit
status.
To
re
qualify
for
Clean
Unit
status,
you
would
generally
follow
the
same
process
that
you
used
in
first
qualifying
for
Clean
Unit
status.
However,
we
will
not
necessarily
require
you
to
meet
an
additional
investment
test
to
re
qualify
for
Clean
Unit
status
for
the
same
controls.
That
is,
unless
the
controls
used
to
establish
Clean
Unit
status
are
no
longer
BACT/
LAER
or
comparable,
there
will
be
no
requirement
for
an
investment
to
re
qualify
for
Clean
Unit
status.
You
may
re
qualify
for
Clean
Unit
status
either
by
going
through
major
NSR
or
by
going
through
the
alternative
Clean
Unit
Test
that
we
described
in
section
V.
C.
3
of
this
preamble:
(
1)
The
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
must
be
comparable
to
BACT
or
LAER;
and
(
2)
the
allowable
emissions
will
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
Regardless
of
which
process
you
used
to
establish
Clean
Unit
status
initially,
you
may
choose
to
requalify
for
Clean
Unit
status
by
going
through
major
NSR
or
by
going
through
the
alternative
two
part
test.
Once
you
have
submitted
an
application
to
re
qualify
for
Clean
Unit
status,
the
reviewing
authority
will
make
a
determination
concerning
current
BACT/
LAER
or
comparable
control
technology.
For
example,
suppose
you
had
Clean
Unit
status
for
an
emissions
unit
for
which
the
controls
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Rules
and
Regulations
went
into
service
June
1,
1996,
the
permit
application
for
Clean
Unit
requalification
was
submitted
December
1,
2004,
and
the
Clean
Unit
status
expires
June
1,
2006.
In
cases
where
the
controls
you
installed
in
1996
are
still
BACT/
LAER
or
comparable
when
the
reviewing
authority
makes
the
determination
following
your
application
submittal
in
2004,
the
emissions
unit
can
re
qualify
for
Clean
Unit
status
based
on
the
controls
installed
in
1996
if
your
emissions
unit
still
meets
all
of
the
criteria
for
Clean
Unit
status.
That
is,
in
addition
to
the
control
technology
review,
the
emissions
unit
must
go
through
an
air
quality
review
and
public
participation.
A
safeguard
related
to
Clean
Unit
controls
is
that
for
re
qualifying
for
Clean
Unit
status
when
the
emissions
unit
is
located
in
a
nonattainment
area,
the
control
determination
must
be
LAER
or
comparable
to
LAER.
If
you
previously
received
Clean
Unit
status
based
on
the
BACT
level
of
control
while
the
source
was
located
in
an
attainment
area
and
the
attainment
area
becomes
a
nonattainment
area
by
the
time
your
Clean
Unit
status
expires,
the
Clean
Unit
status
for
re
qualification
must
be
based
on
controls
that
are
LAER
or
comparable
to
LAER.
The
air
quality
analysis
for
Clean
Unit
re
qualifications
will
be
that
of
the
path
that
you
have
chosen'major
NSR,
or
comparable.
As
we
discuss
in
detail
in
section
V.
C.
3
of
this
preamble,
for
emissions
units
qualifying
for
Clean
Unit
status
through
the
comparable
test,
you
must
show
that
the
allowable
emissions
will
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
We
believe
that
the
control
technology
determination,
air
quality
review,
and
public
participation
requirements
of
the
Clean
Unit
requalification
process
will
ensure
that
Clean
Units
will
continue
to
protect
air
quality
throughout
the
10
year
requalification
period.
Moreover,
any
offset
or
mitigation
requirements
as
a
result
of
a
previous
major
NSR
determination
will
remain
in
force.
We
expect
that
in
many
cases
the
controls
used
to
initially
establish
Clean
Unit
status
will
still
be
operating
efficiently
and
the
Clean
Unit
status
can
be
reestablished
for
an
additional
10
years
based
on
those
controls.
Suppose,
however,
you
submitted
an
application
to
re
qualify
for
Clean
Unit
status
and
the
reviewing
authority
determines
that
your
existing
controls
do
not
meet
the
level
of
current
BACT/
LAER
or
comparable
controls.
In
this
case,
you
must
install
new
or
upgraded
controls
to
re
qualify
for
Clean
Unit
status.
You
must
go
through
the
control
technology
determination,
air
quality
review,
and
public
participation
requirements
of
the
Clean
Unit
re
qualification
process
as
described
above.
10.
What
Terms
and
Conditions
Must
the
Permit
for
my
Clean
Unit
Contain?
Major
NSR
permits
contain
the
emission
limitations
based
on
BACT/
LAER,
other
permit
terms
and
conditions
that
the
reviewing
authority
identifies
as
representative
of
BACT/
LAER
(
such
as
limits
on
hours
of
operation),
and
monitoring,
recordkeeping
and
reporting
requirements
for
the
emissions
unit.
If
you
are
qualifying
for
Clean
Unit
status
through
the
major
NSR
review,
your
major
NSR
permit
will
have
such
terms
and
conditions.
Likewise,
any
permit
under
a
SIP
approved
permitting
process
other
than
major
NSR
that
designates
an
emissions
unit
as
a
Clean
Unit
must
specify:
(
1)
The
sourcespecific
allowable
permit
emission
limitations,
the
exceedance
of
which,
in
combination
with
a
significant
net
emissions
increase,
will
trigger
major
NSR
review;
(
2)
other
permit
terms
and
conditions
that
the
reviewing
authority
identifies
as
representative
or
comparable
to
BACT/
LAER
for
your
control
technology
(
such
as
limits
on
operating
parameters,
etc.);
(
3)
any
conditions
used
as
the
basis
for
the
control
technology
determinations
(
hours
of
operation,
limits
on
raw
materials,
etc.);
and
(
4)
the
monitoring,
recordkeeping,
and
reporting
requirements
necessary
to
demonstrate
that
a
``
clean''
level
of
emissions
control
is
being
achieved.
Additional
monitoring,
recordkeeping,
and
reporting
may
be
required
to
assure
compliance
under
§
§
70.6(
a)(
3)
or
70.6(
c)(
1)
(
that
is,
to
assure
compliance
under
title
V).
The
State
and
local
agency
permits
establishing
Clean
Unit
status
must
contain
a
statement
designating
the
emissions
unit
as
a
Clean
Unit.
The
State
or
local
agency
permit
must
also
include
general
terms
and
conditions
indicating
the
Clean
Unit
effective
date
and
expiration
date.
Suppose
the
State
or
local
agency
permit
has
an
effective
date
of
May
5,
2006,
and
the
controls
will
be
installed
after
this
date.
The
SIP
permit
would
state
that
the
effective
date
of
the
Clean
Unit
status
is
the
date
the
controls
go
into
service.
The
permit
would
also
state
that
Clean
Unit
status
will
expire
no
later
than
May
5,
2016.
Your
title
V
permit
must
include
the
Clean
Unit
status,
as
well
as
the
effective
and
expiration
dates
of
the
Clean
Unit
status.
Your
title
V
permit
must
also
include:
the
emission
limitation(
s)
that
reflect
BACT/
LAER
or
comparable
control;
other
permit
terms
and
conditions
that
the
reviewing
authority
has
determined
represent
BACT/
LAER
or
comparable
control
(
such
as
limits
on
hours
of
operation)
and
that
ensure
that
air
quality
is
protected;
and
the
monitoring,
recordkeeping,
and
reporting
requirements
necessary
to
demonstrate
that
a
``
clean''
level
of
emissions
control
is
being
achieved.
11.
How
Will
my
Clean
Unit
Status
be
Incorporated
Into
my
Title
V
Permit?
Clean
Unit
status
and
other
permit
terms
and
conditions
must
be
incorporated
into
the
major
stationary
source's
title
V
permit
in
accordance
with
the
provisions
of
the
applicable
title
V
permit
program
under
part
70
or
part
71,
but
no
later
than
when
the
title
V
permit
is
renewed.
The
title
V
permit
must
also
contain
the
specific
dates
on
which
your
Clean
Unit
status
is
effective
and
on
which
it
expires.
We
are
aware
that
the
specific
Clean
Unit
effective
and
expiration
dates
will
frequently
not
be
determined
at
the
time
that
Clean
Unit
status
is
established.
Therefore,
the
initial
title
V
permit
action
that
incorporates
Clean
Unit
status
and
other
permit
terms
and
conditions
may
need
to
state
the
Clean
Unit
effective
and
expiration
dates
in
general
terms.
For
example,
for
units
that
have
been
through
major
NSR,
the
initial
title
V
permit
might
state
that
the
expiration
date
is
the
earlier
of
the
following
dates:
the
date
10
years
after
(
1)
the
Clean
Unit's
effective
date,
or
(
2)
the
date
the
equipment
went
into
service.
The
permit
does
not
have
to
include
the
specific
Clean
Unit
effective
and
expiration
dates
where
they
cannot
be
determined
at
the
time
of
initial
incorporation,
such
as
would
be
the
case
when
the
Clean
Unit
has
yet
to
be
constructed.
Furthermore,
in
these
instances,
we
are
not
requiring
that
the
title
V
permit
be
modified
to
incorporate
the
specific
Clean
Unit
effective
and
expiration
dates
until
the
next
permit
renewal,
reopening,
or
modification
after
such
dates
are
known.
As
soon
as
the
specific
Clean
Unit
effective
and
expiration
dates
are
known,
the
source
must
report
them
to
the
reviewing
authority.
The
specific
Clean
Unit
effective
and
expiration
dates
must
then
be
incorporated
into
the
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
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31,
2002
/
Rules
and
Regulations
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
However,
it
is
not
necessary
to
amend
the
SIP
approved
permit
to
incorporate
the
specific
Clean
Unit
effective
and
expiration
dates,
as
long
as
these
dates
are
incorporated
into
the
title
V
permit
at
the
next
renewal.
If
you
wish
to
incorporate
the
Clean
Unit
effective
and
expiration
dates
into
the
SIP
permit,
a
title
V
modification
would
be
required.
While
the
title
V
permit
contains
the
Clean
Unit
permit
terms
and
conditions,
we
want
to
emphasize
that
any
changes
to
Clean
Unit
permit
terms
and
conditions
(
other
than
incorporating
the
specific
Clean
Unit
effective
and
expiration
dates)
must
first
be
made
through
a
SIP
approved
permitting
process
that
provides
for
public
review
and
opportunity
for
comment.
Any
such
changes
would
be
incorporated
into
the
title
V
permit
in
the
manner
described
above.
12.
Can
a
Clean
Unit
Be
Used
in
a
Netting
Analysis?
Generally,
for
an
emissions
unit
that
has
Clean
Unit
status
because
it
has
gone
through
major
NSR
permitting,
you
must
not
include
emissions
changes
at
the
Clean
Unit
in
a
netting
analysis,
or
use
them
for
generating
offsets,
unless
the
emissions
changes
occur
and
you
use
them
for
these
purposes
before
the
effective
date
of
Clean
Unit
status
or
after
Clean
Unit
status
expires.
However,
if
you
reduce
emissions
from
the
Clean
Unit
below
the
level
that
qualified
the
unit
as
a
Clean
Unit,
you
may
generate
a
credit
for
the
difference
between
the
level
that
qualified
the
unit
as
a
Clean
Unit
and
the
new
emission
limitation,
if
such
reductions
are
surplus,
quantifiable,
permanent,
and
federally
enforceable
(
for
the
purposes
of
generating
offsets)
and
enforceable
as
a
practical
matter
(
for
purposes
of
determining
creditable
net
emissions
increases
and
decreases).
Such
credits
may
be
used
for
netting
or
as
offsets.
We
are
allowing
the
credit
to
be
computed
in
this
manner
because
the
owner
or
operator
has
already
obtained
an
actual
emissions
based
offset
for
the
emissions
up
to
the
Clean
Unit
emission
limitations.
By
the
owner/
operator's
accepting
a
federally
enforceable
emission
limitation
below
this
level,
these
offsets
are
now
available
to
create
additional
actual
emissions
reductions.
The
final
rules
are
similar
for
emissions
units
that
are
designated
as
Clean
Units
in
a
SIP
approved
permitting
process
other
than
major
NSR.
You
must
not
include
emissions
changes
that
occur
at
such
units
in
a
netting
analysis,
or
use
them
for
generating
offsets,
unless
the
emissions
changes
occur
and
you
use
them
for
these
purposes
before
the
effective
date
of
the
SIP
requirements
adopted
to
implement
the
Clean
Units
or
after
Clean
Unit
status
expires.
However,
if
you
reduce
emissions
from
the
Clean
Unit
below
the
level
that
qualified
the
unit
as
a
Clean
Unit,
you
may
generate
a
credit
for
the
difference
between
the
level
that
qualified
the
unit
as
a
Clean
Unit
and
the
new
emission
limitation,
if
such
reductions
are
surplus,
quantifiable,
permanent,
and
federally
enforceable
(
for
purposes
of
generating
offsets)
and
enforceable
as
a
practical
matter
(
for
purposes
of
determining
creditable
net
emissions
increases
and
decreases).
Such
credits
may
be
used
for
netting
or
as
offsets.
13.
How
Does
Clean
Unit
Status
Apply
When
There
Are
Multiple
Pollutants?
Clean
Unit
status
is
pollutant
specific
and
may
not
be
granted
for
more
than
one
pollutant,
except
in
cases
where
a
group
of
pollutants
is
characterized
as
a
single
pollutant,
such
as
VOCs.
You
may,
however,
qualify
for
simultaneous
Clean
Unit
status
for
other
pollutants
at
those
emissions
units
that
are
sufficiently
controlled
to
independently
qualify
as
``
clean''
for
each
pollutant.
For
units
applying
for
Clean
Unit
status
and
that
do
not
already
have
a
major
NSR
permit,
the
reviewing
authority
must
specify
the
pollutants
for
which
Clean
Unit
status
applies
as
part
of
the
permitting
process
establishing
Clean
Unit
status.
D.
Legal
Basis
for
the
Clean
Unit
Test
As
discussed
above,
the
Clean
Unit
applicability
test
would
provide
an
alternative
emissions
test
for
determining
if
a
significant
increase
in
emissions
has
occurred
after
a
physical
change
or
change
in
the
method
of
operation
at
units
that
are
designated
as
``
clean.''
We
believe
that
we
have
the
authority
to
allow
these
specific
types
of
units
to
use
a
different
applicability
test.
The
CAA
is
silent
on
whether
increases
in
emissions
for
purposes
of
determining
whether
a
physical
or
operational
change
constitutes
a
modification
must
be
measured
in
terms
of
actual
emissions,
potential
emissions,
or
some
other
currency.
We
believe
that
it
is
a
reasonable
interpretation
of
the
CAA
to
determine
applicability
of
the
major
NSR
program
for
units
qualifying
as
Clean
Units
in
terms
of
the
emission
limitations
or
work
practice
requirements
in
the
permit,
and
that
this
interpretation
is
consistent
with
the
statutory
purposes
of
NSR.
The
PSD
permitting
program
has
5
key
elements:
(
1)
Control
technology
review;
(
2)
air
quality
review;
(
3)
monitoring
requirements;
(
4)
information
on
the
source;
and
(
5)
procedures
for
processing
applications,
including
public
notice
and
the
opportunity
for
comment.
A
new
major
source
or
major
modification
in
an
attainment
area
must
go
through
PSD
permitting
to
become
a
Clean
Unit.
That
process
would
have
had
to
include
the
elements
listed
above.
CAA
section
165.
Similarly,
the
CAA
requires
new
major
sources
or
major
modifications
undertaken
in
nonattainment
areas
to
obtain
permits
that
require
them
to
meet
LAER
and
to
obtain
offsetting
emissions
reductions.
CAA
section
173.
In
order
to
be
designated
a
Clean
Unit,
a
major
source
or
modification
in
a
nonattainment
area
would
have
had
to
have
gone
through
major
NSR
permitting
review
in
the
last
10
years.
We
believe
that
units
that
have
undergone
minor
source
permitting
in
a
manner
that
fulfills
the
statutory
purposes
of
major
NSR
either
because
a
State's
minor
NSR
program
already
contains
equivalent
provisions
or
because
the
existing
program
is
enhanced
for
the
purpose
of
allowing
the
reviewing
authority
to
satisfy
Clean
Unit
criteria
also
will
have
satisfied
the
requirements
of
the
CAA
in
a
manner
sufficient
to
justify
Clean
Unit
status.
As
we
have
discussed
in
section
V.
C
of
this
preamble,
to
obtain
Clean
Unit
status
through
a
minor
NSR
program,
that
process
must
include
a
requirement
for
public
participation.
Furthermore,
emissions
units
that
are
designated
as
Clean
Units
through
SIPapproved
minor
NSR
programs
must
satisfy
an
air
quality
test.
You
must
provide
information
demonstrating
that
you
will
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation
or
adverse
impact
on
an
AQRV
in
a
Federal
Class
I
area.
If
your
emissions
unit
has
already
been
permitted
under
minor
NSR
or
another
SIP
approved
permitting
program,
you
may
have
already
satisfied
the
second
part
of
this
test.
If
not,
consistent
with
the
requirements
in
sections
165(
a)(
3)
and
173(
a)
of
the
CAA,
you
will
be
required
to
show
that
the
allowable
emissions
will
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
For
areas
that
do
not
already
attain
the
NAAQS,
the
source
would
be
required
to
show
that
the
emissions
for
the
unit
have
been
previously
offset,
or
the
reviewing
authority
will
have
to
show
that
these
emissions
will
not
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Regulations
34
Vatavuk,
William,
``
Part
II,
Factors
for
Estimating
Capital
and
Operating
Costs,''
Chemical
Engineering,
Nov.
3,
1980.
interfere
with
the
State's
ability
to
achieve
attainment.
For
Clean
Units
that
have
emission
limitations
and/
or
work
practice
requirements
established
through
programs
that
fulfill
relevant
major
NSR
statutory
requirements,
we
believe
that
the
alternative
way
to
estimate
emissions
increases
to
evaluate
applicability
set
forth
under
the
Clean
Unit
Test
is
appropriate
and
consistent
with
Congress's
intent.
A
project
at
a
Clean
Unit
that
would
require
a
revision
to
the
emission
limitations
or
work
practice
requirements
established
through
permitting
programs
that
meet
the
requirements
of
the
Act,
or
that
would
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
permitting
action,
must
go
through
a
new
permitting
process.
The
reviewing
authority
must
have
already
required
state
of
the
art
pollution
control
technology
(
or,
through
an
investment,
its
pollution
prevention
or
work
practice
equivalent),
conducted
the
required
air
quality
analyses
based
on
the
emissions
level
in
the
permit,
and
provided
the
public
with
an
appropriate
opportunity
to
comment
on
that
level
of
emissions
and
air
quality
impact.
Therefore,
we
believe
that
allowing
an
alternative
means
of
evaluating
applicability
based
on
a
revised
emissions
test
for
this
category
of
unit
is
consistent
with
the
CAA.
E.
Summary
of
Major
Comments
and
Responses
Although
a
few
commenters
categorically
oppose
the
Clean
Unit
Test,
most
commenters
support
the
concept.
Practically
all
commenters
oppose
some
aspect
of
the
test
or
request
that
the
test
be
clarified.
Below
are
the
major
comments
and
our
responses.
1.
How
Long
Should
You
Be
Eligible
for
the
Clean
Unit
Applicability
Test?
We
received
numerous
comments
on
the
duration
of
Clean
Unit
status.
In
the
proposal,
we
suggested
a
10
year
duration
and
asked
for
comments
regarding
this
period.
We
received
comments
supporting
various
lengths
of
time
from
2
to
20
years.
Although
some
commenters
support
a
10
year
duration,
other
commenters
oppose
it.
Many
commenters
believe
that
10
years
is
too
short
for
Clean
Unit
status.
These
commenters
argue
that
BACT/
LAER
technologies
accomplish
substantial
pollutant
removals,
and
that
the
cost
of
a
slight
increase
in
pollutant
removal
is
usually
significant.
These
commenters
urge
us
to
establish
a
Clean
Unit
status
duration
that
comports
with
the
useful
life
of
the
control
equipment,
which
would
enable
you
to
recover
the
costs
of
installing
the
pollution
control
technology.
They
believe
that
you
should
be
able
to
recoup
the
investments
in
pollution
control
before
being
forced
to
abandon
that
technology
and
pay
again
for
newer
technology.
Some
commenters
request
that
a
presumptive
life
of
20
years
be
awarded
to
Clean
Units,
which
is
approximately
how
long
the
control
equipment
should
be
effective.
Some
commenters
believe
that
10
years
would
be
too
long,
because
they
believe
that
advances
in
control
technology
occur
more
rapidly.
A
10
year
duration
would
allow
old,
less
effective
technologies
to
be
the
basis
of
immunity
from
the
NSR
program.
These
commenters
are
particularly
concerned
about
the
10
year
duration
for
BACT/
LAER
determinations
that
were
based
on
no
controls.
We
believe
that
we
have
discretion
to
determine
the
appropriate
period
for
which
you
should
be
eligible
for
the
Clean
Unit
applicability
test.
As
a
policy
matter,
we
believe
that
this
time
period
should
reach
a
balance
between
the
unit's
useful
emissions
control
equipment
life
and
the
time
frame
in
which
additional
major
NSR
review
is
likely
to
result
in
no
added
environmental
benefit.
As
a
practical
matter,
we
realize
that
the
``
ideal''
time
frame
will
vary
by
emissions
control
technology
and
by
pollutant;
however,
we
believe
using
a
single
time
frame
will
provide
simplicity
in
our
final
rules.
To
determine
an
average
life
expectancy
for
a
variety
of
control
technologies,
we
relied
on
the
guidelines
for
equipment
life
for
9
commonly
used
emissions
control
technologies
published
in
``
Estimating
Costs
of
Air
Pollution
Control
Systems,
Part
II,
Factors
for
Estimating
Capital
and
Operating
Costs.''
34
Using
the
average
of
the
low,
average,
and
high
values,
we
determined
that
a
reasonable
average
equipment
life
for
a
control
technology
is
equal
to
15
years.
We
then
looked
at
the
incremental
improvement
in
control
technology
over
time.
We
found
that
the
evolution
of
pollution
control
equipment
over
time
is
dominated
by
innovation,
rather
than
invention.
In
other
words,
the
change
in
design
and
capacity
for
any
given
device
type
occurs
infrequently
as
a
series
of
marginal
improvements
over
the
preceding
design.
Consequently,
the
marginal
improvement
in
pollution
abatement
one
can
expect
between
generations
of
the
same
type
of
device
is
also
very
small
too
small
to
justify
the
cost
of
an
entirely
new
unit.
For
example,
flue
gas
desulfurization
(
FGD)
units
have
been
used
in
the
United
States
for
about
20
years,
and
were
used
in
Japan
and
Germany
for
10
years
before
that.
During
the
early
1980'
s,
a
typical
FGD
system
removed
about
90
percent
of
the
sulfur
from
a
flue
gas
stream.
Today,
modern
FGD
systems
typically
average
95
to
99
percent
removal
efficiency
less
than
a
10
percent
improvement
in
20
years.
We
also
evaluated,
from
a
cost
per
ton
basis,
whether
the
marginal
improvement
in
removal
efficiency
is
too
expensive.
Again,
we
considered
the
FGD
example.
From
an
actual
NSR
determination
for
a
coal
fired
electrical
generating
unit
in
the
Midwest,
the
installation
of
an
FGD
system
in
1985
would
have
cost
$
189
million
and
had
a
removal
efficiency
of
90
percent
(
76,500
tons
of
sulfur
per
year).
The
identical
boiler
in
2001
would
use
an
FGD
system
with
a
95
percent
efficiency,
costing
$
285
million,
and
removing
80,750
tpy,
an
additional
4,250
tons.
The
additional
cost
for
the
improved
design
for
the
2001
installation
(
including
the
retrofit
and
upgrade
of
existing
components
and
the
new
cost
of
larger
pumps
and
other
auxiliary
equipment)
would
have
been
more
than
$
100
million,
or
greater
than
$
24,000
per
ton.
Consequently,
from
an
efficiency
standpoint,
requiring
an
upgrade
on
this
unit
to
BACT
or
LAER
levels
would
not
have
been
economical.
After
reviewing
all
of
this
information,
we
determined
that
a
15
year
period
represents
a
reasonable
and
appropriate
time
frame
during
which
you
should
be
allowed
to
use
your
permitted
allowable
emissions
to
determine
whether
an
increase
triggers
major
NSR
review.
However,
we
proposed
and
took
comment
on
a
10
year
duration.
Therefore,
today
we
are
finalizing
a
single
time
frame
of
10
years
that
applies
to
all
types
of
emissions
control
technologies
and
all
types
of
pollutants.
Because
we
believe
that
15
years
represents
a
reasonable
time
frame,
we
will
be
proposing
a
15
year
duration
for
Clean
Unit
status.
After
considering
any
public
comments
on
a
15
year
duration
for
Clean
Unit
status,
we
may
amend
today's
final
regulations.
We
believe
it
is
beneficial
to
allow
emissions
units
using
pollution
prevention
techniques
or
work
practices
to
qualify
for
Clean
Unit
status
where
those
units
meet
certain
criteria.
In
some
cases
(
coating
operations,
for
example),
pollution
prevention
techniques
or
work
practices
are
stateof
the
art
pollution
control,
and
either
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Rules
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Regulations
there
would
not
be
an
improvement
in
pollution
control
if
the
unit
were
required
to
install
add
on
controls
or
the
incremental
cost
effectiveness
of
the
add
on
control
installation
would
be
too
high
for
it
to
qualify
as
BACT.
In
other
cases,
the
most
stringent
control
is
based
on
add
on
control
and
pollution
prevention.
Therefore,
under
many
circumstances,
we
believe
that
pollution
prevention
techniques
and
work
practices
can
be
implemented
to
achieve
a
level
of
emissions
reductions
comparable
to
that
achieved
by
BACT/
LAER
add
on
controls.
Also,
initiation
of
a
pollution
prevention
technique
or
a
work
practice
can
require
a
substantial
investment
in
research
to
retool
or
reformulate
your
operations.
Thus,
we
do
not
believe
that
a
blanket
exclusion
from
Clean
Unit
status
is
appropriate
for
emissions
units
that
are
controlled
with
pollution
control
techniques.
Implementation
of
pollution
prevention
approaches
and
work
practices
usually
requires
research,
followed
by
some
retooling
or
reformulation
of
a
process
line
or
unit
operation.
As
part
of
this
retooling
or
reformulation,
some
equipment
has
to
be
purchased
up
front
(
for
example,
sniffers
for
leak
detection
and
repair
operations,
improved
process
control
consoles
and/
or
software
for
recycle
streams,
initial
modeling
for
combustion
optimization
systems).
This
equipment
purchase
or
initial
modeling
involves
a
one
time
investment;
hence,
there
is
an
investment
associated
with
pollution
prevention
or
work
practice
implementation.
Researching
the
application
of
an
approach
also
qualifies
as
an
investment
for
these
purposes.
We
received
comment
from
a
number
of
commenters
who
are
concerned
about
Clean
Unit
status
when
BACT/
LAER
determinations
are
based
on
no
control.
As
these
commenters
note,
``
no
controls''
does
not
equate
to
a
wellcontrolled
emissions
unit.
We
agree
with
these
commenters,
and
today's
final
rules
clarify
that
Clean
Unit
status
can
be
based
on
add
on
control,
pollution
prevention
techniques,
work
practices,
or
a
combination
of
them.
We
recognize
that
there
are
some
circumstances
when
the
outcome
of
a
reviewing
authority's
BACT
or
LAER
determination
may
result
in
an
emission
limitation
that
you
will
meet
without
using
an
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices).
We
believe
that
such
emissions
units
should
not
qualify
as
Clean
Units,
because
they
fail
the
very
premise
under
which
we
established
the
Clean
Unit
applicability
test.
That
is,
there
is
no
period
of
time
in
which
we
can
reach
a
balance
between
the
unit's
useful
emissions
control
equipment
life
and
the
time
frame
in
which
additional
major
NSR
review
is
likely
to
result
in
no
added
environmental
benefit.
Source
categories
that
currently
have
few
or
no
control
technology
options
are
likely
to
be
the
categories
that
will
experience
a
rapid
advancement
in
emissions
control
technology
over
a
short
period
of
time.
Accordingly,
today's
final
rules
contain
two
limitations
on
use
of
the
Clean
Unit
applicability
test.
You
may
not
use
the
Clean
Unit
applicability
test
for
any
emissions
unit
that
is
not
using
an
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
and
for
which
you
have
not
made
an
investment
to
control
emissions.
2.
Does
the
Clean
Unit
Applicability
Test
Measure
the
Increase
in
Maximum
Hourly
Potential
Emissions?
We
proposed
that
the
Clean
Unit
Test
would
continue
to
apply
as
long
as
the
emissions
unit's
maximum
hourly
potential
emissions
did
not
increase.
The
baseline
for
the
maximum
hourly
potential
emissions
rate
could
be
established
at
any
time
in
the
6
months
before
the
activity
or
project
that
increases
emissions.
Almost
all
commenters
oppose
basing
the
Clean
Unit
Test
on
the
hourly
PTE,
as
well
as
the
6
month
period
for
setting
the
emissions
rate.
Some
commenters
argue
that
an
hourly
PTE
test
is
not
environmentally
protective
enough.
One
commenter
notes
that
we
were
inappropriately
using
the
applicability
test
under
the
NSPS
as
the
applicability
test
for
major
NSR,
which
should
be
based
on
tpy.
Many
commenters
view
the
hourly
PTE
test
as
so
restrictive
that
few
sources
would
take
advantage
of
the
Clean
Unit
Test.
These
commenters
believe
that
the
hourly
emissions
rate
obscures
the
real
basis
for
Clean
Unit
status,
which
is
the
add
on
control
efficiency.
We
agree
with
the
commenters
who
maintain
that
Clean
Unit
status
should
be
based
on
the
emissions
level
achievable
through
the
use
of
control
technologies.
As
these
commenters
note,
once
an
emissions
level
has
been
determined
based
on
BACT/
LAER,
it
is
unlikely
that
additional
review
would
result
in
a
more
stringent
level
of
control.
As
a
result,
we
are
not
finalizing
the
Clean
Unit
Test
as
proposed
with
the
hourly
PTE
test.
Instead,
today's
final
rules
for
Clean
Units
are
based
on
reduction
of
air
pollution
through
the
use
of
control
technology
(
which
includes
pollution
prevention
or
work
practices)
that
meet
both
the
following
requirements.
First,
the
control
technology
achieves
a
BACT/
LAER
level
of
emissions
reduction
as
determined
through
issuance
of
a
major
NSR
permit
within
the
past
10
years.
However,
the
emissions
unit
is
not
eligible
for
Clean
Unit
status
if
the
BACT/
LAER
determination
resulted
in
no
requirement
to
reduce
emissions
below
the
level
of
a
standard,
uncontrolled,
new
emissions
unit
of
the
same
type.
Second,
the
owner
or
operator
made
an
investment
to
install
the
control
technology.
For
the
purpose
of
this
determination,
an
investment
includes
expenses
to
research
the
application
of
a
pollution
prevention
technique
to
the
emissions
unit
or
expenses
to
apply
a
pollution
prevention
technique
to
an
emissions
unit.
By
adopting
this
approach,
we
are
allowing
the
reviewing
authority
to
decide
the
appropriate
emission
limitations
or
work
practice
requirements
that
will
be
used
to
obtain
and
maintain
Clean
Unit
status.
If
a
project
at
a
Clean
Unit
does
not
cause
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
that
form
the
basis
for
Clean
Unit
status,
the
emissions
unit
remains
a
Clean
Unit.
On
the
other
hand,
if
the
project
causes
the
need
for
such
change
to
the
emission
limitations
or
work
practice
requirements,
the
emissions
unit
loses
Clean
Unit
status
and
is
subject
to
the
applicability
requirements
of
major
NSR.
3.
What
Kind
of
Changes
Are
Allowed
Under
Clean
Unit
Status?
It
is
not
our
intention
to
limit
increases
in
emissions
unit
capacity
as
long
as
emissions
are
under
the
sourcespecific
allowable
levels
and
the
increase
is
within
the
capacity
for
which
you
obtained
approval
when
applying
for
Clean
Unit
status.
Incremental
improvements
to
existing
units
are
acceptable.
However,
complete
changes
to
emissions
units
making
them
into
completely
different
units
than
were
originally
permitted
are
not
acceptable.
For
example,
switching
to
a
smaller
but
more
polluting
process
than
originally
permitted
may
trigger
stricter
BACT/
LAER
requirements,
even
at
the
same
annual
emissions
rate,
since
higher
percentage
removal
rates
and
lower
costs
would
be
possible
at
higher
concentrations.
We
expect
that
changes
such
as,
but
not
limited
to,
increasing
production
to
permitted
levels,
reconfiguring
the
process,
changing
process
chemicals
if
consistent
with
the
original
Clean
Unit
application,
replacing
components,
replacing
catalysts,
or
adding
other
controls,
or
other
changes
would
be
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Vol.
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251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
allowable
for
Clean
Units.
In
no
instances
are
we
authorizing
violations
of
any
existing
permit
conditions
or
other
applicable
requirements
that
may
apply
to
the
Clean
Unit.
You
may
not
reconstruct
a
Clean
Unit
under
an
existing
Clean
Unit
status.
4.
Does
the
Clean
Unit
Applicability
Test
Apply
to
Units
That
Have
Not
Gone
Through
a
Major
NSR
Permitting
Review?
In
1996,
we
proposed
that
reviewing
authorities
submit
their
minor
source
permit
decisions
for
us
to
determine
whether
the
emission
limitations
were
comparable
to
BACT
or
LAER.
Commenters
generally
support
allowing
units
permitted
through
minor
NSR
programs
to
qualify
for
Clean
Unit
status.
These
commenters
believe
State
and
local
agencies
are
well
equipped
to
make
control
technology
determinations.
A
few
commenters
are
concerned
that
control
technology
determinations
made
under
minor
NSR
programs
do
not
always
require
adequate
air
quality
review
or
opportunity
for
public
comment
and
review.
They
maintain
that
these
program
elements
are
essential
for
making
control
technology
determinations
that
are
equivalent
to
BACT/
LAER.
We
also
received
comments
on
allowing
Clean
Unit
status
for
emissions
units
that
have
not
gone
through
either
major
or
minor
NSR,
such
as
those
that
decrease
emissions
to
meet
other
requirements
under
the
Act.
These
comments
are
mixed.
A
few
commenters
support
this
option.
Others
believe
it
makes
no
sense
to
extend
the
status
to
units
that
had
not
had
a
recent
control
technology
determination,
particularly
considering
the
burden
the
review
would
place
on
reviewing
authorities.
We
agree
that
control
technology
determinations
made
by
State
and
local
agencies
can
be
comparable
to
BACT/
LAER,
regardless
of
the
purpose
for
which
the
control
technology
decision
is
made.
However,
we
also
agree
with
those
commenters
who
believe
a
thorough
analysis
is
necessary
to
ensure
that
air
quality
is
protected.
Moreover,
we
agree
that
a
control
technology
determination
is
incomplete
unless
it
has
been
through
public
review.
Therefore,
today
we
are
promulgating
regulations
that
allow
emissions
units
that
have
not
had
a
BACT/
LAER
determination
to
qualify
for
Clean
Unit
status,
if
they
are
permitted
under
a
SIPapproved
permitting
program
that
provides
for
public
notice
of
the
proposed
determination
and
opportunity
for
public
comment
to
determine
whether
you
should
qualify
as
a
Clean
Unit.
5.
Does
Clean
Unit
Status
Apply
to
Units
That
Have
RACT
or
MACT
Limits?
A
number
of
commenters
maintain
that
emission
limitations
based
on
RACT
and
MACT
achieve
control
comparable
to
those
based
on
BACT
and
LAER.
These
commenters
therefore
believe
Clean
Unit
status
should
be
available
for
emissions
units
with
RACT
or
MACT
limits.
However,
other
commenters
agree
with
us
that
RACT
and
MACT
limits
should
not
automatically
be
considered
equivalent
to
BACT/
LAER
limits.
We
are
maintaining
our
position
in
the
proposal
rule
that
Clean
Unit
status
does
not
presumptively
apply
to
units
with
limits
based
on
RACT
or
MACT.
However,
when
you
believe
a
specific
RACT
or
MACT
limit
is
comparable
to
BACT/
LAER,
you
may
choose
to
use
a
SIP
approved
permitting
process
to
try
to
obtain
Clean
Unit
status.
6.
How
Should
We
Determine
Whether
a
Control
Technology
Is
Comparable
to
BACT
or
LAER?
We
proposed
two
methods
for
determining
that
control
technology
was
comparable
to
BACT/
LAER
average
of
the
level
of
control
for
the
last
3
years,
and
percent
control.
None
of
the
commenters
support
using
the
average
emissions
rates
to
determine
comparability.
The
commenters
believe
that
in
some
cases
this
approach
could
lead
to
skewed
results,
or
that
the
average
control
determination
can
differ
substantially
from
the
most
recent
determination.
The
commenters
suggested
that
EPA
consider
all
technologies
required
to
be
considered
in
a
BACT/
LAER
determination,
not
just
those
listed
in
the
RBLC.
The
commenters
also
say
that
it
is
not
acceptable
to
call
an
uncontrolled
unit
a
``
clean''
unit,
when
the
Clean
Unit
Test
is
meant
for
companies
that
have
taken
the
effort
and
expense
to
install
controls
or
low
emitting
equipment.
Although
a
few
commenters
support
using
percent
control,
several
commenters
oppose
it.
They
maintain
that
defining
control
levels
based
on
a
certain
percentage
derived
from
BACT
or
LAER
for
equivalent
sources
is
not
simple
and
would
require
the
frequent
collection
and
maintenance
of
large
quantities
of
information.
Based
on
the
public
comments
on
our
two
proposed
methods,
we
have
decided
to
develop
a
modified
version
of
the
proposed
averaging
method
for
determining
when
an
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
is
comparable
to
BACT/
LAER.
You
can
make
a
showing
that
the
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
is
comparable
to
BACT/
LAER
in
one
of
two
ways:
(
1)
by
comparing
your
emissions
unit's
control
level
to
BACT/
LAER
determinations
for
other
similar
sources
in
the
RBLC;
or
(
2)
by
making
a
case
by
case
demonstration
that
your
emissions
control
is
``
substantially
as
effective''
as
BACT
or
LAER.
Under
the
first
approach,
we
have
developed
slightly
different
approaches
for
sources
located
in
attainment
and
nonattainment
areas.
For
those
emissions
units
located
in
attainment
areas,
the
emissions
unit's
control
technology
is
presumed
to
be
comparable
to
BACT
if
it
achieves
an
emission
limitation
that
is
equal
to
or
better
than
the
average
of
the
emission
limitations
achieved
by
all
the
sources
for
which
a
BACT
or
LAER
determination
has
been
made
within
the
preceding
5
years
and
entered
into
the
RBLC,
and
for
which
it
is
technically
feasible
to
apply
the
BACT
or
LAER
control
technology
to
the
emissions
unit.
To
address
the
commenters'
concerns
regarding
other
BACT/
LAER
determinations
that
might
not
be
in
the
RBLC,
we
have
included
a
provision
that
allows
the
reviewing
authority
to
also
compare
this
presumption
to
any
additional
BACT
or
LAER
determinations
of
which
it
is
aware,
and
to
consider
any
information
on
achieved
in
practice
pollution
control
technologies
provided
during
the
public
comment
period,
to
determine
whether
any
presumptive
determination
that
the
control
technology
is
comparable
to
BACT
is
correct.
For
sources
in
nonattainment
areas,
the
emissions
unit's
control
technology
is
presumed
to
be
comparable
to
LAER
if
it
achieves
an
emission
limitation
that
is
at
least
as
stringent
as
any
one
of
the
5
best
performing
similar
sources
for
which
a
LAER
determination
has
been
made
within
the
preceding
5
years,
and
for
which
information
has
been
entered
into
the
RBLC.
As
is
the
case
for
units
in
attainment
areas,
the
reviewing
authority
shall
also
compare
this
presumption
to
any
additional
LAER
determinations
of
which
it
is
aware,
and
shall
consider
any
information
on
achieved
in
practice
pollution
control
technologies
provided
during
the
public
comment
period,
to
determine
whether
any
presumptive
determination
that
the
control
technology
is
comparable
to
LAER
is
correct.
The
second
approach,
the
``
substantially
as
effective''
test,
avoids
a
``
one
size
fits
all''
approach
that
could
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31,
2002
/
Rules
and
Regulations
35
July
1,
1994
memorandum
from
John
S.
Seitz,
Director,
OAQPS,
``
Pollution
Control
Projects
and
New
Source
Review
(
NSR)
Applicability''
and
hereinafter
referred
to
as
the
``
July
1,
1994
policy
guidance.''
preclude
some
well
controlled
sources
from
benefitting
from
the
Clean
Unit
Test
simply
because
there
is
insufficient
information
in
the
RBLC
or
because
they
are
using
an
innovative
approach
to
emissions
control.
This
provision
will
allow
you
to
use
alternative
controls
as
long
as
they
achieve
comparable
control
and
air
quality
results.
We
believe
that
the
reviewing
authority
is
in
the
best
position
to
judge
whether
a
particular
control
technology
achieves
an
emissions
control
level
that
is
comparable
to
BACT
or
LAER
for
a
specific
application,
as
well
as
to
assure
that
air
quality
impacts
have
been
accounted
for.
Thus,
rather
than
requiring
the
reviewing
authority
to
submit
its
permit
decisions
to
us
for
approval
as
a
comparable
technology,
our
final
rules
allow
the
reviewing
authority
the
ability
to
make
this
determination
after
the
public
comment
process.
7.
Can
Clean
Unit
Status
Be
Made
Using
the
Title
V
Permitting
Process?
We
proposed
that
for
sources
that
had
not
undergone
major
NSR,
Clean
Unit
status
would
occur
as
part
of
the
title
V
permitting
process.
Although
a
few
commenters
support
this
concept,
several
State
and
local
agency
commenters
strongly
disagree.
These
commenters
believe
that
title
V
is
an
appropriate
mechanism
for
documenting
Clean
Units,
but
that
the
process
for
certifying
sources
should
be
separate
from
title
V
to
avoid
delays
in
title
V
permitting.
We
agree
with
these
commenters,
and
today
are
promulgating
provisions
that
an
emissions
unit
may
be
designated
as
a
Clean
Unit
once
it
has
gone
through
major
NSR
or
another
SIP
approved
permitting
program
that
provides
for
public
notice
and
opportunity
for
comment.
This
allows
the
reviewing
authority
the
flexibility
to
use
the
permitting
process
that
it
believes
is
most
appropriate
to
make
a
Clean
Unit
status
determination.
However,
once
Clean
Unit
status
has
been
established
through
a
SIP
approved
permitting
program,
it
must
be
incorporated
into
the
title
V
permit.
See
section
V.
C.
7
for
a
discussion
of
this
process.
VI.
Pollution
Control
Projects
A.
Description
and
Purpose
of
This
Action
Our
policy
is
to
promote
pollution
control
and
prevention
projects
whenever
possible.
Today
we
are
finalizing
a
rule
provision
that
would
exclude
from
major
NSR
permitting
requirements
certain
work
practices
and
the
installation
of
qualifying
pollution
control
and
pollution
prevention
projects.
With
these
provisions,
we
are
removing
a
regulatory
disincentive
that
might
otherwise
prevent
industry
from
undertaking
pollution
control
and
prevention
measures
that
result
in
a
net
environmental
benefit.
The
``
Pollution
Control
Project
Exclusion''
(
or
``
PCP
Exclusion'')
will
allow
the
installation
of
certain
projects
that
result
in
net
overall
environmental
benefits
to
avoid
the
permitting
requirements
of
major
NSR
for
their
collateral
emissions
increases
that
exceed
the
significant
level.
This
action
was
proposed
on
July
23,
1996,
and
closely
paralleled
our
existing
policy
memorandum
35
which,
in
effect,
enabled
a
control
project
exclusion
for
EUSGUs
which
was
implemented
under
the
electric
utilityspecific
NSR
rule
(
see
57
FR
32314,
hereinafter
``
WEPCO
PCP
Exclusion'')
to
apply
to
all
types
of
sources,
and
enabled
qualifying
pollution
prevention
projects
to
apply
for
an
exclusion
as
well.
This
action
will
replace
both
the
WEPCO
PCP
Exclusion
and
the
July
1,
1994
policy
guidance
with
a
single,
comprehensive
NSR
exclusion
for
all
types
of
qualifying
PCPs
including
add
on
controls,
switches
to
less
polluting
fuels,
work
practices,
and
pollution
prevention
projects.
Morever,
this
final
rule
will
minimize
procedural
delays
in
getting
a
PCP
approved,
while
ensuring
appropriate
environmental
protection.
We
define
a
PCP
as
an
activity,
set
of
work
practices,
or
project
at
an
existing
emissions
unit
that
reduces
emissions
of
air
pollution
from
the
unit.
The
PCP
Exclusion
may
be
sought
when
a
project
is
installed
at
an
existing
source
where
it
reduces
the
emissions
rate
of
one
air
pollutant
while
causing
an
increase
in
emissions
of
a
different,
``
collateral''
pollutant.
A
common
example
of
such
a
project
is
installation
of
a
thermal
incinerator,
which
forms
NOX
as
a
collateral
pollutant
while
reducing
VOC
emissions.
For
evaluating
the
environmental
impact
of
a
collateral
emissions
increase,
the
source
and
reviewing
authority
will
assess
the
difference
between
the
emissions
unit's
post
change
actual
emissions
and
its
pre
change
baseline
actual
emissions.
This
test
is
discussed
in
section
II
of
today's
preamble.
That
increase
is
then
weighed
against
the
emissions
decrease
of
the
primary
pollutant
to
determine
whether
the
PCP,
as
a
whole,
provides
an
environmental
benefit.
The
source
and
reviewing
authority
also
must
ensure
that
the
change
does
not
cause
or
contribute
to
an
air
quality
violation,
that
no
ERCs
are
generated
(
through
initial
application
of
the
PCP),
and
that
any
significant
emissions
increase
of
a
nonattainment
pollutant
is
accounted
for
with
acceptable
offsets
or
SIP
measures.
In
performing
the
air
quality
analysis
under
this
provision,
the
procedures
established
for
conducting
air
quality
analysis
in
conjunction
with
NSR
permitting
will
be
used.
This
rule
excludes
the
installation
of
qualifying
PCPs
including
add
on
control
devices,
raw
material
substitutions,
work
practices,
process
changes
and
other
pollution
prevention
strategies
from
the
definition
of
``
physical
or
operational
change''
within
the
definition
of
major
modification
in
our
Federal
regulations
(
e.
g.,
§
52.21).
We
are
also
requiring
that
States
adopt
the
same
exclusion
in
their
NSR
programs.
The
decision
to
make
codifying
changes
to
the
existing
WEPCO
PCP
Exclusion
and
the
July
1,
1994
policy
guidance
draws
largely
from
recommendations
of
the
CAAAC
Subcommittee
on
NSR
Reform.
The
members
of
the
Subcommittee
included
representatives
of
State
and
Federal
regulatory
agencies,
Federal
natural
resource
managers,
industry,
and
environmental
and
public
health
interest
groups.
The
Subcommittee's
recommendations
reflected
the
consensus
of
this
balanced
group
of
stakeholders.
B.
What
We
Proposed
and
How
Today's
Action
Compares
To
It
Our
proposed
PCP
Exclusion
provisions
essentially
restated
the
July
1,
1994
policy
guidance,
and
incorporated
a
``
primary
purpose''
test
as
an
initial
hurdle
for
candidate
PCPs.
The
``
primary
purpose''
test
would
have
limited
the
exclusion
to
those
projects
whose
primary
function
is
to
reduce
air
pollution.
The
proposal,
like
the
previous
PCP
Exclusion
rule
and
policy
guidance,
maintained
that
the
exclusion
was
not
applicable
to
air
pollution
controls
and
emissions
associated
with
the
construction
of
a
new
emissions
unit,
nor
to
the
replacement
or
reconstruction
of
an
entire
existing
emissions
unit
with
a
newer
or
different
one.
In
addition,
the
fabrication,
manufacture,
or
production
of
pollution
control/
prevention
equipment
and
inherently
less
polluting
fuels
or
raw
materials
would
not,
in
and
of
themselves,
qualify
as
a
PCP.
We
also
incorporated
two
safeguards
that
were
taken
directly
from
the
WEPCO
PCP
Exclusion
and
the
July
1,
1994
policy
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251
/
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December
31,
2002
/
Rules
and
Regulations
guidance.
First,
the
reviewing
authority
would
be
required
to
determine
that
the
PCP
is
``
environmentally
beneficial.''
A
second
safeguard
from
our
proposal
would
direct
reviewing
authorities
to
evaluate
the
air
quality
impacts
of
a
proposed
PCP
and
ensure
that
it
does
not
cause
or
contribute
to
a
NAAQS
or
PSD
increment
violation,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
We
proposed
specific
add
on
control
technologies
that
would
be
considered
presumptively
``
environmentally
beneficial''
based
on
their
proven
history
of
positive
environmental
impact.
The
proposal
also
allowed
for
fuel
switches
to
less
polluting
fuels
and
substitutions
to
less
potent
ozone
depleting
substances
(
ODS)
to
be
presumptively
environmentally
beneficial
projects.
For
other
pollution
prevention
projects
and
new
add
on
control
technologies
to
qualify
as
a
PCP,
the
proposal
required
the
reviewing
authority
to
determine
that
the
project
was
environmentally
beneficial
and,
additionally
for
new
add
on
control
devices,
that
they
be
``
demonstrated
in
practice.''
We
received
comments
on
every
key
aspect
of
the
proposed
PCP
Exclusion.
Although
most
parties
support
the
PCP
Exclusion,
their
suggestions
regarding
implementation
of
the
exclusion
vary
considerably.
Industry
commenters
generally
desire
maximum
flexibility,
and
suggest
extending
the
exclusion
to
cross
media
control
projects,
limiting
the
``
environmentally
beneficial''
and
``
primary
purpose''
requirements,
allowing
for
the
generation
of
ERCs
from
PCPs,
and
broadening
which
pollution
prevention
projects
qualified.
Other
commenters,
including
State
agencies
and
environmental
organizations,
generally
favor
a
more
restrictive
approach
that
involves
more
agency
oversight
and
creates
more
enforceable
mechanisms
to
ensure
that
the
exclusion
would
not
be
abused.
All
comments
are
specifically
addressed
in
the
Technical
Support
Document.
Today's
rule
revises
the
proposed
PCP
Exclusion
in
several
ways,
including
the
following.
Eliminating
the
``
primary
purpose''
requirement.
Expanding
the
list
of
presumptively
environmentally
beneficial
projects
to
include
additional
control
technologies
and
strategies.
Enabling
projects
that
otherwise
are
PCPs
and
result
in
utilization
increases
to
qualify
for
the
exclusion.
Using
an
actual
to
projected
actual
format
for
determining
emissions
changes
for
all
source
categories
to
demonstrate
net
environmental
benefit
supplemented
by
air
quality
analysis
under
certain
circumstances,
regardless
of
their
projected
emissions
increases
resulting
from
utilization.
Clarifying
that
the
replacement,
reconstruction,
or
modification
of
an
existing
emissions
control
technology
could
qualify
for
the
exclusion.
Detailing
the
calculations
for
determining
whether
a
switch
to
a
different
ODS
is
environmentally
beneficial.
Changing
the
visibility
component
of
the
air
quality
analysis
to
``
an
air
quality
related
value
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
a
FLM,
and
for
which
information
is
available
to
the
general
public''.
Identifying
which
fuel
switches
are
presumed
``
inherently
less
polluting''.
Enabling
work
practice
standards
to
qualify
for
the
exclusion.
Clarifying
that
modeling
for
air
quality
impacts
analyses
may
use
projected
actual
emissions.
Detailing
proper
noticing
requirements
for
listed
projects
to
use
this
exclusion.
Describing
in
detail
the
process
for
granting
the
PCP
Exclusion
for
nonlisted
control
technologies
and
pollution
prevention
strategies.
Disqualifying
projects
that
cannot
secure
acceptable
offsetting
emissions
reductions
or
SIP
measures
for
PCPs
resulting
in
a
significant
net
increase
of
a
nonattainment
pollutant.
Disallowing
generation
of
netting
and
offset
credits
from
the
initial
application
of
PCPs
that
qualify
for
this
exclusion.
Clarifying
that
non
air
pollution
impacts
will
not
be
considered
in
the
``
environmentally
beneficial''
determination.
By
today's
action
we
are
superseding
the
PCP
regulatory
exclusion
that
applied
only
to
EUSGUs.
Today's
action
covers
all
types
of
sources,
including
EUSGUs.
The
new,
broader
PCP
Exclusion
will
ensure
equitable
treatment
of
all
source
categories
and
remove
any
disincentive
for
companies
that
wish
to
install
pollution
control
and
pollution
prevention
projects,
to
the
extent
allowed
by
the
CAA.
Thus,
owners
or
operators
of
EUSGUs
who
want
a
PCP
Exclusion
may,
like
any
other
source
category,
use
the
expanded
definition
of
``
pollution
control
project,''
which
includes
the
lengthened
list
of
environmentally
acceptable
control
devices.
Despite
today's
rule
revisions
addressing
a
broader
array
of
pollution
control
and
pollution
prevention
projects
at
a
larger
variety
of
sources,
we
feel
that
the
rule's
procedures
are
less
complex
than
and
are
clearer
than
the
WEPCO
PCP
Exclusion
and
the
July
1,
1994
policy
guidance.
We
are
satisfied
that
the
final
PCP
Exclusion
best
achieves
the
goals
of
minimizing
regulatory
burden
and
reducing
procedural
delays
for
projects
that
ensure
net
overall
environmental
protection.
1.
Applicability
a.
What
types
of
projects
may
qualify
for
the
PCP
Exclusion?
In
the
WEPCO
PCP
Exclusion,
we
found
that
installation
of
add
on
emissions
control
projects,
switches
to
less
polluting
fuels,
and
certain
clean
coal
demonstration
projects
could
be
PCPs,
``
unless
the
project
renders
the
unit
less
environmentally
beneficial.''
57
FR
32319.
Today's
rule
affirms
that
these
types
of
projects
are
appropriate
candidates
for
the
exclusion,
and
it
expands
the
types
of
projects
that
can
qualify
to
include
installation
of
other
control
devices
that
were
not
previously
listed
in
the
regulations,
as
well
as
work
practice
standards
and
switches
to
less
potent
quantities
of
ODS.
Some
of
the
control
technologies
(
for
example,
oxidation/
absorption
catalyst
and
biofiltration)
listed
in
today's
revisions
were
either
not
well
known
or
not
demonstrated
in
practice
as
of
the
release
of
the
WEPCO
PCP
Exclusion
and
the
July
1,
1994
policy
guidance
exclusion;
consequently,
today's
rule
brings
the
list
of
approved
PCPs
up
to
date.
We
believe
that
the
overall
net
impact
of
installing
and
operating
the
listed
add
on
control
systems
is
environmentally
beneficial
and
that
such
projects
are
desirable
from
an
environmental
perspective.
The
add
on
controls
in
the
approved
list
historically
have
been
applied
to
many
different
kinds
of
sources
to
reduce
emissions.
They
have
been
consistently
used
because
it
is
generally
understood
that,
from
an
overall
environmental
perspective,
these
controls
are
effective
in
reducing
emissions
when
they
are
applied
to
existing
plants
in
a
manner
consistent
with
standard
and
reasonable
practices.
Certain
pollution
prevention
projects
for
example,
fuel
switches
and
low
NOX
burners
are
also
presumed
to
be
environmentally
beneficial
when
properly
applied.
Consequently,
as
part
of
the
exclusion
for
PCPs,
we
do
not
require
a
case
by
case
``
environmentally
beneficial''
demonstration
for
the
``
listed''
PCPs,
as
long
as
they
are
properly
applied
and
site
specific
factors
do
not
indicate
that
their
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/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
application
would
be
environmentally
harmful.
Thus,
the
``
environmentally
beneficial''
presumption
created
by
the
list
may
be
rebutted.
For
companies
wishing
to
install
and
operate
non
listed
PCPs,
however,
the
process
is
more
rigorous.
In
these
cases,
the
reviewing
authority
first
must
consider
casespecific
factors
to
determine
whether
the
non
listed
project
results
in
a
net
environmental
benefit
and
then
must
provide
an
opportunity
for,
and
respond
to,
public
notice
and
comment
before
approving
the
project
as
a
PCP.
b.
Why
does
the
PCP
Exclusion
not
apply
to
greenfield
sources?
Today's
rule
restricts
applicability
of
the
PCP
Exclusion
to
physical
changes
being
made
at
existing
sources.
Installing
or
implementing
a
project
on
an
existing
source
is
more
likely
to
improve
the
environment
than
is
the
construction
of
a
new
source,
since
one
can
reasonably
expect
a
PCP
to
reduce
overall
emissions,
barring
a
considerable
utilization
increase.
New
sources,
however,
introduce
new
emissions
to
the
air
without
reducing
existing
emissions,
and
consequently
should
be
as
clean
as
possible.
Furthermore,
new
emissions
units
are
among
the
major
capital
investments
in
industrial
equipment,
which
are
the
very
types
of
projects
that
Congress
intended
to
address
in
the
NSR
provisions
when
such
projects
result
in
an
overall
emissions
increase
from
the
major
stationary
source.
Thus,
when
emissions
from
a
new
source
exceed
the
significant
level,
they
are
subject
to
NSR,
and
all
emissions
that
are
generated
from
the
new
project
should
be
addressed
in
the
major
NSR
permit
evaluation
for
the
major
stationary
source.
c.
Does
the
PCP
Exclusion
apply
to
rebuilt
or
upgraded
control
devices?
We
are
clarifying
in
today's
rule
that
upgrading
or
replacing
existing
emissions
control
equipment
with
a
more
effective
emissions
control
project
can
qualify
for
the
PCP
Exclusion.
However,
the
new
PCP
would
have
to
result
in
a
level
of
control
more
stringent
than
the
original
control
equipment,
in
terms
of
emissions
rate
or
output
based
emissions
rate,
such
as
upgrading
a
scrubber
to
increase
removal
efficiency.
Another
example
that
would
qualify
is
a
control
device
that
achieves
an
emissions
reduction
equivalent
to
that
of
the
original
device,
but
is
more
energy
efficient.
An
example
of
this
is
the
conversion
of
a
thermal
oxidizer
to
a
catalytic
oxidizer.
As
long
as
the
catalytic
oxidizer
achieved
emissions
control
equivalent
to
that
of
the
thermal
oxidizer,
it
would
qualify
for
a
PCP
Exclusion
since
it
reduces
energy
use.
2.
Environmental
Benefits
a.
What
projects
do
we
presume
to
be
environmentally
beneficial?
Commenters
recommend
that
we
expand
the
list
of
presumptively
environmentally
beneficial
projects
to
include
other
add
on
control
technologies
that
are
commonly
used
to
reduce
emissions
at
major
stationary
sources.
We
agree
with
this
recommendation
and
have
expanded
the
list
of
presumptively
environmentally
beneficial
PCPs
accordingly
in
today's
rule.
We
presume
the
projects
listed
in
Table
2
are
environmentally
beneficial.
We
based
our
decision
to
add
certain
projects
to
the
list
on
two
criteria:
(
1)
The
PCP
is
``
demonstrated
in
practice'';
and
(
2)
its
overall
effectiveness
in
reducing
emissions
of
the
primary
pollutant(
s)
when
balanced
against
its
potential
for
emissions
increases
of
collateral
pollutant(
s).
TABLE
2.
ENVIRONMENTALLY
BENEFICIAL
POLLUTION
CONTROL
PROJECTS
Control
device/
PCP
Pollutant
controlled
Conventional
&
advanced
flue
gas
desulfurization.
SO2
Sorbent
injection
Electrostatic
precipitators
............
Particulates
and
other
pollutants
Baghouses
High
efficiency
multiclones
Scrubbers
Flue
gas
recirculation
.................
NOX
Low
NOX
burners
or
combustors
Selective
non
catalytic
reduction
Selective
catalytic
reduction
Low
emission
combustion
(
for
internal
combustion
engines)
oxidation/
absorption
catalyst
(
e.
g.,
SCONOX
TM)
Regenerative
thermal
oxidizers
..
VOC
and
HAP.
Catalytic
oxidizers
Thermal
incinerators
Hydrocarbon
combustion
flares
36
Condensers
Absorbers
&
adsorbers
Biofiltration
TABLE
2.
ENVIRONMENTALLY
BENEFICIAL
POLLUTION
CONTROL
PROJECTS
Continued
Control
device/
PCP
Pollutant
controlled
Floating
roofs
(
for
storage
vessels
36
For
the
purposes
of
these
rules,
``
Hydrocarbon
combustion
flare''
means
either
a
flare
used
to
comply
with
an
applicable
NSPS
or
MACT
standard
(
including
use
of
flares
during
startup,
shutdown,
or
malfunction
permitted
under
such
a
standard),
or
a
flare
that
serves
to
control
emissions
from
waste
streams
comprised
predominantly
of
hydrocarbons
and
containing
no
more
than
230
mg/
dscm
hydrogen
sulfide.
Other
presumed
environmentally
beneficial
PCPs
include
activities
or
projects
undertaken
to
accommodate:
(
1)
switching
to
different
ODS
with
a
less
damaging
ozone
depleting
effect
(
factoring
in
its
ozone
depletion
potential
and
projected
usage);
and
(
2)
switching
to
an
inherently
less
polluting
fuel,
to
be
limited
to
the
following.
Switching
from
a
heavier
grade
of
fuel
oil
to
a
lighter
fuel
oil,
or
any
grade
of
oil
to
0.05
percent
sulfur
diesel.
(
that
is,
from
a
higher
sulfur
content
#
2
fuel,
or
from
#
6
fuel,
to
CA
0.05
percent
sulfur
#
2
diesel)
Switching
from
coal,
oil,
or
any
solid
fuel
to
natural
gas,
propane,
or
gasified
coal.
Switching
from
coal
to
wood,
excluding
construction
or
demolition
waste,
chemical
or
pesticide
treated
wood,
and
other
forms
of
``
unclean''
wood
Switching
from
coal
to
#
2
fuel
oil
(
0.5
percent
maximum
sulfur
content)
Switching
from
high
sulfur
coal
to
low
sulfur
coal
(
maximum
1.2
percent
sulfur
content)
We
are
presuming
that
the
application
of
a
PCP
listed
above
is
environmentally
beneficial
and
would
be
eligible
for
a
PCP
Exclusion.
This
presumption
is
premised
on
an
understanding
that
you
will
design
and
operate
the
controls
in
a
manner
that
is
consistent
with
proper
industry,
engineering,
and
reasonable
practices,
and
that
you
minimize
increases
in
collateral
pollutants
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy.
You
will
be
required
to
certify
that
this
is
true
in
the
notification
you
send
your
reviewing
authority.
As
stated
before,
the
``
environmentally
beneficial''
determination
is
a
presumption,
so
it
can
be
rebutted
in
cases
in
which
a
reviewing
authority
determines
that
a
particular
proposed
PCP
project
would
not
be
environmentally
beneficial.
Also,
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this
presumption
does
not
apply
when:
(
1)
The
PCP
is
not
designed,
operated,
or
maintained
in
a
manner
consistent
with
standard
and
reasonable
practices;
(
2)
the
collateral
pollutant
emissions
increases
are
not
minimized
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy;
or
(
3)
the
unit
will
be
less
environmentally
beneficial.
Also,
when
a
reviewing
authority
determines
that
an
otherwise
listed
project
would
not
be
constructed
and
operated
consistent
with
standard
practices,
it
may
rebut
the
``
environmentally
beneficial''
presumption
for
that
application
of
the
technology.
Finally,
it
should
be
noted
that
commenters
on
the
proposed
rule
list
several
examples
of
specific
projects
they
believe
we
should
add
to
the
list
of
presumptively
environmentally
beneficial
projects.
However,
some
of
these
suggested
PCP
scenarios
would
never
trigger
NSR
because
there
would
not
be
a
significant
increase
in
emissions,
from
either
the
collateral
or
primary
pollutant.
For
example,
one
commenter
says
we
should
consider
the
termination
or
decommissioning
of
an
emissions
unit
an
environmentally
beneficial
technology.
We
have
never
required
a
unit
to
undergo
NSR
before
terminating
operation;
consequently,
there
is
no
need
for
a
PCP
Exclusion.
Commenters
raised
other
scenarios
but
provided
few
examples
and
insufficient
detail
from
which
we
could
draw
any
conclusions.
We
believe
that
the
PCP
Exclusion
will
benefit
only
a
subset
of
all
PCPs
undertaken
at
existing
sources,
in
part
because
most
control
projects
will
not
cause
an
emissions
increase
of
any
criteria
pollutant
and,
thus,
will
not
trigger
NSR.
As
always,
major
NSR
only
applies
to
your
physical
or
operational
changes
that
result
in
a
significant
net
emissions
increase
at
your
source.
b.
What
is
Meant
by
``
Environmentally
Beneficial''?
The
WEPCO
PCP
Exclusion
defines
a
PCP
as
``
any
activity
or
project
undertaken
.
.
.
for
purposes
of
reducing
emissions.''
§
52.21(
b)(
32).
We
have
explained
that
``
EPA
expects
that
most,
if
not
all,
pollution
control
projects
will
reduce
net
actual
emissions.''
57
FR
32319
(
1992).
The
WEPCO
PCP
Exclusion
therefore
``
avoids
the
need
to
undertake
a
quantitative
emissions
increase
calculation
in
every
case''
that
a
facility
prepares
to
undertake
a
PCP.
Rather,
in
recognition
that
while
a
PCP
``
could
theoretically
cause
a
small
collateral
increase
in
some
emissions,
it
will
substantially
reduce
emissions
of
other
pollutants,''
the
rule
contemplates
that
sources
proposing
PCPs
that
are
not
listed
will
determine
in
the
first
instance
whether
they
are
entitled
to
the
PCP
Exclusion
based
on
the
``
project's
net
emissions
and
overall
impact
on
the
environment.''
Id.
at
32321.
Nevertheless,
``
the
reviewing
authority
can
require
additional
modeling
under
certain
circumstances
to
evaluate
the
air
quality
impact
of
a
[
PCP].''
Id.
As
for
the
WEPCO
PCP
Exclusion,
``
reducing
emissions''
is
the
bedrock
of
the
PCP
Exclusion.
For
the
list
of
PCPs
in
today's
regulation,
we
are
satisfied
that
the
net
impact
on
the
environment
from
these
projects
is
beneficial
because
of
our
broad
experience
with
these
technologies.
Consequently,
such
projects
are
desirable
from
an
environmental
protection
perspective,
and
we
have
no
reason
to
doubt
the
validity
of
the
``
environmentally
beneficial''
presumption
when
such
controls
are
applied
to
existing
sources
consistent
with
standard
and
reasonable
practices.
For
those
projects
not
listed
in
Table
2,
there
is
no
presumption
as
to
whether
or
not
the
projects
are
environmentally
beneficial,
and
therefore
the
PCP
Exclusion
is
not
self
executing.
On
a
case
by
case
basis,
your
reviewing
authority
must
consider
the
net
environmental
benefit
of
a
non
listed
project
and
approve
requests
for
the
PCP
Exclusion
for
a
specific
application
of
the
project
upon
a
showing
that
it
is
environmentally
beneficial.
You
must
receive
this
approval
from
your
reviewing
authority
before
beginning
actual
construction
of
the
PCP.
This
approval
must
be
conducted
through
a
SIP
approved
permitting
process
that
conforms
to
the
requirements
of
§
§
51.160
and
51.161,
including
a
requirement
for
a
public
hearing
and
30
day
public
comment
period
on
all
aspects
of
the
project.
This
includes
an
opportunity
for
the
public
and
EPA
to
review
and
comment
on
the
environmental
benefits
analysis
and
the
air
quality
impacts
assessment.
The
reviewing
authority's
evaluation
of
the
project's
net
environmental
benefits
is
limited
to
air
quality
considerations;
specifically,
the
air
quality
benefits
of
emissions
reductions
of
the
primary
pollutant
must
outweigh
any
detrimental
effects
from
emissions
increases
in
the
collateral
pollutant,
when
comparing
the
unit's
post
change
emissions
to
its
pre
change
baseline
actual
emissions.
Also,
the
reviewing
authority's
decision
on
a
case
specific
approval
of
a
PCP
Exclusion
does
not
serve
to
proclaim
that
a
given
technology
is
environmentally
beneficial
for
purposes
of
subsequent
PCP
Exclusion
applications
for
the
same
technology.
We
may
add
non
listed
control
devices,
work
practices,
and
pollution
prevention
projects
to
the
approved
list,
such
that
a
previously
non
listed
project
can
be
considered
for
a
self
executing
PCP
Exclusion.
The
technology
must
be
reviewed
by
us
to
ensure
that
the
project's
overall
net
impact
on
the
environment
is
indeed
beneficial.
Our
evaluation
would
hinge
on
the
same
factors
mentioned
above
for
the
reviewing
authority's
case
by
case
reviews.
Once
``
listed,''
a
subsequent
project
could
be
presumed
environmentally
beneficial
unless
casespecific
factors
or
impacts
would
indicate
otherwise.
Today's
rule
also
provides
more
guidance
in
this
rule
on
what
constitutes
an
environmentally
beneficial
fuel
switch.
In
general,
we
lack
sufficient
information
from
which
to
categorically
determine
that
a
switch
to
solid
fuel
will
be
``
inherently
less
polluting.''
For
instance,
switching
from
oil
to
woodwaste
may
decrease
sulfur
emissions
while
increasing
particulate
emissions.
Switching
between
solid
fuels,
such
as
coal,
woodwaste,
or
tirederived
fuels,
must
therefore
be
evaluated
more
closely
before
we
can
determine
whether
such
a
switch
could
qualify
as
an
environmentally
beneficial
PCP.
Accordingly,
we
specify
which
fuel
switches
are
presumptively
available
for
the
PCP
Exclusion.
c.
Why
are
not
More
Pollution
Prevention
Projects
Presumed
Environmentally
Beneficial?
Switching
to
a
less
polluting
fuel
or
to
a
less
potent
quantity
of
ODS
are
prime
examples
of
pollution
prevention
projects,
and
both
are
already
listed
as
presumptively
environmentally
beneficial.
However,
some
commenters
point
out
that
there
are
far
more
end
ofpipe
add
on
technologies
that
are
listed
as
environmentally
beneficial
and
recommend
that
we
include
more
pollution
prevention
technologies.
Although
we
fully
support
and
encourage
pollution
prevention
projects
and
strategies,
special
care
must
be
taken
in
evaluating
a
pollution
prevention
project
for
the
PCP
Exclusion.
Pollution
prevention
projects
tend
to
be
dependent
on
site
specific
factors
and
lack
an
historical
record
of
performance,
which
proves
problematic
in
deciding
whether
they
are
environmentally
beneficial
when
applied
universally.
We
believe
that
both
add
on
control
devices
and
pollution
prevention
projects
have
equal
chances
of
being
presumed
environmentally
beneficial,
but
we
have
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more
data
and
history
with
the
add
on
control
equipment,
and
this
is
why
the
list
includes
more
of
those
types
of
pollution
strategies.
Pollution
prevention
projects
can
still
qualify
as
environmentally
beneficial
PCPs,
but
they
must
be
evaluated
by
the
reviewing
authority
to
confirm
their
environmental
benefits.
d.
How
are
Control
Technologies
and
Pollution
Prevention
Strategies
Added
to
the
Presumptively
``
Environmentally
Beneficial''
List?
The
proposal
would
have
allowed
the
reviewing
authority
to
add
to
the
list
of
presumptively
environmentally
beneficial
technologies,
as
long
as
it
determined
that
a
project
had
been
``
demonstrated
in
practice''
and
was
comparable
in
effectiveness
to
the
listed
technologies
on
a
pollutant
specific
basis.
We
will
continue
to
allow
new
control
technologies
that
are
demonstrated
in
practice
to
be
added
to
the
list
of
presumed
environmentally
beneficial
technologies.
However,
unlike
the
proposed
PCP
Exclusion,
we
will
not
require
that
non
listed
technologies
be
comparable
in
effectiveness
on
a
pollutant
specific
basis
with
the
emissions
reduction
efficiency
of
currently
listed
technologies
in
order
to
qualify
as
environmentally
beneficial,
since
this
is
difficult
to
compare
when
different
pollutants
must
be
considered.
Also,
today's
rule
vests
the
EPA
Administrator
with
the
sole
authority
to
approve
non
listed
pollution
strategies
as
presumptively
environmentally
beneficial.
The
reviewing
authority
may
perform
a
case
specific
approval
of
a
PCP
Exclusion
in
which
it
would
determine
that
a
non
listed
technology
is
environmentally
beneficial,
but
that
determination
only
pertains
to
the
particular
case
under
evaluation
and
would
not
serve
to
presume
that
the
technology
is
environmentally
beneficial
for
subsequent
applications.
Through
notice
and
comment
rulemaking,
we
will
maintain
and
update
the
list
as
we
deem
additional
technologies
to
be
environmentally
beneficial
or
to
remove
from
the
list
any
PCP
that
we
erroneously
listed.
Several
commenters
on
the
proposal
suggest
that
we
create
a
clearinghouse
for
newly
added
environmentally
beneficial
PCPs.
We
agree
that
additions
to
the
approved
PCP
list
need
to
be
readily
available
to
the
public;
however,
since
rulemaking
will
be
used
to
add
new
PCPs
to
the
approved
list,
no
additional
public
notice
will
be
necessary.
e.
How
do
I
Calculate
Emissions
Increases?
In
order
to
calculate
emissions
increases
for
primary
and
collateral
pollutants
for
the
purpose
of
determining
the
environmental
impact
of
the
PCP,
you
must
use
the
actual
toprojected
actual
applicability
test
method
for
calculating
the
emissions
increase.
This
test
is
discussed
in
section
II
of
today's
preamble,
and
is
consistent
with
the
remainder
of
today's
rule
revisions.
f.
How
do
you
Perform
the
Emissions
Calculation
for
Switches
to
a
Less
Potent
Amount
of
ODS?
We
have
determined
that
activities
or
projects
undertaken
to
accommodate
switching
to
an
ODS
with
less
potential
for
stratospheric
ozone
damage
are
presumptively
environmentally
beneficial,
as
long
as
the
productive
capacity
of
the
equipment
does
not
increase
as
a
result
of
the
activity
or
project.
For
determining
your
emissions
before
and
after
the
change,
you
must
perform
a
weighted
comparison
of
the
switch
based
on
ozone
depleting
potential
(
ODP),
taken
from
40
CFR
part
82,
and
the
past
and
projected
future
usage
of
each
ODS.
In
cases
where
we
have
expressed
a
chemical's
ODP
in
40
CFR
part
82
as
a
range,
the
most
conservative
value
(
that
is,
the
upper
bound
value)
should
be
used.
The
replaced
ODP
weighted
amount
is
then
calculated
by
multiplying
the
baseline
actual
usage
(
using
the
annualized
average
of
any
24
consecutive
months
of
usage
within
the
past
10
years)
by
the
ODP
of
the
replaced
ODS.
The
projected
ODP
weighted
amount
is
computed
by
multiplying
the
projected
future
annual
usage
of
the
new
substance
by
its
ODP.
The
following
example
illustrates
how
to
make
these
calculations
in
determining
whether
a
switch
to
a
different
ODS
is
environmentally
beneficial.
Example:
Source
plans
to
replace
solvents
in
its
batch
process
line.
Its
current
solvent,
CFC
12,
a
chlorofluorocarbon
(
CFC)
with
an
ODP
of
1.0,
is
emitted
at
200
tpy.
It
will
be
substituted
with
a
less
potent
solvent,
a
hydrochlorofluorocarbon
(
HCFC)
with
an
ODP
of
0.02.
As
a
result
of
this
change,
the
straight
mass
emissions
coming
from
the
solvent
will
increase
twofold
due
to
the
new
process
solvent
having
a
higher
vapor
pressure
than
the
old
solvent.
However,
this
substitution
most
likely
would
be
viewed
as
environmentally
beneficial,
since
the
ODPweighted
emissions
would
reveal
a
decreased
risk
in
environmental
harm.
Specifically,
the
CFC
12
would
be
multiplied
by
its
ODP
of
1.0,
resulting
in
200
tpy
for
pre
change
ODPweighted
emissions.
In
contrast,
the
400
tpy
of
HCFC
emissions
would
be
multiplied
by
0.02,
giving
it
a
post
change,
ODP
weighted
emission
level
of
8
tpy.
The
net
effect
is
an
emissions
decrease
of
192
tpy
on
an
ODPweighted
basis.
g.
Should
Cross
Media
Impacts
be
Considered
in
the
``
Environmentally
Beneficial''
Demonstration?
By
definition,
a
PCP
reduces
emissions
of
air
pollutants
subject
to
regulation
under
the
Act.
Therefore,
while
the
primary
environmental
benefit
of
the
PCP
would
be
to
reduce
air
emissions,
a
secondary
benefit
could
be
reducing
pollution
in
other
media.
However,
these
cross
media
tradeoffs
are
difficult
to
compare,
so
it
is
difficult
to
weigh
their
importance
in
appraising
the
overall
environmental
benefit
of
a
PCP.
We
solicited
comments
in
the
proposal
on
how
to
compare
crossmedia
pollution,
but
we
received
no
suggestions
on
how
to
design
such
a
system.
As
a
result,
we
have
determined
that
it
is
inappropriate
to
consider
nonair
impacts
when
considering
whether
projects,
activities,
or
work
practices
qualify
for
the
PCP
Exclusion.
3.
Air
Quality
Impacts
a.
What
is
the
``
Cause
or
Contribute
Test''?
Another
criterion
for
qualification
for
all
PCPs
is
that
the
emissions
from
the
PCP
cannot
cause
or
contribute
to
a
violation
of
any
NAAQS
or
PSD
increment,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM,
and
for
which
information
is
available
to
the
general
public.
This
has
been
called
the
``
cause
or
contribute
test.''
We
continue
to
believe
that
the
PCP
Exclusion
must
include
such
safeguards
to
ensure
protection
of
the
environment
and
public
health.
In
the
WEPCO
PCP
Exclusion,
we
said
that
the
reviewing
authority
``
under
certain
circumstances''
may
evaluate
the
air
quality
impact
of
a
PCP.
57
FR
32321.
Generally,
these
circumstances
would
include
large
secondary
emissions
increases
in
areas
that
are
nonattainment,
or
marginally
in
attainment,
for
the
pollutant
in
question.
We
anticipate,
however,
that
such
analyses
would
not
normally
be
required,
since
collateral
emissions
increases
from
most
relevant
projects
will
be
so
small
that
additional
modeling
should
not
be
required.
Commenters
from
industry
complain
that
determining
whether
there
would
be
an
adverse
impact
on
an
AQRV
is
too
difficult
and
believe
that
the
proposal
is
ambiguous
in
defining
roles
of
FLMs
and
reviewing
authorities.
The
intention
of
the
statutory
structure
for
preconstruction
permit
review
in
section
165(
d)
of
the
Act
unambiguously
is
to
protect
against
any
adverse
impact
on
AQRVs
in
Class
I
lands.
Therefore,
we
continue
to
believe
that
any
air
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251
/
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December
31,
2002
/
Rules
and
Regulations
quality
assessment
for
a
PCP
should
consider
all
relevant
AQRVs
in
any
Class
I
area
that
are
identified
by
the
FLM
at
the
time
you
submit
your
notice
or
permit
application
for
the
project.
For
purposes
of
those
projects
on
the
list
of
projects
presumptively
qualifying
for
the
PCP
Exclusion,
we
are
limiting
the
consideration
of
AQRVs
to
those
that
have
already
been
identified
by
an
FLM
for
the
Federal
Class
I
area.
You
should
check
with
the
National
Park
Service
website
and
other
public
information
to
determine
if
the
FLM
has
already
identified
an
AQRV
for
a
nearby
Class
I
area.
If
you
are
required
to
obtain
both
approval
from
your
reviewing
authority
and
a
permit
before
beginning
actual
construction
of
your
project,
then
additional
AQRVs
may
be
identified
by
an
FLM
consistent
with
the
procedures
provided
for
in
that
permitting
process.
b.
What
is
Necessary
for
the
Air
Quality
Impacts
Analysis?
Reviewing
authorities
can
require
you
to
analyze
your
air
quality
impacts
whenever
they
have
reason
to
believe
that:
(
1)
the
project
will
result
in
a
significant
emissions
increase
of
any
criteria
pollutant
over
levels
in
the
most
recent
analysis;
and
(
2)
such
an
increase
would
cause
or
contribute
to
a
violation
of
any
NAAQS
or
PSD
increment
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
The
analysis
must
contain
sufficient
data
to
satisfy
the
reviewing
authority
that
the
new
levels
of
emissions
will
not
cause
or
contribute
to
a
violation
of
the
NAAQS
or
PSD
increment,
or
adversely
impact
an
AQRV
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
an
FLM
and
for
which
information
is
available
to
the
general
public.
If
the
air
quality
analysis
shows
that
a
resulting
violation
is
foreseeable,
your
project
cannot
receive
the
PCP
Exclusion.
Many
industry
commenters
complain
that
the
proposed
air
quality
analysis
and
Class
I
provisions
for
the
exclusion
were
overly
burdensome
and
needed
to
be
either
eliminated
or
streamlined.
We
agree
in
part
with
this
point,
even
though
we
strongly
contend
that
there
need
to
be
safeguards
to
protect
against
misuse
of
the
exclusion
with
projects
that
will
not
provide
positive
environmental
results.
Although
today's
final
rule
contains
the
core
safeguard
to
prevent
an
adverse
air
quality
impact,
a
modeling
exercise
is
not
necessarily
warranted
in
all
cases.
While
you
are
not
required
to
notify
the
FLM
of
any
Federal
Class
I
area
located
near
your
facility
as
a
prerequisite
for
proceeding
with
a
PCP,
you
must
determine
whether
any
AQRVs
have
been
identified
in
these
areas.
FLMs
have
identified
AQRVs
for
many
of
the
Federal
Class
I
areas
and
made
this
information
available
on
a
dedicated
web
site
(
http://
www2.
nature.
nps.
gov).
If
no
AQRVs
have
been
identified
for
a
particular
Class
I
area,
your
demonstration
is
simply
a
statement
that
no
AQRVs
exist
in
Class
I
areas
that
your
source
has
the
potential
to
affect.
Similarly,
if
there
are
AQRVs
in
nearby
Federal
Class
I
areas,
but
the
pollutants
associated
with
these
AQRVS
either
will
not
be
emitted
by
your
facility
or
will
not
increase
by
a
significant
amount
as
a
result
of
the
PCP,
then
your
demonstration
should
simply
indicate
the
lack
of
any
association
between
your
PCP
project
and
the
known
AQRVs.
On
the
other
hand,
you
should
be
prepared
to
conduct
modeling
with
respect
to
any
regulated
NSR
pollutant
that
your
PCP
will
cause
to
increase
by
a
significant
amount
when
that
pollutant
is
associated
with
a
known
AQRV
in
a
nearby
Federal
Class
I
area.
Oftentimes,
a
screening
model
may
be
used
to
estimate
the
ambient
impacts
of
the
increase
from
your
facility.
Special
concern
should
be
given
in
cases
where
an
FLM
has
already
identified
adverse
impacts
for
such
AQRV.
In
such
cases,
you
are
expected
to
record
and
consider
any
information
that
the
FLM
has
made
available
concerning
the
adverse
effects,
to
help
determine
whether
the
pollutant
impacts
from
your
facility
have
the
potential
to
cause
further
adverse
impacts.
If
a
reviewing
authority,
upon
receiving
your
notification
of
using
the
PCP
Exclusion,
believes
that
an
air
quality
impacts
analysis
is
reasonably
necessary,
it
is
entitled
to
request
more
information
from
you,
including
additional
local
or
regional
modeling.
c.
How
does
the
PCP
Exclusion
Apply
to
Projects
With
Collateral
Pollutant
Increases
of
Nonattainment
Pollutants?
The
PCP
Exclusion
is
available,
regardless
of
an
area's
attainment
status
or
its
severity
of
nonattainment.
Nonetheless,
because
increases
in
a
nonattainment
pollutant
contribute
to
the
existing
nonattainment
problem,
you
or
the
reviewing
authority
must
offset
with
acceptable
emissions
reductions
any
significant
emissions
increase
in
a
nonattainment
pollutant
resulting
from
a
PCP.
We
are
promulgating
the
PCP
Exclusion
consistent
with
our
proposal's
approach
of
requiring
mitigation
of
any
significant
emissions
increase
of
a
nonattainment
pollutant
resulting
from
a
PCP.
Since
less
than
significant
collateral
emissions
increases
(
for
example,
less
than
40
tpy
of
VOC
in
a
moderate
ozone
nonattainment
area)
do
not
trigger
major
NSR,
such
mitigation
requirements
are
not
necessary
for
the
PCP
Exclusion
when
the
increase
of
the
nonattainment
pollutant
will
be
below
the
applicable
significant
level.
Be
aware,
however,
that
a
less
than
significant
emissions
increase
may
be
subject
to
a
State's
minor
NSR
requirements.
4.
Miscellaneous
a.
Can
you
Generate
ERCs
From
Your
PCP
Excluded
Project?
The
proposal
would
have
allowed
certain
projects
approved
for
the
PCP
Exclusion
to
use
their
primary
pollutant(
s)
emissions
reductions
as
NSR
offsets
or
netting
credits.
We
included
in
the
proposed
rule
a
specialized
``
environmentally
beneficial''
test
that
would
apply
to
PCPs
that
generate
ERCs.
Some
commenters
support
allowing
ERCs
and
creating
more
flexibility
to
use
them.
However,
other
commenters
recommend
that
EPA
avoid
complicating
the
PCP
Exclusion
by
factoring
emissions
trading
credits
with
the
exclusion.
These
commenters
claim
that
the
parceling
out
of
the
appropriate
reductions
for
emissions
credits
and
for
the
newly
installed
PCP
would
take
an
enormous
amount
of
time,
and
cause
problems
with
tracking
emissions
reductions
and
using
the
credits.
We
no
longer
believe
it
would
be
prudent
to
allow
PCPs
to
generate
netting
credits
or
offsets
for
the
emissions
reductions
used
to
initially
qualify
the
project
for
the
PCP
Exclusion,
in
light
of
the
issues
of
increased
complexity
that
the
commenters
raise.
But
perhaps
more
importantly,
we
feel
that
the
emissions
reductions
initially
achieved
by
the
PCP
are
integral
to
the
``
environmentally
beneficial''
demonstration
required
in
order
for
the
PCP
to
qualify
for
the
exclusion.
The
emissions
reductions
are
traded,
in
effect,
for
the
significant
emissions
increase
of
the
collateral
pollutants
and
for
the
benefits
of
being
excluded
from
the
major
NSR
permitting
requirements.
To
then
re
use
the
reductions
would
weaken
the
PCP
Exclusion
and
would
not
ensure
appropriate
environmental
protection.
Consequently,
you
cannot
use
emissions
reductions
that
initially
qualified
a
project
for
the
PCP
Exclusion
as
netting
credits
or
offsets.
However,
you
are
allowed
to
continue
to
use
these
reductions
to
generate
allowances
for
purposes
of
complying
with
the
title
IV
Acid
Rain
program.
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
1992,
the
PCP
Exclusion
was
originally
designed
for
use
by
EUSGUs
because
we
did
not
envision
that
Congress
intended
for
the
NSR
program
to
apply
to
projects
undertaken
to
comply
with
title
IV.
Nothing
in
today's
proposal
is
intended
to
change
that
design.
Moreover,
once
you
qualify
for
the
PCP
Exclusion,
you
can
apply
for
ERCs
if
you
change
your
process
conditions
in
such
a
way
that
further
reduces
emissions.
For
example,
consider
that
you
have
an
add
on
control
technology
which
receives
a
PCP
Exclusion
that,
at
full
operation,
allows
the
source
to
increase
its
emissions
of
a
specific
collateral
pollutant
and
emit
100
tpy
of
a
pollutant
(
either
a
targeted
pollutant
or
a
collateral
pollutant).
If
you
later
decide
to
take
an
hours
of
operation
limit
for
your
process
line
and/
or
control
technology
that
reduces
your
emissions
of
that
pollutant
to
75
tpy,
then
this
25
tpy
reduction
in
emissions
can
be
used
as
ERCs
if
deemed
acceptable
in
all
other
respects
by
your
reviewing
authority.
b.
Why
Are
We
Deleting
the
``
Primary
Purpose''
test?
The
``
primary
purpose''
test
was
proposed
as
an
initial
screening
mechanism
for
reviewing
authorities
to
screen
out
inappropriate
projects
and
to
streamline
the
approval
process.
This
was
designed
to
help
reviewing
authorities
avoid
dedicating
unnecessary
resources
to
non
qualifying
projects.
Furthermore,
we
recognized
that
all
of
the
listed
PCPs
have
a
primary
purpose
of
reducing
air
pollution,
so
it
followed
logically
that
any
other
PCP
should
have
the
same
primary
purpose.
However,
we
received
comments
from
both
industry
and
a
State
trade
association
stating
that
many
activities
and
projects
have
multiple
purposes
in
addition
to
reducing
emissions,
and
they
encourage
EPA
not
to
focus
on
the
primary
purpose
of
a
project,
but
rather
on
the
project's
net
environmental
benefit,
in
considering
it
for
a
PCP
Exclusion.
A
``
primary
purpose''
requirement
would
disqualify
projects
that
may
be
environmentally
beneficial
but
happen
to
not
have
pollution
control
as
their
primary
purpose.
Further,
one
commenter
stated
that
by
focusing
on
the
intent
of
the
project
rather
than
its
end
result,
administrative
agencies
will
unnecessarily
be
forced
to
devote
scarce
resources
to
making
these
determinations.
We
concur
with
these
comments
and
have
determined
that
this
test
is
potentially
unnecessarily
restrictive.
Our
primary
objective
in
allowing
for
a
PCP
Exclusion
is
to
offer
NSR
relief
for
those
projects
that
create
a
net
environmental
benefit,
and
thus
we
should
not
concern
ourselves
with
a
source's
motivation
for
undertaking
its
project.
Therefore,
by
today's
rule
revisions,
even
if
a
project's
primary
purpose
is
not
to
reduce
emissions,
it
can
still
qualify
for
the
PCP
Exclusion
if
it
meets
the
``
environmentally
beneficial''
and
air
quality
tests
set
forth
in
today's
regulations.
c.
How
Do
the
Listed
PCP
Technologies
Compare
to
BACT
or
LAER
Determinations?
The
list
of
presumed
environmentally
beneficial
technologies
contains
several
control
strategies
that
do
not
qualify
as
BACT
or
LAER.
For
example,
installing
low
NOX
burners
on
large
sized
turbines
would
rarely
constitute
an
acceptable
BACT
level.
However,
these
projects
are
presumed
environmentally
beneficial
and
are
eligible
for
the
PCP
Exclusion
from
major
NSR
because
these
controls
are
cleaner
than
the
existing
equipment
is
without
the
controls.
In
addition,
the
PCP
Exclusion
only
applies
to
sources
that
are
installing
PCPs,
and
not
to
the
installation
of
new
emissions
units
or
changes
that
increase
the
capacity
of
the
unit,
both
of
which
would
be
potentially
subject
to
BACT
or
LAER.
We
reiterate,
however,
that
merely
because
a
control
technology
is
listed
as
environmentally
beneficial
does
not
also
imply
that
the
technology
is
equivalent
to
BACT
or
LAER,
and
you
should
not
rely
on
any
such
implication
as
a
presumptive
BACT
or
LAER
determination.
d.
Is
the
Intent
of
the
PCP
Exclusion
to
Allow
Collateral
Pollutant
Emissions
to
go
Uncontrolled?
To
qualify
for
the
PCP
Exclusion,
you
must
minimize
emissions
of
collateral
pollutants
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy.
This
typically
occurs
by
inherent
design
of
the
control
device
that
causes
them.
In
most
cases,
no
additional
control
requirements
will
be
necessary.
e.
What
Does
``
Demonstrated
in
Practice''
Mean?
Representatives
from
industry
comment
that
we
should
ease
restrictions
that
require
new
add
on
technologies
to
be
demonstrated
in
practice.
We
are
continuing
to
require
that
new
technologies
be
demonstrated
in
practice
before
being
added
to
the
list,
in
part
because
this
is
an
important
element
in
a
showing
that
the
candidate
technology
is
environmentally
sound.
However,
we
have
expanded
the
meaning
of
``
demonstrated
in
practice''
to
include
technologies
demonstrated
outside
of
the
United
States.
f.
How
Can
the
Public
Participate
in
the
PCP
Exclusion
Decision
for
Your
Project?
By
these
rule
revisions,
we
are
not
requiring
any
review
of
your
PCP
by
the
public
or
your
reviewing
authority
prior
to
enabling
the
use
of
the
exclusion.
Nonetheless,
existing
State
regulations
for
minor
NSR
will
continue
to
apply
to
projects
that
qualify
for
the
PCP
Exclusion
and
are
not
otherwise
excluded
under
the
State
program.
Minor
NSR
programs
are
designed
to
consider
the
impact
these
increases
could
have
on
air
quality,
including
whether
local
conditions
justify
rebutting
the
presumption
that
a
listed
project
is
environmentally
beneficial.
Nothing
in
this
rule
voids
or
otherwise
creates
an
exclusion
from
any
otherwise
applicable
minor
NSR
preconstruction
review
requirement
in
any
SIP
that
has
been
approved
pursuant
to
section
110(
a)(
2)(
C)
of
the
Act
and
40
CFR
51.160
through
51.164.
The
minor
NSR
permits
may
afford
the
public
an
opportunity
to
review
and
comment
on
the
use
of
the
PCP
Exclusion
for
a
specific
project.
See
§
§
51.160
and
51.161.
Furthermore,
to
undertake
a
PCP
Exclusion,
you
could
use
the
title
V
permit
revision
process
to
officially
effect
the
PCP
Exclusion.
This
would
enable
the
public
to
review
the
PCP
determination
at
that
time.
Thus,
the
process
for
implementing
a
PCP
Exclusion
would
be
similar
to
the
other
exemptions
within
NSR
(
routine
maintenance,
change
in
ownership,
etc.)
whereby
you
are
empowered
to
make
the
proper
decision
based
on
the
facts
of
the
case
and
the
rule
requirements.
C.
Legal
Basis
for
PCP
In
1992,
we
revised
the
NSR
regulations
to
exclude
PCPs
at
existing
EUSGUs.
See
57
FR
32314
(
July
21,
1992),
amending
§
§
51.165(
a)(
1)(
v)(
C)(
8),
51.166(
b)(
2)(
iii)(
h),
and
52.21(
b)(
2)(
iii)(
h).
There,
we
stated
that
we
believed
``
that
Congress
did
not
intend
that
PCPs
be
considered
the
type
of
activity
that
should
trigger
NSR.''
57
FR
32319.
Although
the
1992
rulemaking
applied
only
to
EUSGUs,
we
believe
that
Congress's
intention
holds
true
for
other
industry
sectors
as
well.
Congress
could
not
have
intended
to
require
that,
and
the
Act
should
not
be
construed
such
that,
physical
or
operational
changes
undertaken
to
reduce
emissions
undergo
NSR.
Therefore,
in
today's
action,
we
are
revising
the
PCP
Exclusion
and
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/
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No.
251
/
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December
31,
2002
/
Rules
and
Regulations
removing
the
conditions
limiting
it
to
EUSGUs.
In
the
event
that
a
PCP
results
in
a
significant
emissions
increase
of
a
different
pollutant,
the
reviewing
authority
may
require
an
analysis
of
air
quality
impacts
which
would
serve
the
same
function
as
an
air
quality
impacts
analysis
conducted
as
part
of
NSR
permitting.
Providing
an
exclusion
for
PCPs
enables
facilities
to
reduce
emissions
without
having
to
wait
for
a
major
NSR
permit
to
be
issued.
We
believe
that
this
result
is
consistent
with
the
objectives
of
the
NSR
provisions
in
the
CAA.
Thus,
we
are
revising
our
rules
to
remove
disincentives
to
pollution
control
and
pollution
prevention
projects
to
the
extent
allowed
under
the
CAA.
D.
Implementation
1.
How
Do
You
Apply
For
and
Receive
a
PCP
Exclusion?
The
process
for
obtaining
a
PCP
Exclusion
basically
breaks
down
into
two
separate
scenarios,
depending
on
whether
your
proposed
project
is
``
listed''
or
``
non
listed''
as
environmentally
beneficial.
Both
processes
are
presented
below.
a.
What
Is
the
Process
You
Must
Follow
for
Projects
Involving
Listed
PCPs?
Before
you
begin
actual
construction
on
your
PCP,
you
must
submit
a
notice
to
your
reviewing
authority
that
includes
the
following
information
(
and
depending
on
your
reviewing
authority's
requirements,
this
information
may
be
submitted
with
a
part
70,
part
71
or
other
SIP
approved
permit
application
such
as
a
minor
NSR
permit
application):
(
1)
A
description
of
project;
(
2)
an
analysis
of
the
environmentally
beneficial
nature
of
the
PCP,
including
a
projection
of
emissions
increases
and
decreases
(
speciated,
using
an
appropriate
emissions
test
for
the
emissions
unit);
and
(
3)
a
demonstration
that
the
project
will
not
have
an
adverse
air
quality
impact.
You
may
begin
construction
on
the
PCP
immediately
upon
submitting
your
notice
to
the
reviewing
authority.
However,
if
your
reviewing
authority
determines
that
the
source
does
not
qualify
for
a
PCP
Exclusion,
you
may
be
subject
to
a
delay
in
the
project
or
an
order
to
not
undertake
the
project.
b.
What
Is
the
Process
You
Must
Follow
for
Projects
Involving
Non
Listed
PCPs?
For
projects
not
listed
in
Table
2,
on
a
case
by
case
basis
your
reviewing
authority
must
consider
the
net
environmental
benefit
of
a
non
listed
project
and,
within
a
reasonable
amount
of
time,
act
upon
your
request
for
the
exclusion
for
a
specific
application.
You
must
receive
this
approval
from
your
reviewing
authority
before
beginning
actual
construction
of
the
PCP.
Your
reviewing
authority
will
provide
an
opportunity
for
public
review
and
comment
prior
to
granting
its
approval
for
the
PCP.
Your
application
for
case
specific
approval
of
a
PCP
Exclusion
should
have
the
same
information
as
required
above
for
a
notice
to
use
a
listed
technology.
The
only
difference
between
the
two
processes
is
that
the
use
of
a
listed
technology
allows
you
to
commence
construction
on
your
PCP
immediately
after
submitting
your
notice
to
the
reviewing
authority,
whereas
the
use
of
a
non
listed
technology
requires
you
to
first
submit
an
application
to
your
reviewing
authority
and
obtain
its
approval
prior
to
construction
of
your
PCP.
2.
What
Process
Will
We
Follow
To
Add
New
Projects
to
the
List
of
Environmentally
Beneficial
PCPs?
We
will
use
notice
and
comment
rulemaking
procedures
to
add
new
projects
to
the
list
of
PCPs
that
are
presumed
to
be
environmentally
beneficial.
We
may
take
this
action
on
our
own
initiative
or
you
may
petition
us,
if
you
believe
there
is
a
project
that
should
be
added
to
the
list.
If
you
submit
a
petition
to
us
requesting
that
a
non
listed
air
pollution
control
technology
(
which
includes
pollution
prevention
or
work
practices)
be
determined
environmentally
beneficial
and
presumptively
qualified
for
the
PCP
Exclusion,
you
should
describe
the
anticipated
emissions
consequence
of
installing
the
PCP,
both
for
primary
and
collateral
pollutants.
We
will
review
your
submittal
within
a
reasonable
amount
of
time.
If
we
believe
that
the
project
should
be
added
to
the
list,
we
will
amend
the
list
of
approved
PCPs
through
rulemaking.
Once
the
rule
has
been
amended,
you
may
use
a
newly
listed
PCP
if
you
proceed
in
accordance
with
the
process
for
implementing
the
PCP
Exclusion
for
listed
PCPs.
(
See
section
VI.
D.
1.
a.)
3.
What
Are
Our
Operational
Expectations
for
an
Excluded
PCP?
By
this
rule,
we
are
creating
a
general
duty
for
all
sources
approved
to
use
a
PCP
Exclusion.
This
general
duty
clause
requires
you
to
operate
the
PCP
in
a
manner
consistent
with
reasonable
engineering
practices
and
with
the
basic
applicability
requirements
for
the
exclusion
(
i.
e.,
being
environmentally
beneficial
and
having
no
adverse
air
quality
impacts).
This
means
that
you
have
a
legal
responsibility
to
operate
in
a
manner
that
is
consistent
with
your
analysis
of
the
environmental
benefits
and
air
quality
impacts
analysis,
and
that
you
will
minimize
collateral
pollutant
increases
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy.
4.
What
Are
the
Implications
of
Not
Complying
With
the
PCP
Exclusion
Process?
The
PCP
Exclusion
is
a
mechanism
for
bypassing
the
major
NSR
permitting
requirements.
If
you
do
not
comply
with
the
steps
necessary
to
qualify
for
the
PCP
Exclusion
under
the
terms
of
the
PCP
provisions,
you
can
become
subject
to
major
NSR.
VII.
Listed
Hazardous
Air
Pollutants
The
1990
Amendments
to
the
CAA
at
section
112(
b)(
6)
exempted
HAP
listed
under
section
112(
b)(
1)
from
the
PSD
requirements
in
part
C.
In
our
1996
Federal
Register
Notice,
we
proposed
changes
to
the
regulations
at
§
§
51.166
and
52.21
to
implement
this
exemption.
Specifically,
we
proposed
the
following.
The
HAP
listed
in
section
112(
b)(
1),
as
well
as
any
pollutant
that
may
be
added
to
the
list,
are
excluded
from
the
PSD
provisions
of
part
C.
These
HAP
include
arsenic,
asbestos,
benzene,
beryllium,
mercury,
radionuclides,
and
vinyl
chloride,
all
of
which
were
previously
regulated
under
the
PSD
rules.
This
exemption
applies
to
the
provisions
for
major
stationary
sources
in
§
§
51.166(
b)(
2)
and
52.21(
b)(
2),
the
significant
levels
in
§
§
51.166(
b)(
23)(
i)
and
52.21(
b)(
23)(
i),
and
the
significant
monitoring
concentrations
in
§
§
51.166(
i)(
8)
and
52.21(
i)(
8).
Pollutants
listed
in
regulations
pursuant
to
section
112(
r)(
1),
Accidental
Release,
are
not
excluded
from
the
PSD
provisions
of
part
C.
Any
HAP
listed
in
section
112(
b)(
1)
that
are
regulated
as
constituents
or
precursors
of
a
more
general
pollutant
listed
under
section
108
are
still
subject
to
PSD,
despite
the
exemption
in
section
112(
b)(
6).
If
a
pollutant
is
removed
from
the
list
under
the
provisions
of
section
112(
b)(
3)
of
the
Act,
that
pollutant
would
be
subject
to
the
applicable
PSD
requirements
of
part
C
if
it
is
otherwise
regulated
under
the
Act.
Pollutants
regulated
under
the
Act
and
not
on
the
list
of
HAP,
such
as
fluorides,
TRS
compounds,
and
sulfuric
acid
mist,
continue
to
be
regulated
under
PSD.
Public
commenters
generally
agree
that
our
proposal
reflects
the
statutory
requirements.
Therefore,
today
we
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
taking
final
action
to
promulgate
these
proposed
provisions
at
§
§
51.166(
b)(
23)(
i),
51.166(
i)(
8),
52.21(
b)(
23)(
i),
and
52.21(
i)(
8).
As
today's
regulations
provide,
the
following
pollutants
currently
regulated
under
the
Act
are
subject
to
Federal
PSD
review
and
permitting
requirements.
CO
NOX
SO2
PM
and
particulate
matter
less
than
10
microns
in
diameter
(
PM
10)
Ozone
(
VOC)
Lead
(
Pb)
(
elemental)
Fluorides
(
excluding
hydrogen
fluoride)
Sulfuric
acid
mist
H2S
TRS
compounds
(
including
H2S)
CFCs
11,
12,
112,
114,
115
Halons
1211,
1301,
2402
Municipal
Waste
Combustor
(
MWC)
acid
gases,
MWC
metals,
and
MWC
organics
ODS
regulated
under
title
VI
The
PSD
program
applies
automatically
to
newly
regulated
NSR
pollutants,
which
would
include
final
promulgation
of
an
NSPS
applicable
to
a
previously
unregulated
pollutant.
As
we
indicated
in
our
proposal
package,
CAA
section
112(
b)(
7)
states
that
elemental
Pb
(
the
named
chemical)
may
not
be
listed
by
the
Administrator
as
a
HAP
under
section
112(
b)(
1).
Therefore,
because
section
112(
b)(
6)
exempts
only
the
pollutants
listed
in
section
112,
elemental
Pb
emissions
are
not
exempt
from
the
Federal
PSD
requirements.
Elemental
Pb
continues
to
be
a
criteria
pollutant
subject
to
the
Pb
NAAQS
and
other
requirements
of
the
Act.
As
proposed,
we
are
also
continuing
to
maintain
that
the
reference
to
Pb
in
the
regulations
regarding
the
significant
levels
and
significant
monitoring
concentrations
covers
the
Pb
portion
of
Pb
compounds.
See
§
§
51.166(
b)(
23),
51.166(
i)(
8),
52.21(
b)(
23),
and
52.21(
i)(
8).
Otherwise,
the
word
elemental
might
imply
that
only
Pb
that
is
not
part
of
a
Pb
compound
is
covered.
One
commenter
requests
that
we
amend
the
regulations
to
include
a
definition
of
pollutants
regulated
under
the
Act.
We
agree
with
the
commenter
that
such
a
provision
would
clarify
which
pollutants
are
covered
under
the
PSD
program.
Moreover,
the
nonattainment
NSR
rules
at
§
51.165
would
also
benefit
from
this
clarity.
Therefore,
today's
final
regulations
include
a
definition
for
regulated
NSR
pollutant.
This
new
definition
replaces
the
terminology
``
pollutants
regulated
under
the
Act.''
The
term
``
Regulated
NSR
pollutant''
includes
the
following
pollutants.
NOX
or
any
VOC
Any
pollutant
for
which
a
NAAQS
has
been
promulgated
Any
pollutant
that
is
subject
to
any
standard
promulgated
under
section
111
of
the
Act
Any
Class
I
or
II
substance
subject
to
a
standard
promulgated
under
or
established
by
title
VI
of
the
Act.
The
new
definition
excludes
HAPs
listed
in
section
112
of
the
Act
(
including
any
pollutants
that
may
be
added
to
the
list
pursuant
to
section
112(
b)(
2)
of
the
Act).
However,
when
any
pollutant
listed
under
section
112
of
the
Act
is
also
a
constituent
or
precursor
of
a
more
general
pollutant
that
is
regulated
under
section
108
of
the
Act,
that
listed
pollutant
may
be
regulated
under
NSR
but
only
as
part
of
regulation
of
the
general
pollutant.
As
we
indicated
in
our
proposal,
State
and
local
agencies
with
an
approved
PSD
program
may
continue
to
regulate
the
HAP
now
exempted
from
Federal
PSD
by
section
112(
b)(
6)
if
their
PSD
regulations
provide
an
independent
basis
to
do
so.
These
State
and
local
rules
remain
in
effect
unless
they
are
revised
to
provide
similar
exemptions.
Such
provisions
that
are
part
of
the
SIP
are
federally
enforceable.
Section
112(
q)
retains
existing
NESHAP
regulations
by
specifying
that
any
standard
under
section
112
in
effect
before
the
enactment
of
the
1990
Amendments
remains
in
force.
Therefore,
the
requirements
of
§
§
61.05
to
61.08,
including
preconstruction
permitting
requirements
for
new
and
modified
sources
subject
to
existing
NESHAP
regulations,
are
still
applicable.
Pollutants
listed
under
section
112(
r)
are
not
included
in
the
definition
of
regulated
NSR
pollutant.
As
we
proposed,
substances
regulated
under
section
112(
r)
may
still
be
subject
to
PSD
if
they
are
regulated
under
other
provisions
of
the
Act.
For
example,
even
though
H2S
is
listed
under
section
112(
r),
it
is
still
regulated
under
the
Federal
PSD
provisions
because
it
is
regulated
under
the
NSPS
program
in
section
111.
This
means
that
the
listing
of
a
substance
under
section
112(
r)
does
not
exclude
the
substance
from
the
Federal
PSD
provisions;
the
PSD
provisions
apply
if
the
substance
is
otherwise
regulated
under
the
Act.
We
are
not
taking
final
action
on
ambient
impact
concentrations
or
maximum
allowable
increases
in
pollutant
concentrations
as
proposed
in
§
51.166(
b)(
23)(
iv)
and
(
v)
and
§
52.21(
b)(
23)(
iv)
and
(
v).
Although
these
provisions
are
included
in
the
definition
of
significant,
they
do
not
relate
to
the
new
provisions
for
HAP.
Instead,
they
concern
Class
I
issues,
which
we
have
not
taken
final
action
on.
VIII.
Effective
Date
for
Today's
Requirements
As
discussed
above,
today
we
are
changing
the
existing
NSR
requirements
in
five
ways.
Providing
a
new
method
for
determining
baseline
actual
emissions
Adopting
the
actual
to
projectedactual
methodology
for
determining
whether
a
major
modification
has
occurred
Allowing
major
stationary
sources
to
comply
with
PALs
to
avoid
having
a
significant
emissions
increase
that
triggers
the
requirements
of
the
major
NSR
program
Providing
new
applicability
provisions
for
emissions
units
that
are
designated
Clean
Units
Excluding
PCPs
from
the
definition
of
``
physical
change
or
change
in
the
method
of
operation''
Today's
rules
codify
our
longstanding
policy
for
calculating
the
baseline
actual
emissions
for
EUSGUs,
which
is
any
consecutive
2
years
in
the
past
5
years,
or
another
more
representative
period.
In
today's
final
rules
we
are
also
including
a
new
section
that
outlines
how
a
major
modification
is
determined
under
the
various
major
NSR
applicability
options
and
clarifies
where
you
will
find
the
provisions
in
our
revised
rules.
All
of
these
changes
will
take
effect
in
the
Federal
PSD
program
(
codified
at
§
52.21)
on
March
3,
2003.
This
means
that
these
rules
will
apply
on
March
3,
2003,
in
any
area
without
an
approved
PSD
program,
for
which
we
are
the
reviewing
authority,
or
for
which
we
have
delegated
our
authority
to
issue
permits
to
a
State
or
local
reviewing
authority.
To
be
approvable
under
the
SIP,
State
and
local
agency
programs
implementing
part
C
(
PSD
permit
program
in
§
51.166)
or
part
D
(
nonattainment
NSR
permit
program
in
§
51.165)
must
include
today's
changes
as
minimum
program
elements.
State
and
local
agencies
should
assure
that
any
program
changes
under
§
§
51.165
and
51.166
are
consistently
accounted
for
in
other
SIP
planning
measures.
State
and
local
agencies
must
adopt
and
submit
revisions
to
their
part
51
permitting
programs
implementing
these
minimum
program
elements
no
later
than
January
2,
2006.
That
is,
for
both
nonattainment
and
attainment
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2002
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Rules
and
Regulations
areas,
the
SIP
revisions
must
be
adopted
and
submitted
within
3
years
from
today.
The
Act
does
not
specify
a
date
for
submission
of
SIPs
when
we
revise
the
PSD
and
NSR
rules.
We
believe
it
is
appropriate
to
establish
a
date
analogous
to
the
date
for
submission
of
new
SIPs
when
a
NAAQS
is
promulgated
or
revised.
Under
section
110(
a)(
1)
of
the
Act,
as
amended
in
1990,
that
date
is
3
years
from
promulgation
or
revision
of
the
NAAQS.
Accordingly,
we
have
established
3
years
from
today's
revisions
as
the
required
date
for
submission
of
conforming
SIP
revisions.
We
have
made
conforming
changes
to
the
PSD
regulations
at
§
51.166(
a)(
6)(
i)
to
indicate
that
State
and
local
agencies
must
adopt
and
submit
plan
revisions
within
3
years
after
new
amendments
are
published
in
the
Federal
Register.
In
our
1996
proposed
rule,
we
solicited
comment
on
a
new
approach
for
implementing
the
applicabilityrelated
NSR
improvements
(
i.
e.,
PALs,
the
Clean
Unit
provision,
the
PCP
Exclusion,
and
provisions
related
to
measuring
emissions
increases).
We
noted
that
the
Agency
in
the
past
``
has
essentially
required
States
to
follow
a
single
applicability
methodology,''
but
that
``
States
could,
of
course,
have
a
more
stringent
approach.''
61
FR
38253.
Instead
of
following
this
normal
course,
we
proposed
to
establish
the
new
applicability
provisions
as
a
``
menu''
of
options.
Under
this
approach,
we
would
have
allowed
States
to
adopt
into
their
NSR
programs
all,
some,
or
none
of
the
new
provisions.
In
today's
final
rule,
we
have
decided
not
to
implement
the
menu
approach.
We
have
opted
instead
to
retain
our
longstanding
approach
of
incorporating
all
of
the
new
provisions
into
our
``
base''
NSR
program
requirements,
which
are
set
forth
in
§
§
51.165,
51.166,
and
52.24.
The
same
provisions
will
be
included
in
§
52.21,
our
own
PSD
permitting
program.
Our
decision
is
based
primarily
on
our
belief
that
the
NSR
program
will
work
better
as
a
practical
matter
and
will
produce
better
environmental
results
if
all
five
of
the
new
applicability
provisions
are
adopted
and
implemented.
We
and
our
stakeholders
invested
unprecedented
amounts
of
time,
energy,
and
resources
in
deciding
how
best
to
improve
the
NSR
program.
After
well
over
a
decade
of
sustained
effort,
we
believe
that
we
have
found
effective
solutions
to
many
of
the
program's
most
intractable
problems.
We
hope
that
making
the
new
provisions
part
of
our
base
programs
will
provide
incentive
for
these
provisions
to
be
adopted
on
a
widespread
basis.
Notably,
even
without
the
menu
approach,
State
and
local
jurisdictions
have
significant
freedom
to
customize
their
NSR
programs.
Ever
since
our
current
NSR
regulations
were
adopted
in
1980,
we
have
taken
the
position
that
States
may
meet
the
requirements
of
part
51
``
with
different
but
equivalent
regulations.''
45
FR
52676.
Several
States
have,
indeed,
implemented
programs
that
work
every
bit
as
well
as
our
own
base
programs,
yet
depart
substantially
from
the
basic
framework
established
in
our
rules.
A
good
example
is
Oregon,
where
the
SIPapproved
program
requires
all
major
sources
to
obtain
plantwide
permits
not
unlike
the
PALs
that
we
are
finalizing
today.
Oregon's
program
plainly
illustrates
that
we
have
not
implemented
our
base
programs
with
a
one
size
fits
all
mentality
and
certainly
do
not
have
the
goal
of
``
preempting''
State
creativity
or
innovation.
Perhaps
the
biggest
potential
disadvantages
to
implementing
the
new
applicability
provisions
as
part
of
our
base
programs
are
the
time
and
effort
required
to
revise
existing
State
programs
and
to
have
the
revised
programs
approved
as
part
of
the
SIP.
For
States
that
choose
to
adopt
all
of
the
new
applicability
provisions,
we
expect
that
the
SIP
approval
process
will
be
expeditious.
Of
course,
the
review
and
approval
process
will
be
more
complicated
for
States
that
choose
to
adopt
a
program
that
differs
from
our
base
programs.
For
example,
if
a
State
decides
it
does
not
want
to
implement
any
of
the
new
applicability
provisions,
that
State
will
need
to
show
that
its
existing
program
is
at
least
as
stringent
as
our
revised
base
program.
It
would
be
impossible
for
us
to
plan
ahead
for
all
of
the
possible
variations
that
States
might
ultimately
elect
to
pursue.
We
will,
however,
reach
out
to
relevant
stakeholders
immediately
after
publication
of
these
rules
and
try
to
develop
streamlined
methods
for
addressing
common
questions
that
may
arise
during
the
SIP
approval
process.
IX.
Administrative
Requirements
A.
Executive
Order
12866
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
the
Agency
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
OMB
review
and
the
requirements
of
the
Executive
Order.
The
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligations
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
OMB
has
notified
us
that
it
considers
this
rule
a
``
significant
regulatory
action.''
As
such,
this
action
was
submitted
to
OMB
for
review.
B.
Executive
Order
13132
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
This
final
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
While
this
final
rule
will
result
in
some
expenditures
by
the
States,
we
expect
those
expenditures
to
be
limited
to
$
331,250
per
year.
This
figure
includes
the
small
increase
in
the
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
revise
the
State's
SIP.
However,
these
revisions
provide
greater
operational
flexibility
to
sources
permitted
by
the
States,
which
will
in
turn
reduce
the
overall
burden
of
the
program
on
State
and
local
authorities
by
reducing
the
number
of
required
permit
modifications.
Thus,
Executive
Order
13132
does
not
apply
to
this
rule.
Nevertheless,
in
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
we
specifically
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2002
/
Rules
and
Regulations
solicited
comment
on
the
proposed
rule
from
State
and
local
officials.
C.
Executive
Order
13175
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
9,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
We
believe
that
this
final
rule
does
not
have
tribal
implications
as
specified
in
Executive
Order
13175.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
EPA
began
considering
potential
revisions
to
the
NSR
rules
in
the
early
1990'
s
and
proposed
changes
in
1996.
The
purpose
of
today's
final
rule
is
to
add
greater
flexibility
to
the
existing
major
NSR
regulations.
These
changes
will
benefit
both
reviewing
authorities
and
the
regulated
community
by
providing
increased
certainty
as
to
when
the
requirements
apply,
and
by
providing
alternative
ways
to
comply
with
the
requirements.
Taken
as
a
whole,
today's
final
rule
should
result
in
no
added
burden
or
compliance
costs
and
should
not
substantially
change
the
level
of
environmental
performance
achieved
under
the
previous
rules.
We
anticipate
that
initially
these
changes
will
result
in
a
small
increase
in
the
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
be
included
in
the
State's
SIP,
as
well
as
other
small
increases
in
burden
discussed
under
``
Paperwork
Reduction
Act.''
Nevertheless,
these
revisions
will
ultimately
provide
greater
operational
flexibility
to
sources
permitted
by
the
States,
which
will
in
turn
reduce
the
overall
burden
of
the
program
on
State
and
local
authorities
by
reducing
the
number
of
required
permit
modifications.
In
comparison,
no
tribal
government
currently
has
an
approved
tribal
implementation
plan
(
TIP)
under
the
CAA
to
implement
the
NSR
program.
The
Federal
government
is
currently
the
NSR
reviewing
authority
in
Indian
country,
thus
tribal
governments
should
not
experience
added
burden,
nor
should
their
laws
be
affected
with
respect
to
implementation
of
this
rule.
Additionally,
although
major
stationary
sources
affected
by
today's
final
rule
could
be
located
in
or
near
Indian
country
and/
or
be
owned
or
operated
by
tribal
governments,
such
sources
would
not
incur
additional
costs
or
compliance
burdens
as
a
result
of
this
rule.
Instead,
the
only
effect
on
such
sources
should
be
the
benefit
of
the
added
certainty
and
flexibility
provided
by
the
rule.
We
recognize
the
importance
of
including
tribal
consultation
as
part
of
the
rulemaking
process.
Although
we
did
not
include
specific
consultation
with
tribal
officials
as
part
of
our
outreach
process
on
this
final
rule,
which
was
developed
largely
prior
to
issuance
of
Executive
Order
13175
and
which
does
not
have
tribal
implications
under
Executive
Order
13175,
we
will
continue
to
consult
with
tribes
on
future
rulemakings
to
assess
and
address
tribal
implications,
and
will
work
with
tribes
interested
in
seeking
TIP
approval
to
implement
the
NSR
program
to
ensure
consistency
of
tribal
plans
with
this
rule.
D.
Executive
Order
13045
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045,
entitled
``
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks''
(
62
FR
19885,
April
23,
1997),
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866;
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
Agency
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
This
final
rule
is
not
subject
to
the
Executive
Order
because
it
is
not
economically
significant
as
defined
in
Executive
Order
12866,
and
because
the
Agency
does
not
have
reason
to
believe
the
environmental
health
or
safety
risks
addressed
by
this
action
present
a
disproportionate
risk
to
children
because
we
believe
that
this
package
as
a
whole
will
result
in
equal
or
better
environmental
protection
than
currently
provided
by
the
existing
regulations,
and
do
so
in
a
more
streamlined
and
effective
manner.
E.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Pub.
L.
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
as
to
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
have
determined
that
this
rule
does
not
contain
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
Although
initially
these
changes
are
expected
to
result
in
a
small
increase
in
the
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
be
included
in
the
State's
SIP,
as
well
as
other
small
increases
in
burden
discussed
under
``
Paperwork
Reduction
Act,''
these
revisions
will
ultimately
provide
greater
operational
flexibility
to
sources
permitted
by
the
States,
which
will
in
turn
reduce
the
overall
burden
of
the
program
on
State
and
local
authorities
by
reducing
the
number
of
required
permit
modifications.
In
addition,
we
believe
the
rule
changes
will
actually
reduce
the
regulatory
burden
associated
with
the
major
NSR
program
by
improving
the
operational
flexibility
of
owners
and
operators,
improving
the
clarity
of
requirements,
and
providing
alternatives
that
sources
may
take
advantage
of
to
further
improve
their
operational
flexibility.
Thus,
today's
rule
is
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.
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/
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67,
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/
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December
31,
2002
/
Rules
and
Regulations
For
the
same
reasons
stated
above,
we
have
determined
that
this
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments.
Thus,
today's
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.
F.
Regulatory
Flexibility
Analysis
EPA
has
determined
that
it
is
not
necessary
to
prepare
a
regulatory
flexibility
analysis
in
connection
with
this
final
rule.
EPA
has
also
determined
that
this
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
For
purposes
of
assessing
the
impacts
of
today's
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
Any
small
business
employing
fewer
than
500
employees;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district,
or
special
district
with
a
population
of
less
than
50,000;
or
(
3)
a
small
organization
that
is
any
not
forprofit
enterprise
that
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
After
considering
the
economic
impacts
of
today's
final
rule
on
small
entities,
we
have
concluded
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
In
determining
whether
a
rule
has
a
significant
economic
impact
on
a
substantial
number
of
small
entities,
the
impact
of
concern
is
any
significant
adverse
economic
impact
on
small
entities,
since
the
primary
purpose
of
the
regulatory
flexibility
analyses
is
to
identify
and
address
regulatory
alternatives
``
which
minimize
any
significant
economic
impact
of
the
proposed
rule
on
small
entities.''
5
U.
S.
C.
603
and
604.
Thus,
an
agency
may
conclude
that
a
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
if
the
rule
relieves
regulatory
burden,
or
otherwise
has
a
positive
economic
effect,
on
all
of
the
small
entities
subject
to
the
rule.
A
Regulatory
Flexibility
Act
Screening
Analysis
(
RFASA),
developed
as
part
of
a
1994
draft
Regulatory
Impact
Analysis
(
RIA)
and
incorporated
into
the
September
1995
ICR
renewal
analysis,
showed
that
the
changes
to
the
NSR
program
due
to
the
1990
CAA
Amendments
would
not
have
an
adverse
impact
on
small
entities.
This
analysis
encompassed
the
entire
universe
of
applicable
major
sources
that
were
likely
to
also
be
small
businesses
(
approximately
50
``
small
business''
major
sources).
Because
the
administrative
burden
of
the
NSR
program
is
the
primary
source
of
the
NSR
program's
regulatory
costs,
the
analysis
estimated
a
negligible
``
cost
to
sales''
(
regulatory
cost
divided
by
the
business
category
mean
revenue)
ratio
for
this
source
group.
Currently,
and
as
reported
in
the
current
ICR,
there
is
no
economic
basis
for
a
different
conclusion.
We
believe
these
rule
changes
will
reduce
the
regulatory
burden
associated
with
the
major
NSR
program
for
all
sources,
including
all
small
businesses,
by
improving
the
operational
flexibility
of
owners
and
operators,
improving
the
clarity
of
requirements,
and
providing
alternatives
that
sources
may
take
advantage
of
to
further
improve
their
operational
flexibility.
As
a
result,
the
program
changes
provided
in
the
final
rule
are
not
expected
to
result
in
any
increases
in
expenditure
by
any
small
entity.
We
have
therefore
concluded
that
today's
final
rule
will
relieve
regulatory
burden
for
all
small
entities.
G.
Paperwork
Reduction
Act
The
information
collection
requirements
in
this
rule
will
be
contained
in
two
different
Information
Collection
Requests
(
ICRs).
The
Office
of
Management
and
Budget
(
OMB)
has
approved
the
information
collection
requirements
contained
under
the
provisions
of
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
and
has
assigned
OMB
control
number
2060
0003
(
ICR
1230.10).
The
EPA
prepared
an
ICR
document
(
ICR
No.
1230.10)
extending
the
approval
of
the
ICR
for
the
promulgated
NSR
regulations
on
March
30,
2001.
On
October
29,
2001,
OMB
approved
EPA's
request
for
extension
for
3
years
until
October
31,
2004.
The
OMB
number
for
this
approval
is
2060
0003.
In
addition
to
the
existing
ICR,
the
information
collection
requirements
in
this
final
rule
have
been
submitted
for
approval
to
OMB
under
the
requirements
of
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
An
ICR
document
has
been
prepared
by
EPA
(
ICR
No.
2074.01),
and
a
copy
may
be
obtained
from
Susan
Auby,
U.
S.
Environmental
Protection
Agency,
Office
of
Environmental
Information,
Collection
Strategies
Division
(
2822T),
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460
0001,
by
e
mail
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
1672.
A
copy
may
also
be
downloaded
off
the
Internet
at
http://
www.
epa.
gov/
icr.
The
information
requirements
included
in
ICR
No.
2074.01
are
not
effective
until
OMB
approves
them.
The
information
that
ICR
No.
2074.01
covers
is
required
for
the
submittal
of
a
complete
permit
application
for
the
construction
or
modification
of
all
major
new
stationary
sources
of
pollutants
in
attainment
and
nonattainment
areas,
as
well
as
for
applicable
minor
stationary
sources
of
pollutants.
This
information
collection
is
necessary
for
the
proper
performance
of
EPA's
functions,
has
practical
utility,
and
is
not
unnecessarily
duplicative
of
information
we
otherwise
can
reasonably
access.
We
have
reduced,
to
the
extent
practicable
and
appropriate,
the
burden
on
persons
providing
the
information
to
or
for
EPA.
According
to
ICR
No.
2074.01,
as
a
result
of
the
rule
changes,
the
total
3
year
burden
change
of
the
revised
collection
is
estimated
at
about
219,741
hours
at
a
total
cost
of
$
7.7
million.
The
annual
burden
change
to
industry
is
about
64,287
hours
at
a
cost
of
$
2.2
million.
The
annual
burden
change
to
reviewing
agencies
is
about
8,960
hours
at
a
cost
of
$
331,520.
The
total
annual
respondent
change
is
73,247
hours
for
a
total
respondent
change
in
cost
of
$
2.6
million.
These
costs
changes
are
based
upon
62
PSD
and
123
NSR
non
utility
sources
(
185
total);
and
85
PSD
and
169
NSR
(
254
total)
sources,
including
utilities.
For
the
number
of
respondent
reviewing
authorities,
the
analysis
uses
the
112
reviewing
authorities
count
used
by
other
permitting
ICRs
for
the
one
time
tasks
(
for
example,
SIP
revisions)
and
the
appropriate
source
count
for
individual
permit
related
items
(
for
example,
attending
preapplication
meetings
with
the
source).
There
is
only
one
Federal
source
listed
in
the
ICR.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purpose
of
responding
to
the
information
collection;
adjust
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
respond
to
a
collection
of
information;
search
existing
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
We
will
continue
to
present
OMB
control
numbers
in
a
consolidated
table
format
to
be
codified
in
40
CFR
part
9
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Vol.
67,
No.
251
/
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December
31,
2002
/
Rules
and
Regulations
of
the
Agency's
regulations,
and
in
each
CFR
volume
containing
EPA
regulations.
The
table
lists
the
section
numbers
with
reporting
and
recordkeeping
requirements,
and
the
current
OMB
control
numbers.
This
listing
of
the
OMB
control
numbers
and
their
subsequent
codification
in
the
CFR
satisfy
the
requirements
of
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.)
and
OMB's
implementing
regulations
at
5
CFR
part
1320.
H.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(
NTTAA),
Pub.
L.
104
113,
12(
d)
(
15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
in
its
regulatory
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
for
example,
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
that
are
developed
or
adopted
by
voluntary
consensus
standards
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
OMB,
explanations
when
the
Agency
decides
not
to
use
available
and
applicable
voluntary
consensus
standards.
This
action
does
not
involve
technical
standards.
This
final
rule
does
not
create
new
requirements
but,
rather,
revises
an
existing
permitting
program
by
providing
a
series
of
program
options
that
affected
facilities
may
choose
to
adopt.
These
options
will
reduce
the
regulatory
burden
associated
with
the
major
NSR
program
by
improving
the
operational
flexibility
of
owners
and
operators,
improving
the
clarity
of
requirements,
and
providing
alternatives
that
sources
may
take
advantage
of
to
further
improve
their
operational
flexibility.
Therefore,
EPA
did
not
consider
the
use
of
any
voluntary
consensus
standards.
I.
Congressional
Review
Act
The
Congressional
Review
Act,
5
U.
S.
C.
801
et
seq.,
as
added
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
that
before
a
rule
may
take
effect,
the
agency
promulgating
the
rule
must
submit
a
rule
report,
which
includes
a
copy
of
the
rule,
to
each
House
of
the
Congress
and
to
the
Comptroller
General
of
the
United
States.
EPA
submitted
a
report
containing
this
rule
and
other
required
information
to
the
U.
S.
Senate,
the
U.
S.
House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
the
rule
in
the
Federal
Register.
A
major
rule
cannot
take
effect
until
60
days
after
it
is
published
in
the
Federal
Register.
This
action
is
not
a
``
major
rule''
as
defined
by
5
U.
S.
C.
804(
2).
Nonetheless,
the
Agency
has
decided
to
provide
an
effective
date
that
is
60
days
after
publication
in
the
Federal
Register.
This
rule
will
be
effective
March
3,
2003.
J.
Executive
Order
13211
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
rule
is
not
a
``
significant
energy
action''
as
defined
in
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355,
May
22,
2001)
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
Today's
rule
improves
the
ability
of
sources
to
undertake
pollution
prevention
or
energy
efficiency
projects,
switch
to
less
polluting
fuels
or
raw
materials,
maintain
the
reliability
of
production
facilities,
and
effectively
utilize
and
improve
existing
capacity.
The
rule
also
includes
a
number
of
provisions
to
streamline
administrative
and
permitting
processes
so
that
facilities
can
quickly
accommodate
changes
in
supply
and
demand.
The
regulations
provide
several
alternatives
that
are
specifically
designed
to
reduce
administrative
burden
for
sources
that
use
pollution
prevention
or
energy
efficient
projects.
X.
Statutory
Authority
The
statutory
authority
for
this
action
is
provided
by
sections
101,
112,
114,
116,
and
301
of
the
Act
as
amended
(
42
U.
S.
C.
7401,
7412,
7414,
7416,
and
7601).
This
rulemaking
is
also
subject
to
section
307(
d)
of
the
Act
(
42
U.
S.
C.
7407(
d)).
XI.
Judicial
Review
Under
section
307(
b)(
1)
of
the
Act,
judicial
review
of
this
final
rule
is
available
only
by
the
filing
of
a
petition
for
review
in
the
U.
S.
Court
of
Appeals
for
the
District
of
Columbia
Circuit
by
March
3,
2003.
Any
such
judicial
review
is
limited
to
only
those
objections
that
are
raised
with
reasonable
specificity
in
timely
comments.
Under
section
307(
b)(
2)
of
the
Act,
the
requirements
that
are
the
subject
of
this
final
rule
may
not
be
challenged
later
in
civil
or
criminal
proceedings
brought
by
us
to
enforce
these
requirements.
List
of
Subjects
40
CFR
Part
51
Environmental
protection,
Administrative
practices
and
procedures,
Air
pollution
control,
BACT,
Baseline
emissions,
Carbon
monoxide,
Clean
Units,
Hydrocarbons,
Intergovernmental
relations,
LAER,
Lead,
Major
modifications,
Nitrogen
oxides,
Ozone,
Particular
matter,
Plantwide
applicability
limitations,
Pollution
control
projects,
Sulfur
oxides.
40
CFR
Part
52
Environmental
protection,
Administrative
practices
and
procedures,
Air
pollution
control,
BACT,
Baseline
emissions,
Carbon
monoxide,
Clean
Units,
Hydrocarbons,
Intergovernmental
relations,
LAER,
Lead,
Major
modifications,
Nitrogen
oxides,
Ozone,
Particulate
matter,
Plantwide
applicability
limitations,
Pollution
control
projects,
Sulfur
oxides.
Dated:
November
22,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
set
out
in
the
preamble,
title
40,
chapter
I
of
the
Code
of
Federal
Regulations
is
amended
as
follows:
PART
51
[
Amended]
1.
The
authority
citation
for
part
51
continues
to
read
as
follows:
Authority:
23
U.
S.
C.
101;
42
U.
S.
C.
7401
7671
q.
Subpart
I
[
Amended]
2.
In
40
CFR
51.165(
a)(
1)(
i),
remove
the
words
``
any
air
pollutant
subject
to
regulation
under
the
Act,''
and
add,
in
their
place,
the
words
``
a
regulated
NSR
pollutant.''
3.
In
addition
to
the
amendments
set
forth
above,
in
40
CFR
51.165
(
a)(
1)(
iv)(
A)(
1),
remove
the
words
``
pollutant
subject
to
regulation
under
the
Act''
and
add,
in
their
place,
the
words
``
regulated
NSR
pollutant.''
4.
In
addition
to
the
amendments
set
forth
above,
§
51.165
is
amended:
a.
By
revising
the
introductory
text
in
paragraph
(
a).
b.
By
revising
paragraphs
(
a)(
1)(
v)(
A)
and
(
B).
c.
By
revising
paragraph
(
a)(
1)(
v)(
C)(
8).
d.
By
adding
paragraph
(
a)(
1)(
v)(
D).
e.
By
revising
paragraph
(
a)(
1)(
vi)(
A).
f.
By
revising
paragraph
(
a)(
1)(
vi)(
C).
g.
By
revising
paragraph
(
a)(
1)(
vi)(
E)(
2).
h.
By
revising
paragraph
(
a)(
1)(
vi)(
E)(
4).
i.
By
adding
paragraph
(
a)(
1)(
vi)(
E)(
5).
j.
By
adding
paragraph
(
a)(
1)(
vi)(
G).
k.
By
revising
paragraph
(
a)(
1)(
vii).
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and
Regulations
l.
By
revising
paragraph
(
a)(
1)(
xii).
m.
By
revising
the
introductory
text
in
paragraph
(
a)(
1)(
xiii).
n.
By
revising
paragraph
(
a)(
1)(
xviii).
o.
By
reserving
paragraph
(
a)(
1)(
xxi).
p.
By
revising
paragraph
(
a)(
1)(
xxv).
q.
By
adding
paragraphs
(
a)(
1)(
xxvi)
through
(
xlii).
r.
By
revising
paragraph
(
a)(
2).
s.
By
adding
paragraphs
(
a)(
3)(
ii)(
H)
through
(
J).
t.
By
adding
paragraphs
(
a)(
6)
through
(
7).
u.
By
adding
paragraphs
(
c)
through
(
g).
The
revisions
and
additions
read
as
follows:
§
51.165
Permit
requirements.
(
a)
State
Implementation
Plan
and
Tribal
Implementation
Plan
provisions
satisfying
sections
172(
c)(
5)
and
173
of
the
Act
shall
meet
the
following
conditions:
(
1)
*
*
*
(
v)
*
*
*
(
A)
Major
modification
means
any
physical
change
in
or
change
in
the
method
of
operation
of
a
major
stationary
source
that
would
result
in:
(
1)
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
(
as
defined
in
paragraph
(
a)(
1)(
xxxvii)
of
this
section);
and
(
2)
A
significant
net
emissions
increase
of
that
pollutant
from
the
major
stationary
source.
(
B)
Any
significant
emissions
increase
(
as
defined
in
paragraph
(
a)(
1)(
xxvii)
of
this
section)
from
any
emissions
units
or
net
emissions
increase
(
as
defined
in
paragraph
(
a)(
1)(
vi)
of
this
section)
at
a
major
stationary
source
that
is
significant
for
volatile
organic
compounds
shall
be
considered
significant
for
ozone.
(
C)
*
*
*
(
8)
The
addition,
replacement,
or
use
of
a
PCP,
as
defined
in
paragraph
(
a)(
1)(
xxv)
of
this
section,
at
an
existing
emissions
unit
meeting
the
requirements
of
paragraph
(
e)
of
this
section.
A
replacement
control
technology
must
provide
more
effective
emissions
control
than
that
of
the
replaced
control
technology
to
qualify
for
this
exclusion.
*
*
*
*
*
(
D)
This
definition
shall
not
apply
with
respect
to
a
particular
regulated
NSR
pollutant
when
the
major
stationary
source
is
complying
with
the
requirements
under
paragraph
(
f)
of
this
section
for
a
PAL
for
that
pollutant.
Instead,
the
definition
at
paragraph
(
f)(
2)(
viii)
of
this
section
shall
apply.
(
vi)(
A)
Net
emissions
increase
means,
with
respect
to
any
regulated
NSR
pollutant
emitted
by
a
major
stationary
source,
the
amount
by
which
the
sum
of
the
following
exceeds
zero:
(
1)
The
increase
in
emissions
from
a
particular
physical
change
or
change
in
the
method
of
operation
at
a
stationary
source
as
calculated
pursuant
to
paragraph
(
a)(
2)(
ii)
of
this
section;
and
(
2)
Any
other
increases
and
decreases
in
actual
emissions
at
the
major
stationary
source
that
are
contemporaneous
with
the
particular
change
and
are
otherwise
creditable.
Baseline
actual
emissions
for
calculating
increases
and
decreases
under
this
paragraph
(
a)(
1)(
vi)(
A)(
2)
shall
be
determined
as
provided
in
paragraph
(
a)(
1)(
xxxv)
of
this
section,
except
that
paragraphs
(
a)(
1)(
xxxv)(
A)(
3)
and
(
a)(
1)(
xxxv)(
B)(
4)
of
this
section
shall
not
apply.
*
*
*
*
*
(
C)
An
increase
or
decrease
in
actual
emissions
is
creditable
only
if:
(
1)
It
occurs
within
a
reasonable
period
to
be
specified
by
the
reviewing
authority;
and
(
2)
The
reviewing
authority
has
not
relied
on
it
in
issuing
a
permit
for
the
source
under
regulations
approved
pursuant
to
this
section,
which
permit
is
in
effect
when
the
increase
in
actual
emissions
from
the
particular
change
occurs;
and
(
3)
The
increase
or
decrease
in
emissions
did
not
occur
at
a
Clean
Unit,
except
as
provided
in
paragraphs
(
c)(
8)
and
(
d)(
10)
of
this
section.
*
*
*
*
*
(
E)
*
*
*
(
2)
It
is
enforceable
as
a
practical
matter
at
and
after
the
time
that
actual
construction
on
the
particular
change
begins;
and
*
*
*
*
*
(
4)
It
has
approximately
the
same
qualitative
significance
for
public
health
and
welfare
as
that
attributed
to
the
increase
from
the
particular
change;
and
(
5)
The
decrease
in
actual
emissions
did
not
result
from
the
installation
of
add
on
control
technology
or
application
of
pollution
prevention
practices
that
were
relied
on
in
designating
an
emissions
unit
as
a
Clean
Unit
under
40
CFR
52.21(
y)
or
under
regulations
approved
pursuant
to
paragraph
(
d)
of
this
section
or
§
51.166(
u).
That
is,
once
an
emissions
unit
has
been
designated
as
a
Clean
Unit,
the
owner
or
operator
cannot
later
use
the
emissions
reduction
from
the
air
pollution
control
measures
that
the
Clean
Unit
designation
is
based
on
in
calculating
the
net
emissions
increase
for
another
emissions
unit
(
i.
e.,
must
not
use
that
reduction
in
a
``
netting
analysis''
for
another
emissions
unit).
However,
any
new
emissions
reductions
that
were
not
relied
upon
in
a
PCP
excluded
pursuant
to
paragraph
(
e)
of
this
section
or
for
a
Clean
Unit
designation
are
creditable
to
the
extent
they
meet
the
requirements
in
paragraphs
(
e)(
6)(
iv)
of
this
section
for
the
PCP
and
paragraphs
(
c)(
8)
or
(
d)(
10)
of
this
section
for
a
Clean
Unit.
*
*
*
*
*
(
G)
Paragraph
(
a)(
1)(
xii)(
B)
of
this
section
shall
not
apply
for
determining
creditable
increases
and
decreases
or
after
a
change.
*
*
*
*
*
(
vii)
Emissions
unit
means
any
part
of
a
stationary
source
that
emits
or
would
have
the
potential
to
emit
any
regulated
NSR
pollutant
and
includes
an
electric
steam
generating
unit
as
defined
in
paragraph
(
a)(
1)(
xx)
of
this
section.
For
purposes
of
this
section,
there
are
two
types
of
emissions
units
as
described
in
paragraphs
(
a)(
1)(
vii)(
A)
and
(
B)
of
this
section.
(
A)
A
new
emissions
unit
is
any
emissions
unit
which
is
(
or
will
be)
newly
constructed
and
which
has
existed
for
less
than
2
years
from
the
date
such
emissions
unit
first
operated.
(
B)
An
existing
emissions
unit
is
any
emissions
unit
that
does
not
meet
the
requirements
in
paragraph
(
a)(
1)(
vii)(
A)
of
this
section.
*
*
*
*
*
(
xii)(
A)
Actual
emissions
means
the
actual
rate
of
emissions
of
a
regulated
NSR
pollutant
from
an
emissions
unit,
as
determined
in
accordance
with
paragraphs
(
a)(
1)(
xii)(
B)
through
(
D)
of
this
section,
except
that
this
definition
shall
not
apply
for
calculating
whether
a
significant
emissions
increase
has
occurred,
or
for
establishing
a
PAL
under
paragraph
(
f)
of
this
section.
Instead,
paragraphs
(
a)(
1)(
xxviii)
and
(
xxxv)
of
this
section
shall
apply
for
those
purposes.
(
B)
In
general,
actual
emissions
as
of
a
particular
date
shall
equal
the
average
rate,
in
tons
per
year,
at
which
the
unit
actually
emitted
the
pollutant
during
a
consecutive
24
month
period
which
precedes
the
particular
date
and
which
is
representative
of
normal
source
operation.
The
reviewing
authority
shall
allow
the
use
of
a
different
time
period
upon
a
determination
that
it
is
more
representative
of
normal
source
operation.
Actual
emissions
shall
be
calculated
using
the
unit's
actual
operating
hours,
production
rates,
and
types
of
materials
processed,
stored,
or
combusted
during
the
selected
time
period.
(
C)
The
reviewing
authority
may
presume
that
source
specific
allowable
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emissions
for
the
unit
are
equivalent
to
the
actual
emissions
of
the
unit.
(
D)
For
any
emissions
unit
that
has
not
begun
normal
operations
on
the
particular
date,
actual
emissions
shall
equal
the
potential
to
emit
of
the
unit
on
that
date.
(
xiii)
Lowest
achievable
emission
rate
(
LAER)
means,
for
any
source,
the
more
stringent
rate
of
emissions
based
on
the
following:
*
*
*
*
*
*
*
*
(
xviii)
Construction
means
any
physical
change
or
change
in
the
method
of
operation
(
including
fabrication,
erection,
installation,
demolition,
or
modification
of
an
emissions
unit)
that
would
result
in
a
change
in
emissions.
*
*
*
*
*
(
xxi)
[
Reserved]
*
*
*
*
*
(
xxv)
Pollution
control
project
(
PCP)
means
any
activity,
set
of
work
practices
or
project
(
including
pollution
prevention
as
defined
under
paragraph
(
a)(
1)(
xxvi)
of
this
section)
undertaken
at
an
existing
emissions
unit
that
reduces
emissions
of
air
pollutants
from
such
unit.
Such
qualifying
activities
or
projects
can
include
the
replacement
or
upgrade
of
an
existing
emissions
control
technology
with
a
more
effective
unit.
Other
changes
that
may
occur
at
the
source
are
not
considered
part
of
the
PCP
if
they
are
not
necessary
to
reduce
emissions
through
the
PCP.
Projects
listed
in
paragraphs
(
a)(
1)(
xxv)(
A)
through
(
F)
of
this
section
are
presumed
to
be
environmentally
beneficial
pursuant
to
paragraph
(
e)(
2)(
i)
of
this
section.
Projects
not
listed
in
these
paragraphs
may
qualify
for
a
casespecific
PCP
exclusion
pursuant
to
the
requirements
of
paragraphs
(
e)(
2)
and
(
e)(
5)
of
this
section.
(
A)
Conventional
or
advanced
flue
gas
desulfurization
or
sorbent
injection
for
control
of
SO2.
(
B)
Electrostatic
precipitators,
baghouses,
high
efficiency
multiclones,
or
scrubbers
for
control
of
particulate
matter
or
other
pollutants.
(
C)
Flue
gas
recirculation,
low
NOX
burners
or
combustors,
selective
noncatalytic
reduction,
selective
catalytic
reduction,
low
emission
combustion
(
for
IC
engines),
and
oxidation/
absorption
catalyst
for
control
of
NOX.
(
D)
Regenerative
thermal
oxidizers,
catalytic
oxidizers,
condensers,
thermal
incinerators,
hydrocarbon
combustion
flares,
biofiltration,
absorbers
and
adsorbers,
and
floating
roofs
for
storage
vessels
for
control
of
volatile
organic
compounds
or
hazardous
air
pollutants.
For
the
purpose
of
this
section,
``
hydrocarbon
combustion
flare''
means
either
a
flare
used
to
comply
with
an
applicable
NSPS
or
MACT
standard
(
including
uses
of
flares
during
startup,
shutdown,
or
malfunction
permitted
under
such
a
standard),
or
a
flare
that
serves
to
control
emissions
of
waste
streams
comprised
predominately
of
hydrocarbons
and
containing
no
more
than
230
mg/
dscm
hydrogen
sulfide.
(
E)
Activities
or
projects
undertaken
to
accommodate
switching
(
or
partially
switching)
to
an
inherently
less
polluting
fuel,
to
be
limited
to
the
following
fuel
switches:
(
1)
Switching
from
a
heavier
grade
of
fuel
oil
to
a
lighter
fuel
oil,
or
any
grade
of
oil
to
0.05
percent
sulfur
diesel
(
i.
e.,
from
a
higher
sulfur
content
#
2
fuel
or
from
#
6
fuel,
to
CA
0.05
percent
sulfur
#
2
diesel);
(
2)
Switching
from
coal,
oil,
or
any
solid
fuel
to
natural
gas,
propane,
or
gasified
coal;
(
3)
Switching
from
coal
to
wood,
excluding
construction
or
demolition
waste,
chemical
or
pesticide
treated
wood,
and
other
forms
of
``
unclean''
wood;
(
4)
Switching
from
coal
to
#
2
fuel
oil
(
0.5
percent
maximum
sulfur
content);
and
(
5)
Switching
from
high
sulfur
coal
to
low
sulfur
coal
(
maximum
1.2
percent
sulfur
content).
(
F)
Activities
or
projects
undertaken
to
accommodate
switching
from
the
use
of
one
ozone
depleting
substance
(
ODS)
to
the
use
of
a
substance
with
a
lower
or
zero
ozone
depletion
potential
(
ODP),
including
changes
to
equipment
needed
to
accommodate
the
activity
or
project,
that
meet
the
requirements
of
paragraphs
(
a)(
1)(
xxv)(
F)(
1)
and
(
2)
of
this
section.
(
1)
The
productive
capacity
of
the
equipment
is
not
increased
as
a
result
of
the
activity
or
project.
(
2)
The
projected
usage
of
the
new
substance
is
lower,
on
an
ODP
weighted
basis,
than
the
baseline
usage
of
the
replaced
ODS.
To
make
this
determination,
follow
the
procedure
in
paragraphs
(
a)(
1)(
xxv)(
F)(
2)(
i)
through
(
iv)
of
this
section.
(
i)
Determine
the
ODP
of
the
substances
by
consulting
40
CFR
part
82,
subpart
A,
appendices
A
and
B.
(
ii)
Calculate
the
replaced
ODPweighted
amount
by
multiplying
the
baseline
actual
usage
(
using
the
annualized
average
of
any
24
consecutive
months
of
usage
within
the
past
10
years)
by
the
ODP
of
the
replaced
ODS.
(
iii)
Calculate
the
projected
ODPweighted
amount
by
multiplying
the
projected
future
annual
usage
of
the
new
substance
by
its
ODP.
(
iv)
If
the
value
calculated
in
paragraph
(
a)(
1)(
xxv)(
F)(
2)(
ii)
of
this
section
is
more
than
the
value
calculated
in
paragraph
(
a)(
1)(
xxv)(
F)(
2)(
iii)
of
this
section,
then
the
projected
use
of
the
new
substance
is
lower,
on
an
ODP
weighted
basis,
than
the
baseline
usage
of
the
replaced
ODS.
(
xxvi)
Pollution
prevention
means
any
activity
that
through
process
changes,
product
reformulation
or
redesign,
or
substitution
of
less
polluting
raw
materials,
eliminates
or
reduces
the
release
of
air
pollutants
(
including
fugitive
emissions)
and
other
pollutants
to
the
environment
prior
to
recycling,
treatment,
or
disposal;
it
does
not
mean
recycling
(
other
than
certain
``
in
process
recycling''
practices),
energy
recovery,
treatment,
or
disposal.
(
xxvii)
Significant
emissions
increase
means,
for
a
regulated
NSR
pollutant,
an
increase
in
emissions
that
is
significant
(
as
defined
in
paragraph
(
a)(
1)(
x)
of
this
section)
for
that
pollutant.
(
xxviii)(
A)
Projected
actual
emissions
means,
the
maximum
annual
rate,
in
tons
per
year,
at
which
an
existing
emissions
unit
is
projected
to
emit
a
regulated
NSR
pollutant
in
any
one
of
the
5
years
(
12
month
period)
following
the
date
the
unit
resumes
regular
operation
after
the
project,
or
in
any
one
of
the
10
years
following
that
date,
if
the
project
involves
increasing
the
emissions
unit's
design
capacity
or
its
potential
to
emit
of
that
regulated
NSR
pollutant
and
full
utilization
of
the
unit
would
result
in
a
significant
emissions
increase
or
a
significant
net
emissions
increase
at
the
major
stationary
source.
(
B)
In
determining
the
projected
actual
emissions
under
paragraph
(
a)(
1)(
xxviii)(
A)
of
this
section
before
beginning
actual
construction,
the
owner
or
operator
of
the
major
stationary
source:
(
1)
Shall
consider
all
relevant
information,
including
but
not
limited
to,
historical
operational
data,
the
company's
own
representations,
the
company's
expected
business
activity
and
the
company's
highest
projections
of
business
activity,
the
company's
filings
with
the
State
or
Federal
regulatory
authorities,
and
compliance
plans
under
the
approved
plan;
and
(
2)
Shall
include
fugitive
emissions
to
the
extent
quantifiable,
and
emissions
associated
with
startups,
shutdowns,
and
malfunctions;
and
(
3)
Shall
exclude,
in
calculating
any
increase
in
emissions
that
results
from
the
particular
project,
that
portion
of
the
unit's
emissions
following
the
project
that
an
existing
unit
could
have
accommodated
during
the
consecutive
24
month
period
used
to
establish
the
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Rules
and
Regulations
baseline
actual
emissions
under
paragraph
(
a)(
1)(
xxxv)
of
this
section
and
that
are
also
unrelated
to
the
particular
project,
including
any
increased
utilization
due
to
product
demand
growth;
or,
(
4)
In
lieu
of
using
the
method
set
out
in
paragraphs
(
a)(
1)(
xxviii)(
B)(
1)
through
(
3)
of
this
section,
may
elect
to
use
the
emissions
unit's
potential
to
emit,
in
tons
per
year,
as
defined
under
paragraph
(
a)(
1)(
iii)
of
this
section.
(
xxix)
Clean
Unit
means
any
emissions
unit
that
has
been
issued
a
major
NSR
permit
that
requires
compliance
with
BACT
or
LAER,
that
is
complying
with
such
BACT/
LAER
requirements,
and
qualifies
as
a
Clean
Unit
pursuant
to
regulations
approved
by
the
Administrator
in
accordance
with
paragraph
(
c)
of
this
section;
or
any
emissions
unit
that
has
been
designated
by
a
reviewing
authority
as
a
Clean
Unit,
based
on
the
criteria
in
paragraphs
(
d)(
3)(
i)
through
(
iv)
of
this
section,
using
a
plan
approved
permitting
process;
or
any
emissions
unit
that
has
been
designated
as
a
Clean
Unit
by
the
Administrator
in
accordance
with
§
52.21(
y)(
3)(
i)
through
(
iv)
of
this
chapter.
(
xxx)
Nonattainment
major
new
source
review
(
NSR)
program
means
a
major
source
preconstruction
permit
program
that
has
been
approved
by
the
Administrator
and
incorporated
into
the
plan
to
implement
the
requirements
of
this
section,
or
a
program
that
implements
part
51,
appendix
S,
Sections
I
through
VI
of
this
chapter.
Any
permit
issued
under
such
a
program
is
a
major
NSR
permit.
(
xxxi)
Continuous
emissions
monitoring
system
(
CEMS)
means
all
of
the
equipment
that
may
be
required
to
meet
the
data
acquisition
and
availability
requirements
of
this
section,
to
sample,
condition
(
if
applicable),
analyze,
and
provide
a
record
of
emissions
on
a
continuous
basis.
(
xxxii)
Predictive
emissions
monitoring
system
(
PEMS)
means
all
of
the
equipment
necessary
to
monitor
process
and
control
device
operational
parameters
(
for
example,
control
device
secondary
voltages
and
electric
currents)
and
other
information
(
for
example,
gas
flow
rate,
O2
or
CO2
concentrations),
and
calculate
and
record
the
mass
emissions
rate
(
for
example,
lb/
hr)
on
a
continuous
basis.
(
xxxiii)
Continuous
parameter
monitoring
system
(
CPMS)
means
all
of
the
equipment
necessary
to
meet
the
data
acquisition
and
availability
requirements
of
this
section,
to
monitor
process
and
control
device
operational
parameters
(
for
example,
control
device
secondary
voltages
and
electric
currents)
and
other
information
(
for
example,
gas
flow
rate,
O2
or
CO2
concentrations),
and
to
record
average
operational
parameter
value(
s)
on
a
continuous
basis.
(
xxxiv)
Continuous
emissions
rate
monitoring
system
(
CERMS)
means
the
total
equipment
required
for
the
determination
and
recording
of
the
pollutant
mass
emissions
rate
(
in
terms
of
mass
per
unit
of
time).
(
xxxv)
Baseline
actual
emissions
means
the
rate
of
emissions,
in
tons
per
year,
of
a
regulated
NSR
pollutant,
as
determined
in
accordance
with
paragraphs
(
a)(
1)(
xxxv)(
A)
through
(
D)
of
this
section.
(
A)
For
any
existing
electric
utility
steam
generating
unit,
baseline
actual
emissions
means
the
average
rate,
in
tons
per
year,
at
which
the
unit
actually
emitted
the
pollutant
during
any
consecutive
24
month
period
selected
by
the
owner
or
operator
within
the
5
year
period
immediately
preceding
when
the
owner
or
operator
begins
actual
construction
of
the
project.
The
reviewing
authority
shall
allow
the
use
of
a
different
time
period
upon
a
determination
that
it
is
more
representative
of
normal
source
operation.
(
1)
The
average
rate
shall
include
fugitive
emissions
to
the
extent
quantifiable,
and
emissions
associated
with
startups,
shutdowns,
and
malfunctions.
(
2)
The
average
rate
shall
be
adjusted
downward
to
exclude
any
noncompliant
emissions
that
occurred
while
the
source
was
operating
above
any
emission
limitation
that
was
legally
enforceable
during
the
consecutive
24
month
period.
(
3)
For
a
regulated
NSR
pollutant,
when
a
project
involves
multiple
emissions
units,
only
one
consecutive
24
month
period
must
be
used
to
determine
the
baseline
actual
emissions
for
the
emissions
units
being
changed.
A
different
consecutive
24
month
period
can
be
used
for
each
regulated
NSR
pollutant.
(
4)
The
average
rate
shall
not
be
based
on
any
consecutive
24
month
period
for
which
there
is
inadequate
information
for
determining
annual
emissions,
in
tons
per
year,
and
for
adjusting
this
amount
if
required
by
paragraph
(
a)(
1)(
xxxv)(
A)(
2)
of
this
section.
(
B)
For
an
existing
emissions
unit
(
other
than
an
electric
utility
steam
generating
unit),
baseline
actual
emissions
means
the
average
rate,
in
tons
per
year,
at
which
the
emissions
unit
actually
emitted
the
pollutant
during
any
consecutive
24
month
period
selected
by
the
owner
or
operator
within
the
10
year
period
immediately
preceding
either
the
date
the
owner
or
operator
begins
actual
construction
of
the
project,
or
the
date
a
complete
permit
application
is
received
by
the
reviewing
authority
for
a
permit
required
either
under
this
section
or
under
a
plan
approved
by
the
Administrator,
whichever
is
earlier,
except
that
the
10
year
period
shall
not
include
any
period
earlier
than
November
15,
1990.
(
1)
The
average
rate
shall
include
fugitive
emissions
to
the
extent
quantifiable,
and
emissions
associated
with
startups,
shutdowns,
and
malfunctions.
(
2)
The
average
rate
shall
be
adjusted
downward
to
exclude
any
noncompliant
emissions
that
occurred
while
the
source
was
operating
above
an
emission
limitation
that
was
legally
enforceable
during
the
consecutive
24
month
period.
(
3)
The
average
rate
shall
be
adjusted
downward
to
exclude
any
emissions
that
would
have
exceeded
an
emission
limitation
with
which
the
major
stationary
source
must
currently
comply,
had
such
major
stationary
source
been
required
to
comply
with
such
limitations
during
the
consecutive
24
month
period.
However,
if
an
emission
limitation
is
part
of
a
maximum
achievable
control
technology
standard
that
the
Administrator
proposed
or
promulgated
under
part
63
of
this
chapter,
the
baseline
actual
emissions
need
only
be
adjusted
if
the
State
has
taken
credit
for
such
emissions
reductions
in
an
attainment
demonstration
or
maintenance
plan
consistent
with
the
requirements
of
paragraph
(
a)(
3)(
ii)(
G)
of
this
section.
(
4)
For
a
regulated
NSR
pollutant,
when
a
project
involves
multiple
emissions
units,
only
one
consecutive
24
month
period
must
be
used
to
determine
the
baseline
actual
emissions
for
the
emissions
units
being
changed.
A
different
consecutive
24
month
period
can
be
used
For
each
regulated
NSR
pollutant.
(
5)
The
average
rate
shall
not
be
based
on
any
consecutive
24
month
period
for
which
there
is
inadequate
information
for
determining
annual
emissions,
in
tons
per
year,
and
for
adjusting
this
amount
if
required
by
paragraphs
(
a)(
1)(
xxxv)(
B)(
2)
and
(
3)
of
this
section.
(
C)
For
a
new
emissions
unit,
the
baseline
actual
emissions
for
purposes
of
determining
the
emissions
increase
that
will
result
from
the
initial
construction
and
operation
of
such
unit
shall
equal
zero;
and
thereafter,
for
all
other
purposes,
shall
equal
the
unit's
potential
to
emit.
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December
31,
2002
/
Rules
and
Regulations
(
D)
For
a
PAL
for
a
major
stationary
source,
the
baseline
actual
emissions
shall
be
calculated
for
existing
electric
utility
steam
generating
units
in
accordance
with
the
procedures
contained
in
paragraph
(
a)(
1)(
xxxv)(
A)
of
this
section,
for
other
existing
emissions
units
in
accordance
with
the
procedures
contained
in
paragraph
(
a)(
1)(
xxxv)(
B)
of
this
section,
and
for
a
new
emissions
unit
in
accordance
with
the
procedures
contained
in
paragraph
(
a)(
1)(
xxxv)(
C)
of
this
section.
(
xxxvi)
[
Reserved]
(
xxxvii)
Regulated
NSR
pollutant,
for
purposes
of
this
section,
means
the
following:
(
A)
Nitrogen
oxides
or
any
volatile
organic
compounds;
(
B)
Any
pollutant
for
which
a
national
ambient
air
quality
standard
has
been
promulgated;
or
(
C)
Any
pollutant
that
is
a
constituent
or
precursor
of
a
general
pollutant
listed
under
paragraphs
(
a)(
1)(
xxxvii)(
A)
or
(
B)
of
this
section,
provided
that
a
constituent
or
precursor
pollutant
may
only
be
regulated
under
NSR
as
part
of
regulation
of
the
general
pollutant.
(
xxxviii)
Reviewing
authority
means
the
State
air
pollution
control
agency,
local
agency,
other
State
agency,
Indian
tribe,
or
other
agency
authorized
by
the
Administrator
to
carry
out
a
permit
program
under
this
section
and
§
51.166,
or
the
Administrator
in
the
case
of
EPA
implemented
permit
programs
under
§
52.21.
(
xxxix)
Project
means
a
physical
change
in,
or
change
in
the
method
of
operation
of,
an
existing
major
stationary
source.
(
XL)
Best
available
control
technology
(
BACT)
means
an
emissions
limitation
(
including
a
visible
emissions
standard)
based
on
the
maximum
degree
of
reduction
for
each
regulated
NSR
pollutant
which
would
be
emitted
from
any
proposed
major
stationary
source
or
major
modification
which
the
reviewing
authority,
on
a
case
by
case
basis,
taking
into
account
energy,
environmental,
and
economic
impacts
and
other
costs,
determines
is
achievable
for
such
source
or
modification
through
application
of
production
processes
or
available
methods,
systems,
and
techniques,
including
fuel
cleaning
or
treatment
or
innovative
fuel
combustion
techniques
for
control
of
such
pollutant.
In
no
event
shall
application
of
best
available
control
technology
result
in
emissions
of
any
pollutant
which
would
exceed
the
emissions
allowed
by
any
applicable
standard
under
40
CFR
part
60
or
61.
If
the
reviewing
authority
determines
that
technological
or
economic
limitations
on
the
application
of
measurement
methodology
to
a
particular
emissions
unit
would
make
the
imposition
of
an
emissions
standard
infeasible,
a
design,
equipment,
work
practice,
operational
standard,
or
combination
thereof,
may
be
prescribed
instead
to
satisfy
the
requirement
for
the
application
of
BACT.
Such
standard
shall,
to
the
degree
possible,
set
forth
the
emissions
reduction
achievable
by
implementation
of
such
design,
equipment,
work
practice
or
operation,
and
shall
provide
for
compliance
by
means
which
achieve
equivalent
results.
(
XLi)
Prevention
of
Significant
Deterioration
(
PSD)
permit
means
any
permit
that
is
issued
under
a
major
source
preconstruction
permit
program
that
has
been
approved
by
the
Administrator
and
incorporated
into
the
plan
to
implement
the
requirements
of
§
51.166
of
this
chapter,
or
under
the
program
in
§
52.21
of
this
chapter.
(
XLii)
Federal
Land
Manager
means,
with
respect
to
any
lands
in
the
United
States,
the
Secretary
of
the
department
with
authority
over
such
lands.
(
2)
Applicability
procedures.
(
i)
Each
plan
shall
adopt
a
preconstruction
review
program
to
satisfy
the
requirements
of
sections
172(
c)(
5)
and
173
of
the
Act
for
any
area
designated
nonattainment
for
any
national
ambient
air
quality
standard
under
subpart
C
of
40
CFR
part
81.
Such
a
program
shall
apply
to
any
new
major
stationary
source
or
major
modification
that
is
major
for
the
pollutant
for
which
the
area
is
designated
nonattainment
under
section
107(
d)(
1)(
A)(
i)
of
the
Act,
if
the
stationary
source
or
modification
would
locate
anywhere
in
the
designated
nonattainment
area.
(
ii)
Each
plan
shall
use
the
specific
provisions
of
paragraphs
(
a)(
2)(
ii)(
A)
through
(
F)
of
this
section.
Deviations
from
these
provisions
will
be
approved
only
if
the
State
specifically
demonstrates
that
the
submitted
provisions
are
more
stringent
than
or
at
least
as
stringent
in
all
respects
as
the
corresponding
provisions
in
paragraphs
(
a)(
2)(
ii)(
A)
through
(
F)
of
this
section.
(
A)
Except
as
otherwise
provided
in
paragraphs
(
a)(
2)(
iii)
and
(
iv)
of
this
section,
and
consistent
with
the
definition
of
major
modification
contained
in
paragraph
(
a)(
1)(
v)(
A)
of
this
section,
a
project
is
a
major
modification
for
a
regulated
NSR
pollutant
if
it
causes
two
types
of
emissions
increases
a
significant
emissions
increase
(
as
defined
in
paragraph
(
a)(
1)(
xxvii)
of
this
section),
and
a
significant
net
emissions
increase
(
as
defined
in
paragraphs
(
a)(
1)(
vi)
and
(
x)
of
this
section).
The
project
is
not
a
major
modification
if
it
does
not
cause
a
significant
emissions
increase.
If
the
project
causes
a
significant
emissions
increase,
then
the
project
is
a
major
modification
only
if
it
also
results
in
a
significant
net
emissions
increase.
(
B)
The
procedure
for
calculating
(
before
beginning
actual
construction)
whether
a
significant
emissions
increase
(
i.
e.,
the
first
step
of
the
process)
will
occur
depends
upon
the
type
of
emissions
units
being
modified,
according
to
paragraphs
(
a)(
2)(
ii)(
C)
through
(
F)
of
this
section.
The
procedure
for
calculating
(
before
beginning
actual
construction)
whether
a
significant
net
emissions
increase
will
occur
at
the
major
stationary
source
(
i.
e.,
the
second
step
of
the
process)
is
contained
in
the
definition
in
paragraph
(
a)(
1)(
vi)
of
this
section.
Regardless
of
any
such
preconstruction
projections,
a
major
modification
results
if
the
project
causes
a
significant
emissions
increase
and
a
significant
net
emissions
increase.
(
C)
Actual
to
projected
actual
applicability
test
for
projects
that
only
involve
existing
emissions
units.
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
is
projected
to
occur
if
the
sum
of
the
difference
between
the
projected
actual
emissions
(
as
defined
in
paragraph
(
a)(
1)(
xxviii)
of
this
section)
and
the
baseline
actual
emissions
(
as
defined
in
paragraphs
(
a)(
1)(
xxxv)(
A)
and
(
B)
of
this
section,
as
applicable),
for
each
existing
emissions
unit,
equals
or
exceeds
the
significant
amount
for
that
pollutant
(
as
defined
in
paragraph
(
a)(
1)(
x)
of
this
section).
(
D)
Actual
to
potential
test
for
projects
that
only
involve
construction
of
a
new
emissions
unit(
s).
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
is
projected
to
occur
if
the
sum
of
the
difference
between
the
potential
to
emit
(
as
defined
in
paragraph
(
a)(
1)(
iii)
of
this
section)
from
each
new
emissions
unit
following
completion
of
the
project
and
the
baseline
actual
emissions
(
as
defined
in
paragraph
(
a)(
1)(
xxxv)(
C)
of
this
section)
of
these
units
before
the
project
equals
or
exceeds
the
significant
amount
for
that
pollutant
(
as
defined
in
paragraph
(
a)(
1)(
x)
of
this
section).
(
E)
Emission
test
for
projects
that
involve
Clean
Units.
For
a
project
that
will
be
constructed
and
operated
at
a
Clean
Unit
without
causing
the
emissions
unit
to
lose
its
Clean
Unit
designation,
no
emissions
increase
is
deemed
to
occur.
(
F)
Hybrid
test
for
projects
that
involve
multiple
types
of
emissions
units.
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
is
projected
to
occur
if
the
sum
of
the
emissions
increases
for
each
emissions
unit,
using
the
method
specified
in
paragraphs
(
a)(
2)(
ii)(
C)
through
(
E)
of
this
section
as
applicable
with
respect
to
each
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Rules
and
Regulations
emissions
unit,
for
each
type
of
emissions
unit
equals
or
exceeds
the
significant
amount
for
that
pollutant
(
as
defined
in
paragraph
(
a)(
1)(
x)
of
this
section).
For
example,
if
a
project
involves
both
an
existing
emissions
unit
and
a
Clean
Unit,
the
projected
increase
is
determined
by
summing
the
values
determined
using
the
method
specified
in
paragraph
(
a)(
2)(
ii)(
C)
of
this
section
for
the
existing
unit
and
using
the
method
specified
in
paragraph
(
a)(
2)(
ii)(
E)
of
this
section
for
the
Clean
Unit.
(
iii)
The
plan
shall
require
that
for
any
major
stationary
source
for
a
PAL
for
a
regulated
NSR
pollutant,
the
major
stationary
source
shall
comply
with
requirements
under
paragraph
(
f)
of
this
section.
(
iv)
The
plan
shall
require
that
an
owner
or
operator
undertaking
a
PCP
(
as
defined
in
paragraph
(
a)(
1)(
xxv)
of
this
section)
shall
comply
with
the
requirements
under
paragraph
(
e)
of
this
section.
(
3)
*
*
*
(
ii)
*
*
*
(
H)
Decreases
in
actual
emissions
resulting
from
the
installation
of
add
on
control
technology
or
application
of
pollution
prevention
measures
that
were
relied
upon
in
designating
an
emissions
unit
as
a
Clean
Unit
or
a
project
as
a
PCP
cannot
be
used
as
offsets.
(
I)
Decreases
in
actual
emissions
occurring
at
a
Clean
Unit
cannot
be
used
as
offsets,
except
as
provided
in
paragraphs
(
c)(
8)
and
(
d)(
10)
of
this
section.
Similarly,
decreases
in
actual
emissions
occurring
at
a
PCP
cannot
be
used
as
offsets,
except
as
provided
in
paragraph
(
e)(
6)(
iv)
of
this
section.
(
J)
The
total
tonnage
of
increased
emissions,
in
tons
per
year,
resulting
from
a
major
modification
that
must
be
offset
in
accordance
with
section
173
of
the
Act
shall
be
determined
by
summing
the
difference
between
the
allowable
emissions
after
the
modification
(
as
defined
by
paragraph
(
a)(
1)(
xi)
of
this
section)
and
the
actual
emissions
before
the
modification
(
as
defined
in
paragraph
(
a)(
1)(
xii)
of
this
section)
for
each
emissions
unit.
*
*
*
*
*
(
6)
Each
plan
shall
provide
that
the
following
specific
provisions
apply
to
projects
at
existing
emissions
units
at
a
major
stationary
source
(
other
than
projects
at
a
Clean
Unit
or
at
a
source
with
a
PAL)
in
circumstances
where
there
is
a
reasonable
possibility
that
a
project
that
is
not
a
part
of
a
major
modification
may
result
in
a
significant
emissions
increase
and
the
owner
or
operator
elects
to
use
the
method
specified
in
paragraphs
(
a)(
1)(
xxviii)(
B)(
1)
through
(
3)
of
this
section
for
calculating
projected
actual
emissions.
Deviations
from
these
provisions
will
be
approved
only
if
the
State
specifically
demonstrates
that
the
submitted
provisions
are
more
stringent
than
or
at
least
as
stringent
in
all
respects
as
the
corresponding
provisions
in
paragraphs
(
a)(
6)(
i)
through
(
v)
of
this
section.
(
i)
Before
beginning
actual
construction
of
the
project,
the
owner
or
operator
shall
document
and
maintain
a
record
of
the
following
information:
(
A)
A
description
of
the
project;
(
B)
Identification
of
the
emissions
unit(
s)
whose
emissions
of
a
regulated
NSR
pollutant
could
be
affected
by
the
project;
and
(
C)
A
description
of
the
applicability
test
used
to
determine
that
the
project
is
not
a
major
modification
for
any
regulated
NSR
pollutant,
including
the
baseline
actual
emissions,
the
projected
actual
emissions,
the
amount
of
emissions
excluded
under
paragraph
(
a)(
1)(
xxviii)(
B)(
3)
of
this
section
and
an
explanation
for
why
such
amount
was
excluded,
and
any
netting
calculations,
if
applicable.
(
ii)
If
the
emissions
unit
is
an
existing
electric
utility
steam
generating
unit,
before
beginning
actual
construction,
the
owner
or
operator
shall
provide
a
copy
of
the
information
set
out
in
paragraph
(
a)(
6)(
i)
of
this
section
to
the
reviewing
authority.
Nothing
in
this
paragraph
(
a)(
6)(
ii)
shall
be
construed
to
require
the
owner
or
operator
of
such
a
unit
to
obtain
any
determination
from
the
reviewing
authority
before
beginning
actual
construction.
(
iii)
The
owner
or
operator
shall
monitor
the
emissions
of
any
regulated
NSR
pollutant
that
could
increase
as
a
result
of
the
project
and
that
is
emitted
by
any
emissions
units
identified
in
paragraph
(
a)(
6)(
i)(
B)
of
this
section;
and
calculate
and
maintain
a
record
of
the
annual
emissions,
in
tons
per
year
on
a
calendar
year
basis,
for
a
period
of
5
years
following
resumption
of
regular
operations
after
the
change,
or
for
a
period
of
10
years
following
resumption
of
regular
operations
after
the
change
if
the
project
increases
the
design
capacity
or
potential
to
emit
of
that
regulated
NSR
pollutant
at
such
emissions
unit.
(
iv)
If
the
unit
is
an
existing
electric
utility
steam
generating
unit,
the
owner
or
operator
shall
submit
a
report
to
the
reviewing
authority
within
60
days
after
the
end
of
each
year
during
which
records
must
be
generated
under
paragraph
(
a)(
6)(
iii)
of
this
section
setting
out
the
unit's
annual
emissions
during
the
year
that
preceded
submission
of
the
report.
(
v)
If
the
unit
is
an
existing
unit
other
than
an
electric
utility
steam
generating
unit,
the
owner
or
operator
shall
submit
a
report
to
the
reviewing
authority
if
the
annual
emissions,
in
tons
per
year,
from
the
project
identified
in
paragraph
(
a)(
6)(
i)
of
this
section,
exceed
the
baseline
actual
emissions
(
as
documented
and
maintained
pursuant
to
paragraph
(
a)(
6)(
i)(
C)
of
this
section,
by
a
significant
amount
(
as
defined
in
paragraph
(
a)(
1)(
x)
of
this
section)
for
that
regulated
NSR
pollutant,
and
if
such
emissions
differ
from
the
preconstruction
projection
as
documented
and
maintained
pursuant
to
paragraph
(
a)(
6)(
i)(
C)
of
this
section.
Such
report
shall
be
submitted
to
the
reviewing
authority
within
60
days
after
the
end
of
such
year.
The
report
shall
contain
the
following:
(
A)
The
name,
address
and
telephone
number
of
the
major
stationary
source;
(
B)
The
annual
emissions
as
calculated
pursuant
to
paragraph
(
a)(
6)(
iii)
of
this
section;
and
(
C)
Any
other
information
that
the
owner
or
operator
wishes
to
include
in
the
report
(
e.
g.,
an
explanation
as
to
why
the
emissions
differ
from
the
preconstruction
projection).
(
7)
Each
plan
shall
provide
that
the
owner
or
operator
of
the
source
shall
make
the
information
required
to
be
documented
and
maintained
pursuant
to
paragraph
(
a)(
6)
of
this
section
available
for
review
upon
a
request
for
inspection
by
the
reviewing
authority
or
the
general
public
pursuant
to
the
requirements
contained
in
§
70.4(
b)(
3)(
viii)
of
this
chapter.
*
*
*
*
*
(
c)
Clean
Unit
Test
for
emissions
units
that
are
subject
to
LAER.
The
plan
shall
provide
an
owner
or
operator
of
a
major
stationary
source
the
option
of
using
the
Clean
Unit
Test
to
determine
whether
emissions
increases
at
a
Clean
Unit
are
part
of
a
project
that
is
a
major
modification
according
to
the
provisions
in
paragraphs
(
c)(
1)
through
(
9)
of
this
section.
(
1)
Applicability.
The
provisions
of
this
paragraph
(
c)
apply
to
any
emissions
unit
for
which
the
reviewing
authority
has
issued
a
major
NSR
permit
within
the
past
10
years.
(
2)
General
provisions
for
Clean
Units.
The
provisions
in
paragraphs
(
c)(
2)(
i)
through
(
v)
of
this
section
apply
to
a
Clean
Unit.
(
i)
Any
project
for
which
the
owner
or
operator
begins
actual
construction
after
the
effective
date
of
the
Clean
Unit
designation
(
as
determined
in
accordance
with
paragraph
(
c)(
4)
of
this
section)
and
before
the
expiration
date
(
as
determined
in
accordance
with
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/
Rules
and
Regulations
paragraph
(
c)(
5)
of
this
section)
will
be
considered
to
have
occurred
while
the
emissions
unit
was
a
Clean
Unit.
(
ii)
If
a
project
at
a
Clean
Unit
does
not
cause
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
were
adopted
in
conjunction
with
LAER
and
the
project
would
not
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
LAER
determination
as
specified
in
paragraph
(
c)(
6)(
iv)
of
this
section,
the
emissions
unit
remains
a
Clean
Unit.
(
iii)
If
a
project
causes
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
were
adopted
in
conjunction
with
LAER
or
the
project
would
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
LAER
determination
as
specified
in
paragraph
(
c)(
6)(
iv)
of
this
section,
then
the
emissions
unit
loses
its
designation
as
a
Clean
Unit
upon
issuance
of
the
necessary
permit
revisions
(
unless
the
unit
requalifies
as
a
Clean
Unit
pursuant
to
paragraph
(
c)(
3)(
iii)
of
this
section).
If
the
owner
or
operator
begins
actual
construction
on
the
project
without
first
applying
to
revise
the
emissions
unit's
permit,
the
Clean
Unit
designation
ends
immediately
prior
to
the
time
when
actual
construction
begins.
(
iv)
A
project
that
causes
an
emissions
unit
to
lose
its
designation
as
a
Clean
Unit
is
subject
to
the
applicability
requirements
of
paragraphs
(
a)(
2)(
ii)(
A)
through
(
D)
and
paragraph
(
a)(
2)(
ii)(
F)
of
this
section
as
if
the
emissions
unit
is
not
a
Clean
Unit.
(
v)
Certain
Emissions
Units
with
PSD
permits.
For
emissions
units
that
meet
the
requirements
of
paragraphs
(
c)(
2)(
v)(
A)
and
(
B)
of
this
section,
the
BACT
level
of
emissions
reductions
and/
or
work
practice
requirements
shall
satisfy
the
requirement
for
LAER
in
meeting
the
requirements
for
Clean
Units
under
paragraphs
(
c)(
3)
through
(
8)
of
this
section.
For
these
emissions
units,
all
requirements
for
the
LAER
determination
under
paragraphs
(
c)(
2)(
ii)
and
(
iii)
of
this
section
shall
also
apply
to
the
BACT
permit
terms
and
conditions.
In
addition,
the
requirements
of
paragraph
(
c)(
7)(
i)(
B)
of
this
section
do
not
apply
to
emissions
units
that
qualify
for
Clean
Unit
status
under
this
paragraph
(
c)(
2)(
v).
(
A)
The
emissions
unit
must
have
received
a
PSD
permit
within
the
last
10
years
and
such
permit
must
require
the
emissions
unit
to
comply
with
BACT.
(
B)
The
emissions
unit
must
be
located
in
an
area
that
was
redesignated
as
nonattainment
for
the
relevant
pollutant(
s)
after
issuance
of
the
PSD
permit
and
before
the
effective
date
of
the
Clean
Unit
Test
provisions
in
the
area.
(
3)
Qualifying
or
re
qualifying
to
use
the
Clean
Unit
applicability
test.
An
emissions
unit
automatically
qualifies
as
a
Clean
Unit
when
the
unit
meets
the
criteria
in
paragraphs
(
c)(
3)(
i)
and
(
ii)
of
this
section.
After
the
original
Clean
Unit
designation
expires
in
accordance
with
paragraph
(
c)(
5)
of
this
section
or
is
lost
pursuant
to
paragraph
(
c)(
2)(
iii)
of
this
section,
such
emissions
unit
may
re
qualify
as
a
Clean
Unit
under
either
paragraph
(
c)(
3)(
iii)
of
this
section,
or
under
the
Clean
Unit
provisions
in
paragraph
(
d)
of
this
section.
To
requalify
as
a
Clean
Unit
under
paragraph
(
c)(
3)(
iii)
of
this
section,
the
emissions
unit
must
obtain
a
new
major
NSR
permit
issued
through
the
applicable
nonattainment
major
NSR
program
and
meet
all
the
criteria
in
paragraph
(
c)(
3)(
iii)
of
this
section.
Clean
Unit
designation
applies
individually
for
each
pollutant
emitted
by
the
emissions
unit.
(
i)
Permitting
requirement.
The
emissions
unit
must
have
received
a
major
NSR
permit
within
the
past
10
years.
The
owner
or
operator
must
maintain
and
be
able
to
provide
information
that
would
demonstrate
that
this
permitting
requirement
is
met.
(
ii)
Qualifying
air
pollution
control
technologies.
Air
pollutant
emissions
from
the
emissions
unit
must
be
reduced
through
the
use
of
an
air
pollution
control
technology
(
which
includes
pollution
prevention
as
defined
under
paragraph
(
a)(
1)(
xxvi)
of
this
section
or
work
practices)
that
meets
both
the
following
requirements
in
paragraphs
(
c)(
3)(
ii)(
A)
and
(
B)
of
this
section.
(
A)
The
control
technology
achieves
the
LAER
level
of
emissions
reductions
as
determined
through
issuance
of
a
major
NSR
permit
within
the
past
10
years.
However,
the
emissions
unit
is
not
eligible
for
Clean
Unit
designation
if
the
LAER
determination
resulted
in
no
requirement
to
reduce
emissions
below
the
level
of
a
standard,
uncontrolled,
new
emissions
unit
of
the
same
type.
(
B)
The
owner
or
operator
made
an
investment
to
install
the
control
technology.
For
the
purpose
of
this
determination,
an
investment
includes
expenses
to
research
the
application
of
a
pollution
prevention
technique
to
the
emissions
unit
or
expenses
to
apply
a
pollution
prevention
technique
to
an
emissions
unit.
(
iii)
Re
qualifying
for
the
Clean
Unit
designation.
The
emissions
unit
must
obtain
a
new
major
NSR
permit
that
requires
compliance
with
the
currentday
LAER,
and
the
emissions
unit
must
meet
the
requirements
in
paragraphs
(
c)(
3)(
i)
and
(
c)(
3)(
ii)
of
this
section.
(
4)
Effective
date
of
the
Clean
Unit
designation.
The
effective
date
of
an
emissions
unit's
Clean
Unit
designation
(
that
is,
the
date
on
which
the
owner
or
operator
may
begin
to
use
the
Clean
Unit
Test
to
determine
whether
a
project
at
the
emissions
unit
is
a
major
modification)
is
determined
according
to
the
applicable
paragraph
(
c)(
4)(
i)
or
(
c)(
4)(
ii)
of
this
section.
(
i)
Original
Clean
Unit
designation,
and
emissions
units
that
re
qualify
as
Clean
Units
by
implementing
a
new
control
technology
to
meet
current
day
LAER.
The
effective
date
is
the
date
the
emissions
unit's
air
pollution
control
technology
is
placed
into
service,
or
3
years
after
the
issuance
date
of
the
major
NSR
permit,
whichever
is
earlier,
but
no
sooner
than
the
date
that
provisions
for
the
Clean
Unit
applicability
test
are
approved
by
the
Administrator
for
incorporation
into
the
plan
and
become
effective
for
the
State
in
which
the
unit
is
located.
(
ii)
Emissions
units
that
re
qualify
for
the
Clean
Unit
designation
using
an
existing
control
technology.
The
effective
date
is
the
date
the
new,
major
NSR
permit
is
issued.
(
5)
Clean
Unit
expiration.
An
emissions
unit's
Clean
Unit
designation
expires
(
that
is,
the
date
on
which
the
owner
or
operator
may
no
longer
use
the
Clean
Unit
Test
to
determine
whether
a
project
affecting
the
emissions
unit
is,
or
is
part
of,
a
major
modification)
according
to
the
applicable
paragraph
(
c)(
5)(
i)
or
(
ii)
of
this
section.
(
i)
Original
Clean
Unit
designation,
and
emissions
units
that
re
qualify
by
implementing
new
control
technology
to
meet
current
day
LAER.
For
any
emissions
unit
that
automatically
qualifies
as
a
Clean
Unit
under
paragraphs
(
c)(
3)(
i)
and
(
ii)
of
this
section,
the
Clean
Unit
designation
expires
10
years
after
the
effective
date,
or
the
date
the
equipment
went
into
service,
whichever
is
earlier;
or,
it
expires
at
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
Clean
Unit
designation
in
paragraph
(
c)(
7)
of
this
section.
(
ii)
Emissions
units
that
re
qualify
for
the
Clean
Unit
designation
using
an
existing
control
technology.
For
any
emissions
unit
that
re
qualifies
as
a
Clean
Unit
under
paragraph
(
c)(
3)(
iii)
of
this
section,
the
Clean
Unit
designation
expires
10
years
after
the
effective
date;
or,
it
expires
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
the
Clean
Unit
Designation
in
paragraph
(
c)(
7)
of
this
section.
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31,
2002
/
Rules
and
Regulations
(
6)
Required
title
V
permit
content
for
a
Clean
Unit.
After
the
effective
date
of
the
Clean
Unit
designation,
and
in
accordance
with
the
provisions
of
the
applicable
title
V
permit
program
under
part
70
or
part
71
of
this
chapter,
but
no
later
than
when
the
title
V
permit
is
renewed,
the
title
V
permit
for
the
major
stationary
source
must
include
the
following
terms
and
conditions
in
paragraphs
(
c)(
6)(
i)
through
(
vi)
of
this
section
related
to
the
Clean
Unit.
(
i)
A
statement
indicating
that
the
emissions
unit
qualifies
as
a
Clean
Unit
and
identifying
the
pollutant(
s)
for
which
this
Clean
Unit
designation
applies.
(
ii)
The
effective
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
Clean
Unit
designation
is
initially
recorded
in
the
title
V
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
the
permit
must
describe
the
event
that
will
determine
the
effective
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
effective
date
is
determined,
the
owner
or
operator
must
notify
the
reviewing
authority
of
the
exact
date.
This
specific
effective
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iii)
The
expiration
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
Clean
Unit
designation
is
initially
recorded
into
the
title
V
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
then
the
permit
must
describe
the
event
that
will
determine
the
expiration
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
expiration
date
is
determined,
the
owner
or
operator
must
notify
the
reviewing
authority
of
the
exact
date.
The
expiration
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iv)
All
emission
limitations
and
work
practice
requirements
adopted
in
conjunction
with
the
LAER,
and
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
LAER
determination
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
v)
Monitoring,
recordkeeping,
and
reporting
requirements
as
necessary
to
demonstrate
that
the
emissions
unit
continues
to
meet
the
criteria
for
maintaining
the
Clean
Unit
designation.
(
See
paragraph
(
c)(
7)
of
this
section.)
(
vi)
Terms
reflecting
the
owner
or
operator's
duties
to
maintain
the
Clean
Unit
designation
and
the
consequences
of
failing
to
do
so,
as
presented
in
paragraph
(
c)(
7)
of
this
section.
(
7)
Maintaining
the
Clean
Unit
designation.
To
maintain
the
Clean
Unit
designation,
the
owner
or
operator
must
conform
to
all
the
restrictions
listed
in
paragraphs
(
c)(
7)(
i)
through
(
iii)
of
this
section.
This
paragraph
(
c)(
7)
applies
independently
to
each
pollutant
for
which
the
emissions
unit
has
the
Clean
Unit
designation.
That
is,
failing
to
conform
to
the
restrictions
for
one
pollutant
affects
Clean
Unit
designation
only
for
that
pollutant.
(
i)
The
Clean
Unit
must
comply
with
the
emission
limitation(
s)
and/
or
work
practice
requirements
adopted
in
conjunction
with
the
LAER
that
is
recorded
in
the
major
NSR
permit,
and
subsequently
reflected
in
the
title
V
permit.
(
A)
The
owner
or
operator
may
not
make
a
physical
change
in
or
change
in
the
method
of
operation
of
the
Clean
Unit
that
causes
the
emissions
unit
to
function
in
a
manner
that
is
inconsistent
with
the
physical
or
operational
characteristics
that
formed
the
basis
for
the
LAER
determination
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
B)
The
Clean
Unit
may
not
emit
above
a
level
that
has
been
offset.
(
ii)
The
Clean
Unit
must
comply
with
any
terms
and
conditions
in
the
title
V
permit
related
to
the
unit's
Clean
Unit
designation.
(
iii)
The
Clean
Unit
must
continue
to
control
emissions
using
the
specific
air
pollution
control
technology
that
was
the
basis
for
its
Clean
Unit
designation.
If
the
emissions
unit
or
control
technology
is
replaced,
then
the
Clean
Unit
designation
ends.
(
8)
Offsets
and
netting
at
Clean
Units.
Emissions
changes
that
occur
at
a
Clean
Unit
must
not
be
included
in
calculating
a
significant
net
emissions
increase
(
that
is,
must
not
be
used
in
a
``
netting
analysis''),
or
be
used
for
generating
offsets
unless
such
use
occurs
before
the
effective
date
of
the
Clean
Unit
designation,
or
after
the
Clean
Unit
designation
expires;
or,
unless
the
emissions
unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit.
However,
if
the
Clean
Unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit,
then,
the
owner
or
operator
may
generate
a
credit
for
the
difference
between
the
level
that
qualified
the
unit
as
a
Clean
Unit
and
the
new
emission
limitation
if
such
reductions
are
surplus,
quantifiable,
and
permanent.
For
purposes
of
generating
offsets,
the
reductions
must
also
be
federally
enforceable.
For
purposes
of
determining
creditable
net
emissions
increases
and
decreases,
the
reductions
must
also
be
enforceable
as
a
practical
matter.
(
9)
Effect
of
redesignation
on
the
Clean
Unit
designation.
The
Clean
Unit
designation
of
an
emissions
unit
is
not
affected
by
redesignation
of
the
attainment
status
of
the
area
in
which
it
is
located.
That
is,
if
a
Clean
Unit
is
located
in
an
attainment
area
and
the
area
is
redesignated
to
nonattainment,
its
Clean
Unit
designation
is
not
affected.
Similarly,
redesignation
from
nonattainment
to
attainment
does
not
affect
the
Clean
Unit
designation.
However,
if
an
existing
Clean
Unit
designation
expires,
it
must
re
qualify
under
the
requirements
that
are
currently
applicable
in
the
area.
(
d)
Clean
Unit
provisions
for
emissions
units
that
achieve
an
emission
limitation
comparable
to
LAER.
The
plan
shall
provide
an
owner
or
operator
of
a
major
stationary
source
the
option
of
using
the
Clean
Unit
Test
to
determine
whether
emissions
increases
at
a
Clean
Unit
are
part
of
a
project
that
is
a
major
modification
according
to
the
provisions
in
paragraphs
(
d)(
1)
through
(
11)
of
this
section.
(
1)
Applicability.
The
provisions
of
this
paragraph
(
d)
apply
to
emissions
units
which
do
not
qualify
as
Clean
Units
under
paragraph
(
c)
of
this
section,
but
which
are
achieving
a
level
of
emissions
control
comparable
to
LAER,
as
determined
by
the
reviewing
authority
in
accordance
with
this
paragraph
(
d).
(
2)
General
provisions
for
Clean
Units.
The
provisions
in
paragraphs
(
d)(
2)(
i)
through
(
iv)
of
this
section
apply
to
a
Clean
Unit
(
designated
under
this
paragraph
(
d)).
(
i)
Any
project
for
which
the
owner
or
operator
begins
actual
construction
after
the
effective
date
of
the
Clean
Unit
designation
(
as
determined
in
accordance
with
paragraph
(
d)(
5)
of
this
section)
and
before
the
expiration
date
(
as
determined
in
accordance
with
paragraph
(
d)(
6)
of
this
section)
will
be
considered
to
have
occurred
while
the
emissions
unit
was
a
Clean
Unit.
(
ii)
If
a
project
at
a
Clean
Unit
does
not
cause
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
have
been
determined
(
pursuant
to
paragraph
(
d)(
4)
of
this
section)
to
be
comparable
to
LAER,
and
the
project
would
not
alter
any
physical
or
operational
characteristics
that
formed
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Vol.
67,
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251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
the
basis
for
determining
that
the
emissions
unit's
control
technology
achieves
a
level
of
emissions
control
comparable
to
LAER
as
specified
in
paragraph
(
d)(
8)(
iv)
of
this
section,
the
emissions
unit
remains
a
Clean
Unit.
(
iii)
If
a
project
causes
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
have
been
determined
(
pursuant
to
paragraph
(
d)(
4)
of
this
section)
to
be
comparable
to
LAER,
or
the
project
would
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
determining
that
the
emissions
unit's
control
technology
achieves
a
level
of
emissions
control
comparable
to
LAER
as
specified
in
paragraph
(
d)(
8)(
iv)
of
this
section,
then
the
emissions
unit
loses
its
designation
as
a
Clean
Unit
upon
issuance
of
the
necessary
permit
revisions
(
unless
the
unit
re
qualifies
as
a
Clean
Unit
pursuant
to
paragraph
(
d)(
3)(
iv)
of
this
section).
If
the
owner
or
operator
begins
actual
construction
on
the
project
without
first
applying
to
revise
the
emissions
unit's
permit,
the
Clean
Unit
designation
ends
immediately
prior
to
the
time
when
actual
construction
begins.
(
iv)
A
project
that
causes
an
emissions
unit
to
lose
its
designation
as
a
Clean
Unit
is
subject
to
the
applicability
requirements
of
paragraphs
(
a)(
2)(
ii)(
A)
through
(
D)
and
paragraph
(
a)(
2)(
ii)(
F)
of
this
section
as
if
the
emissions
unit
were
never
a
Clean
Unit.
(
3)
Qualifying
or
re
qualifying
to
use
the
Clean
Unit
applicability
test.
An
emissions
unit
qualifies
as
a
Clean
Unit
when
the
unit
meets
the
criteria
in
paragraphs
(
d)(
3)(
i)
through
(
iii)
of
this
section.
After
the
original
Clean
Unit
designation
expires
in
accordance
with
paragraph
(
d)(
6)
of
this
section
or
is
lost
pursuant
to
paragraph
(
d)(
2)(
iii)
of
this
section,
such
emissions
unit
may
requalify
as
a
Clean
Unit
under
either
paragraph
(
d)(
3)(
iv)
of
this
section,
or
under
the
Clean
Unit
provisions
in
paragraph
(
c)
of
this
section.
To
requalify
as
a
Clean
Unit
under
paragraph
(
d)(
3)(
iv)
of
this
section,
the
emissions
unit
must
obtain
a
new
permit
issued
pursuant
to
the
requirements
in
paragraphs
(
d)(
7)
and
(
8)
of
this
section
and
meet
all
the
criteria
in
paragraph
(
d)(
3)(
iv)
of
this
section.
The
reviewing
authority
will
make
a
separate
Clean
Unit
designation
for
each
pollutant
emitted
by
the
emissions
unit
for
which
the
emissions
unit
qualifies
as
a
Clean
Unit.
(
i)
Qualifying
air
pollution
control
technologies.
Air
pollutant
emissions
from
the
emissions
unit
must
be
reduced
through
the
use
of
air
pollution
control
technology
(
which
includes
pollution
prevention
as
defined
under
paragraph
(
a)(
1)(
xxvi)
of
this
section
or
work
practices)
that
meets
both
the
following
requirements
in
paragraphs
(
d)(
3)(
i)(
A)
and
(
B)
of
this
section.
(
A)
The
owner
or
operator
has
demonstrated
that
the
emissions
unit's
control
technology
is
comparable
to
LAER
according
to
the
requirements
of
paragraph
(
d)(
4)
of
this
section.
However,
the
emissions
unit
is
not
eligible
for
the
Clean
Unit
designation
if
its
emissions
are
not
reduced
below
the
level
of
a
standard,
uncontrolled
emissions
unit
of
the
same
type
(
e.
g.,
if
the
LAER
determinations
to
which
it
is
compared
have
resulted
in
a
determination
that
no
control
measures
are
required).
(
B)
The
owner
or
operator
made
an
investment
to
install
the
control
technology.
For
the
purpose
of
this
determination,
an
investment
includes
expenses
to
research
the
application
of
a
pollution
prevention
technique
to
the
emissions
unit
or
to
retool
the
unit
to
apply
a
pollution
prevention
technique.
(
ii)
Impact
of
emissions
from
the
unit.
The
reviewing
authority
must
determine
that
the
allowable
emissions
from
the
emissions
unit
will
not
cause
or
contribute
to
a
violation
of
any
national
ambient
air
quality
standard
or
PSD
increment,
or
adversely
impact
an
air
quality
related
value
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
and
for
which
information
is
available
to
the
general
public.
(
iii)
Date
of
installation.
An
emissions
unit
may
qualify
as
a
Clean
Unit
even
if
the
control
technology,
on
which
the
Clean
Unit
designation
is
based,
was
installed
before
the
effective
date
of
plan
requirements
to
implement
the
requirements
of
this
paragraph
(
d)(
3)(
iii).
However,
for
such
emissions
units,
the
owner
or
operator
must
apply
for
the
Clean
Unit
designation
within
2
years
after
the
plan
requirements
become
effective.
For
technologies
installed
after
the
plan
requirements
become
effective,
the
owner
or
operator
must
apply
for
the
Clean
Unit
designation
at
the
time
the
control
technology
is
installed.
(
iv)
Re
qualifying
as
a
Clean
Unit.
The
emissions
unit
must
obtain
a
new
permit
(
pursuant
to
requirements
in
paragraphs
(
d)(
7)
and
(
8)
of
this
section)
that
demonstrates
that
the
emissions
unit's
control
technology
is
achieving
a
level
of
emission
control
comparable
to
current
day
LAER,
and
the
emissions
unit
must
meet
the
requirements
in
paragraphs
(
d)(
3)(
i)(
A)
and
(
d)(
3)(
ii)
of
this
section.
(
4)
Demonstrating
control
effectiveness
comparable
to
LAER.
The
owner
or
operator
may
demonstrate
that
the
emissions
unit's
control
technology
is
comparable
to
LAER
for
purposes
of
paragraph
(
d)(
3)(
i)
of
this
section
according
to
either
paragraph
(
d)(
4)(
i)
or
(
ii)
of
this
section.
Paragraph
(
d)(
4)(
iii)
of
this
section
specifies
the
time
for
making
this
comparison.
(
i)
Comparison
to
previous
LAER
determinations.
The
administrator
maintains
an
on
line
data
base
of
previous
determinations
of
RACT,
BACT,
and
LAER
in
the
RACT/
BACT/
LAER
Clearinghouse
(
RBLC).
The
emissions
unit's
control
technology
is
presumed
to
be
comparable
to
LAER
if
it
achieves
an
emission
limitation
that
is
at
least
as
stringent
as
any
one
of
the
five
best
performing
similar
sources
for
which
a
LAER
determination
has
been
made
within
the
preceding
5
years,
and
for
which
information
has
been
entered
into
the
RBLC.
The
reviewing
authority
shall
also
compare
this
presumption
to
any
additional
LAER
determinations
of
which
it
is
aware,
and
shall
consider
any
information
on
achieved
in
practice
pollution
control
technologies
provided
during
the
public
comment
period,
to
determine
whether
any
presumptive
determination
that
the
control
technology
is
comparable
to
LAER
is
correct.
(
ii)
The
substantially
as
effective
test.
The
owner
or
operator
may
demonstrate
that
the
emissions
unit's
control
technology
is
substantially
as
effective
as
LAER.
In
addition,
any
other
person
may
present
evidence
related
to
whether
the
control
technology
is
substantially
as
effective
as
LAER
during
the
public
participation
process
required
under
paragraph
(
d)(
7)
of
this
section.
The
reviewing
authority
shall
consider
such
evidence
on
a
case
by
case
basis
and
determine
whether
the
emissions
unit's
air
pollution
control
technology
is
substantially
as
effective
as
LAER.
(
iii)
Time
of
comparison.
(
A)
Emissions
units
with
control
technologies
that
are
installed
before
the
effective
date
of
plan
requirements
implementing
this
paragraph.
The
owner
or
operator
of
an
emissions
unit
whose
control
technology
is
installed
before
the
effective
date
of
plan
requirements
implementing
this
paragraph
(
d)
may,
at
its
option,
either
demonstrate
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
the
LAER
requirements
that
applied
at
the
time
the
control
technology
was
installed,
or
demonstrate
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
current
day
LAER
requirements.
The
expiration
date
of
the
Clean
Unit
designation
will
depend
on
which
option
the
owner
or
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Federal
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
operator
uses,
as
specified
in
paragraph
(
d)(
6)
of
this
section.
(
B)
Emissions
units
with
control
technologies
that
are
installed
after
the
effective
date
of
plan
requirements
implementing
this
paragraph.
The
owner
or
operator
must
demonstrate
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
current
day
LAER
requirements.
(
5)
Effective
date
of
the
Clean
Unit
designation.
The
effective
date
of
an
emissions
unit's
Clean
Unit
designation
(
that
is,
the
date
on
which
the
owner
or
operator
may
begin
to
use
the
Clean
Unit
Test
to
determine
whether
a
project
involving
the
emissions
unit
is
a
major
modification)
is
the
date
that
the
permit
required
by
paragraph
(
d)(
7)
of
this
section
is
issued
or
the
date
that
the
emissions
unit's
air
pollution
control
technology
is
placed
into
service,
whichever
is
later.
(
6)
Clean
Unit
expiration.
If
the
owner
or
operator
demonstrates
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
the
LAER
requirements
that
applied
at
the
time
the
control
technology
was
installed,
then
the
Clean
Unit
designation
expires
10
years
from
the
date
that
the
control
technology
was
installed.
For
all
other
emissions
units,
the
Clean
Unit
designation
expires
10
years
from
the
effective
date
of
the
Clean
Unit
designation,
as
determined
according
to
paragraph
(
d)(
5)
of
this
section.
In
addition,
for
all
emissions
units,
the
Clean
Unit
designation
expires
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
the
Clean
Unit
designation
in
paragraph
(
d)(
9)
of
this
section.
(
7)
Procedures
for
designating
emissions
units
as
Clean
Units.
The
reviewing
authority
shall
designate
an
emissions
unit
a
Clean
Unit
only
by
issuing
a
permit
through
a
permitting
program
that
has
been
approved
by
the
Administrator
and
that
conforms
with
the
requirements
of
§
§
51.160
through
51.164
of
this
chapter
including
requirements
for
public
notice
of
the
proposed
Clean
Unit
designation
and
opportunity
for
public
comment.
Such
permit
must
also
meet
the
requirements
in
paragraph
(
d)(
8).
(
8)
Required
permit
content.
The
permit
required
by
paragraph
(
d)(
7)
of
this
section
shall
include
the
terms
and
conditions
set
forth
in
paragraphs
(
d)(
8)(
i)
through
(
vi)
of
this
section.
Such
terms
and
conditions
shall
be
incorporated
into
the
major
stationary
source's
title
V
permit
in
accordance
with
the
provisions
of
the
applicable
title
V
permit
program
under
part
70
or
part
71
of
this
chapter,
but
no
later
than
when
the
title
V
permit
is
renewed.
(
i)
A
statement
indicating
that
the
emissions
unit
qualifies
as
a
Clean
Unit
and
identifying
the
pollutant(
s)
for
which
this
designation
applies.
(
ii)
The
effective
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
reviewing
authority
issues
the
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
then
the
permit
must
describe
the
event
that
will
determine
the
effective
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
effective
date
is
known,
then
the
owner
or
operator
must
notify
the
reviewing
authority
of
the
exact
date.
This
specific
effective
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iii)
The
expiration
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
reviewing
authority
issues
the
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
then
the
permit
must
describe
the
event
that
will
determine
the
expiration
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
expiration
date
is
known,
then
the
owner
or
operator
must
notify
the
reviewing
authority
of
the
exact
date.
The
expiration
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iv)
All
emission
limitations
and
work
practice
requirements
adopted
in
conjunction
with
emission
limitations
necessary
to
assure
that
the
control
technology
continues
to
achieve
an
emission
limitation
comparable
to
LAER,
and
any
physical
or
operational
characteristics
that
formed
the
basis
for
determining
that
the
emissions
unit's
control
technology
achieves
a
level
of
emissions
control
comparable
to
LAER
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
v)
Monitoring,
recordkeeping,
and
reporting
requirements
as
necessary
to
demonstrate
that
the
emissions
unit
continues
to
meet
the
criteria
for
maintaining
its
Clean
Unit
designation.
(
See
paragraph
(
d)(
9)
of
this
section.)
(
vi)
Terms
reflecting
the
owner
or
operator's
duties
to
maintain
the
Clean
Unit
designation
and
the
consequences
of
failing
to
do
so,
as
presented
in
paragraph
(
d)(
9)
of
this
section.
(
9)
Maintaining
Clean
Unit
designation.
To
maintain
Clean
Unit
designation,
the
owner
or
operator
must
conform
to
all
the
restrictions
listed
in
paragraphs
(
d)(
9)(
i)
through
(
v)
of
this
section.
This
paragraph
(
d)(
9)
applies
independently
to
each
pollutant
for
which
the
reviewing
authority
has
designated
the
emissions
unit
a
Clean
Unit.
That
is,
failing
to
conform
to
the
restrictions
for
one
pollutant
affects
the
Clean
Unit
designation
only
for
that
pollutant.
(
i)
The
Clean
Unit
must
comply
with
the
emission
limitation(
s)
and/
or
work
practice
requirements
adopted
to
ensure
that
the
control
technology
continues
to
achieve
emission
control
comparable
to
LAER.
(
ii)
The
owner
or
operator
may
not
make
a
physical
change
in
or
change
in
the
method
of
operation
of
the
Clean
Unit
that
causes
the
emissions
unit
to
function
in
a
manner
that
is
inconsistent
with
the
physical
or
operational
characteristics
that
formed
the
basis
for
the
determination
that
the
control
technology
is
achieving
a
level
of
emission
control
that
is
comparable
to
LAER
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
iii)
The
Clean
Unit
may
not
emit
above
a
level
that
has
been
offset.
(
iv)
The
Clean
Unit
must
comply
with
any
terms
and
conditions
in
the
title
V
permit
related
to
the
unit's
Clean
Unit
designation.
(
v)
The
Clean
Unit
must
continue
to
control
emissions
using
the
specific
air
pollution
control
technology
that
was
the
basis
for
its
Clean
Unit
designation.
If
the
emissions
unit
or
control
technology
is
replaced,
then
the
Clean
Unit
designation
ends.
(
10)
Offsets
and
Netting
at
Clean
Units.
Emissions
changes
that
occur
at
a
Clean
Unit
must
not
be
included
in
calculating
a
significant
net
emissions
increase
(
that
is,
must
not
be
used
in
a
``
netting
analysis''),
or
be
used
for
generating
offsets
unless
such
use
occurs
before
the
effective
date
of
plan
requirements
adopted
to
implement
this
paragraph
(
d)
or
after
the
Clean
Unit
designation
expires;
or,
unless
the
emissions
unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit.
However,
if
the
Clean
Unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit,
then
the
owner
or
operator
may
generate
a
credit
for
the
difference
between
the
level
that
qualified
the
unit
as
a
Clean
Unit
and
the
emissions
unit's
new
emission
limitation
if
such
reductions
are
surplus,
quantifiable,
and
permanent.
For
purposes
of
generating
offsets,
the
reductions
must
also
be
federally
enforceable.
For
purposes
of
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31,
2002
/
Rules
and
Regulations
determining
creditable
net
emissions
increases
and
decreases,
the
reductions
must
also
be
enforceable
as
a
practical
matter.
(
11)
Effect
of
redesignation
on
the
Clean
Unit
designation.
The
Clean
Unit
designation
of
an
emissions
unit
is
not
affected
by
redesignation
of
the
attainment
status
of
the
area
in
which
it
is
located.
That
is,
if
a
Clean
Unit
is
located
in
an
attainment
area
and
the
area
is
redesignated
to
nonattainment,
its
Clean
Unit
designation
is
not
affected.
Similarly,
redesignation
from
nonattainment
to
attainment
does
not
affect
the
Clean
Unit
designation.
However,
if
a
Clean
Unit's
designation
expires
or
is
lost
pursuant
to
paragraphs
(
c)(
2)(
iii)
and
(
d)(
2)(
iii)
of
this
section,
it
must
re
qualify
under
the
requirements
that
are
currently
applicable.
(
e)
PCP
exclusion
procedural
requirements.
Each
plan
shall
include
provisions
for
PCPs
equivalent
to
those
contained
in
paragraphs
(
e)(
1)
through
(
6)
of
this
section.
(
1)
Before
an
owner
or
operator
begins
actual
construction
of
a
PCP,
the
owner
or
operator
must
either
submit
a
notice
to
the
reviewing
authority
if
the
project
is
listed
in
paragraphs
(
a)(
1)(
xxv)(
A)
through
(
F)
of
this
section,
or
if
the
project
is
not
listed
in
paragraphs
(
a)(
1)(
xxv)(
A)
through
(
F)
of
this
section,
then
the
owner
or
operator
must
submit
a
permit
application
and
obtain
approval
to
use
the
PCP
exclusion
from
the
reviewing
authority
consistent
with
the
requirements
in
paragraph
(
e)(
5)
of
this
section.
Regardless
of
whether
the
owner
or
operator
submits
a
notice
or
a
permit
application,
the
project
must
meet
the
requirements
in
paragraph
(
e)(
2)
of
this
section,
and
the
notice
or
permit
application
must
contain
the
information
required
in
paragraph
(
e)(
3)
of
this
section.
(
2)
Any
project
that
relies
on
the
PCP
exclusion
must
meet
the
requirements
in
paragraphs
(
e)(
2)(
i)
and
(
ii)
of
this
section.
(
i)
Environmentally
beneficial
analysis.
The
environmental
benefit
from
the
emission
reductions
of
pollutants
regulated
under
the
Act
must
outweigh
the
environmental
detriment
of
emissions
increases
in
pollutants
regulated
under
the
Act.
A
statement
that
a
technology
from
paragraphs
(
a)(
1)(
xxv)(
A)
through
(
F)
of
this
section
is
being
used
shall
be
presumed
to
satisfy
this
requirement.
(
ii)
Air
quality
analysis.
The
emissions
increases
from
the
project
will
not
cause
or
contribute
to
a
violation
of
any
national
ambient
air
quality
standard
or
PSD
increment,
or
adversely
impact
an
air
quality
related
value
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
and
for
which
information
is
available
to
the
general
public.
(
3)
Content
of
notice
or
permit
application.
In
the
notice
or
permit
application
sent
to
the
reviewing
authority,
the
owner
or
operator
must
include,
at
a
minimum,
the
information
listed
in
paragraphs
(
e)(
3)(
i)
through
(
v)
of
this
section.
(
i)
A
description
of
the
project.
(
ii)
The
potential
emissions
increases
and
decreases
of
any
pollutant
regulated
under
the
Act
and
the
projected
emissions
increases
and
decreases
using
the
methodology
in
paragraph
(
a)(
2)(
ii)
of
this
section,
that
will
result
from
the
project,
and
a
copy
of
the
environmentally
beneficial
analysis
required
by
paragraph
(
e)(
2)(
i)
of
this
section.
(
iii)
A
description
of
monitoring
and
recordkeeping,
and
all
other
methods,
to
be
used
on
an
ongoing
basis
to
demonstrate
that
the
project
is
environmentally
beneficial.
Methods
should
be
sufficient
to
meet
the
requirements
in
part
70
and
part
71.
(
iv)
A
certification
that
the
project
will
be
designed
and
operated
in
a
manner
that
is
consistent
with
proper
industry
and
engineering
practices,
in
a
manner
that
is
consistent
with
the
environmentally
beneficial
analysis
and
air
quality
analysis
required
by
paragraphs
(
e)(
2)(
i)
and
(
ii)
of
this
section,
with
information
submitted
in
the
notice
or
permit
application,
and
in
such
a
way
as
to
minimize,
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy,
emissions
of
collateral
pollutants.
(
v)
Demonstration
that
the
PCP
will
not
have
an
adverse
air
quality
impact
(
e.
g.,
modeling,
screening
level
modeling
results,
or
a
statement
that
the
collateral
emissions
increase
is
included
within
the
parameters
used
in
the
most
recent
modeling
exercise)
as
required
by
paragraph
(
e)(
2)(
ii)
of
this
section.
An
air
quality
impact
analysis
is
not
required
for
any
pollutant
which
will
not
experience
a
significant
emissions
increase
as
a
result
of
the
project.
(
4)
Notice
process
for
listed
projects.
For
projects
listed
in
paragraphs
(
a)(
1)(
xxv)(
A)
through
(
F)
of
this
section,
the
owner
or
operator
may
begin
actual
construction
of
the
project
immediately
after
notice
is
sent
to
the
reviewing
authority
(
unless
otherwise
prohibited
under
requirements
of
the
applicable
plan).
The
owner
or
operator
shall
respond
to
any
requests
by
its
reviewing
authority
for
additional
information
that
the
reviewing
authority
determines
is
necessary
to
evaluate
the
suitability
of
the
project
for
the
PCP
exclusion.
(
5)
Permit
process
for
unlisted
projects.
Before
an
owner
or
operator
may
begin
actual
construction
of
a
PCP
project
that
is
not
listed
in
paragraphs
(
a)(
1)(
xxv)(
A)
through
(
F)
of
this
section,
the
project
must
be
approved
by
the
reviewing
authority
and
recorded
in
a
plan
approved
permit
or
title
V
permit
using
procedures
that
are
consistent
with
§
§
51.160
and
51.161
of
this
chapter.
This
includes
the
requirement
that
the
reviewing
authority
provide
the
public
with
notice
of
the
proposed
approval,
with
access
to
the
environmentally
beneficial
analysis
and
the
air
quality
analysis,
and
provide
at
least
a
30
day
period
for
the
public
and
the
Administrator
to
submit
comments.
The
reviewing
authority
must
address
all
material
comments
received
by
the
end
of
the
comment
period
before
taking
final
action
on
the
permit.
(
6)
Operational
requirements.
Upon
installation
of
the
PCP,
the
owner
or
operator
must
comply
with
the
requirements
of
paragraphs
(
e)(
6)(
i)
through
(
iii)
of
this
section.
(
i)
General
duty.
The
owner
or
operator
must
operate
the
PCP
in
a
manner
consistent
with
proper
industry
and
engineering
practices,
in
a
manner
that
is
consistent
with
the
environmentally
beneficial
analysis
and
air
quality
analysis
required
by
paragraphs
(
e)(
2)(
i)
and
(
ii)
of
this
section,
with
information
submitted
in
the
notice
or
permit
application
required
by
paragraph
(
e)(
3)
of
this
section,
and
in
such
a
way
as
to
minimize,
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy,
emissions
of
collateral
pollutants.
(
ii)
Recordkeeping.
The
owner
or
operator
must
maintain
copies
on
site
of
the
environmentally
beneficial
analysis,
the
air
quality
impacts
analysis,
and
monitoring
and
other
emission
records
to
prove
that
the
PCP
operated
consistent
with
the
general
duty
requirements
in
paragraph
(
e)(
6)(
i)
of
this
section.
(
iii)
Permit
requirements.
The
owner
or
operator
must
comply
with
any
provisions
in
the
plan
approved
permit
or
title
V
permit
related
to
use
and
approval
of
the
PCP
exclusion.
(
iv)
Generation
of
emission
reduction
credits.
Emission
reductions
created
by
a
PCP
shall
not
be
included
in
calculating
a
significant
net
emissions
increase,
or
be
used
for
generating
offsets,
unless
the
emissions
unit
further
reduces
emissions
after
qualifying
for
the
PCP
exclusion
(
e.
g.,
taking
an
operational
restriction
on
the
hours
of
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31,
2002
/
Rules
and
Regulations
operation).
The
owner
or
operator
may
generate
a
credit
for
the
difference
between
the
level
of
reduction
which
was
used
to
qualify
for
the
PCP
exclusion
and
the
new
emission
limitation
if
such
reductions
are
surplus,
quantifiable,
and
permanent.
For
purposes
of
generating
offsets,
the
reductions
must
also
be
federally
enforceable.
For
purposes
of
determining
creditable
net
emissions
increases
and
decreases,
the
reductions
must
also
be
enforceable
as
a
practical
matter.
(
f)
Actuals
PALs.
The
plan
shall
provide
for
PALs
according
to
the
provisions
in
paragraphs
(
f)(
1)
through
(
15)
of
this
section.
(
1)
Applicability.
(
i)
The
reviewing
authority
may
approve
the
use
of
an
actuals
PAL
for
any
existing
major
stationary
source
(
except
as
provided
in
paragraph
(
f)(
1)(
ii)
of
this
section)
if
the
PAL
meets
the
requirements
in
paragraphs
(
f)(
1)
through
(
15)
of
this
section.
The
term
``
PAL''
shall
mean
``
actuals
PAL''
throughout
paragraph
(
f)
of
this
section.
(
ii)
The
reviewing
authority
shall
not
allow
an
actuals
PAL
for
VOC
or
NOX
for
any
major
stationary
source
located
in
an
extreme
ozone
nonattainment
area.
(
iii)
Any
physical
change
in
or
change
in
the
method
of
operation
of
a
major
stationary
source
that
maintains
its
total
source
wide
emissions
below
the
PAL
level,
meets
the
requirements
in
paragraphs
(
f)(
1)
through
(
15)
of
this
section,
and
complies
with
the
PAL
permit:
(
A)
Is
not
a
major
modification
for
the
PAL
pollutant;
(
B)
Does
not
have
to
be
approved
through
the
plan's
nonattainment
major
NSR
program;
and
(
C)
Is
not
subject
to
the
provisions
in
paragraph
(
a)(
5)(
ii)
of
this
section
(
restrictions
on
relaxing
enforceable
emission
limitations
that
the
major
stationary
source
used
to
avoid
applicability
of
the
nonattainment
major
NSR
program).
(
iv)
Except
as
provided
under
paragraph
(
f)(
1)(
iii)(
C)
of
this
section,
a
major
stationary
source
shall
continue
to
comply
with
all
applicable
Federal
or
State
requirements,
emission
limitations,
and
work
practice
requirements
that
were
established
prior
to
the
effective
date
of
the
PAL.
(
2)
Definitions.
The
plan
shall
use
the
definitions
in
paragraphs
(
f)(
2)(
i)
through
(
xi)
of
this
section
for
the
purpose
of
developing
and
implementing
regulations
that
authorize
the
use
of
actuals
PALs
consistent
with
paragraphs
(
f)(
1)
through
(
15)
of
this
section.
When
a
term
is
not
defined
in
these
paragraphs,
it
shall
have
the
meaning
given
in
paragraph
(
a)(
1)
of
this
section
or
in
the
Act.
(
i)
Actuals
PAL
for
a
major
stationary
source
means
a
PAL
based
on
the
baseline
actual
emissions
(
as
defined
in
paragraph
(
a)(
1)(
xxxv)
of
this
section)
of
all
emissions
units
(
as
defined
in
paragraph
(
a)(
1)(
vii)
of
this
section)
at
the
source,
that
emit
or
have
the
potential
to
emit
the
PAL
pollutant.
(
ii)
Allowable
emissions
means
``
allowable
emissions''
as
defined
in
paragraph
(
a)(
1)(
xi)
of
this
section,
except
as
this
definition
is
modified
according
to
paragraphs
(
f)(
2)(
ii)(
A)
through
(
B)
of
this
section.
(
A)
The
allowable
emissions
for
any
emissions
unit
shall
be
calculated
considering
any
emission
limitations
that
are
enforceable
as
a
practical
matter
on
the
emissions
unit's
potential
to
emit.
(
B)
An
emissions
unit's
potential
to
emit
shall
be
determined
using
the
definition
in
paragraph
(
a)(
1)(
iii)
of
this
section,
except
that
the
words
``
or
enforceable
as
a
practical
matter''
should
be
added
after
``
federally
enforceable.''
(
iii)
Small
emissions
unit
means
an
emissions
unit
that
emits
or
has
the
potential
to
emit
the
PAL
pollutant
in
an
amount
less
than
the
significant
level
for
that
PAL
pollutant,
as
defined
in
paragraph
(
a)(
1)(
x)
of
this
section
or
in
the
Act,
whichever
is
lower.
(
iv)
Major
emissions
unit
means:
(
A)
Any
emissions
unit
that
emits
or
has
the
potential
to
emit
100
tons
per
year
or
more
of
the
PAL
pollutant
in
an
attainment
area;
or
(
B)
Any
emissions
unit
that
emits
or
has
the
potential
to
emit
the
PAL
pollutant
in
an
amount
that
is
equal
to
or
greater
than
the
major
source
threshold
for
the
PAL
pollutant
as
defined
by
the
Act
for
nonattainment
areas.
For
example,
in
accordance
with
the
definition
of
major
stationary
source
in
section
182(
c)
of
the
Act,
an
emissions
unit
would
be
a
major
emissions
unit
for
VOC
if
the
emissions
unit
is
located
in
a
serious
ozone
nonattainment
area
and
it
emits
or
has
the
potential
to
emit
50
or
more
tons
of
VOC
per
year.
(
v)
Plantwide
applicability
limitation
(
PAL)
means
an
emission
limitation
expressed
in
tons
per
year,
for
a
pollutant
at
a
major
stationary
source,
that
is
enforceable
as
a
practical
matter
and
established
source
wide
in
accordance
with
paragraphs
(
f)(
1)
through
(
f)(
15)
of
this
section.
(
vi)
PAL
effective
date
generally
means
the
date
of
issuance
of
the
PAL
permit.
However,
the
PAL
effective
date
for
an
increased
PAL
is
the
date
any
emissions
unit
which
is
part
of
the
PAL
major
modification
becomes
operational
and
begins
to
emit
the
PAL
pollutant.
(
vii)
PAL
effective
period
means
the
period
beginning
with
the
PAL
effective
date
and
ending
10
years
later.
(
viii)
PAL
major
modification
means,
notwithstanding
paragraphs
(
a)(
1)(
v)
and
(
vi)
of
this
section
(
the
definitions
for
major
modification
and
net
emissions
increase),
any
physical
change
in
or
change
in
the
method
of
operation
of
the
PAL
source
that
causes
it
to
emit
the
PAL
pollutant
at
a
level
equal
to
or
greater
than
the
PAL.
(
ix)
PAL
permit
means
the
major
NSR
permit,
the
minor
NSR
permit,
or
the
State
operating
permit
under
a
program
that
is
approved
into
the
plan,
or
the
title
V
permit
issued
by
the
reviewing
authority
that
establishes
a
PAL
for
a
major
stationary
source.
(
x)
PAL
pollutant
means
the
pollutant
for
which
a
PAL
is
established
at
a
major
stationary
source.
(
xi)
Significant
emissions
unit
means
an
emissions
unit
that
emits
or
has
the
potential
to
emit
a
PAL
pollutant
in
an
amount
that
is
equal
to
or
greater
than
the
significant
level
(
as
defined
in
paragraph
(
a)(
1)(
x)
of
this
section
or
in
the
Act,
whichever
is
lower)
for
that
PAL
pollutant,
but
less
than
the
amount
that
would
qualify
the
unit
as
a
major
emissions
unit
as
defined
in
paragraph
(
f)(
2)(
iv)
of
this
section.
(
3)
Permit
application
requirements.
As
part
of
a
permit
application
requesting
a
PAL,
the
owner
or
operator
of
a
major
stationary
source
shall
submit
the
following
information
to
the
reviewing
authority
for
approval:
(
i)
A
list
of
all
emissions
units
at
the
source
designated
as
small,
significant
or
major
based
on
their
potential
to
emit.
In
addition,
the
owner
or
operator
of
the
source
shall
indicate
which,
if
any,
Federal
or
State
applicable
requirements,
emission
limitations
or
work
practices
apply
to
each
unit.
(
ii)
Calculations
of
the
baseline
actual
emissions
(
with
supporting
documentation).
Baseline
actual
emissions
are
to
include
emissions
associated
not
only
with
operation
of
the
unit,
but
also
emissions
associated
with
startup,
shutdown
and
malfunction.
(
iii)
The
calculation
procedures
that
the
major
stationary
source
owner
or
operator
proposes
to
use
to
convert
the
monitoring
system
data
to
monthly
emissions
and
annual
emissions
based
on
a
12
month
rolling
total
for
each
month
as
required
by
paragraph
(
f)(
13)(
i)
of
this
section.
(
4)
General
requirements
for
establishing
PALs.
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
(
i)
The
plan
allows
the
reviewing
authority
to
establish
a
PAL
at
a
major
stationary
source,
provided
that
at
a
minimum,
the
requirements
in
paragraphs
(
f)(
4)(
i)(
A)
through
(
G)
of
this
section
are
met.
(
A)
The
PAL
shall
impose
an
annual
emission
limitation
in
tons
per
year,
that
is
enforceable
as
a
practical
matter,
for
the
entire
major
stationary
source.
For
each
month
during
the
PAL
effective
period
after
the
first
12
months
of
establishing
a
PAL,
the
major
stationary
source
owner
or
operator
shall
show
that
the
sum
of
the
monthly
emissions
from
each
emissions
unit
under
the
PAL
for
the
previous
12
consecutive
months
is
less
than
the
PAL
(
a
12
month
average,
rolled
monthly).
For
each
month
during
the
first
11
months
from
the
PAL
effective
date,
the
major
stationary
source
owner
or
operator
shall
show
that
the
sum
of
the
preceding
monthly
emissions
from
the
PAL
effective
date
for
each
emissions
unit
under
the
PAL
is
less
than
the
PAL.
(
B)
The
PAL
shall
be
established
in
a
PAL
permit
that
meets
the
public
participation
requirements
in
paragraph
(
f)(
5)
of
this
section.
(
C)
The
PAL
permit
shall
contain
all
the
requirements
of
paragraph
(
f)(
7)
of
this
section.
(
D)
The
PAL
shall
include
fugitive
emissions,
to
the
extent
quantifiable,
from
all
emissions
units
that
emit
or
have
the
potential
to
emit
the
PAL
pollutant
at
the
major
stationary
source.
(
E)
Each
PAL
shall
regulate
emissions
of
only
one
pollutant.
(
F)
Each
PAL
shall
have
a
PAL
effective
period
of
10
years.
(
G)
The
owner
or
operator
of
the
major
stationary
source
with
a
PAL
shall
comply
with
the
monitoring,
recordkeeping,
and
reporting
requirements
provided
in
paragraphs
(
f)(
12)
through
(
14)
of
this
section
for
each
emissions
unit
under
the
PAL
through
the
PAL
effective
period.
(
ii)
At
no
time
(
during
or
after
the
PAL
effective
period)
are
emissions
reductions
of
a
PAL
pollutant,
which
occur
during
the
PAL
effective
period,
creditable
as
decreases
for
purposes
of
offsets
under
paragraph
(
a)(
3)(
ii)
of
this
section
unless
the
level
of
the
PAL
is
reduced
by
the
amount
of
such
emissions
reductions
and
such
reductions
would
be
creditable
in
the
absence
of
the
PAL.
(
5)
Public
participation
requirement
for
PALs.
PALs
for
existing
major
stationary
sources
shall
be
established,
renewed,
or
increased
through
a
procedure
that
is
consistent
with
§
§
51.160
and
51.161
of
this
chapter.
This
includes
the
requirement
that
the
reviewing
authority
provide
the
public
with
notice
of
the
proposed
approval
of
a
PAL
permit
and
at
least
a
30
day
period
for
submittal
of
public
comment.
The
reviewing
authority
must
address
all
material
comments
before
taking
final
action
on
the
permit.
(
6)
Setting
the
10
year
actuals
PAL
level.
The
plan
shall
provide
that
the
actuals
PAL
level
for
a
major
stationary
source
shall
be
established
as
the
sum
of
the
baseline
actual
emissions
(
as
defined
in
paragraph
(
a)(
1)(
xxxv)
of
this
section)
of
the
PAL
pollutant
for
each
emissions
unit
at
the
source;
plus
an
amount
equal
to
the
applicable
significant
level
for
the
PAL
pollutant
under
paragraph
(
a)(
1)(
x)
of
this
section
or
under
the
Act,
whichever
is
lower.
When
establishing
the
actuals
PAL
level,
for
a
PAL
pollutant,
only
one
consecutive
24
month
period
must
be
used
to
determine
the
baseline
actual
emissions
for
all
existing
emissions
units.
However,
a
different
consecutive
24
month
period
may
be
used
for
each
different
PAL
pollutant.
Emissions
associated
with
units
that
were
permanently
shutdown
after
this
24
month
period
must
be
subtracted
from
the
PAL
level.
Emissions
from
units
on
which
actual
construction
began
after
the
24
month
period
must
be
added
to
the
PAL
level
in
an
amount
equal
to
the
potential
to
emit
of
the
units.
The
reviewing
authority
shall
specify
a
reduced
PAL
level(
s)
(
in
tons/
yr)
in
the
PAL
permit
to
become
effective
on
the
future
compliance
date(
s)
of
any
applicable
Federal
or
State
regulatory
requirement(
s)
that
the
reviewing
authority
is
aware
of
prior
to
issuance
of
the
PAL
permit.
For
instance,
if
the
source
owner
or
operator
will
be
required
to
reduce
emissions
from
industrial
boilers
in
half
from
baseline
emissions
of
60
ppm
NOX
to
a
new
rule
limit
of
30
ppm,
then
the
permit
shall
contain
a
future
effective
PAL
level
that
is
equal
to
the
current
PAL
level
reduced
by
half
of
the
original
baseline
emissions
of
such
unit(
s).
(
7)
Contents
of
the
PAL
permit.
The
plan
shall
require
that
the
PAL
permit
contain,
at
a
minimum,
the
information
in
paragraphs
(
f)(
7)(
i)
through
(
x)
of
this
section.
(
i)
The
PAL
pollutant
and
the
applicable
source
wide
emission
limitation
in
tons
per
year.
(
ii)
The
PAL
permit
effective
date
and
the
expiration
date
of
the
PAL
(
PAL
effective
period).
(
iii)
Specification
in
the
PAL
permit
that
if
a
major
stationary
source
owner
or
operator
applies
to
renew
a
PAL
in
accordance
with
paragraph
(
f)(
10)
of
this
section
before
the
end
of
the
PAL
effective
period,
then
the
PAL
shall
not
expire
at
the
end
of
the
PAL
effective
period.
It
shall
remain
in
effect
until
a
revised
PAL
permit
is
issued
by
the
reviewing
authority.
(
iv)
A
requirement
that
emission
calculations
for
compliance
purposes
include
emissions
from
startups,
shutdowns
and
malfunctions.
(
v)
A
requirement
that,
once
the
PAL
expires,
the
major
stationary
source
is
subject
to
the
requirements
of
paragraph
(
f)(
9)
of
this
section.
(
vi)
The
calculation
procedures
that
the
major
stationary
source
owner
or
operator
shall
use
to
convert
the
monitoring
system
data
to
monthly
emissions
and
annual
emissions
based
on
a
12
month
rolling
total
for
each
month
as
required
by
paragraph
(
f)(
13)(
i)
of
this
section.
(
vii)
A
requirement
that
the
major
stationary
source
owner
or
operator
monitor
all
emissions
units
in
accordance
with
the
provisions
under
paragraph
(
f)(
12)
of
this
section.
(
viii)
A
requirement
to
retain
the
records
required
under
paragraph
(
f)(
13)
of
this
section
on
site.
Such
records
may
be
retained
in
an
electronic
format.
(
ix)
A
requirement
to
submit
the
reports
required
under
paragraph
(
f)(
14)
of
this
section
by
the
required
deadlines.
(
x)
Any
other
requirements
that
the
reviewing
authority
deems
necessary
to
implement
and
enforce
the
PAL.
(
8)
PAL
effective
period
and
reopening
of
the
PAL
permit.
The
plan
shall
require
the
information
in
paragraphs
(
f)(
8)(
i)
and
(
ii)
of
this
section.
(
i)
PAL
effective
period.
The
reviewing
authority
shall
specify
a
PAL
effective
period
of
10
years.
(
ii)
Reopening
of
the
PAL
permit.
(
A)
During
the
PAL
effective
period,
the
plan
shall
require
the
reviewing
authority
to
reopen
the
PAL
permit
to:
(
1)
Correct
typographical/
calculation
errors
made
in
setting
the
PAL
or
reflect
a
more
accurate
determination
of
emissions
used
to
establish
the
PAL.
(
2)
Reduce
the
PAL
if
the
owner
or
operator
of
the
major
stationary
source
creates
creditable
emissions
reductions
for
use
as
offsets
under
paragraph
(
a)(
3)(
ii)
of
this
section.
(
3)
Revise
the
PAL
to
reflect
an
increase
in
the
PAL
as
provided
under
paragraph
(
f)(
11)
of
this
section.
(
B)
The
plan
shall
provide
the
reviewing
authority
discretion
to
reopen
the
PAL
permit
for
the
following:
(
1)
Reduce
the
PAL
to
reflect
newly
applicable
Federal
requirements
(
for
example,
NSPS)
with
compliance
dates
after
the
PAL
effective
date.
(
2)
Reduce
the
PAL
consistent
with
any
other
requirement,
that
is
enforceable
as
a
practical
matter,
and
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Federal
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
that
the
State
may
impose
on
the
major
stationary
source
under
the
plan.
(
3)
Reduce
the
PAL
if
the
reviewing
authority
determines
that
a
reduction
is
necessary
to
avoid
causing
or
contributing
to
a
NAAQS
or
PSD
increment
violation,
or
to
an
adverse
impact
on
an
air
quality
related
value
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
and
for
which
information
is
available
to
the
general
public.
(
C)
Except
for
the
permit
reopening
in
paragraph
(
f)(
8)(
ii)(
A)(
1)
of
this
section
for
the
correction
of
typographical/
calculation
errors
that
do
not
increase
the
PAL
level,
all
other
reopenings
shall
be
carried
out
in
accordance
with
the
public
participation
requirements
of
paragraph
(
f)(
5)
of
this
section.
(
9)
Expiration
of
a
PAL.
Any
PAL
which
is
not
renewed
in
accordance
with
the
procedures
in
paragraph
(
f)(
10)
of
this
section
shall
expire
at
the
end
of
the
PAL
effective
period,
and
the
requirements
in
paragraphs
(
f)(
9)(
i)
through
(
v)
of
this
section
shall
apply.
(
i)
Each
emissions
unit
(
or
each
group
of
emissions
units)
that
existed
under
the
PAL
shall
comply
with
an
allowable
emission
limitation
under
a
revised
permit
established
according
to
the
procedures
in
paragraphs
(
f)(
9)(
i)(
A)
through
(
B)
of
this
section.
(
A)
Within
the
time
frame
specified
for
PAL
renewals
in
paragraph
(
f)(
10)(
ii)
of
this
section,
the
major
stationary
source
shall
submit
a
proposed
allowable
emission
limitation
for
each
emissions
unit
(
or
each
group
of
emissions
units,
if
such
a
distribution
is
more
appropriate
as
decided
by
the
reviewing
authority)
by
distributing
the
PAL
allowable
emissions
for
the
major
stationary
source
among
each
of
the
emissions
units
that
existed
under
the
PAL.
If
the
PAL
had
not
yet
been
adjusted
for
an
applicable
requirement
that
became
effective
during
the
PAL
effective
period,
as
required
under
paragraph
(
f)(
10)(
v)
of
this
section,
such
distribution
shall
be
made
as
if
the
PAL
had
been
adjusted.
(
B)
The
reviewing
authority
shall
decide
whether
and
how
the
PAL
allowable
emissions
will
be
distributed
and
issue
a
revised
permit
incorporating
allowable
limits
for
each
emissions
unit,
or
each
group
of
emissions
units,
as
the
reviewing
authority
determines
is
appropriate.
(
ii)
Each
emissions
unit(
s)
shall
comply
with
the
allowable
emission
limitation
on
a
12
month
rolling
basis.
The
reviewing
authority
may
approve
the
use
of
monitoring
systems
(
source
testing,
emission
factors,
etc.)
other
than
CEMS,
CERMS,
PEMS
or
CPMS
to
demonstrate
compliance
with
the
allowable
emission
limitation.
(
iii)
Until
the
reviewing
authority
issues
the
revised
permit
incorporating
allowable
limits
for
each
emissions
unit,
or
each
group
of
emissions
units,
as
required
under
paragraph
(
f)(
9)(
i)(
A)
of
this
section,
the
source
shall
continue
to
comply
with
a
source
wide,
multi
unit
emissions
cap
equivalent
to
the
level
of
the
PAL
emission
limitation.
(
iv)
Any
physical
change
or
change
in
the
method
of
operation
at
the
major
stationary
source
will
be
subject
to
the
nonattainment
major
NSR
requirements
if
such
change
meets
the
definition
of
major
modification
in
paragraph
(
a)(
1)(
v)
of
this
section.
(
v)
The
major
stationary
source
owner
or
operator
shall
continue
to
comply
with
any
State
or
Federal
applicable
requirements
(
BACT,
RACT,
NSPS,
etc.)
that
may
have
applied
either
during
the
PAL
effective
period
or
prior
to
the
PAL
effective
period
except
for
those
emission
limitations
that
had
been
established
pursuant
to
paragraph
(
a)(
5)(
ii)
of
this
section,
but
were
eliminated
by
the
PAL
in
accordance
with
the
provisions
in
paragraph
(
f)(
1)(
iii)(
C)
of
this
section.
(
10)
Renewal
of
a
PAL.
(
i)
The
reviewing
authority
shall
follow
the
procedures
specified
in
paragraph
(
f)(
5)
of
this
section
in
approving
any
request
to
renew
a
PAL
for
a
major
stationary
source,
and
shall
provide
both
the
proposed
PAL
level
and
a
written
rationale
for
the
proposed
PAL
level
to
the
public
for
review
and
comment.
During
such
public
review,
any
person
may
propose
a
PAL
level
for
the
source
for
consideration
by
the
reviewing
authority.
(
ii)
Application
deadline.
The
plan
shall
require
that
a
major
stationary
source
owner
or
operator
shall
submit
a
timely
application
to
the
reviewing
authority
to
request
renewal
of
a
PAL.
A
timely
application
is
one
that
is
submitted
at
least
6
months
prior
to,
but
not
earlier
than
18
months
from,
the
date
of
permit
expiration.
This
deadline
for
application
submittal
is
to
ensure
that
the
permit
will
not
expire
before
the
permit
is
renewed.
If
the
owner
or
operator
of
a
major
stationary
source
submits
a
complete
application
to
renew
the
PAL
within
this
time
period,
then
the
PAL
shall
continue
to
be
effective
until
the
revised
permit
with
the
renewed
PAL
is
issued.
(
iii)
Application
requirements.
The
application
to
renew
a
PAL
permit
shall
contain
the
information
required
in
paragraphs
(
f)(
10)(
iii)(
A)
through
(
D)
of
this
section.
(
A)
The
information
required
in
paragraphs
(
f)(
3)(
i)
through
(
iii)
of
this
section.
(
B)
A
proposed
PAL
level.
(
C)
The
sum
of
the
potential
to
emit
of
all
emissions
units
under
the
PAL
(
with
supporting
documentation).
(
D)
Any
other
information
the
owner
or
operator
wishes
the
reviewing
authority
to
consider
in
determining
the
appropriate
level
for
renewing
the
PAL.
(
iv)
PAL
adjustment.
In
determining
whether
and
how
to
adjust
the
PAL,
the
reviewing
authority
shall
consider
the
options
outlined
in
paragraphs
(
f)(
10)(
iv)(
A)
and
(
B)
of
this
section.
However,
in
no
case
may
any
such
adjustment
fail
to
comply
with
paragraph
(
f)(
10)(
iv)(
C)
of
this
section.
(
A)
If
the
emissions
level
calculated
in
accordance
with
paragraph
(
f)(
6)
of
this
section
is
equal
to
or
greater
than
80
percent
of
the
PAL
level,
the
reviewing
authority
may
renew
the
PAL
at
the
same
level
without
considering
the
factors
set
forth
in
paragraph
(
f)(
10)(
iv)(
B)
of
this
section;
or
(
B)
The
reviewing
authority
may
set
the
PAL
at
a
level
that
it
determines
to
be
more
representative
of
the
source's
baseline
actual
emissions,
or
that
it
determines
to
be
appropriate
considering
air
quality
needs,
advances
in
control
technology,
anticipated
economic
growth
in
the
area,
desire
to
reward
or
encourage
the
source's
voluntary
emissions
reductions,
or
other
factors
as
specifically
identified
by
the
reviewing
authority
in
its
written
rationale.
(
C)
Notwithstanding
paragraphs
(
f)(
10)(
iv)(
A)
and
(
B)
of
this
section,
(
1)
If
the
potential
to
emit
of
the
major
stationary
source
is
less
than
the
PAL,
the
reviewing
authority
shall
adjust
the
PAL
to
a
level
no
greater
than
the
potential
to
emit
of
the
source;
and
(
2)
The
reviewing
authority
shall
not
approve
a
renewed
PAL
level
higher
than
the
current
PAL,
unless
the
major
stationary
source
has
complied
with
the
provisions
of
paragraph
(
f)(
11)
of
this
section
(
increasing
a
PAL).
(
v)
If
the
compliance
date
for
a
State
or
Federal
requirement
that
applies
to
the
PAL
source
occurs
during
the
PAL
effective
period,
and
if
the
reviewing
authority
has
not
already
adjusted
for
such
requirement,
the
PAL
shall
be
adjusted
at
the
time
of
PAL
permit
renewal
or
title
V
permit
renewal,
whichever
occurs
first.
(
11)
Increasing
a
PAL
during
the
PAL
effective
period.
(
i)
The
plan
shall
require
that
the
reviewing
authority
may
increase
a
PAL
emission
limitation
only
if
the
major
stationary
source
complies
with
the
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/
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December
31,
2002
/
Rules
and
Regulations
provisions
in
paragraphs
(
f)(
11)(
i)(
A)
through
(
D)
of
this
section.
(
A)
The
owner
or
operator
of
the
major
stationary
source
shall
submit
a
complete
application
to
request
an
increase
in
the
PAL
limit
for
a
PAL
major
modification.
Such
application
shall
identify
the
emissions
unit(
s)
contributing
to
the
increase
in
emissions
so
as
to
cause
the
major
stationary
source's
emissions
to
equal
or
exceed
its
PAL.
(
B)
As
part
of
this
application,
the
major
stationary
source
owner
or
operator
shall
demonstrate
that
the
sum
of
the
baseline
actual
emissions
of
the
small
emissions
units,
plus
the
sum
of
the
baseline
actual
emissions
of
the
significant
and
major
emissions
units
assuming
application
of
BACT
equivalent
controls,
plus
the
sum
of
the
allowable
emissions
of
the
new
or
modified
emissions
unit(
s)
exceeds
the
PAL.
The
level
of
control
that
would
result
from
BACT
equivalent
controls
on
each
significant
or
major
emissions
unit
shall
be
determined
by
conducting
a
new
BACT
analysis
at
the
time
the
application
is
submitted,
unless
the
emissions
unit
is
currently
required
to
comply
with
a
BACT
or
LAER
requirement
that
was
established
within
the
preceding
10
years.
In
such
a
case,
the
assumed
control
level
for
that
emissions
unit
shall
be
equal
to
the
level
of
BACT
or
LAER
with
which
that
emissions
unit
must
currently
comply.
(
C)
The
owner
or
operator
obtains
a
major
NSR
permit
for
all
emissions
unit(
s)
identified
in
paragraph
(
f)(
11)(
i)(
A)
of
this
section,
regardless
of
the
magnitude
of
the
emissions
increase
resulting
from
them
(
that
is,
no
significant
levels
apply).
These
emissions
unit(
s)
shall
comply
with
any
emissions
requirements
resulting
from
the
nonattainment
major
NSR
program
process
(
for
example,
LAER),
even
though
they
have
also
become
subject
to
the
PAL
or
continue
to
be
subject
to
the
PAL.
(
D)
The
PAL
permit
shall
require
that
the
increased
PAL
level
shall
be
effective
on
the
day
any
emissions
unit
that
is
part
of
the
PAL
major
modification
becomes
operational
and
begins
to
emit
the
PAL
pollutant.
(
ii)
The
reviewing
authority
shall
calculate
the
new
PAL
as
the
sum
of
the
allowable
emissions
for
each
modified
or
new
emissions
unit,
plus
the
sum
of
the
baseline
actual
emissions
of
the
significant
and
major
emissions
units
(
assuming
application
of
BACT
equivalent
controls
as
determined
in
accordance
with
paragraph
(
f)(
11)(
i)(
B)),
plus
the
sum
of
the
baseline
actual
emissions
of
the
small
emissions
units.
(
iii)
The
PAL
permit
shall
be
revised
to
reflect
the
increased
PAL
level
pursuant
to
the
public
notice
requirements
of
paragraph
(
f)(
5)
of
this
section.
(
12)
Monitoring
requirements
for
PALs.
(
i)
General
Requirements.
(
A)
Each
PAL
permit
must
contain
enforceable
requirements
for
the
monitoring
system
that
accurately
determines
plantwide
emissions
of
the
PAL
pollutant
in
terms
of
mass
per
unit
of
time.
Any
monitoring
system
authorized
for
use
in
the
PAL
permit
must
be
based
on
sound
science
and
meet
generally
acceptable
scientific
procedures
for
data
quality
and
manipulation.
Additionally,
the
information
generated
by
such
system
must
meet
minimum
legal
requirements
for
admissibility
in
a
judicial
proceeding
to
enforce
the
PAL
permit.
(
B)
The
PAL
monitoring
system
must
employ
one
or
more
of
the
four
general
monitoring
approaches
meeting
the
minimum
requirements
set
forth
in
paragraphs
(
f)(
12)(
ii)(
A)
through
(
D)
of
this
section
and
must
be
approved
by
the
reviewing
authority.
(
C)
Notwithstanding
paragraph
(
f)(
12)(
i)(
B)
of
this
section,
you
may
also
employ
an
alternative
monitoring
approach
that
meets
paragraph
(
f)(
12)(
i)(
A)
of
this
section
if
approved
by
the
reviewing
authority.
(
D)
Failure
to
use
a
monitoring
system
that
meets
the
requirements
of
this
section
renders
the
PAL
invalid.
(
ii)
Minimum
Performance
Requirements
for
Approved
Monitoring
Approaches.
The
following
are
acceptable
general
monitoring
approaches
when
conducted
in
accordance
with
the
minimum
requirements
in
paragraphs
(
f)(
12)(
iii)
through
(
ix)
of
this
section:
(
A)
Mass
balance
calculations
for
activities
using
coatings
or
solvents;
(
B)
CEMS;
(
C)
CPMS
or
PEMS;
and
(
D)
Emission
Factors.
(
iii)
Mass
Balance
Calculations.
An
owner
or
operator
using
mass
balance
calculations
to
monitor
PAL
pollutant
emissions
from
activities
using
coating
or
solvents
shall
meet
the
following
requirements:
(
A)
Provide
a
demonstrated
means
of
validating
the
published
content
of
the
PAL
pollutant
that
is
contained
in
or
created
by
all
materials
used
in
or
at
the
emissions
unit;
(
B)
Assume
that
the
emissions
unit
emits
all
of
the
PAL
pollutant
that
is
contained
in
or
created
by
any
raw
material
or
fuel
used
in
or
at
the
emissions
unit,
if
it
cannot
otherwise
be
accounted
for
in
the
process;
and
(
C)
Where
the
vendor
of
a
material
or
fuel,
which
is
used
in
or
at
the
emissions
unit,
publishes
a
range
of
pollutant
content
from
such
material,
the
owner
or
operator
must
use
the
highest
value
of
the
range
to
calculate
the
PAL
pollutant
emissions
unless
the
reviewing
authority
determines
there
is
site
specific
data
or
a
site
specific
monitoring
program
to
support
another
content
within
the
range.
(
iv)
CEMS.
An
owner
or
operator
using
CEMS
to
monitor
PAL
pollutant
emissions
shall
meet
the
following
requirements:
(
A)
CEMS
must
comply
with
applicable
Performance
Specifications
found
in
40
CFR
part
60,
appendix
B;
and
(
B)
CEMS
must
sample,
analyze
and
record
data
at
least
every
15
minutes
while
the
emissions
unit
is
operating.
(
v)
CPMS
or
PEMS.
An
owner
or
operator
using
CPMS
or
PEMS
to
monitor
PAL
pollutant
emissions
shall
meet
the
following
requirements:
(
A)
The
CPMS
or
the
PEMS
must
be
based
on
current
site
specific
data
demonstrating
a
correlation
between
the
monitored
parameter(
s)
and
the
PAL
pollutant
emissions
across
the
range
of
operation
of
the
emissions
unit;
and
(
B)
Each
CPMS
or
PEMS
must
sample,
analyze,
and
record
data
at
least
every
15
minutes,
or
at
another
less
frequent
interval
approved
by
the
reviewing
authority,
while
the
emissions
unit
is
operating.
(
vi)
Emission
factors.
An
owner
or
operator
using
emission
factors
to
monitor
PAL
pollutant
emissions
shall
meet
the
following
requirements:
(
A)
All
emission
factors
shall
be
adjusted,
if
appropriate,
to
account
for
the
degree
of
uncertainty
or
limitations
in
the
factors'
development;
(
B)
The
emissions
unit
shall
operate
within
the
designated
range
of
use
for
the
emission
factor,
if
applicable;
and
(
C)
If
technically
practicable,
the
owner
or
operator
of
a
significant
emissions
unit
that
relies
on
an
emission
factor
to
calculate
PAL
pollutant
emissions
shall
conduct
validation
testing
to
determine
a
sitespecific
emission
factor
within
6
months
of
PAL
permit
issuance,
unless
the
reviewing
authority
determines
that
testing
is
not
required.
(
vii)
A
source
owner
or
operator
must
record
and
report
maximum
potential
emissions
without
considering
enforceable
emission
limitations
or
operational
restrictions
for
an
emissions
unit
during
any
period
of
time
that
there
is
no
monitoring
data,
unless
another
method
for
determining
emissions
during
such
periods
is
specified
in
the
PAL
permit.
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
(
viii)
Notwithstanding
the
requirements
in
paragraphs
(
f)(
12)(
iii)
through
(
vii)
of
this
section,
where
an
owner
or
operator
of
an
emissions
unit
cannot
demonstrate
a
correlation
between
the
monitored
parameter(
s)
and
the
PAL
pollutant
emissions
rate
at
all
operating
points
of
the
emissions
unit,
the
reviewing
authority
shall,
at
the
time
of
permit
issuance:
(
A)
Establish
default
value(
s)
for
determining
compliance
with
the
PAL
based
on
the
highest
potential
emissions
reasonably
estimated
at
such
operating
point(
s);
or
(
B)
Determine
that
operation
of
the
emissions
unit
during
operating
conditions
when
there
is
no
correlation
between
monitored
parameter(
s)
and
the
PAL
pollutant
emissions
is
a
violation
of
the
PAL.
(
ix)
Re
validation.
All
data
used
to
establish
the
PAL
pollutant
must
be
revalidated
through
performance
testing
or
other
scientifically
valid
means
approved
by
the
reviewing
authority.
Such
testing
must
occur
at
least
once
every
5
years
after
issuance
of
the
PAL.
(
13)
Recordkeeping
requirements.
(
i)
The
PAL
permit
shall
require
an
owner
or
operator
to
retain
a
copy
of
all
records
necessary
to
determine
compliance
with
any
requirement
of
paragraph
(
f)
of
this
section
and
of
the
PAL,
including
a
determination
of
each
emissions
unit's
12
month
rolling
total
emissions,
for
5
years
from
the
date
of
such
record.
(
ii)
The
PAL
permit
shall
require
an
owner
or
operator
to
retain
a
copy
of
the
following
records
for
the
duration
of
the
PAL
effective
period
plus
5
years:
(
A)
A
copy
of
the
PAL
permit
application
and
any
applications
for
revisions
to
the
PAL;
and
(
B)
Each
annual
certification
of
compliance
pursuant
to
title
V
and
the
data
relied
on
in
certifying
the
compliance.
(
14)
Reporting
and
notification
requirements.
The
owner
or
operator
shall
submit
semi
annual
monitoring
reports
and
prompt
deviation
reports
to
the
reviewing
authority
in
accordance
with
the
applicable
title
V
operating
permit
program.
The
reports
shall
meet
the
requirements
in
paragraphs
(
f)(
14)(
i)
through
(
iii).
(
i)
Semi
Annual
Report.
The
semiannual
report
shall
be
submitted
to
the
reviewing
authority
within
30
days
of
the
end
of
each
reporting
period.
This
report
shall
contain
the
information
required
in
paragraphs
(
f)(
14)(
i)(
A)
through
(
G)
of
this
section.
(
A)
The
identification
of
owner
and
operator
and
the
permit
number.
(
B)
Total
annual
emissions
(
tons/
year)
based
on
a
12
month
rolling
total
for
each
month
in
the
reporting
period
recorded
pursuant
to
paragraph
(
f)(
13)(
i)
of
this
section.
(
C)
All
data
relied
upon,
including,
but
not
limited
to,
any
Quality
Assurance
or
Quality
Control
data,
in
calculating
the
monthly
and
annual
PAL
pollutant
emissions.
(
D)
A
list
of
any
emissions
units
modified
or
added
to
the
major
stationary
source
during
the
preceding
6
month
period.
(
E)
The
number,
duration,
and
cause
of
any
deviations
or
monitoring
malfunctions
(
other
than
the
time
associated
with
zero
and
span
calibration
checks),
and
any
corrective
action
taken.
(
F)
A
notification
of
a
shutdown
of
any
monitoring
system,
whether
the
shutdown
was
permanent
or
temporary,
the
reason
for
the
shutdown,
the
anticipated
date
that
the
monitoring
system
will
be
fully
operational
or
replaced
with
another
monitoring
system,
and
whether
the
emissions
unit
monitored
by
the
monitoring
system
continued
to
operate,
and
the
calculation
of
the
emissions
of
the
pollutant
or
the
number
determined
by
method
included
in
the
permit,
as
provided
by
paragraph
(
f)(
12)(
vii)
of
this
section.
(
G)
A
signed
statement
by
the
responsible
official
(
as
defined
by
the
applicable
title
V
operating
permit
program)
certifying
the
truth,
accuracy,
and
completeness
of
the
information
provided
in
the
report.
(
ii)
Deviation
report.
The
major
stationary
source
owner
or
operator
shall
promptly
submit
reports
of
any
deviations
or
exceedance
of
the
PAL
requirements,
including
periods
where
no
monitoring
is
available.
A
report
submitted
pursuant
to
§
70.6(
a)(
3)(
iii)(
B)
of
this
chapter
shall
satisfy
this
reporting
requirement.
The
deviation
reports
shall
be
submitted
within
the
time
limits
prescribed
by
the
applicable
program
implementing
§
70.6(
a)(
3)(
iii)(
B)
of
this
chapter.
The
reports
shall
contain
the
following
information:
(
A)
The
identification
of
owner
and
operator
and
the
permit
number;
(
B)
The
PAL
requirement
that
experienced
the
deviation
or
that
was
exceeded;
(
C)
Emissions
resulting
from
the
deviation
or
the
exceedance;
and
(
D)
A
signed
statement
by
the
responsible
official
(
as
defined
by
the
applicable
title
V
operating
permit
program)
certifying
the
truth,
accuracy,
and
completeness
of
the
information
provided
in
the
report.
(
iii)
Re
validation
results.
The
owner
or
operator
shall
submit
to
the
reviewing
authority
the
results
of
any
re
validation
test
or
method
within
3
months
after
completion
of
such
test
or
method.
(
15)
Transition
requirements.
(
i)
No
reviewing
authority
may
issue
a
PAL
that
does
not
comply
with
the
requirements
in
paragraphs
(
f)(
1)
through
(
15)
of
this
section
after
the
Administrator
has
approved
regulations
incorporating
these
requirements
into
a
plan.
(
ii)
The
reviewing
authority
may
supersede
any
PAL
which
was
established
prior
to
the
date
of
approval
of
the
plan
by
the
Administrator
with
a
PAL
that
complies
with
the
requirements
of
paragraphs
(
f)(
1)
through
(
15)
of
this
section.
(
g)
If
any
provision
of
this
section,
or
the
application
of
such
provision
to
any
person
or
circumstance,
is
held
invalid,
the
remainder
of
this
section,
or
the
application
of
such
provision
to
persons
or
circumstances
other
than
those
as
to
which
it
is
held
invalid,
shall
not
be
affected
thereby.
5.
In
40
CFR
51.166(
b)(
1)(
i)(
b)
and
(
b)(
5),
remove
the
words
``
any
air
pollutant
subject
to
regulation
under
the
Act,''
and
add,
in
their
place,
the
words
``
a
regulated
NSR
pollutant.''
6.
In
addition
to
the
amendments
set
forth
above,
section
51.166
is
amended:
a.
By
revising
paragraph
(
a)(
1).
b.
By
revising
paragraph
(
a)(
6)(
i).
c.
By
adding
paragraph
(
a)(
7).
d.
By
revising
paragraphs
(
b)(
2)(
i)
and
(
ii).
e.
By
revising
paragraph
(
b)(
2)(
iii)(
h).
f.
By
adding
paragraph
(
b)(
2)(
iv).
g.
By
revising
paragraph
(
b)(
3)(
i).
h.
By
revising
paragraphs
(
b)(
3)(
iii)
and
(
iv).
i.
By
revising
paragraphs
(
b)(
3)(
vi)(
b)
and
(
c).
j.
By
adding
paragraph
(
b)(
3)(
vi)(
d).
k.
By
adding
paragraph
(
b)(
3)(
viii).
l.
By
revising
paragraphs
(
b)(
7)
and
(
8).
m.
By
revising
paragraph
(
b)(
13).
n.
By
revising
paragraph
(
b)(
21).
o.
By
removing
the
following
from
paragraph
(
b)(
23)(
i):
Asbestos:
0.007
tpy;
Beryllium:
0.0004
tpy;
Mercury:
0.1
tpy;
and
Vinyl
Chloride:
1
tpy.
p.
By
revising
paragraph
(
b)(
31).
q.
By
reserving
paragraph
(
b)(
32).
r.
By
adding
paragraphs
(
b)(
38)
through
(
52).
s.
By
revising
the
introductory
text
of
paragraph
(
i).
t.
By
removing
paragraphs
(
i)(
1)
through
(
3).
u.
By
re
designating
paragraphs
(
i)(
4)
through
(
12)
as
paragraphs
(
i)(
1)
through
(
9).
v.
By
revising
newly
redesignated
paragraphs
(
i)(
5)(
i)(
g)
through
(
j).
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Rules
and
Regulations
w.
By
removing
newly
redesignated
paragraphs
(
i)(
5)(
i)(
k)
through
(
m).
x.
By
adding
paragraphs
(
r)(
3)
through
(
7).
y.
By
adding
paragraphs
(
t)
through
(
x).
7.
In
addition
to
the
amendments
set
forth
above,
in
40
CFR
51.166,
remove
the
words
``
pollutant
subject
to
regulation
under
the
Act''
and
add,
in
their
place,
the
words
``
a
regulated
NSR
pollutant''
in
the
following
places:
a.
(
b)(
1)(
i)(
a);
c.
(
b)(
12);
d.
(
b)(
23)(
ii);
e.
newly
redesignated
(
i)(
4);
and
f.
(
j)(
2)
and
(
3).
The
revisions
and
additions
read
as
follows:
§
51.166
Prevention
of
significant
deterioration
of
air
quality.
(
a)(
1)
Plan
requirements.
In
accordance
with
the
policy
of
section
101(
b)(
1)
of
the
Act
and
the
purposes
of
section
160
of
the
Act,
each
applicable
State
Implementation
Plan
and
each
applicable
Tribal
Implementation
Plan
shall
contain
emission
limitations
and
such
other
measures
as
may
be
necessary
to
prevent
significant
deterioration
of
air
quality.
*
*
*
*
*
(
6)
*
*
*
(
i)
Any
State
required
to
revise
its
implementation
plan
by
reason
of
an
amendment
to
this
section,
including
any
amendment
adopted
simultaneously
with
this
paragraph
(
a)(
6)(
i),
shall
adopt
and
submit
such
plan
revision
to
the
Administrator
for
approval
no
later
than
three
years
after
such
amendment
is
published
in
the
Federal
Register.
*
*
*
*
*
(
7)
Applicability.
Each
plan
shall
contain
procedures
that
incorporate
the
requirements
in
paragraphs
(
a)(
7)(
i)
through
(
vi)
of
this
section.
(
i)
The
requirements
of
this
section
apply
to
the
construction
of
any
new
major
stationary
source
(
as
defined
in
paragraph
(
b)(
1)
of
this
section)
or
any
project
at
an
existing
major
stationary
source
in
an
area
designated
as
attainment
or
unclassifiable
under
sections
107(
d)(
1)(
A)(
ii)
or
(
iii)
of
the
Act.
(
ii)
The
requirements
of
paragraphs
(
j)
through
(
r)
of
this
section
apply
to
the
construction
of
any
new
major
stationary
source
or
the
major
modification
of
any
existing
major
stationary
source,
except
as
this
section
otherwise
provides.
(
iii)
No
new
major
stationary
source
or
major
modification
to
which
the
requirements
of
paragraphs
(
j)
through
(
r)(
5)
of
this
section
apply
shall
begin
actual
construction
without
a
permit
that
states
that
the
major
stationary
source
or
major
modification
will
meet
those
requirements.
(
iv)
Each
plan
shall
use
the
specific
provisions
of
paragraphs
(
a)(
7)(
iv)(
a)
through
(
f)
of
this
section.
Deviations
from
these
provisions
will
be
approved
only
if
the
State
specifically
demonstrates
that
the
submitted
provisions
are
more
stringent
than
or
at
least
as
stringent
in
all
respects
as
the
corresponding
provisions
in
paragraphs
(
a)(
7)(
iv)(
a)
through
(
f)
of
this
section.
(
a)
Except
as
otherwise
provided
in
paragraphs
(
a)(
7)(
v)
and
(
vi)
of
this
section,
and
consistent
with
the
definition
of
major
modification
contained
in
paragraph
(
b)(
2)
of
this
section,
a
project
is
a
major
modification
for
a
regulated
NSR
pollutant
if
it
causes
two
types
of
emissions
increases
a
significant
emissions
increase
(
as
defined
in
paragraph
(
b)(
39)
of
this
section),
and
a
significant
net
emissions
increase
(
as
defined
in
paragraphs
(
b)(
3)
and
(
b)(
23)
of
this
section).
The
project
is
not
a
major
modification
if
it
does
not
cause
a
significant
emissions
increase.
If
the
project
causes
a
significant
emissions
increase,
then
the
project
is
a
major
modification
only
if
it
also
results
in
a
significant
net
emissions
increase.
(
b)
The
procedure
for
calculating
(
before
beginning
actual
construction)
whether
a
significant
emissions
increase
(
i.
e.,
the
first
step
of
the
process)
will
occur
depends
upon
the
type
of
emissions
units
being
modified,
according
to
paragraphs
(
a)(
7)(
iv)(
c)
through
(
f)
of
this
section.
The
procedure
for
calculating
(
before
beginning
actual
construction)
whether
a
significant
net
emissions
increase
will
occur
at
the
major
stationary
source
(
i.
e.,
the
second
step
of
the
process)
is
contained
in
the
definition
in
paragraph
(
b)(
3)
of
this
section.
Regardless
of
any
such
preconstruction
projections,
a
major
modification
results
if
the
project
causes
a
significant
emissions
increase
and
a
significant
net
emissions
increase.
(
c)
Actual
to
projected
actual
applicability
test
for
projects
that
only
involve
existing
emissions
units.
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
is
projected
to
occur
if
the
sum
of
the
difference
between
the
projected
actual
emissions
(
as
defined
in
paragraph
(
b)(
40)
of
this
section)
and
the
baseline
actual
emissions
(
as
defined
in
paragraphs
(
b)(
47)(
i)
and
(
ii)
of
this
section)
for
each
existing
emissions
unit,
equals
or
exceeds
the
significant
amount
for
that
pollutant
(
as
defined
in
paragraph
(
b)(
23)
of
this
section).
(
d)
Actual
to
potential
test
for
projects
that
only
involve
construction
of
a
new
emissions
unit(
s).
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
is
projected
to
occur
if
the
sum
of
the
difference
between
the
potential
to
emit
(
as
defined
in
paragraph
(
b)(
4)
of
this
section)
from
each
new
emissions
unit
following
completion
of
the
project
and
the
baseline
actual
emissions
(
as
defined
in
paragraph
(
b)(
47)(
iii)
of
this
section)
of
these
units
before
the
project
equals
or
exceeds
the
significant
amount
for
that
pollutant
(
as
defined
in
paragraph
(
b)(
23)
of
this
section).
(
e)
Emission
test
for
projects
that
involve
Clean
Units.
For
a
project
that
will
be
constructed
and
operated
at
a
Clean
Unit
without
causing
the
emissions
unit
to
lose
its
Clean
Unit
designation,
no
emissions
increase
is
deemed
to
occur.
(
f)
Hybrid
test
for
projects
that
involve
multiple
types
of
emissions
units.
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
is
projected
to
occur
if
the
sum
of
the
emissions
increases
for
each
emissions
unit,
using
the
method
specified
in
paragraphs
(
a)(
7)(
iv)(
c)
through
(
e)
of
this
section
as
applicable
with
respect
to
each
emissions
unit,
for
each
type
of
emissions
unit
equals
or
exceeds
the
significant
amount
for
that
pollutant
(
as
defined
in
paragraph
(
b)(
23)
of
this
section).
For
example,
if
a
project
involves
both
an
existing
emissions
unit
and
a
Clean
Unit,
the
projected
increase
is
determined
by
summing
the
values
determined
using
the
method
specified
in
paragraph
(
a)(
7)(
iv)(
c)
of
this
section
for
the
existing
unit
and
determined
using
the
method
specified
in
paragraph
(
a)(
7)(
iv)(
e)
of
this
section
for
the
Clean
Unit.
(
v)
The
plan
shall
require
that
for
any
major
stationary
source
for
a
PAL
for
a
regulated
NSR
pollutant,
the
major
stationary
source
shall
comply
with
requirements
under
paragraph
(
w)
of
this
section.
(
vi)
The
plan
shall
require
that
an
owner
or
operator
undertaking
a
PCP
(
as
defined
in
paragraph
(
b)(
31)
of
this
section)
shall
comply
with
the
requirements
under
paragraph
(
v)
of
this
section.
*
*
*
*
*
(
b)
*
*
*
(
2)(
i)
Major
modification
means
any
physical
change
in
or
change
in
the
method
of
operation
of
a
major
stationary
source
that
would
result
in:
a
significant
emissions
increase
(
as
defined
in
paragraph
(
b)(
39)
of
this
section)
of
a
regulated
NSR
pollutant
(
as
defined
in
paragraph
(
b)(
49)
of
this
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2002
/
Rules
and
Regulations
section);
and
a
significant
net
emissions
increase
of
that
pollutant
from
the
major
stationary
source.
(
ii)
Any
significant
emissions
increase
(
as
defined
at
paragraph
(
b)(
39)
of
this
section)
from
any
emissions
units
or
net
emissions
increase
(
as
defined
at
paragraph
(
b)(
3)
of
this
section)
at
a
major
stationary
source
that
is
significant
for
volatile
organic
compounds
shall
be
considered
significant
for
ozone.
(
iii)
*
*
*
(
h)
The
addition,
replacement,
or
use
of
a
PCP,
as
defined
in
paragraph
(
b)(
31)
of
this
section,
at
an
existing
emissions
unit
meeting
the
requirements
of
paragraph
(
v)
of
this
section.
A
replacement
control
technology
must
provide
more
effective
emission
control
than
that
of
the
replaced
control
technology
to
qualify
for
this
exclusion.
*
*
*
*
*
(
iv)
This
definition
shall
not
apply
with
respect
to
a
particular
regulated
NSR
pollutant
when
the
major
stationary
source
is
complying
with
the
requirements
under
paragraph
(
w)
of
this
section
for
a
PAL
for
that
pollutant.
Instead,
the
definition
at
paragraph
(
w)(
2)(
viii)
of
this
section
shall
apply.
(
3)(
i)
Net
emissions
increase
means,
with
respect
to
any
regulated
NSR
pollutant
emitted
by
a
major
stationary
source,
the
amount
by
which
the
sum
of
the
following
exceeds
zero:
(
a)
The
increase
in
emissions
from
a
particular
physical
change
or
change
in
the
method
of
operation
at
a
stationary
source
as
calculated
pursuant
to
paragraph
(
a)(
7)(
iv)
of
this
section;
and
(
b)
Any
other
increases
and
decreases
in
actual
emissions
at
the
major
stationary
source
that
are
contemporaneous
with
the
particular
change
and
are
otherwise
creditable.
Baseline
actual
emissions
for
calculating
increases
and
decreases
under
this
paragraph
(
b)(
3)(
i)(
b)
shall
be
determined
as
provided
in
paragraph
(
b)(
47),
except
that
paragraphs
(
b)(
47)(
i)(
c)
and
(
b)(
47)(
ii)(
d)
of
this
section
shall
not
apply.
*
*
*
*
*
(
iii)
An
increase
or
decrease
in
actual
emissions
is
creditable
only
if:
(
a)
It
occurs
within
a
reasonable
period
(
to
be
specified
by
the
reviewing
authority);
and
(
b)
The
reviewing
authority
has
not
relied
on
it
in
issuing
a
permit
for
the
source
under
regulations
approved
pursuant
to
this
section,
which
permit
is
in
effect
when
the
increase
in
actual
emissions
from
the
particular
change
occurs;
and
(
c)
The
increase
or
decrease
in
emissions
did
not
occur
at
a
Clean
Unit,
except
as
provided
in
paragraphs
(
t)(
8)
and
(
u)(
10)
of
this
section.
(
iv)
An
increase
or
decrease
in
actual
emissions
of
sulfur
dioxide,
particulate
matter,
or
nitrogen
oxides
that
occurs
before
the
applicable
minor
source
baseline
date
is
creditable
only
if
it
is
required
to
be
considered
in
calculating
the
amount
of
maximum
allowable
increases
remaining
available.
*
*
*
*
*
(
vi)
*
*
*
(
b)
It
is
enforceable
as
a
practical
matter
at
and
after
the
time
that
actual
construction
on
the
particular
change
begins;
(
c)
It
has
approximately
the
same
qualitative
significance
for
public
health
and
welfare
as
that
attributed
to
the
increase
from
the
particular
change;
and
(
d)
The
decrease
in
actual
emissions
did
not
result
from
the
installation
of
add
on
control
technology
or
application
of
pollution
prevention
practices
that
were
relied
on
in
designating
an
emissions
unit
as
a
Clean
Unit
under
§
52.21(
y)
or
under
regulations
approved
pursuant
to
paragraph
(
u)
of
this
section
or
§
51.165(
d).
That
is,
once
an
emissions
unit
has
been
designated
as
a
Clean
Unit,
the
owner
or
operator
cannot
later
use
the
emissions
reduction
from
the
air
pollution
control
measures
that
the
Clean
Unit
designation
is
based
on
in
calculating
the
net
emissions
increase
for
another
emissions
unit
(
i.
e.,
must
not
use
that
reduction
in
a
``
netting
analysis''
for
another
emissions
unit).
However,
any
new
emissions
reductions
that
were
not
relied
upon
in
a
PCP
excluded
pursuant
to
paragraph
(
v)
of
this
section
or
for
the
Clean
Unit
designation
are
creditable
to
the
extent
they
meet
the
requirements
in
paragraph
(
v)(
6)(
iv)
of
this
section
for
the
PCP
and
paragraph
(
t)(
8)
or
(
u)(
10)
of
this
section
for
a
Clean
Unit.
*
*
*
*
*
(
viii)
Paragraph
(
b)(
21)(
ii)
of
this
section
shall
not
apply
for
determining
creditable
increases
and
decreases.
*
*
*
*
*
(
7)
Emissions
unit
means
any
part
of
a
stationary
source
that
emits
or
would
have
the
potential
to
emit
any
regulated
NSR
pollutant
and
includes
an
electric
utility
steam
generating
unit
as
defined
in
paragraph
(
b)(
30)
of
this
section.
For
purposes
of
this
section,
there
are
two
types
of
emissions
units
as
described
in
paragraphs
(
b)(
7)(
i)
and
(
ii)
of
this
section.
(
i)
A
new
emissions
unit
is
any
emissions
unit
that
is
(
or
will
be)
newly
constructed
and
that
has
existed
for
less
than
2
years
from
the
date
such
emissions
unit
first
operated.
(
ii)
An
existing
emissions
unit
is
any
emissions
unit
that
does
not
meet
the
requirements
in
paragraph
(
b)(
7)(
i)
of
this
section.
(
8)
Construction
means
any
physical
change
or
change
in
the
method
of
operation
(
including
fabrication,
erection,
installation,
demolition,
or
modification
of
an
emissions
unit)
that
would
result
in
a
change
in
emissions.
*
*
*
*
*
(
13)(
i)
Baseline
concentration
means
that
ambient
concentration
level
that
exists
in
the
baseline
area
at
the
time
of
the
applicable
minor
source
baseline
date.
A
baseline
concentration
is
determined
for
each
pollutant
for
which
a
minor
source
baseline
date
is
established
and
shall
include:
(
a)
The
actual
emissions,
as
defined
in
paragraph
(
b)(
21)
of
this
section,
representative
of
sources
in
existence
on
the
applicable
minor
source
baseline
date,
except
as
provided
in
paragraph
(
b)(
13)(
ii)
of
this
section;
(
b)
The
allowable
emissions
of
major
stationary
sources
that
commenced
construction
before
the
major
source
baseline
date,
but
were
not
in
operation
by
the
applicable
minor
source
baseline
date.
(
ii)
The
following
will
not
be
included
in
the
baseline
concentration
and
will
affect
the
applicable
maximum
allowable
increase(
s):
(
a)
Actual
emissions,
as
defined
in
paragraph
(
b)(
21)
of
this
section,
from
any
major
stationary
source
on
which
construction
commenced
after
the
major
source
baseline
date;
and
(
b)
Actual
emissions
increases
and
decreases,
as
defined
in
paragraph
(
b)(
21)
of
this
section,
at
any
stationary
source
occurring
after
the
minor
source
baseline
date.
*
*
*
*
*
(
21)(
i)
Actual
emissions
means
the
actual
rate
of
emissions
of
a
regulated
NSR
pollutant
from
an
emissions
unit,
as
determined
in
accordance
with
paragraphs
(
b)(
21)(
ii)
through
(
iv)
of
this
section,
except
that
this
definition
shall
not
apply
for
calculating
whether
a
significant
emissions
increase
has
occurred,
or
for
establishing
a
PAL
under
paragraph
(
w)
of
this
section.
Instead,
paragraphs
(
b)(
40)
and
(
b)(
47)
of
this
section
shall
apply
for
those
purposes.
(
ii)
In
general,
actual
emissions
as
of
a
particular
date
shall
equal
the
average
rate,
in
tons
per
year,
at
which
the
unit
actually
emitted
the
pollutant
during
a
consecutive
24
month
period
which
precedes
the
particular
date
and
which
is
representative
of
normal
source
operation.
The
reviewing
authority
shall
allow
the
use
of
a
different
time
period
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upon
a
determination
that
it
is
more
representative
of
normal
source
operation.
Actual
emissions
shall
be
calculated
using
the
unit's
actual
operating
hours,
production
rates,
and
types
of
materials
processed,
stored,
or
combusted
during
the
selected
time
period.
(
iii)
The
reviewing
authority
may
presume
that
source
specific
allowable
emissions
for
the
unit
are
equivalent
to
the
actual
emissions
of
the
unit.
(
iv)
For
any
emissions
unit
that
has
not
begun
normal
operations
on
the
particular
date,
actual
emissions
shall
equal
the
potential
to
emit
of
the
unit
on
that
date.
*
*
*
*
*
(
31)
Pollution
control
project
(
PCP)
means
any
activity,
set
of
work
practices
or
project
(
including
pollution
prevention
as
defined
under
paragraph
(
b)(
38)
of
this
section)
undertaken
at
an
existing
emissions
unit
that
reduces
emissions
of
air
pollutants
from
such
unit.
Such
qualifying
activities
or
projects
can
include
the
replacement
or
upgrade
of
an
existing
emissions
control
technology
with
a
more
effective
unit.
Other
changes
that
may
occur
at
the
source
are
not
considered
part
of
the
PCP
if
they
are
not
necessary
to
reduce
emissions
through
the
PCP.
Projects
listed
in
paragraphs
(
b)(
31)(
i)
through
(
vi)
of
this
section
are
presumed
to
be
environmentally
beneficial
pursuant
to
paragraph
(
v)(
2)(
i)
of
this
section.
Projects
not
listed
in
these
paragraphs
may
qualify
for
a
case
specific
PCP
exclusion
pursuant
to
the
requirements
of
paragraphs
(
v)(
2)
and
(
v)(
5)
of
this
section.
(
i)
Conventional
or
advanced
flue
gas
desulfurization
or
sorbent
injection
for
control
of
SO2.
(
ii)
Electrostatic
precipitators,
baghouses,
high
efficiency
multiclones,
or
scrubbers
for
control
of
particulate
matter
or
other
pollutants.
(
iii)
Flue
gas
recirculation,
low
NOX
burners
or
combustors,
selective
noncatalytic
reduction,
selective
catalytic
reduction,
low
emission
combustion
(
for
IC
engines),
and
oxidation/
absorption
catalyst
for
control
of
NOX.
(
iv)
Regenerative
thermal
oxidizers,
catalytic
oxidizers,
condensers,
thermal
incinerators,
hydrocarbon
combustion
flares,
biofiltration,
absorbers
and
adsorbers,
and
floating
roofs
for
storage
vessels
for
control
of
volatile
organic
compounds
or
hazardous
air
pollutants.
For
the
purpose
of
this
section,
``
hydrocarbon
combustion
flare''
means
either
a
flare
used
to
comply
with
an
applicable
NSPS
or
MACT
standard
(
including
uses
of
flares
during
startup,
shutdown,
or
malfunction
permitted
under
such
a
standard),
or
a
flare
that
serves
to
control
emissions
of
waste
streams
comprised
predominately
of
hydrocarbons
and
containing
no
more
than
230
mg/
dscm
hydrogen
sulfide.
(
v)
Activities
or
projects
undertaken
to
accommodate
switching
(
or
partially
switching)
to
an
inherently
less
polluting
fuel,
to
be
limited
to
the
following
fuel
switches:
(
a)
Switching
from
a
heavier
grade
of
fuel
oil
to
a
lighter
fuel
oil,
or
any
grade
of
oil
to
0.05
percent
sulfur
diesel
(
i.
e.,
from
a
higher
sulfur
content
#
2
fuel
or
from
#
6
fuel,
to
CA
0.05
percent
sulfur
#
2
diesel);
(
b)
Switching
from
coal,
oil,
or
any
solid
fuel
to
natural
gas,
propane,
or
gasified
coal;
(
c)
Switching
from
coal
to
wood,
excluding
construction
or
demolition
waste,
chemical
or
pesticide
treated
wood,
and
other
forms
of
``
unclean''
wood;
(
d)
Switching
from
coal
to
#
2
fuel
oil
(
0.5
percent
maximum
sulfur
content);
and
(
e)
Switching
from
high
sulfur
coal
to
low
sulfur
coal
(
maximum
1.2
percent
sulfur
content).
(
vi)
Activities
or
projects
undertaken
to
accommodate
switching
from
the
use
of
one
ozone
depleting
substance
(
ODS)
to
the
use
of
a
substance
with
a
lower
or
zero
ozone
depletion
potential
(
ODP),
including
changes
to
equipment
needed
to
accommodate
the
activity
or
project,
that
meet
the
requirements
of
paragraphs
(
b)(
31)(
vi)(
a)
and
(
b)
of
this
section.
(
a)
The
productive
capacity
of
the
equipment
is
not
increased
as
a
result
of
the
activity
or
project.
(
b)
The
projected
usage
of
the
new
substance
is
lower,
on
an
ODP
weighted
basis,
than
the
baseline
usage
of
the
replaced
ODS.
To
make
this
determination,
follow
the
procedure
in
paragraphs
(
b)(
31)(
vi)(
b)(
1)
through
(
4)
of
this
section.
(
1)
Determine
the
ODP
of
the
substances
by
consulting
40
CFR
part
82,
subpart
A,
appendices
A
and
B.
(
2)
Calculate
the
replaced
ODPweighted
amount
by
multiplying
the
baseline
actual
usage
(
using
the
annualized
average
of
any
24
consecutive
months
of
usage
within
the
past
10
years)
by
the
ODP
of
the
replaced
ODS.
(
3)
Calculate
the
projected
ODPweighted
amount
by
multiplying
the
projected
annual
usage
of
the
new
substance
by
its
ODP.
(
4)
If
the
value
calculated
in
paragraph
(
b)(
31)(
vi)(
b)(
2)
of
this
section
is
more
than
the
value
calculated
in
paragraph
(
b)(
31)(
vi)(
b)(
3)
of
this
section,
then
the
projected
use
of
the
new
substance
is
lower,
on
an
ODPweighted
basis,
than
the
baseline
usage
of
the
replaced
ODS.
(
32)
[
Reserved]
*
*
*
*
*
(
38)
Pollution
prevention
means
any
activity
that
through
process
changes,
product
reformulation
or
redesign,
or
substitution
of
less
polluting
raw
materials,
eliminates
or
reduces
the
release
of
air
pollutants
(
including
fugitive
emissions)
and
other
pollutants
to
the
environment
prior
to
recycling,
treatment,
or
disposal;
it
does
not
mean
recycling
(
other
than
certain
``
in
process
recycling''
practices),
energy
recovery,
treatment,
or
disposal.
(
39)
Significant
emissions
increase
means,
for
a
regulated
NSR
pollutant,
an
increase
in
emissions
that
is
significant
(
as
defined
in
paragraph
(
b)(
23)
of
this
section)
for
that
pollutant.
(
40)(
i)
Projected
actual
emissions
means
the
maximum
annual
rate,
in
tons
per
year,
at
which
an
existing
emissions
unit
is
projected
to
emit
a
regulated
NSR
pollutant
in
any
one
of
the
5
years
(
12
month
period)
following
the
date
the
unit
resumes
regular
operation
after
the
project,
or
in
any
one
of
the
10
years
following
that
date,
if
the
project
involves
increasing
the
emissions
unit's
design
capacity
or
its
potential
to
emit
that
regulated
NSR
pollutant,
and
full
utilization
of
the
unit
would
result
in
a
significant
emissions
increase,
or
a
significant
net
emissions
increase
at
the
major
stationary
source.
(
ii)
In
determining
the
projected
actual
emissions
under
paragraph
(
b)(
40)(
i)
of
this
section
(
before
beginning
actual
construction),
the
owner
or
operator
of
the
major
stationary
source:
(
a)
Shall
consider
all
relevant
information,
including
but
not
limited
to,
historical
operational
data,
the
company's
own
representations,
the
company's
expected
business
activity
and
the
company's
highest
projections
of
business
activity,
the
company's
filings
with
the
State
or
Federal
regulatory
authorities,
and
compliance
plans
under
the
approved
plan;
and
(
b)
Shall
include
fugitive
emissions
to
the
extent
quantifiable
and
emissions
associated
with
startups,
shutdowns,
and
malfunctions;
and
(
c)
Shall
exclude,
in
calculating
any
increase
in
emissions
that
results
from
the
particular
project,
that
portion
of
the
unit's
emissions
following
the
project
that
an
existing
unit
could
have
accommodated
during
the
consecutive
24
month
period
used
to
establish
the
baseline
actual
emissions
under
paragraph
(
b)(
47)
of
this
section
and
that
are
also
unrelated
to
the
particular
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project,
including
any
increased
utilization
due
to
product
demand
growth;
or,
(
d)
In
lieu
of
using
the
method
set
out
in
paragraphs
(
b)(
40)(
ii)(
a)
through
(
c)
of
this
section,
may
elect
to
use
the
emissions
unit's
potential
to
emit,
in
tons
per
year,
as
defined
under
paragraph
(
b)(
4)
of
this
section.
(
41)
Clean
Unit
means
any
emissions
unit
that
has
been
issued
a
major
NSR
permit
that
requires
compliance
with
BACT
or
LAER,
is
complying
with
such
BACT/
LAER
requirements,
and
qualifies
as
a
Clean
Unit
pursuant
to
regulations
approved
by
the
Administrator
in
accordance
with
paragraph
(
t)
of
this
section;
or
any
emissions
unit
that
has
been
designated
by
a
reviewing
authority
as
a
Clean
Unit,
based
on
the
criteria
in
paragraphs
(
u)(
3)(
i)
through
(
iv)
of
this
section,
using
a
planapproved
permitting
process;
or
any
emissions
unit
that
has
been
designated
as
a
Clean
Unit
by
the
Administrator
in
accordance
with
52.21
(
y)(
3)(
i)
through
(
iv)
of
this
chapter.
(
42)
Prevention
of
Significant
Deterioration
Program
(
PSD)
program
means
a
major
source
preconstruction
permit
program
that
has
been
approved
by
the
Administrator
and
incorporated
into
the
plan
to
implement
the
requirements
of
this
section,
or
the
program
in
§
52.21
of
this
chapter.
Any
permit
issued
under
such
a
program
is
a
major
NSR
permit.
(
43)
Continuous
emissions
monitoring
system
(
CEMS)
means
all
of
the
equipment
that
may
be
required
to
meet
the
data
acquisition
and
availability
requirements
of
this
section,
to
sample,
condition
(
if
applicable),
analyze,
and
provide
a
record
of
emissions
on
a
continuous
basis.
(
44)
Predictive
emissions
monitoring
system
(
PEMS)
means
all
of
the
equipment
necessary
to
monitor
process
and
control
device
operational
parameters
(
for
example,
control
device
secondary
voltages
and
electric
currents)
and
other
information
(
for
example,
gas
flow
rate,
O2
or
CO2
concentrations),
and
calculate
and
record
the
mass
emissions
rate
(
for
example,
lb/
hr)
on
a
continuous
basis.
(
45)
Continuous
parameter
monitoring
system
(
CPMS)
means
all
of
the
equipment
necessary
to
meet
the
data
acquisition
and
availability
requirements
of
this
section,
to
monitor
process
and
control
device
operational
parameters
(
for
example,
control
device
secondary
voltages
and
electric
currents)
and
other
information
(
for
example,
gas
flow
rate,
O2
or
CO2
concentrations),
and
to
record
average
operational
parameter
value(
s)
on
a
continuous
basis.
(
46)
Continuous
emissions
rate
monitoring
system
(
CERMS)
means
the
total
equipment
required
for
the
determination
and
recording
of
the
pollutant
mass
emissions
rate
(
in
terms
of
mass
per
unit
of
time).
(
47)
Baseline
actual
emissions
means
the
rate
of
emissions,
in
tons
per
year,
of
a
regulated
NSR
pollutant,
as
determined
in
accordance
with
paragraphs
(
b)(
47)(
i)
through
(
iv)
of
this
section.
(
i)
For
any
existing
electric
utility
steam
generating
unit,
baseline
actual
emissions
means
the
average
rate,
in
tons
per
year,
at
which
the
unit
actually
emitted
the
pollutant
during
any
consecutive
24
month
period
selected
by
the
owner
or
operator
within
the
5
year
period
immediately
preceding
when
the
owner
or
operator
begins
actual
construction
of
the
project.
The
reviewing
authority
shall
allow
the
use
of
a
different
time
period
upon
a
determination
that
it
is
more
representative
of
normal
source
operation.
(
a)
The
average
rate
shall
include
fugitive
emissions
to
the
extent
quantifiable,
and
emissions
associated
with
startups,
shutdowns,
and
malfunctions.
(
b)
The
average
rate
shall
be
adjusted
downward
to
exclude
any
noncompliant
emissions
that
occurred
while
the
source
was
operating
above
an
emission
limitation
that
was
legally
enforceable
during
the
consecutive
24
month
period.
(
c)
For
a
regulated
NSR
pollutant,
when
a
project
involves
multiple
emissions
units,
only
one
consecutive
24
month
period
must
be
used
to
determine
the
baseline
actual
emissions
for
the
emissions
units
being
changed.
A
different
consecutive
24
month
period
can
be
used
For
each
regulated
NSR
pollutant.
(
d)
The
average
rate
shall
not
be
based
on
any
consecutive
24
month
period
for
which
there
is
inadequate
information
for
determining
annual
emissions,
in
tons
per
year,
and
for
adjusting
this
amount
if
required
by
paragraph
(
b)(
47)(
i)(
b)
of
this
section.
(
ii)
For
an
existing
emissions
unit
(
other
than
an
electric
utility
steam
generating
unit),
baseline
actual
emissions
means
the
average
rate,
in
tons
per
year,
at
which
the
emissions
unit
actually
emitted
the
pollutant
during
any
consecutive
24
month
period
selected
by
the
owner
or
operator
within
the
10
year
period
immediately
preceding
either
the
date
the
owner
or
operator
begins
actual
construction
of
the
project,
or
the
date
a
complete
permit
application
is
received
by
the
reviewing
authority
for
a
permit
required
either
under
this
section
or
under
a
plan
approved
by
the
Administrator,
whichever
is
earlier,
except
that
the
10
year
period
shall
not
include
any
period
earlier
than
November
15,
1990.
(
a)
The
average
rate
shall
include
fugitive
emissions
to
the
extent
quantifiable,
and
emissions
associated
with
startups,
shutdowns,
and
malfunctions.
(
b)
The
average
rate
shall
be
adjusted
downward
to
exclude
any
noncompliant
emissions
that
occurred
while
the
source
was
operating
above
an
emission
limitation
that
was
legally
enforceable
during
the
consecutive
24
month
period.
(
c)
The
average
rate
shall
be
adjusted
downward
to
exclude
any
emissions
that
would
have
exceeded
an
emission
limitation
with
which
the
major
stationary
source
must
currently
comply,
had
such
major
stationary
source
been
required
to
comply
with
such
limitations
during
the
consecutive
24
month
period.
However,
if
an
emission
limitation
is
part
of
a
maximum
achievable
control
technology
standard
that
the
Administrator
proposed
or
promulgated
under
part
63
of
this
chapter,
the
baseline
actual
emissions
need
only
be
adjusted
if
the
State
has
taken
credit
for
such
emissions
reductions
in
an
attainment
demonstration
or
maintenance
plan
consistent
with
the
requirements
of
§
51.165(
a)(
3)(
ii)(
G).
(
d)
For
a
regulated
NSR
pollutant,
when
a
project
involves
multiple
emissions
units,
only
one
consecutive
24
month
period
must
be
used
to
determine
the
baseline
actual
emissions
for
the
emissions
units
being
changed.
A
different
consecutive
24
month
period
can
be
used
For
each
regulated
NSR
pollutant.
(
e)
The
average
rate
shall
not
be
based
on
any
consecutive
24
month
period
for
which
there
is
inadequate
information
for
determining
annual
emissions,
in
tons
per
year,
and
for
adjusting
this
amount
if
required
by
paragraphs
(
b)(
47)(
ii)(
b)
and
(
c)
of
this
section.
(
iii)
For
a
new
emissions
unit,
the
baseline
actual
emissions
for
purposes
of
determining
the
emissions
increase
that
will
result
from
the
initial
construction
and
operation
of
such
unit
shall
equal
zero;
and
thereafter,
for
all
other
purposes,
shall
equal
the
unit's
potential
to
emit.
(
iv)
For
a
PAL
for
a
stationary
source,
the
baseline
actual
emissions
shall
be
calculated
for
existing
electric
utility
steam
generating
units
in
accordance
with
the
procedures
contained
in
paragraph
(
b)(
47)(
i)
of
this
section,
for
other
existing
emissions
units
in
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Vol.
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251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
accordance
with
the
procedures
contained
in
paragraph
(
b)(
47)(
ii)
of
this
section,
and
for
a
new
emissions
unit
in
accordance
with
the
procedures
contained
in
paragraph
(
b)(
47)(
iii)
of
this
section.
(
48)
[
Reserved]
(
49)
Regulated
NSR
pollutant,
for
purposes
of
this
section,
means
the
following:
(
i)
Any
pollutant
for
which
a
national
ambient
air
quality
standard
has
been
promulgated
and
any
constituents
or
precursors
for
such
pollutants
identified
by
the
Administrator
(
e.
g.,
volatile
organic
compounds
are
precursors
for
ozone);
(
ii)
Any
pollutant
that
is
subject
to
any
standard
promulgated
under
section
111
of
the
Act;
(
iii)
Any
Class
I
or
II
substance
subject
to
a
standard
promulgated
under
or
established
by
title
VI
of
the
Act;
or
(
iv)
Any
pollutant
that
otherwise
is
subject
to
regulation
under
the
Act;
except
that
any
or
all
hazardous
air
pollutants
either
listed
in
section
112
of
the
Act
or
added
to
the
list
pursuant
to
section
112(
b)(
2)
of
the
Act,
which
have
not
been
delisted
pursuant
to
section
112(
b)(
3)
of
the
Act,
are
not
regulated
NSR
pollutants
unless
the
listed
hazardous
air
pollutant
is
also
regulated
as
a
constituent
or
precursor
of
a
general
pollutant
listed
under
section
108
of
the
Act.
(
50)
Reviewing
authority
means
the
State
air
pollution
control
agency,
local
agency,
other
State
agency,
Indian
tribe,
or
other
agency
authorized
by
the
Administrator
to
carry
out
a
permit
program
under
§
51.165
and
this
section,
or
the
Administrator
in
the
case
of
EPA
implemented
permit
programs
under
§
52.21
of
this
chapter.
(
51)
Project
means
a
physical
change
in,
or
change
in
method
of
operation
of,
an
existing
major
stationary
source.
(
52)
Lowest
achievable
emission
rate
(
LAER)
is
as
defined
in
§
51.165(
a)(
1)(
xiii).
*
*
*
*
*
(
i)
Exemptions.
*
*
*
*
*
(
5)
*
*
*
(
i)
*
*
*
(
g)
Fluorides
0.25
µ
g/
m3,
24
hour
average;
(
h)
Total
reduced
sulfur
10
µ
g/
m3,
1
hour
average
(
i)
Hydrogen
sulfide
0.2
µ
g/
m3,
1
hour
average;
(
j)
Reduced
sulfur
compounds
10
µ
g/
m3,
1
hour
average;
or
*
*
*
*
*
(
r)
*
*
*
(
3)
[
Reserved]
(
4)
[
Reserved]
(
5)
[
Reserved]
(
6)
Each
plan
shall
provide
that
the
following
specific
provisions
apply
to
projects
at
existing
emissions
units
at
a
major
stationary
source
(
other
than
projects
at
a
Clean
Unit
or
at
a
source
with
a
PAL)
in
circumstances
where
there
is
a
reasonable
possibility
that
a
project
that
is
not
a
part
of
a
major
modification
may
result
in
a
significant
emissions
increase
and
the
owner
or
operator
elects
to
use
the
method
specified
in
paragraphs
(
b)(
40)(
ii)(
a)
through
(
c)
of
this
section
for
calculating
projected
actual
emissions.
Deviations
from
these
provisions
will
be
approved
only
if
the
State
specifically
demonstrates
that
the
submitted
provisions
are
more
stringent
than
or
at
least
as
stringent
in
all
respects
as
the
corresponding
provisions
in
paragraphs
(
r)(
6)(
i)
through
(
v)
of
this
section.
(
i)
Before
beginning
actual
construction
of
the
project,
the
owner
or
operator
shall
document
and
maintain
a
record
of
the
following
information:
(
a)
A
description
of
the
project;
(
b)
Identification
of
the
emissions
unit(
s)
whose
emissions
of
a
regulated
NSR
pollutant
could
be
affected
by
the
project;
and
(
c)
A
description
of
the
applicability
test
used
to
determine
that
the
project
is
not
a
major
modification
for
any
regulated
NSR
pollutant,
including
the
baseline
actual
emissions,
the
projected
actual
emissions,
the
amount
of
emissions
excluded
under
paragraph
(
b)(
40)(
ii)(
c)
of
this
section
and
an
explanation
for
why
such
amount
was
excluded,
and
any
netting
calculations,
if
applicable.
(
ii)
If
the
emissions
unit
is
an
existing
electric
utility
steam
generating
unit,
before
beginning
actual
construction,
the
owner
or
operator
shall
provide
a
copy
of
the
information
set
out
in
paragraph
(
r)(
6)(
i)
of
this
section
to
the
reviewing
authority.
Nothing
in
this
paragraph
(
r)(
6)(
ii)
shall
be
construed
to
require
the
owner
or
operator
of
such
a
unit
to
obtain
any
determination
from
the
reviewing
authority
before
beginning
actual
construction.
(
iii)
The
owner
or
operator
shall
monitor
the
emissions
of
any
regulated
NSR
pollutant
that
could
increase
as
a
result
of
the
project
and
that
is
emitted
by
any
emissions
unit
identified
in
paragraph
(
r)(
6)(
i)(
b)
of
this
section;
and
calculate
and
maintain
a
record
of
the
annual
emissions,
in
tons
per
year
on
a
calendar
year
basis,
for
a
period
of
5
years
following
resumption
of
regular
operations
after
the
change,
or
for
a
period
of
10
years
following
resumption
of
regular
operations
after
the
change
if
the
project
increases
the
design
capacity
or
potential
to
emit
of
that
regulated
NSR
pollutant
at
such
emissions
unit.
(
iv)
If
the
unit
is
an
existing
electric
utility
steam
generating
unit,
the
owner
or
operator
shall
submit
a
report
to
the
reviewing
authority
within
60
days
after
the
end
of
each
year
during
which
records
must
be
generated
under
paragraph
(
r)(
6)(
iii)
of
this
section
setting
out
the
unit's
annual
emissions
during
the
calendar
year
that
preceded
submission
of
the
report.
(
v)
If
the
unit
is
an
existing
unit
other
than
an
electric
utility
steam
generating
unit,
the
owner
or
operator
shall
submit
a
report
to
the
reviewing
authority
if
the
annual
emissions,
in
tons
per
year,
from
the
project
identified
in
paragraph
(
r)(
6)(
i)
of
this
section,
exceed
the
baseline
actual
emissions
(
as
documented
and
maintained
pursuant
to
paragraph
(
r)(
6)(
i)(
c)
of
this
section)
by
a
significant
amount
(
as
defined
in
paragraph
(
b)(
23)
of
this
section)
for
that
regulated
NSR
pollutant,
and
if
such
emissions
differ
from
the
preconstruction
projection
as
documented
and
maintained
pursuant
to
paragraph
(
r)(
6)(
i)(
c)
of
this
section.
Such
report
shall
be
submitted
to
the
reviewing
authority
within
60
days
after
the
end
of
such
year.
The
report
shall
contain
the
following:
(
a)
The
name,
address
and
telephone
number
of
the
major
stationary
source;
(
b)
The
annual
emissions
as
calculated
pursuant
to
paragraph
(
r)(
6)(
iii)
of
this
section;
and
(
c)
Any
other
information
that
the
owner
or
operator
wishes
to
include
in
the
report
(
e.
g.,
an
explanation
as
to
why
the
emissions
differ
from
the
preconstruction
projection).
(
7)
Each
plan
shall
provide
that
the
owner
or
operator
of
the
source
shall
make
the
information
required
to
be
documented
and
maintained
pursuant
to
paragraph
(
r)(
6)
of
this
section
available
for
review
upon
request
for
inspection
by
the
reviewing
authority
or
the
general
public
pursuant
to
the
requirements
contained
in
§
70.4(
b)(
3)(
viii)
of
this
chapter.
*
*
*
*
*
(
t)
Clean
Unit
Test
for
emissions
units
that
are
subject
to
BACT
or
LAER.
The
plan
shall
provide
an
owner
or
operator
of
a
major
stationary
source
the
option
of
using
the
Clean
Unit
Test
to
determine
whether
emissions
increases
at
a
Clean
Unit
are
part
of
a
project
that
is
a
major
modification
according
to
the
provisions
in
paragraphs
(
t)(
1)
through
(
9)
of
this
section.
(
1)
Applicability.
The
provisions
of
this
paragraph
(
t)
apply
to
any
emissions
unit
for
which
the
reviewing
authority
has
issued
a
major
NSR
permit
within
the
past
10
years.
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
(
2)
General
provisions
for
Clean
Units.
The
provisions
in
paragraphs
(
t)(
2)(
i)
through
(
iv)
of
this
section
apply
to
a
Clean
Unit.
(
i)
Any
project
for
which
the
owner
or
operator
begins
actual
construction
after
the
effective
date
of
the
Clean
Unit
designation
(
as
determined
in
accordance
with
paragraph
(
t)(
4)
of
this
section)
and
before
the
expiration
date
(
as
determined
in
accordance
with
paragraph
(
t)(
5)
of
this
section)
will
be
considered
to
have
occurred
while
the
emissions
unit
was
a
Clean
Unit.
(
ii)
If
a
project
at
a
Clean
Unit
does
not
cause
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
were
adopted
in
conjunction
with
BACT
and
the
project
would
not
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT
determination
as
specified
in
paragraph
(
t)(
6)(
iv)
of
this
section,
the
emissions
unit
remains
a
Clean
Unit.
(
iii)
If
a
project
causes
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
were
adopted
in
conjunction
with
BACT
or
the
project
would
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT
determination
as
specified
in
paragraph
(
t)(
6)(
iv)
of
this
section,
then
the
emissions
unit
loses
its
designation
as
a
Clean
Unit
upon
issuance
of
the
necessary
permit
revisions
(
unless
the
unit
re
qualifies
as
a
Clean
Unit
pursuant
to
paragraph
(
t)(
3)(
iii)
of
this
section).
If
the
owner
or
operator
begins
actual
construction
on
the
project
without
first
applying
to
revise
the
emissions
unit's
permit,
the
Clean
Unit
designation
ends
immediately
prior
to
the
time
when
actual
construction
begins.
(
iv)
A
project
that
causes
an
emissions
unit
to
lose
its
designation
as
a
Clean
Unit
is
subject
to
the
applicability
requirements
of
paragraphs
(
a)(
7)(
iv)(
a)
through
(
d)
and
paragraph
(
a)(
7)(
iv)(
f)
of
this
section
as
if
the
emissions
unit
is
not
a
Clean
Unit.
(
3)
Qualifying
or
re
qualifying
to
use
the
Clean
Unit
Applicability
Test.
An
emissions
unit
automatically
qualifies
as
a
Clean
Unit
when
the
unit
meets
the
criteria
in
paragraphs
(
t)(
3)(
i)
and
(
ii)
of
this
section.
After
the
original
Clean
Unit
designation
expires
in
accordance
with
paragraph
(
t)(
5)
of
this
section
or
is
lost
pursuant
to
paragraph
(
t)(
2)(
iii)
of
this
section,
such
emissions
unit
may
re
qualify
as
a
Clean
Unit
under
either
paragraph
(
t)(
3)(
iii)
of
this
section,
or
under
the
Clean
Unit
provisions
in
paragraph
(
u)
of
this
section.
To
requalify
as
a
Clean
Unit
under
paragraph
(
t)(
3)(
iii)
of
this
section,
the
emissions
unit
must
obtain
a
new
major
NSR
permit
issued
through
the
applicable
PSD
program
and
meet
all
the
criteria
in
paragraph
(
t)(
3)(
iii)
of
this
section.
The
Clean
Unit
designation
applies
individually
for
each
pollutant
emitted
by
the
emissions
unit.
(
i)
Permitting
requirement.
The
emissions
unit
must
have
received
a
major
NSR
permit
within
the
past
10
years.
The
owner
or
operator
must
maintain
and
be
able
to
provide
information
that
would
demonstrate
that
this
permitting
requirement
is
met.
(
ii)
Qualifying
air
pollution
control
technologies.
Air
pollutant
emissions
from
the
emissions
unit
must
be
reduced
through
the
use
of
air
pollution
control
technology
(
which
includes
pollution
prevention
as
defined
under
paragraph
(
b)(
38)
of
this
section
or
work
practices)
that
meets
both
the
following
requirements
in
paragraphs
(
t)(
3)(
ii)(
a)
and
(
b)
of
this
section.
(
a)
The
control
technology
achieves
the
BACT
or
LAER
level
of
emissions
reductions
as
determined
through
issuance
of
a
major
NSR
permit
within
the
past
10
years.
However,
the
emissions
unit
is
not
eligible
for
the
Clean
Unit
designation
if
the
BACT
determination
resulted
in
no
requirement
to
reduce
emissions
below
the
level
of
a
standard,
uncontrolled,
new
emissions
unit
of
the
same
type.
(
b)
The
owner
or
operator
made
an
investment
to
install
the
control
technology.
For
the
purpose
of
this
determination,
an
investment
includes
expenses
to
research
the
application
of
a
pollution
prevention
technique
to
the
emissions
unit
or
expenses
to
apply
a
pollution
prevention
technique
to
an
emissions
unit.
(
iii)
Re
qualifying
for
the
Clean
Unit
designation.
The
emissions
unit
must
obtain
a
new
major
NSR
permit
that
requires
compliance
with
the
currentday
BACT
(
or
LAER),
and
the
emissions
unit
must
meet
the
requirements
in
paragraphs
(
t)(
3)(
i)
and
(
t)(
3)(
ii)
of
this
section.
(
4)
Effective
date
of
the
Clean
Unit
designation.
The
effective
date
of
an
emissions
unit's
Clean
Unit
designation
(
that
is,
the
date
on
which
the
owner
or
operator
may
begin
to
use
the
Clean
Unit
Test
to
determine
whether
a
project
at
the
emissions
unit
is
a
major
modification)
is
determined
according
to
the
applicable
paragraph
(
t)(
4)(
i)
or
(
t)(
4)(
ii)
of
this
section.
(
i)
Original
Clean
Unit
designation,
and
emissions
units
that
re
qualify
as
Clean
Units
by
implementing
a
new
control
technology
to
meet
current
day
BACT.
The
effective
date
is
the
date
the
emissions
unit's
air
pollution
control
technology
is
placed
into
service,
or
3
years
after
the
issuance
date
of
the
major
NSR
permit,
whichever
is
earlier,
but
no
sooner
than
the
date
that
provisions
for
the
Clean
Unit
applicability
test
are
approved
by
the
Administrator
for
incorporation
into
the
plan
and
become
effective
for
the
State
in
which
the
unit
is
located.
(
ii)
Emissions
Units
that
re
qualify
for
the
Clean
Unit
designation
using
an
existing
control
technology.
The
effective
date
is
the
date
the
new,
major
NSR
permit
is
issued.
(
5)
Clean
Unit
expiration.
An
emissions
unit's
Clean
Unit
designation
expires
(
that
is,
the
date
on
which
the
owner
or
operator
may
no
longer
use
the
Clean
Unit
Test
to
determine
whether
a
project
affecting
the
emissions
unit
is,
or
is
part
of,
a
major
modification)
according
to
the
applicable
paragraph
(
t)(
5)(
i)
or
(
ii)
of
this
section.
(
i)
Original
Clean
Unit
designation,
and
emissions
units
that
re
qualify
by
implementing
new
control
technology
to
meet
current
day
BACT.
For
any
emissions
unit
that
automatically
qualifies
as
a
Clean
Unit
under
paragraphs
(
t)(
3)(
i)
and
(
ii)
of
this
section
or
re
qualifies
by
implementing
new
control
technology
to
meet
currentday
BACT
under
paragraph
(
t)(
3)(
iii)
of
this
section,
the
Clean
Unit
designation
expires
10
years
after
the
effective
date,
or
the
date
the
equipment
went
into
service,
whichever
is
earlier;
or,
it
expires
at
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
the
Clean
Unit
designation
in
paragraph
(
t)(
7)
of
this
section.
(
ii)
Emissions
units
that
re
qualify
for
the
Clean
Unit
designation
using
an
existing
control
technology.
For
any
emissions
unit
that
re
qualifies
as
a
Clean
Unit
under
paragraph
(
t)(
3)(
iii)
of
this
section
using
an
existing
control
technology,
the
Clean
Unit
designation
expires
10
years
after
the
effective
date;
or,
it
expires
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
the
Clean
Unit
designation
in
paragraph
(
t)(
7)
of
this
section.
(
6)
Required
title
V
permit
content
for
a
Clean
Unit.
After
the
effective
date
of
the
Clean
Unit
designation,
and
in
accordance
with
the
provisions
of
the
applicable
title
V
permit
program
under
part
70
or
part
71
of
this
chapter,
but
no
later
than
when
the
title
V
permit
is
renewed,
the
title
V
permit
for
the
major
stationary
source
must
include
the
following
terms
and
conditions
related
to
the
Clean
Unit
in
paragraphs
(
t)(
6)(
i)
through
(
vi)
of
this
section.
(
i)
A
statement
indicating
that
the
emissions
unit
qualifies
as
a
Clean
Unit
and
identifying
the
pollutant(
s)
for
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
which
this
Clean
Unit
designation
applies.
(
ii)
The
effective
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
Clean
Unit
designation
is
initially
recorded
in
the
title
V
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
the
permit
must
describe
the
event
that
will
determine
the
effective
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
effective
date
is
determined,
the
owner
or
operator
must
notify
the
reviewing
authority
of
the
exact
date.
This
specific
effective
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iii)
The
expiration
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
Clean
Unit
designation
is
initially
recorded
into
the
title
V
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
then
the
permit
must
describe
the
event
that
will
determine
the
expiration
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
expiration
date
is
determined,
the
owner
or
operator
must
notify
the
reviewing
authority
of
the
exact
date.
The
expiration
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iv)
All
emission
limitations
and
work
practice
requirements
adopted
in
conjunction
with
BACT,
and
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT
determination
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
v)
Monitoring,
recordkeeping,
and
reporting
requirements
as
necessary
to
demonstrate
that
the
emissions
unit
continues
to
meet
the
criteria
for
maintaining
the
Clean
Unit
designation.
(
See
paragraph
(
t)(
7)
of
this
section.)
(
vi)
Terms
reflecting
the
owner
or
operator's
duties
to
maintain
the
Clean
Unit
designation
and
the
consequences
of
failing
to
do
so,
as
presented
in
paragraph
(
t)(
7)
of
this
section.
(
7)
Maintaining
the
Clean
Unit
designation.
To
maintain
the
Clean
Unit
designation,
the
owner
or
operator
must
conform
to
all
the
restrictions
listed
in
paragraphs
(
t)(
7)(
i)
through
(
iii)
of
this
section.
This
paragraph
(
t)(
7)
applies
independently
to
each
pollutant
for
which
the
emissions
unit
has
the
Clean
Unit
designation.
That
is,
failing
to
conform
to
the
restrictions
for
one
pollutant
affects
the
Clean
Unit
designation
only
for
that
pollutant.
(
i)
The
Clean
Unit
must
comply
with
the
emission
limitation(
s)
and/
or
work
practice
requirements
adopted
in
conjunction
with
the
BACT
that
is
recorded
in
the
major
NSR
permit,
and
subsequently
reflected
in
the
title
V
permit.
The
owner
or
operator
may
not
make
a
physical
change
in
or
change
in
the
method
of
operation
of
the
Clean
Unit
that
causes
the
emissions
unit
to
function
in
a
manner
that
is
inconsistent
with
the
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT
determination
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
ii)
The
Clean
Unit
must
comply
with
any
terms
and
conditions
in
the
title
V
permit
related
to
the
unit's
Clean
Unit
designation.
(
iii)
The
Clean
Unit
must
continue
to
control
emissions
using
the
specific
air
pollution
control
technology
that
was
the
basis
for
its
Clean
Unit
designation.
If
the
emissions
unit
or
control
technology
is
replaced,
then
the
Clean
Unit
designation
ends.
(
8)
Netting
at
Clean
Units.
Emissions
changes
that
occur
at
a
Clean
Unit
must
not
be
included
in
calculating
a
significant
net
emissions
increase
(
that
is,
must
not
be
used
in
a
``
netting
analysis''),
unless
such
use
occurs
before
the
effective
date
of
the
Clean
Unit
designation,
or
after
the
Clean
Unit
designation
expires;
or,
unless
the
emissions
unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit.
However,
if
the
Clean
Unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit,
then
the
owner
or
operator
may
generate
a
credit
for
the
difference
between
the
level
that
qualified
the
unit
as
a
Clean
Unit
and
the
new
emission
limitation
if
such
reductions
are
surplus,
quantifiable,
and
permanent.
For
purposes
of
generating
offsets,
the
reductions
must
also
be
federally
enforceable.
For
purposes
of
determining
creditable
net
emissions
increases
and
decreases,
the
reductions
must
also
be
enforceable
as
a
practical
matter.
(
9)
Effect
of
redesignation
on
the
Clean
Unit
designation.
The
Clean
Unit
designation
of
an
emissions
unit
is
not
affected
by
redesignation
of
the
attainment
status
of
the
area
in
which
it
is
located.
That
is,
if
a
Clean
Unit
is
located
in
an
attainment
area
and
the
area
is
redesignated
to
nonattainment,
its
Clean
Unit
designation
is
not
affected.
Similarly,
redesignation
from
nonattainment
to
attainment
does
not
affect
the
Clean
Unit
designation.
However,
if
an
existing
Clean
Unit
designation
expires,
it
must
re
qualify
under
the
requirements
that
are
currently
applicable
in
the
area.
(
u)
Clean
Unit
provisions
for
emissions
units
that
achieve
an
emission
limitation
comparable
to
BACT.
The
plan
shall
provide
an
owner
or
operator
of
a
major
stationary
source
the
option
of
using
the
Clean
Unit
Test
to
determine
whether
emissions
increases
at
a
Clean
Unit
are
part
of
a
project
that
is
a
major
modification
according
to
the
provisions
in
paragraphs
(
u)(
1)
through
(
11)
of
this
section.
(
1)
Applicability.
The
provisions
of
this
paragraph
(
u)
apply
to
emissions
units
which
do
not
qualify
as
Clean
Units
under
paragraph
(
t)
of
this
section,
but
which
are
achieving
a
level
of
emissions
control
comparable
to
BACT,
as
determined
by
the
reviewing
authority
in
accordance
with
this
paragraph
(
u).
(
2)
General
provisions
for
Clean
Units.
The
provisions
in
paragraphs
(
u)(
2)(
i)
through
(
iv)
of
this
section
apply
to
a
Clean
Unit.
(
i)
Any
project
for
which
the
owner
or
operator
begins
actual
construction
after
the
effective
date
of
the
Clean
Unit
designation
(
as
determined
in
accordance
with
paragraph
(
u)(
5)
of
this
section)
and
before
the
expiration
date
(
as
determined
in
accordance
with
paragraph
(
u)(
6)
of
this
section)
will
be
considered
to
have
occurred
while
the
emissions
unit
was
a
Clean
Unit.
(
ii)
If
a
project
at
a
Clean
Unit
does
not
cause
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
have
been
determined
(
pursuant
to
paragraph
(
u)(
4)
of
this
section)
to
be
comparable
to
BACT,
and
the
project
would
not
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
determining
that
the
emissions
unit's
control
technology
achieves
a
level
of
emissions
control
comparable
to
BACT
as
specified
in
paragraph
(
u)(
8)(
iv)
of
this
section,
the
emissions
unit
remains
a
Clean
Unit.
(
iii)
If
a
project
causes
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
have
been
determined
(
pursuant
to
paragraph
(
u)(
4)
of
this
section)
to
be
comparable
to
BACT,
or
the
project
would
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
determining
that
the
emissions
unit's
control
technology
achieves
a
level
of
emissions
control
comparable
to
BACT
as
specified
in
paragraph
(
u)(
8)(
iv)
of
this
section,
then
the
emissions
unit
loses
its
designation
as
a
Clean
Unit
upon
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/
Rules
and
Regulations
issuance
of
the
necessary
permit
revisions
(
unless
the
unit
re
qualifies
as
a
Clean
Unit
pursuant
to
paragraph
(
u)(
3)(
iv)
of
this
section).
If
the
owner
or
operator
begins
actual
construction
on
the
project
without
first
applying
to
revise
the
emissions
unit's
permit,
the
Clean
Unit
designation
ends
immediately
prior
to
the
time
when
actual
construction
begins.
(
iv)
A
project
that
causes
an
emissions
unit
to
lose
its
designation
as
a
Clean
Unit
is
subject
to
the
applicability
requirements
of
paragraphs
(
a)(
7)(
iv)(
a)
through
(
d)
and
paragraph
(
a)(
7)(
iv)(
f)
of
this
section
as
if
the
emissions
unit
is
not
a
Clean
Unit.
(
3)
Qualifying
or
re
qualifying
to
use
the
Clean
Unit
applicability
test.
An
emissions
unit
qualifies
as
a
Clean
Unit
when
the
unit
meets
the
criteria
in
paragraphs
(
u)(
3)(
i)
through
(
iii)
of
this
section.
After
the
original
Clean
Unit
designation
expires
in
accordance
with
paragraph
(
u)(
6)
of
this
section
or
is
lost
pursuant
to
paragraph
(
u)(
2)(
iii)
of
this
section,
such
emissions
unit
may
requalify
as
a
Clean
Unit
under
either
paragraph
(
u)(
3)(
iv)
of
this
section,
or
under
the
Clean
Unit
provisions
in
paragraph
(
t)
of
this
section.
To
requalify
as
a
Clean
Unit
under
paragraph
(
u)(
3)(
iv)
of
this
section,
the
emissions
unit
must
obtain
a
new
permit
issued
pursuant
to
the
requirements
in
paragraphs
(
u)(
7)
and
(
8)
of
this
section
and
meet
all
the
criteria
in
paragraph
(
u)(
3)(
iv)
of
this
section.
The
reviewing
authority
will
make
a
separate
Clean
Unit
designation
for
each
pollutant
emitted
by
the
emissions
unit
for
which
the
emissions
unit
qualifies
as
a
Clean
Unit.
(
i)
Qualifying
air
pollution
control
technologies.
Air
pollutant
emissions
from
the
emissions
unit
must
be
reduced
through
the
use
of
air
pollution
control
technology
(
which
includes
pollution
prevention
as
defined
under
paragraph
(
b)(
38)
or
work
practices)
that
meets
both
the
following
requirements
in
paragraphs
(
u)(
3)(
i)(
a)
and
(
b)
of
this
section.
(
a)
The
owner
or
operator
has
demonstrated
that
the
emissions
unit's
control
technology
is
comparable
to
BACT
according
to
the
requirements
of
paragraph
(
u)(
4)
of
this
section.
However,
the
emissions
unit
is
not
eligible
for
the
Clean
Unit
designation
if
its
emissions
are
not
reduced
below
the
level
of
a
standard,
uncontrolled
emissions
unit
of
the
same
type
(
e.
g.,
if
the
BACT
determinations
to
which
it
is
compared
have
resulted
in
a
determination
that
no
control
measures
are
required).
(
b)
The
owner
or
operator
made
an
investment
to
install
the
control
technology.
For
the
purpose
of
this
determination,
an
investment
includes
expenses
to
research
the
application
of
a
pollution
prevention
technique
to
the
emissions
unit
or
to
retool
the
unit
to
apply
a
pollution
prevention
technique.
(
ii)
Impact
of
emissions
from
the
unit.
The
reviewing
authority
must
determine
that
the
allowable
emissions
from
the
emissions
unit
will
not
cause
or
contribute
to
a
violation
of
any
national
ambient
air
quality
standard
or
PSD
increment,
or
adversely
impact
an
air
quality
related
value
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
and
for
which
information
is
available
to
the
general
public.
(
iii)
Date
of
installation.
An
emissions
unit
may
qualify
as
a
Clean
Unit
even
if
the
control
technology,
on
which
the
Clean
Unit
designation
is
based,
was
installed
before
the
effective
date
of
plan
requirements
to
implement
the
requirements
of
this
paragraph
(
u)(
3)(
iii).
However,
for
such
emissions
units,
the
owner
or
operator
must
apply
for
the
Clean
Unit
designation
within
2
years
after
the
plan
requirements
become
effective.
For
technologies
installed
after
the
plan
requirements
become
effective,
the
owner
or
operator
must
apply
for
the
Clean
Unit
designation
at
the
time
the
control
technology
is
installed.
(
iv)
Re
qualifying
as
a
Clean
Unit.
The
emissions
unit
must
obtain
a
new
permit
(
pursuant
to
requirements
in
paragraphs
(
u)(
7)
and
(
8)
of
this
section)
that
demonstrates
that
the
emissions
unit's
control
technology
is
achieving
a
level
of
emission
control
comparable
to
current
day
BACT,
and
the
emissions
unit
must
meet
the
requirements
in
paragraphs
(
u)(
3)(
i)(
a)
and
(
u)(
3)(
ii)
of
this
section.
(
4)
Demonstrating
control
effectiveness
comparable
to
BACT.
The
owner
or
operator
may
demonstrate
that
the
emissions
unit's
control
technology
is
comparable
to
BACT
for
purposes
of
paragraph
(
u)(
3)(
i)
of
this
section
according
to
either
paragraph
(
u)(
4)(
i)
or
(
ii)
of
this
section.
Paragraph
(
u)(
4)(
iii)
of
this
section
specifies
the
time
for
making
this
comparison.
(
i)
Comparison
to
previous
BACT
and
LAER
determinations.
The
Administrator
maintains
an
on
line
data
base
of
previous
determinations
of
RACT,
BACT,
and
LAER
in
the
RACT/
BACT/
LAER
Clearinghouse
(
RBLC).
The
emissions
unit's
control
technology
is
presumed
to
be
comparable
to
BACT
if
it
achieves
an
emission
limitation
that
is
equal
to
or
better
than
the
average
of
the
emission
limitations
achieved
by
all
the
sources
for
which
a
BACT
or
LAER
determination
has
been
made
within
the
preceding
5
years
and
entered
into
the
RBLC,
and
for
which
it
is
technically
feasible
to
apply
the
BACT
or
LAER
control
technology
to
the
emissions
unit.
The
reviewing
authority
shall
also
compare
this
presumption
to
any
additional
BACT
or
LAER
determinations
of
which
it
is
aware,
and
shall
consider
any
information
on
achieved
in
practice
pollution
control
technologies
provided
during
the
public
comment
period,
to
determine
whether
any
presumptive
determination
that
the
control
technology
is
comparable
to
BACT
is
correct.
(
ii)
The
substantially
as
effective
test.
The
owner
or
operator
may
demonstrate
that
the
emissions
unit's
control
technology
is
substantially
as
effective
as
BACT.
In
addition,
any
other
person
may
present
evidence
related
to
whether
the
control
technology
is
substantially
as
effective
as
BACT
during
the
public
participation
process
required
under
paragraph
(
u)(
7)
of
this
section.
The
reviewing
authority
shall
consider
such
evidence
on
a
case
by
case
basis
and
determine
whether
the
emissions
unit's
air
pollution
control
technology
is
substantially
as
effective
as
BACT.
(
iii)
Time
of
comparison.
(
a)
Emissions
units
with
control
technologies
that
are
installed
before
the
effective
date
of
plan
requirements
implementing
this
paragraph.
The
owner
or
operator
of
an
emissions
unit
whose
control
technology
is
installed
before
the
effective
date
of
plan
requirements
implementing
this
paragraph
(
u)
may,
at
its
option,
either
demonstrate
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
the
BACT
requirements
that
applied
at
the
time
the
control
technology
was
installed,
or
demonstrate
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
current
day
BACT
requirements.
The
expiration
date
of
the
Clean
Unit
designation
will
depend
on
which
option
the
owner
or
operator
uses,
as
specified
in
paragraph
(
u)(
6)
of
this
section.
(
b)
Emissions
units
with
control
technologies
that
are
installed
after
the
effective
date
of
plan
requirements
implementing
this
paragraph.
The
owner
or
operator
must
demonstrate
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
current
day
BACT
requirements.
(
5)
Effective
date
of
the
Clean
Unit
designation.
The
effective
date
of
an
emissions
unit's
Clean
Unit
designation
(
that
is,
the
date
on
which
the
owner
or
operator
may
begin
to
use
the
Clean
Unit
Test
to
determine
whether
a
project
involving
the
emissions
unit
is
a
major
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31,
2002
/
Rules
and
Regulations
modification)
is
the
date
that
the
permit
required
by
paragraph
(
u)(
7)
of
this
section
is
issued
or
the
date
that
the
emissions
unit's
air
pollution
control
technology
is
placed
into
service,
whichever
is
later.
(
6)
Clean
Unit
expiration.
If
the
owner
or
operator
demonstrates
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
the
BACT
requirements
that
applied
at
the
time
the
control
technology
was
installed,
then
the
Clean
Unit
designation
expires
10
years
from
the
date
that
the
control
technology
was
installed.
For
all
other
emissions
units,
the
Clean
Unit
designation
expires
10
years
from
the
effective
date
of
the
Clean
Unit
designation,
as
determined
according
to
paragraph
(
u)(
5)
of
this
section.
In
addition,
for
all
emissions
units,
the
Clean
Unit
designation
expires
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
the
Clean
Unit
designation
in
paragraph
(
u)(
9)
of
this
section.
(
7)
Procedures
for
designating
emissions
units
as
Clean
Units.
The
reviewing
authority
shall
designate
an
emissions
unit
a
Clean
Unit
only
by
issuing
a
permit
through
a
permitting
program
that
has
been
approved
by
the
Administrator
and
that
conforms
with
the
requirements
of
§
§
51.160
through
51.164
of
this
chapter,
including
requirements
for
public
notice
of
the
proposed
Clean
Unit
designation
and
opportunity
for
public
comment.
Such
permit
must
also
meet
the
requirements
in
paragraph
(
u)(
8)
of
this
section.
(
8)
Required
permit
content.
The
permit
required
by
paragraph
(
u)(
7)
of
this
section
shall
include
the
terms
and
conditions
set
forth
in
paragraphs
(
u)(
8)(
i)
through
(
vi).
Such
terms
and
conditions
shall
be
incorporated
into
the
major
stationary
source's
title
V
permit
in
accordance
with
the
provisions
of
the
applicable
title
V
permit
program
under
part
70
or
part
71
of
this
chapter,
but
no
later
than
when
the
title
V
permit
is
renewed.
(
i)
A
statement
indicating
that
the
emissions
unit
qualifies
as
a
Clean
Unit
and
identifying
the
pollutant(
s)
for
which
the
Clean
Unit
designation
applies.
(
ii)
The
effective
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
reviewing
authority
issues
the
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
then
the
permit
must
describe
the
event
that
will
determine
the
effective
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
effective
date
is
known,
then
the
owner
or
operator
must
notify
the
reviewing
authority
of
the
exact
date.
This
specific
effective
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iii)
The
expiration
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
reviewing
authority
issues
the
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
then
the
permit
must
describe
the
event
that
will
determine
the
expiration
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
expiration
date
is
known,
then
the
owner
or
operator
must
notify
the
reviewing
authority
of
the
exact
date.
The
expiration
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iv)
All
emission
limitations
and
work
practice
requirements
adopted
in
conjunction
with
emission
limitations
necessary
to
assure
that
the
control
technology
continues
to
achieve
an
emission
limitation
comparable
to
BACT,
and
any
physical
or
operational
characteristics
that
formed
the
basis
for
determining
that
the
emissions
unit's
control
technology
achieves
a
level
of
emissions
control
comparable
to
BACT
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
v)
Monitoring,
recordkeeping,
and
reporting
requirements
as
necessary
to
demonstrate
that
the
emissions
unit
continues
to
meet
the
criteria
for
maintaining
its
Clean
Unit
designation.
(
See
paragraph
(
u)(
9)
of
this
section.)
(
vi)
Terms
reflecting
the
owner
or
operator's
duties
to
maintain
the
Clean
Unit
designation
and
the
consequences
of
failing
to
do
so,
as
presented
in
paragraph
(
u)(
9)
of
this
section.
(
9)
Maintaining
the
Clean
Unit
designation.
To
maintain
the
Clean
Unit
designation,
the
owner
or
operator
must
conform
to
all
the
restrictions
listed
in
paragraphs
(
u)(
9)(
i)
through
(
v)
of
this
section.
This
paragraph
(
u)(
9)
applies
independently
to
each
pollutant
for
which
the
reviewing
authority
has
designated
the
emissions
unit
a
Clean
Unit.
That
is,
failing
to
conform
to
the
restrictions
for
one
pollutant
affects
the
Clean
Unit
designation
only
for
that
pollutant.
(
i)
The
Clean
Unit
must
comply
with
the
emission
limitation(
s)
and/
or
work
practice
requirements
adopted
to
ensure
that
the
control
technology
continues
to
achieve
emission
control
comparable
to
BACT.
(
ii)
The
owner
or
operator
may
not
make
a
physical
change
in
or
change
in
the
method
of
operation
of
the
Clean
Unit
that
causes
the
emissions
unit
to
function
in
a
manner
that
is
inconsistent
with
the
physical
or
operational
characteristics
that
formed
the
basis
for
the
determination
that
the
control
technology
is
achieving
a
level
of
emission
control
that
is
comparable
to
BACT
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
iii)
[
Reserved]
(
iv)
The
Clean
Unit
must
comply
with
any
terms
and
conditions
in
the
title
V
permit
related
to
the
unit's
Clean
Unit
designation.
(
v)
The
Clean
Unit
must
continue
to
control
emissions
using
the
specific
air
pollution
control
technology
that
was
the
basis
for
its
Clean
Unit
designation.
If
the
emissions
unit
or
control
technology
is
replaced,
then
the
Clean
Unit
designation
ends.
(
10)
Netting
at
Clean
Units.
Emissions
changes
that
occur
at
a
Clean
Unit
must
not
be
included
in
calculating
a
significant
net
emissions
increase
(
that
is,
must
not
be
used
in
a
``
netting
analysis'')
unless
such
use
occurs
before
the
effective
date
of
plan
requirements
adopted
to
implement
this
paragraph
(
u)
or
after
the
Clean
Unit
designation
expires;
or,
unless
the
emissions
unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit.
However,
if
the
Clean
Unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit,
then
the
owner
or
operator
may
generate
a
credit
for
the
difference
between
the
level
that
qualified
the
unit
as
a
Clean
Unit
and
the
emissions
unit's
new
emission
limitation
if
such
reductions
are
surplus,
quantifiable,
and
permanent.
For
purposes
of
generating
offsets,
the
reductions
must
also
be
federally
enforceable.
For
purposes
of
determining
creditable
net
emissions
increases
and
decreases,
the
reductions
must
also
be
enforceable
as
a
practical
matter.
(
11)
Effect
of
redesignation
on
the
Clean
Unit
designation.
The
Clean
Unit
designation
of
an
emissions
unit
is
not
affected
by
redesignation
of
the
attainment
designation
of
the
area
in
which
it
is
located.
That
is,
if
a
Clean
Unit
is
located
in
an
attainment
area
and
the
area
is
redesignated
to
nonattainment,
its
Clean
Unit
designation
is
not
affected.
Similarly,
redesignation
from
nonattainment
to
attainment
does
not
affect
the
Clean
Unit
designation.
However,
if
a
Clean
Unit's
designation
expires
or
is
lost
pursuant
to
paragraphs
(
t)(
2)(
iii)
and
(
u)(
2)(
iii)
of
this
section,
it
must
re
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2002
/
Rules
and
Regulations
qualify
under
the
requirements
that
are
currently
applicable.
(
v)
PCP
exclusion
procedural
requirements.
Each
plan
shall
include
provisions
for
PCPs
equivalent
to
those
contained
in
paragraphs
(
v)(
1)
through
(
6)
of
this
section.
(
1)
Before
an
owner
or
operator
begins
actual
construction
of
a
PCP,
the
owner
or
operator
must
either
submit
a
notice
to
the
reviewing
authority
if
the
project
is
listed
in
paragraphs
(
b)(
31)(
i)
through
(
vi)
of
this
section,
or
if
the
project
is
not
listed
in
paragraphs
(
b)(
31)(
i)
through
(
vi)
of
this
section,
then
the
owner
or
operator
must
submit
a
permit
application
and
obtain
approval
to
use
the
PCP
exclusion
from
the
reviewing
authority
consistent
with
the
requirements
in
paragraph
(
v)(
5)
of
this
section.
Regardless
of
whether
the
owner
or
operator
submits
a
notice
or
a
permit
application,
the
project
must
meet
the
requirements
in
paragraph
(
v)(
2)
of
this
section,
and
the
notice
or
permit
application
must
contain
the
information
required
in
paragraph
(
v)(
3)
of
this
section.
(
2)
Any
project
that
relies
on
the
PCP
exclusion
must
meet
the
requirements
in
paragraphs
(
v)(
2)(
i)
and
(
ii)
of
this
section.
(
i)
Environmentally
beneficial
analysis.
The
environmental
benefit
from
the
emission
reductions
of
pollutants
regulated
under
the
Act
must
outweigh
the
environmental
detriment
of
emissions
increases
in
pollutants
regulated
under
the
Act.
A
statement
that
a
technology
from
paragraphs
(
b)(
31)(
i)
through
(
vi)
of
this
section
is
being
used
shall
be
presumed
to
satisfy
this
requirement.
(
ii)
Air
quality
analysis.
The
emissions
increases
from
the
project
will
not
cause
or
contribute
to
a
violation
of
any
national
ambient
air
quality
standard
or
PSD
increment,
or
adversely
impact
an
air
quality
related
value
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
and
for
which
information
is
available
to
the
general
public.
(
3)
Content
of
notice
or
permit
application.
In
the
notice
or
permit
application
sent
to
the
reviewing
authority,
the
owner
or
operator
must
include,
at
a
minimum,
the
information
listed
in
paragraphs
(
v)(
3)(
i)
through
(
v)
of
this
section.
(
i)
A
description
of
the
project.
(
ii)
The
potential
emissions
increases
and
decreases
of
any
pollutant
regulated
under
the
Act
and
the
projected
emissions
increases
and
decreases
using
the
methodology
in
paragraph
(
a)(
7)(
vi)
of
this
section,
that
will
result
from
the
project,
and
a
copy
of
the
environmentally
beneficial
analysis
required
by
paragraph
(
v)(
2)(
i)
of
this
section.
(
iii)
A
description
of
monitoring
and
recordkeeping,
and
all
other
methods,
to
be
used
on
an
ongoing
basis
to
demonstrate
that
the
project
is
environmentally
beneficial.
Methods
should
be
sufficient
to
meet
the
requirements
in
part
70
and
part
71.
(
iv)
A
certification
that
the
project
will
be
designed
and
operated
in
a
manner
that
is
consistent
with
proper
industry
and
engineering
practices,
in
a
manner
that
is
consistent
with
the
environmentally
beneficial
analysis
and
air
quality
analysis
required
by
paragraphs
(
v)(
2)(
i)
and
(
ii)
of
this
section,
with
information
submitted
in
the
notice
or
permit
application,
and
in
such
a
way
as
to
minimize,
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy,
emissions
of
collateral
pollutants.
(
v)
Demonstration
that
the
PCP
will
not
have
an
adverse
air
quality
impact
(
e.
g.,
modeling,
screening
level
modeling
results,
or
a
statement
that
the
collateral
emissions
increase
is
included
within
the
parameters
used
in
the
most
recent
modeling
exercise)
as
required
by
paragraph
(
v)(
2)(
ii)
of
this
section.
An
air
quality
impact
analysis
is
not
required
for
any
pollutant
that
will
not
experience
a
significant
emissions
increase
as
a
result
of
the
project.
(
4)
Notice
process
for
listed
projects.
For
projects
listed
in
paragraphs
(
b)(
31)(
i)
through
(
vi)
of
this
section,
the
owner
or
operator
may
begin
actual
construction
of
the
project
immediately
after
notice
is
sent
to
the
reviewing
authority
(
unless
otherwise
prohibited
under
requirements
of
the
applicable
plan).
The
owner
or
operator
shall
respond
to
any
requests
by
its
reviewing
authority
for
additional
information
that
the
reviewing
authority
determines
is
necessary
to
evaluate
the
suitability
of
the
project
for
the
PCP
exclusion.
(
5)
Permit
process
for
unlisted
projects.
Before
an
owner
or
operator
may
begin
actual
construction
of
a
PCP
project
that
is
not
listed
in
paragraphs
(
b)(
31)(
i)
through
(
vi)
of
this
section,
the
project
must
be
approved
by
the
reviewing
authority
and
recorded
in
a
plan
approved
permit
or
title
V
permit
using
procedures
that
are
consistent
with
§
§
51.160
and
51.161
of
this
chapter.
This
includes
the
requirement
that
the
reviewing
authority
provide
the
public
with
notice
of
the
proposed
approval,
with
access
to
the
environmentally
beneficial
analysis
and
the
air
quality
analysis,
and
provide
at
least
a
30
day
period
for
the
public
and
the
Administrator
to
submit
comments.
The
reviewing
authority
must
address
all
material
comments
received
by
the
end
of
the
comment
period
before
taking
final
action
on
the
permit.
(
6)
Operational
requirements.
Upon
installation
of
the
PCP,
the
owner
or
operator
must
comply
with
the
requirements
of
paragraphs
(
v)(
6)(
i)
through
(
iv)
of
this
section.
(
i)
General
duty.
The
owner
or
operator
must
operate
the
PCP
consistent
with
proper
industry
and
engineering
practices,
in
a
manner
that
is
consistent
with
the
environmentally
beneficial
analysis
and
air
quality
analysis
required
by
paragraphs
(
v)(
2)(
i)
and
(
ii)
of
this
section,
with
information
submitted
in
the
notice
or
permit
application
required
by
paragraph
(
v)(
3),
and
in
such
a
way
as
to
minimize,
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy,
emissions
of
collateral
pollutants.
(
ii)
Recordkeeping.
The
owner
or
operator
must
maintain
copies
on
site
of
the
environmentally
beneficial
analysis,
the
air
quality
impacts
analysis,
and
monitoring
and
other
emission
records
to
prove
that
the
PCP
operated
consistent
with
the
general
duty
requirements
in
paragraph
(
v)(
6)(
i)
of
this
section.
(
iii)
Permit
requirements.
The
owner
or
operator
must
comply
with
any
provisions
in
the
plan
approved
permit
or
title
V
permit
related
to
use
and
approval
of
the
PCP
exclusion.
(
iv)
Generation
of
Emission
Reduction
Credits.
Emission
reductions
created
by
a
PCP
shall
not
be
included
in
calculating
a
significant
net
emissions
increase
unless
the
emissions
unit
further
reduces
emissions
after
qualifying
for
the
PCP
exclusion
(
e.
g.,
taking
an
operational
restriction
on
the
hours
of
operation.)
The
owner
or
operator
may
generate
a
credit
for
the
difference
between
the
level
of
reduction
which
was
used
to
qualify
for
the
PCP
exclusion
and
the
new
emission
limitation
if
such
reductions
are
surplus,
quantifiable,
and
permanent.
For
purposes
of
generating
offsets,
the
reductions
must
also
be
federally
enforceable.
For
purposes
of
determining
creditable
net
emissions
increases
and
decreases,
the
reductions
must
also
be
enforceable
as
a
practical
matter.
(
w)
Actuals
PALs.
The
plan
shall
provide
for
PALs
according
to
the
provisions
in
paragraphs
(
w)(
1)
through
(
15)
of
this
section.
(
1)
Applicability.
(
i)
The
reviewing
authority
may
approve
the
use
of
an
actuals
PAL
for
any
existing
major
stationary
source
if
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251
/
Tuesday,
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31,
2002
/
Rules
and
Regulations
the
PAL
meets
the
requirements
in
paragraphs
(
w)(
1)
through
(
15)
of
this
section.
The
term
``
PAL''
shall
mean
``
actuals
PAL''
throughout
paragraph
(
w)
of
this
section.
(
ii)
Any
physical
change
in
or
change
in
the
method
of
operation
of
a
major
stationary
source
that
maintains
its
total
source
wide
emissions
below
the
PAL
level,
meets
the
requirements
in
paragraphs
(
w)(
1)
through
(
15)
of
this
section,
and
complies
with
the
PAL
permit:
(
a)
Is
not
a
major
modification
for
the
PAL
pollutant;
(
b)
Does
not
have
to
be
approved
through
the
plan's
major
NSR
program;
and
(
c)
Is
not
subject
to
the
provisions
in
paragraph
(
r)(
2)
of
this
section
(
restrictions
on
relaxing
enforceable
emission
limitations
that
the
major
stationary
source
used
to
avoid
applicability
of
the
major
NSR
program).
(
iii)
Except
as
provided
under
paragraph
(
w)(
1)(
ii)(
c)
of
this
section,
a
major
stationary
source
shall
continue
to
comply
with
all
applicable
Federal
or
State
requirements,
emission
limitations,
and
work
practice
requirements
that
were
established
prior
to
the
effective
date
of
the
PAL.
(
2)
Definitions.
The
plan
shall
use
the
definitions
in
paragraphs
(
w)(
2)(
i)
through
(
xi)
of
this
section
for
the
purpose
of
developing
and
implementing
regulations
that
authorize
the
use
of
actuals
PALs
consistent
with
paragraphs
(
w)(
1)
through
(
15)
of
this
section.
When
a
term
is
not
defined
in
these
paragraphs,
it
shall
have
the
meaning
given
in
paragraph
(
b)
of
this
section
or
in
the
Act.
(
i)
Actuals
PAL
for
a
major
stationary
source
means
a
PAL
based
on
the
baseline
actual
emissions
(
as
defined
in
paragraph
(
b)(
47)
of
this
section)
of
all
emissions
units
(
as
defined
in
paragraph
(
b)(
7)
of
this
section)
at
the
source,
that
emit
or
have
the
potential
to
emit
the
PAL
pollutant.
(
ii)
Allowable
emissions
means
``
allowable
emissions''
as
defined
in
paragraph
(
b)(
16)
of
this
section,
except
as
this
definition
is
modified
according
to
paragraphs
(
w)(
2)(
ii)(
a)
and
(
b)
of
this
section.
(
a)
The
allowable
emissions
for
any
emissions
unit
shall
be
calculated
considering
any
emission
limitations
that
are
enforceable
as
a
practical
matter
on
the
emissions
unit's
potential
to
emit.
(
b)
An
emissions
unit's
potential
to
emit
shall
be
determined
using
the
definition
in
paragraph
(
b)(
4)
of
this
section,
except
that
the
words
``
or
enforceable
as
a
practical
matter''
should
be
added
after
``
federally
enforceable.''
(
iii)
Small
emissions
unit
means
an
emissions
unit
that
emits
or
has
the
potential
to
emit
the
PAL
pollutant
in
an
amount
less
than
the
significant
level
for
that
PAL
pollutant,
as
defined
in
paragraph
(
b)(
23)
of
this
section
or
in
the
Act,
whichever
is
lower.
(
iv)
Major
emissions
unit
means:
(
a)
Any
emissions
unit
that
emits
or
has
the
potential
to
emit
100
tons
per
year
or
more
of
the
PAL
pollutant
in
an
attainment
area;
or
(
b)
Any
emissions
unit
that
emits
or
has
the
potential
to
emit
the
PAL
pollutant
in
an
amount
that
is
equal
to
or
greater
than
the
major
source
threshold
for
the
PAL
pollutant
as
defined
by
the
Act
for
nonattainment
areas.
For
example,
in
accordance
with
the
definition
of
major
stationary
source
in
section
182(
c)
of
the
Act,
an
emissions
unit
would
be
a
major
emissions
unit
for
VOC
if
the
emissions
unit
is
located
in
a
serious
ozone
nonattainment
area
and
it
emits
or
has
the
potential
to
emit
50
or
more
tons
of
VOC
per
year.
(
v)
Plantwide
applicability
limitation
(
PAL)
means
an
emission
limitation
expressed
in
tons
per
year,
for
a
pollutant
at
a
major
stationary
source,
that
is
enforceable
as
a
practical
matter
and
established
source
wide
in
accordance
with
paragraphs
(
w)(
1)
through
(
15)
of
this
section.
(
vi)
PAL
effective
date
generally
means
the
date
of
issuance
of
the
PAL
permit.
However,
the
PAL
effective
date
for
an
increased
PAL
is
the
date
any
emissions
unit
that
is
part
of
the
PAL
major
modification
becomes
operational
and
begins
to
emit
the
PAL
pollutant.
(
vii)
PAL
effective
period
means
the
period
beginning
with
the
PAL
effective
date
and
ending
10
years
later.
(
viii)
PAL
major
modification
means,
notwithstanding
paragraphs
(
b)(
2)
and
(
b)(
3)
of
this
section
(
the
definitions
for
major
modification
and
net
emissions
increase),
any
physical
change
in
or
change
in
the
method
of
operation
of
the
PAL
source
that
causes
it
to
emit
the
PAL
pollutant
at
a
level
equal
to
or
greater
than
the
PAL.
(
ix)
PAL
permit
means
the
major
NSR
permit,
the
minor
NSR
permit,
or
the
State
operating
permit
under
a
program
that
is
approved
into
the
plan,
or
the
title
V
permit
issued
by
the
reviewing
authority
that
establishes
a
PAL
for
a
major
stationary
source.
(
x)
PAL
pollutant
means
the
pollutant
for
which
a
PAL
is
established
at
a
major
stationary
source.
(
xi)
Significant
emissions
unit
means
an
emissions
unit
that
emits
or
has
the
potential
to
emit
a
PAL
pollutant
in
an
amount
that
is
equal
to
or
greater
than
the
significant
level
(
as
defined
in
paragraph
(
b)(
23)
of
this
section
or
in
the
Act,
whichever
is
lower)
for
that
PAL
pollutant,
but
less
than
the
amount
that
would
qualify
the
unit
as
a
major
emissions
unit
as
defined
in
paragraph
(
w)(
2)(
iv)
of
this
section.
(
3)
Permit
application
requirements.
As
part
of
a
permit
application
requesting
a
PAL,
the
owner
or
operator
of
a
major
stationary
source
shall
submit
the
following
information
in
paragraphs
(
w)(
3)(
i)
through
(
iii)
of
this
section
to
the
reviewing
authority
for
approval.
(
i)
A
list
of
all
emissions
units
at
the
source
designated
as
small,
significant
or
major
based
on
their
potential
to
emit.
In
addition,
the
owner
or
operator
of
the
source
shall
indicate
which,
if
any,
Federal
or
State
applicable
requirements,
emission
limitations,
or
work
practices
apply
to
each
unit.
(
ii)
Calculations
of
the
baseline
actual
emissions
(
with
supporting
documentation).
Baseline
actual
emissions
are
to
include
emissions
associated
not
only
with
operation
of
the
unit,
but
also
emissions
associated
with
startup,
shutdown,
and
malfunction.
(
iii)
The
calculation
procedures
that
the
major
stationary
source
owner
or
operator
proposes
to
use
to
convert
the
monitoring
system
data
to
monthly
emissions
and
annual
emissions
based
on
a
12
month
rolling
total
for
each
month
as
required
by
paragraph
(
w)(
13)(
i)
of
this
section.
(
4)
General
requirements
for
establishing
PALs.
(
i)
The
plan
allows
the
reviewing
authority
to
establish
a
PAL
at
a
major
stationary
source,
provided
that
at
a
minimum,
the
requirements
in
paragraphs
(
w)(
4)(
i)(
a)
through
(
g)
of
this
section
are
met.
(
a)
The
PAL
shall
impose
an
annual
emission
limitation
in
tons
per
year,
that
is
enforceable
as
a
practical
matter,
for
the
entire
major
stationary
source.
For
each
month
during
the
PAL
effective
period
after
the
first
12
months
of
establishing
a
PAL,
the
major
stationary
source
owner
or
operator
shall
show
that
the
sum
of
the
monthly
emissions
from
each
emissions
unit
under
the
PAL
for
the
previous
12
consecutive
months
is
less
than
the
PAL
(
a
12
month
average,
rolled
monthly).
For
each
month
during
the
first
11
months
from
the
PAL
effective
date,
the
major
stationary
source
owner
or
operator
shall
show
that
the
sum
of
the
preceding
monthly
emissions
from
the
PAL
effective
date
for
each
emissions
unit
under
the
PAL
is
less
than
the
PAL.
(
b)
The
PAL
shall
be
established
in
a
PAL
permit
that
meets
the
public
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251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
participation
requirements
in
paragraph
(
w)(
5)
of
this
section.
(
c)
The
PAL
permit
shall
contain
all
the
requirements
of
paragraph
(
w)(
7)
of
this
section.
(
d)
The
PAL
shall
include
fugitive
emissions,
to
the
extent
quantifiable,
from
all
emissions
units
that
emit
or
have
the
potential
to
emit
the
PAL
pollutant
at
the
major
stationary
source.
(
e)
Each
PAL
shall
regulate
emissions
of
only
one
pollutant.
(
f)
Each
PAL
shall
have
a
PAL
effective
period
of
10
years.
(
g)
The
owner
or
operator
of
the
major
stationary
source
with
a
PAL
shall
comply
with
the
monitoring,
recordkeeping,
and
reporting
requirements
provided
in
paragraphs
(
w)(
12)
through
(
14)
of
this
section
for
each
emissions
unit
under
the
PAL
through
the
PAL
effective
period.
(
ii)
At
no
time
(
during
or
after
the
PAL
effective
period)
are
emissions
reductions
of
a
PAL
pollutant
that
occur
during
the
PAL
effective
period
creditable
as
decreases
for
purposes
of
offsets
under
§
51.165(
a)(
3)(
ii)
of
this
chapter
unless
the
level
of
the
PAL
is
reduced
by
the
amount
of
such
emissions
reductions
and
such
reductions
would
be
creditable
in
the
absence
of
the
PAL.
(
5)
Public
participation
requirements
for
PALs.
PALs
for
existing
major
stationary
sources
shall
be
established,
renewed,
or
increased,
through
a
procedure
that
is
consistent
with
§
§
51.160
and
51.161
of
this
chapter.
This
includes
the
requirement
that
the
reviewing
authority
provide
the
public
with
notice
of
the
proposed
approval
of
a
PAL
permit
and
at
least
a
30
day
period
for
submittal
of
public
comment.
The
reviewing
authority
must
address
all
material
comments
before
taking
final
action
on
the
permit.
(
6)
Setting
the
10
year
actuals
PAL
level.
The
plan
shall
provide
that
the
actuals
PAL
level
for
a
major
stationary
source
shall
be
established
as
the
sum
of
the
baseline
actual
emissions
(
as
defined
in
paragraph
(
b)(
47)
of
this
section)
of
the
PAL
pollutant
for
each
emissions
unit
at
the
source;
plus
an
amount
equal
to
the
applicable
significant
level
for
the
PAL
pollutant
under
paragraph
(
b)(
23)
of
this
section
or
under
the
Act,
whichever
is
lower.
When
establishing
the
actuals
PAL
level,
for
a
PAL
pollutant,
only
one
consecutive
24
month
period
must
be
used
to
determine
the
baseline
actual
emissions
for
all
existing
emissions
units.
However,
a
different
consecutive
24
month
period
may
be
used
for
each
different
PAL
pollutant.
Emissions
associated
with
units
that
were
permanently
shutdown
after
this
24
month
period
must
be
subtracted
from
the
PAL
level.
Emissions
from
units
on
which
actual
construction
began
after
the
24
month
period
must
be
added
to
the
PAL
level
in
an
amount
equal
to
the
potential
to
emit
of
the
units.
The
reviewing
authority
shall
specify
a
reduced
PAL
level(
s)
(
in
tons/
yr)
in
the
PAL
permit
to
become
effective
on
the
future
compliance
date(
s)
of
any
applicable
Federal
or
State
regulatory
requirement(
s)
that
the
reviewing
authority
is
aware
of
prior
to
issuance
of
the
PAL
permit.
For
instance,
if
the
source
owner
or
operator
will
be
required
to
reduce
emissions
from
industrial
boilers
in
half
from
baseline
emissions
of
60
ppm
NOX
to
a
new
rule
limit
of
30
ppm,
then
the
permit
shall
contain
a
future
effective
PAL
level
that
is
equal
to
the
current
PAL
level
reduced
by
half
of
the
original
baseline
emissions
of
such
unit(
s).
(
7)
Contents
of
the
PAL
permit.
The
plan
shall
require
that
the
PAL
permit
contain,
at
a
minimum,
the
information
in
paragraphs
(
w)(
7)(
i)
through
(
x)
of
this
section.
(
i)
The
PAL
pollutant
and
the
applicable
source
wide
emission
limitation
in
tons
per
year.
(
ii)
The
PAL
permit
effective
date
and
the
expiration
date
of
the
PAL
(
PAL
effective
period).
(
iii)
Specification
in
the
PAL
permit
that
if
a
major
stationary
source
owner
or
operator
applies
to
renew
a
PAL
in
accordance
with
paragraph
(
w)(
10)
of
this
section
before
the
end
of
the
PAL
effective
period,
then
the
PAL
shall
not
expire
at
the
end
of
the
PAL
effective
period.
It
shall
remain
in
effect
until
a
revised
PAL
permit
is
issued
by
the
reviewing
authority.
(
iv)
A
requirement
that
emission
calculations
for
compliance
purposes
include
emissions
from
startups,
shutdowns
and
malfunctions.
(
v)
A
requirement
that,
once
the
PAL
expires,
the
major
stationary
source
is
subject
to
the
requirements
of
paragraph
(
w)(
9)
of
this
section.
(
vi)
The
calculation
procedures
that
the
major
stationary
source
owner
or
operator
shall
use
to
convert
the
monitoring
system
data
to
monthly
emissions
and
annual
emissions
based
on
a
12
month
rolling
total
for
each
month
as
required
by
paragraph
(
w)(
3)(
i)
of
this
section.
(
vii)
A
requirement
that
the
major
stationary
source
owner
or
operator
monitor
all
emissions
units
in
accordance
with
the
provisions
under
paragraph
(
w)(
13)
of
this
section.
(
viii)
A
requirement
to
retain
the
records
required
under
paragraph
(
w)(
13)
of
this
section
on
site.
Such
records
may
be
retained
in
an
electronic
format.
(
ix)
A
requirement
to
submit
the
reports
required
under
paragraph
(
w)(
14)
of
this
section
by
the
required
deadlines.
(
x)
Any
other
requirements
that
the
reviewing
authority
deems
necessary
to
implement
and
enforce
the
PAL.
(
8)
PAL
effective
period
and
reopening
of
the
PAL
permit.
The
plan
shall
require
the
information
in
paragraphs
(
w)(
8)(
i)
and
(
ii)
of
this
section.
(
i)
PAL
effective
period.
The
reviewing
authority
shall
specify
a
PAL
effective
period
of
10
years.
(
ii)
Reopening
of
the
PAL
permit.
(
a)
During
the
PAL
effective
period,
the
plan
shall
require
the
reviewing
authority
to
reopen
the
PAL
permit
to:
(
1)
Correct
typographical/
calculation
errors
made
in
setting
the
PAL
or
reflect
a
more
accurate
determination
of
emissions
used
to
establish
the
PAL;
(
2)
Reduce
the
PAL
if
the
owner
or
operator
of
the
major
stationary
source
creates
creditable
emissions
reductions
for
use
as
offsets
under
§
51.165(
a)(
3)(
ii)
of
this
chapter;
and
(
3)
Revise
the
PAL
to
reflect
an
increase
in
the
PAL
as
provided
under
paragraph
(
w)(
11)
of
this
section.
(
b)
The
plan
shall
provide
the
reviewing
authority
discretion
to
reopen
the
PAL
permit
for
the
following:
(
1)
Reduce
the
PAL
to
reflect
newly
applicable
Federal
requirements
(
for
example,
NSPS)
with
compliance
dates
after
the
PAL
effective
date;
(
2)
Reduce
the
PAL
consistent
with
any
other
requirement,
that
is
enforceable
as
a
practical
matter,
and
that
the
State
may
impose
on
the
major
stationary
source
under
the
plan;
and
(
3)
Reduce
the
PAL
if
the
reviewing
authority
determines
that
a
reduction
is
necessary
to
avoid
causing
or
contributing
to
a
NAAQS
or
PSD
increment
violation,
or
to
an
adverse
impact
on
an
AQRV
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
and
for
which
information
is
available
to
the
general
public.
(
c)
Except
for
the
permit
reopening
in
paragraph
(
w)(
8)(
ii)(
a)(
1)
of
this
section
for
the
correction
of
typographical/
calculation
errors
that
do
not
increase
the
PAL
level,
all
reopenings
shall
be
carried
out
in
accordance
with
the
public
participation
requirements
of
paragraph
(
w)(
5)
of
this
section.
(
9)
Expiration
of
a
PAL.
Any
PAL
that
is
not
renewed
in
accordance
with
the
procedures
in
paragraph
(
w)(
10)
of
this
section
shall
expire
at
the
end
of
the
PAL
effective
period,
and
the
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31DER3.
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
requirements
in
paragraphs
(
w)(
9)(
i)
through
(
v)
of
this
section
shall
apply.
(
i)
Each
emissions
unit
(
or
each
group
of
emissions
units)
that
existed
under
the
PAL
shall
comply
with
an
allowable
emission
limitation
under
a
revised
permit
established
according
to
the
procedures
in
paragraphs
(
w)(
9)(
i)(
a)
and
(
b)
of
this
section.
(
a)
Within
the
time
frame
specified
for
PAL
renewals
in
paragraph
(
w)(
10)(
ii)
of
this
section,
the
major
stationary
source
shall
submit
a
proposed
allowable
emission
limitation
for
each
emissions
unit
(
or
each
group
of
emissions
units,
if
such
a
distribution
is
more
appropriate
as
decided
by
the
reviewing
authority)
by
distributing
the
PAL
allowable
emissions
for
the
major
stationary
source
among
each
of
the
emissions
units
that
existed
under
the
PAL.
If
the
PAL
had
not
yet
been
adjusted
for
an
applicable
requirement
that
became
effective
during
the
PAL
effective
period,
as
required
under
paragraph
(
w)(
10)(
v)
of
this
section,
such
distribution
shall
be
made
as
if
the
PAL
had
been
adjusted.
(
b)
The
reviewing
authority
shall
decide
whether
and
how
the
PAL
allowable
emissions
will
be
distributed
and
issue
a
revised
permit
incorporating
allowable
limits
for
each
emissions
unit,
or
each
group
of
emissions
units,
as
the
reviewing
authority
determines
is
appropriate.
(
ii)
Each
emissions
unit(
s)
shall
comply
with
the
allowable
emission
limitation
on
a
12
month
rolling
basis.
The
reviewing
authority
may
approve
the
use
of
monitoring
systems
(
source
testing,
emission
factors,
etc.)
other
than
CEMS,
CERMS,
PEMS
or
CPMS
to
demonstrate
compliance
with
the
allowable
emission
limitation.
(
iii)
Until
the
reviewing
authority
issues
the
revised
permit
incorporating
allowable
limits
for
each
emissions
unit,
or
each
group
of
emissions
units,
as
required
under
paragraph
(
w)(
9)(
i)(
b)
of
this
section,
the
source
shall
continue
to
comply
with
a
source
wide,
multi
unit
emissions
cap
equivalent
to
the
level
of
the
PAL
emission
limitation.
(
iv)
Any
physical
change
or
change
in
the
method
of
operation
at
the
major
stationary
source
will
be
subject
to
major
NSR
requirements
if
such
change
meets
the
definition
of
major
modification
in
paragraph
(
b)(
2)
of
this
section.
(
v)
The
major
stationary
source
owner
or
operator
shall
continue
to
comply
with
any
State
or
Federal
applicable
requirements
(
BACT,
RACT,
NSPS,
etc.)
that
may
have
applied
either
during
the
PAL
effective
period
or
prior
to
the
PAL
effective
period
except
for
those
emission
limitations
that
had
been
established
pursuant
to
paragraph
(
r)(
2)
of
this
section,
but
were
eliminated
by
the
PAL
in
accordance
with
the
provisions
in
paragraph
(
w)(
1)(
ii)(
c)
of
this
section.
(
10)
Renewal
of
a
PAL.
(
i)
The
reviewing
authority
shall
follow
the
procedures
specified
in
paragraph
(
w)(
5)
of
this
section
in
approving
any
request
to
renew
a
PAL
for
a
major
stationary
source,
and
shall
provide
both
the
proposed
PAL
level
and
a
written
rationale
for
the
proposed
PAL
level
to
the
public
for
review
and
comment.
During
such
public
review,
any
person
may
propose
a
PAL
level
for
the
source
for
consideration
by
the
reviewing
authority.
(
ii)
Application
deadline.
The
plan
shall
require
that
a
major
stationary
source
owner
or
operator
shall
submit
a
timely
application
to
the
reviewing
authority
to
request
renewal
of
a
PAL.
A
timely
application
is
one
that
is
submitted
at
least
6
months
prior
to,
but
not
earlier
than
18
months
from,
the
date
of
permit
expiration.
This
deadline
for
application
submittal
is
to
ensure
that
the
permit
will
not
expire
before
the
permit
is
renewed.
If
the
owner
or
operator
of
a
major
stationary
source
submits
a
complete
application
to
renew
the
PAL
within
this
time
period,
then
the
PAL
shall
continue
to
be
effective
until
the
revised
permit
with
the
renewed
PAL
is
issued.
(
iii)
Application
requirements.
The
application
to
renew
a
PAL
permit
shall
contain
the
information
required
in
paragraphs
(
w)(
10)(
iii)
(
a)
through
(
d)
of
this
section.
(
a)
The
information
required
in
paragraphs
(
w)(
3)(
i)
through
(
iii)
of
this
section.
(
b)
A
proposed
PAL
level.
(
c)
The
sum
of
the
potential
to
emit
of
all
emissions
units
under
the
PAL
(
with
supporting
documentation).
(
d)
Any
other
information
the
owner
or
operator
wishes
the
reviewing
authority
to
consider
in
determining
the
appropriate
level
for
renewing
the
PAL.
(
iv)
PAL
adjustment.
In
determining
whether
and
how
to
adjust
the
PAL,
the
reviewing
authority
shall
consider
the
options
outlined
in
paragraphs
(
w)(
10)(
iv)
(
a)
and
(
b)
of
this
section.
However,
in
no
case
may
any
such
adjustment
fail
to
comply
with
paragraph
(
w)(
10)(
iv)(
c)
of
this
section.
(
a)
If
the
emissions
level
calculated
in
accordance
with
paragraph
(
w)(
6)
of
this
section
is
equal
to
or
greater
than
80
percent
of
the
PAL
level,
the
reviewing
authority
may
renew
the
PAL
at
the
same
level
without
considering
the
factors
set
forth
in
paragraph
(
w)(
10)(
iv)(
b)
of
this
section;
or
(
b)
The
reviewing
authority
may
set
the
PAL
at
a
level
that
it
determines
to
be
more
representative
of
the
source's
baseline
actual
emissions,
or
that
it
determines
to
be
appropriate
considering
air
quality
needs,
advances
in
control
technology,
anticipated
economic
growth
in
the
area,
desire
to
reward
or
encourage
the
source's
voluntary
emissions
reductions,
or
other
factors
as
specifically
identified
by
the
reviewing
authority
in
its
written
rationale.
(
c)
Notwithstanding
paragraphs
(
w)(
10)(
iv)
(
a)
and
(
b)
of
this
section:
(
1)
If
the
potential
to
emit
of
the
major
stationary
source
is
less
than
the
PAL,
the
reviewing
authority
shall
adjust
the
PAL
to
a
level
no
greater
than
the
potential
to
emit
of
the
source;
and
(
2)
The
reviewing
authority
shall
not
approve
a
renewed
PAL
level
higher
than
the
current
PAL,
unless
the
major
stationary
source
has
complied
with
the
provisions
of
paragraph
(
w)(
11)
of
this
section
(
increasing
a
PAL).
(
v)
If
the
compliance
date
for
a
State
or
Federal
requirement
that
applies
to
the
PAL
source
occurs
during
the
PAL
effective
period,
and
if
the
reviewing
authority
has
not
already
adjusted
for
such
requirement,
the
PAL
shall
be
adjusted
at
the
time
of
PAL
permit
renewal
or
title
V
permit
renewal,
whichever
occurs
first.
(
11)
Increasing
a
PAL
during
the
PAL
effective
period.
(
i)
The
plan
shall
require
that
the
reviewing
authority
may
increase
a
PAL
emission
limitation
only
if
the
major
stationary
source
complies
with
the
provisions
in
paragraphs
(
w)(
11)(
i)
(
a)
through
(
d)
of
this
section.
(
a)
The
owner
or
operator
of
the
major
stationary
source
shall
submit
a
complete
application
to
request
an
increase
in
the
PAL
limit
for
a
PAL
major
modification.
Such
application
shall
identify
the
emissions
unit(
s)
contributing
to
the
increase
in
emissions
so
as
to
cause
the
major
stationary
source's
emissions
to
equal
or
exceed
its
PAL.
(
b)
As
part
of
this
application,
the
major
stationary
source
owner
or
operator
shall
demonstrate
that
the
sum
of
the
baseline
actual
emissions
of
the
small
emissions
units,
plus
the
sum
of
the
baseline
actual
emissions
of
the
significant
and
major
emissions
units
assuming
application
of
BACT
equivalent
controls,
plus
the
sum
of
the
allowable
emissions
of
the
new
or
modified
emissions
unit(
s),
exceeds
the
PAL.
The
level
of
control
that
would
result
from
BACT
equivalent
controls
on
each
significant
or
major
emissions
unit
shall
be
determined
by
conducting
a
new
BACT
analysis
at
the
time
the
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Rules
and
Regulations
application
is
submitted,
unless
the
emissions
unit
is
currently
required
to
comply
with
a
BACT
or
LAER
requirement
that
was
established
within
the
preceding
10
years.
In
such
a
case,
the
assumed
control
level
for
that
emissions
unit
shall
be
equal
to
the
level
of
BACT
or
LAER
with
which
that
emissions
unit
must
currently
comply.
(
c)
The
owner
or
operator
obtains
a
major
NSR
permit
for
all
emissions
unit(
s)
identified
in
paragraph
(
w)(
11)(
i)(
a)
of
this
section,
regardless
of
the
magnitude
of
the
emissions
increase
resulting
from
them
(
that
is,
no
significant
levels
apply).
These
emissions
unit(
s)
shall
comply
with
any
emissions
requirements
resulting
from
the
major
NSR
process
(
for
example,
BACT),
even
though
they
have
also
become
subject
to
the
PAL
or
continue
to
be
subject
to
the
PAL.
(
d)
The
PAL
permit
shall
require
that
the
increased
PAL
level
shall
be
effective
on
the
day
any
emissions
unit
that
is
part
of
the
PAL
major
modification
becomes
operational
and
begins
to
emit
the
PAL
pollutant.
(
ii)
The
reviewing
authority
shall
calculate
the
new
PAL
as
the
sum
of
the
allowable
emissions
for
each
modified
or
new
emissions
unit,
plus
the
sum
of
the
baseline
actual
emissions
of
the
significant
and
major
emissions
units
(
assuming
application
of
BACT
equivalent
controls
as
determined
in
accordance
with
paragraph
(
w)(
11)(
i)(
b)
of
this
section),
plus
the
sum
of
the
baseline
actual
emissions
of
the
small
emissions
units.
(
iii)
The
PAL
permit
shall
be
revised
to
reflect
the
increased
PAL
level
pursuant
to
the
public
notice
requirements
of
paragraph
(
w)(
5)
of
this
section.
(
12)
Monitoring
requirements
for
PALs.
(
i)
General
requirements.
(
a)
Each
PAL
permit
must
contain
enforceable
requirements
for
the
monitoring
system
that
accurately
determines
plantwide
emissions
of
the
PAL
pollutant
in
terms
of
mass
per
unit
of
time.
Any
monitoring
system
authorized
for
use
in
the
PAL
permit
must
be
based
on
sound
science
and
meet
generally
acceptable
scientific
procedures
for
data
quality
and
manipulation.
Additionally,
the
information
generated
by
such
system
must
meet
minimum
legal
requirements
for
admissibility
in
a
judicial
proceeding
to
enforce
the
PAL
permit.
(
b)
The
PAL
monitoring
system
must
employ
one
or
more
of
the
four
general
monitoring
approaches
meeting
the
minimum
requirements
set
forth
in
paragraphs
(
w)(
12)(
ii)
(
a)
through
(
d)
of
this
section
and
must
be
approved
by
the
reviewing
authority.
(
c)
Notwithstanding
paragraph
(
w)(
12)(
i)(
b)
of
this
section,
you
may
also
employ
an
alternative
monitoring
approach
that
meets
paragraph
(
w)(
12)(
i)(
a)
of
this
section
if
approved
by
the
reviewing
authority.
(
d)
Failure
to
use
a
monitoring
system
that
meets
the
requirements
of
this
section
renders
the
PAL
invalid.
(
ii)
Minimum
performance
requirements
for
approved
monitoring
approaches.
The
following
are
acceptable
general
monitoring
approaches
when
conducted
in
accordance
with
the
minimum
requirements
in
paragraphs
(
w)(
12)(
iii)
through
(
ix)
of
this
section:
(
a)
Mass
balance
calculations
for
activities
using
coatings
or
solvents;
(
b)
CEMS;
(
c)
CPMS
or
PEMS;
and
(
d)
Emission
factors.
(
iii)
Mass
balance
calculations.
An
owner
or
operator
using
mass
balance
calculations
to
monitor
PAL
pollutant
emissions
from
activities
using
coating
or
solvents
shall
meet
the
following
requirements:
(
a)
Provide
a
demonstrated
means
of
validating
the
published
content
of
the
PAL
pollutant
that
is
contained
in
or
created
by
all
materials
used
in
or
at
the
emissions
unit;
(
b)
Assume
that
the
emissions
unit
emits
all
of
the
PAL
pollutant
that
is
contained
in
or
created
by
any
raw
material
or
fuel
used
in
or
at
the
emissions
unit,
if
it
cannot
otherwise
be
accounted
for
in
the
process;
and
(
c)
Where
the
vendor
of
a
material
or
fuel,
which
is
used
in
or
at
the
emissions
unit,
publishes
a
range
of
pollutant
content
from
such
material,
the
owner
or
operator
must
use
the
highest
value
of
the
range
to
calculate
the
PAL
pollutant
emissions
unless
the
reviewing
authority
determines
there
is
site
specific
data
or
a
site
specific
monitoring
program
to
support
another
content
within
the
range.
(
iv)
CEMS.
An
owner
or
operator
using
CEMS
to
monitor
PAL
pollutant
emissions
shall
meet
the
following
requirements:
(
a)
CEMS
must
comply
with
applicable
Performance
Specifications
found
in
40
CFR
part
60,
appendix
B;
and
(
b)
CEMS
must
sample,
analyze,
and
record
data
at
least
every
15
minutes
while
the
emissions
unit
is
operating.
(
v)
CPMS
or
PEMS.
An
owner
or
operator
using
CPMS
or
PEMS
to
monitor
PAL
pollutant
emissions
shall
meet
the
following
requirements:
(
a)
The
CPMS
or
the
PEMS
must
be
based
on
current
site
specific
data
demonstrating
a
correlation
between
the
monitored
parameter(
s)
and
the
PAL
pollutant
emissions
across
the
range
of
operation
of
the
emissions
unit;
and
(
b)
Each
CPMS
or
PEMS
must
sample,
analyze,
and
record
data
at
least
every
15
minutes,
or
at
another
less
frequent
interval
approved
by
the
reviewing
authority,
while
the
emissions
unit
is
operating.
(
vi)
Emission
factors.
An
owner
or
operator
using
emission
factors
to
monitor
PAL
pollutant
emissions
shall
meet
the
following
requirements:
(
a)
All
emission
factors
shall
be
adjusted,
if
appropriate,
to
account
for
the
degree
of
uncertainty
or
limitations
in
the
factors'
development;
(
b)
The
emissions
unit
shall
operate
within
the
designated
range
of
use
for
the
emission
factor,
if
applicable;
and
(
c)
If
technically
practicable,
the
owner
or
operator
of
a
significant
emissions
unit
that
relies
on
an
emission
factor
to
calculate
PAL
pollutant
emissions
shall
conduct
validation
testing
to
determine
a
sitespecific
emission
factor
within
6
months
of
PAL
permit
issuance,
unless
the
reviewing
authority
determines
that
testing
is
not
required.
(
vii)
A
source
owner
or
operator
must
record
and
report
maximum
potential
emissions
without
considering
enforceable
emission
limitations
or
operational
restrictions
for
an
emissions
unit
during
any
period
of
time
that
there
is
no
monitoring
data,
unless
another
method
for
determining
emissions
during
such
periods
is
specified
in
the
PAL
permit.
(
viii)
Notwithstanding
the
requirements
in
paragraphs
(
w)(
12)(
iii)
through
(
vii)
of
this
section,
where
an
owner
or
operator
of
an
emissions
unit
cannot
demonstrate
a
correlation
between
the
monitored
parameter(
s)
and
the
PAL
pollutant
emissions
rate
at
all
operating
points
of
the
emissions
unit,
the
reviewing
authority
shall,
at
the
time
of
permit
issuance:
(
a)
Establish
default
value(
s)
for
determining
compliance
with
the
PAL
based
on
the
highest
potential
emissions
reasonably
estimated
at
such
operating
point(
s);
or
(
b)
Determine
that
operation
of
the
emissions
unit
during
operating
conditions
when
there
is
no
correlation
between
monitored
parameter(
s)
and
the
PAL
pollutant
emissions
is
a
violation
of
the
PAL.
(
ix)
Re
validation.
All
data
used
to
establish
the
PAL
pollutant
must
be
revalidated
through
performance
testing
or
other
scientifically
valid
means
approved
by
the
reviewing
authority.
Such
testing
must
occur
at
least
once
every
5
years
after
issuance
of
the
PAL.
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251
/
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December
31,
2002
/
Rules
and
Regulations
(
13)
Recordkeeping
requirements.
(
i)
The
PAL
permit
shall
require
an
owner
or
operator
to
retain
a
copy
of
all
records
necessary
to
determine
compliance
with
any
requirement
of
paragraph
(
w)
of
this
section
and
of
the
PAL,
including
a
determination
of
each
emissions
unit's
12
month
rolling
total
emissions,
for
5
years
from
the
date
of
such
record.
(
ii)
The
PAL
permit
shall
require
an
owner
or
operator
to
retain
a
copy
of
the
following
records,
for
the
duration
of
the
PAL
effective
period
plus
5
years:
(
a)
A
copy
of
the
PAL
permit
application
and
any
applications
for
revisions
to
the
PAL;
and
(
b)
Each
annual
certification
of
compliance
pursuant
to
title
V
and
the
data
relied
on
in
certifying
the
compliance.
(
14)
Reporting
and
notification
requirements.
The
owner
or
operator
shall
submit
semi
annual
monitoring
reports
and
prompt
deviation
reports
to
the
reviewing
authority
in
accordance
with
the
applicable
title
V
operating
permit
program.
The
reports
shall
meet
the
requirements
in
paragraphs
(
w)(
14)(
i)
through
(
iii)
of
this
section.
(
i)
Semi
annual
report.
The
semiannual
report
shall
be
submitted
to
the
reviewing
authority
within
30
days
of
the
end
of
each
reporting
period.
This
report
shall
contain
the
information
required
in
paragraphs
(
w)(
14)(
i)(
a)
through
(
g)
of
this
section.
(
a)
The
identification
of
owner
and
operator
and
the
permit
number.
(
b)
Total
annual
emissions
(
tons/
year)
based
on
a
12
month
rolling
total
for
each
month
in
the
reporting
period
recorded
pursuant
to
paragraph
(
w)(
13)(
i)
of
this
section.
(
c)
All
data
relied
upon,
including,
but
not
limited
to,
any
Quality
Assurance
or
Quality
Control
data,
in
calculating
the
monthly
and
annual
PAL
pollutant
emissions.
(
d)
A
list
of
any
emissions
units
modified
or
added
to
the
major
stationary
source
during
the
preceding
6
month
period.
(
e)
The
number,
duration,
and
cause
of
any
deviations
or
monitoring
malfunctions
(
other
than
the
time
associated
with
zero
and
span
calibration
checks),
and
any
corrective
action
taken.
(
f)
A
notification
of
a
shutdown
of
any
monitoring
system,
whether
the
shutdown
was
permanent
or
temporary,
the
reason
for
the
shutdown,
the
anticipated
date
that
the
monitoring
system
will
be
fully
operational
or
replaced
with
another
monitoring
system,
and
whether
the
emissions
unit
monitored
by
the
monitoring
system
continued
to
operate,
and
the
calculation
of
the
emissions
of
the
pollutant
or
the
number
determined
by
method
included
in
the
permit,
as
provided
by
paragraph
(
w)(
12)(
vii)
of
this
section.
(
g)
A
signed
statement
by
the
responsible
official
(
as
defined
by
the
applicable
title
V
operating
permit
program)
certifying
the
truth,
accuracy,
and
completeness
of
the
information
provided
in
the
report.
(
ii)
Deviation
report.
The
major
stationary
source
owner
or
operator
shall
promptly
submit
reports
of
any
deviations
or
exceedance
of
the
PAL
requirements,
including
periods
where
no
monitoring
is
available.
A
report
submitted
pursuant
to
§
70.6(
a)(
3)(
iii)(
B)
of
this
chapter
shall
satisfy
this
reporting
requirement.
The
deviation
reports
shall
be
submitted
within
the
time
limits
prescribed
by
the
applicable
program
implementing
§
70.6(
a)(
3)(
iii)(
B)
of
this
chapter.
The
reports
shall
contain
the
following
information:
(
a)
The
identification
of
owner
and
operator
and
the
permit
number;
(
b)
The
PAL
requirement
that
experienced
the
deviation
or
that
was
exceeded;
(
c)
Emissions
resulting
from
the
deviation
or
the
exceedance;
and
(
d)
A
signed
statement
by
the
responsible
official
(
as
defined
by
the
applicable
title
V
operating
permit
program)
certifying
the
truth,
accuracy,
and
completeness
of
the
information
provided
in
the
report.
(
iii)
Re
validation
results.
The
owner
or
operator
shall
submit
to
the
reviewing
authority
the
results
of
any
re
validation
test
or
method
within
three
months
after
completion
of
such
test
or
method.
(
15)
Transition
requirements.
(
i)
No
reviewing
authority
may
issue
a
PAL
that
does
not
comply
with
the
requirements
in
paragraphs
(
w)(
1)
through
(
15)
of
this
section
after
the
Administrator
has
approved
regulations
incorporating
these
requirements
into
a
plan.
(
ii)
The
reviewing
authority
may
supersede
any
PAL
which
was
established
prior
to
the
date
of
approval
of
the
plan
by
the
Administrator
with
a
PAL
that
complies
with
the
requirements
of
paragraphs
(
w)(
1)
through
(
15)
of
this
section.
(
x)
If
any
provision
of
this
section,
or
the
application
of
such
provision
to
any
person
or
circumstance,
is
held
invalid,
the
remainder
of
this
section,
or
the
application
of
such
provision
to
persons
or
circumstances
other
than
those
as
to
which
it
is
held
invalid,
shall
not
be
affected
thereby.
PART
52
[
AMENDED]
1.
The
authority
citation
for
part
52
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
Subpart
A
[
Amended]
2.
In
40
CFR
52.21(
b)(
1)(
i)(
b)
and
(
b)(
5),
remove
the
words
``
any
air
pollutant
subject
to
regulation
under
the
Act,''
and
add,
in
their
place,
the
words
``
a
regulated
NSR
pollutant.''
3.
In
addition
to
the
amendments
set
forth
above,
section
52.21
is
amended:
a.
By
redesignating
paragraph
(
a)
as
paragraph
(
a)(
1).
b.
By
adding
paragraph
(
a)(
2).
c.
By
revising
paragraphs
(
b)(
2)(
i)
and
(
ii).
d.
By
revising
paragraph
(
b)(
2)(
iii)(
h).
e.
By
adding
paragraph
(
b)(
2)(
iv).
f.
By
revising
paragraph
(
b)(
3)(
i).
g.
By
revising
paragraphs
(
b)(
3)(
iii)
and
(
iv).
h.
By
revising
paragraphs
(
b)(
3)(
vi)(
b)
and
(
c).
i.
By
adding
paragraph
(
b)(
3)(
vi)(
d).
j.
By
adding
paragraph
(
b)(
3)(
ix).
k.
By
revising
paragraphs
(
b)(
7)
and
(
8).
l.
By
revising
paragraph
(
b)(
13).
m.
By
revising
paragraph
(
b)(
21).
n.
By
removing
the
following
items
from
the
list
in
paragraph
(
b)(
23)(
i):
``
Asbestos:
0.007
tpy'';
``
Beryllium:
0.0004
tpy'';
``
Mercury:
0.1
tpy'';
and
``
Vinyl
Chloride:
1
tpy''.
o.
By
revising
paragraph
(
b)(
32).
p.
By
removing
and
reserving
paragraph
(
b)(
33).
q.
By
adding
paragraphs
(
b)(
39)
through
(
48),
adding
and
reserving
paragraph
(
b)(
49),
and
by
adding
paragraphs
(
b)(
50)
through
(
b)(
54).
r.
By
revising
the
introductory
text
of
paragraph
(
i).
s.
By
removing
paragraphs
(
i)(
1)
through
(
3).
t.
By
redesignating
paragraphs
(
i)(
4)
through
(
13)
as
paragraphs
(
i)(
1)
through
(
10).
u.
By
removing
the
following
items
from
the
list
in
newly
redesignated
paragraph
(
i)(
5)(
i):
``
Mercury
0.25
µ
g/
m3,
24
hour
average'';
``
Beryllium
0.001
µ
g/
m3,
24
hour
average'';
``
Vinyl
chloride
15
µ
g/
m3,
24
hour
average''.
v.
By
adding
and
reserving
paragraphs
(
r)(
5)
and
adding
paragraphs
(
r)(
6)
through
(
7).
w.
By
adding
paragraphs
(
x)
through
(
bb).
4.
In
addition
to
the
amendments
set
forth
above,
in
40
CFR
52.21,
remove
the
words
``
pollutant
subject
to
regulation
under
the
Act''
and
add,
in
their
place,
the
words
``
regulated
NSR
pollutant''
in
the
following
places:
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/
Rules
and
Regulations
a.
(
b)(
1)(
i)(
a);
b.
(
b)(
2)(
i);
c.
(
b)(
23)(
ii);
d.
newly
redesignated
(
i)(
4);
and
e.
(
j)(
2)
and
(
3).
The
revisions
and
additions
read
as
follows:
§
52.21
Prevention
of
significant
deterioration
of
air
quality.
(
a)(
1)
Plan
disapproval.
*
*
*
(
2)
Applicability
procedures.
(
i)
The
requirements
of
this
section
apply
to
the
construction
of
any
new
major
stationary
source
(
as
defined
in
paragraph
(
b)(
1)
of
this
section)
or
any
project
at
an
existing
major
stationary
source
in
an
area
designated
as
attainment
or
unclassifiable
under
sections
107(
d)(
1)(
A)(
ii)
or
(
iii)
of
the
Act.
(
ii)
The
requirements
of
paragraphs
(
j)
through
(
r)
of
this
section
apply
to
the
construction
of
any
new
major
stationary
source
or
the
major
modification
of
any
existing
major
stationary
source,
except
as
this
section
otherwise
provides.
(
iii)
No
new
major
stationary
source
or
major
modification
to
which
the
requirements
of
paragraphs
(
j)
through
(
r)(
5)
of
this
section
apply
shall
begin
actual
construction
without
a
permit
that
states
that
the
major
stationary
source
or
major
modification
will
meet
those
requirements.
The
Administrator
has
authority
to
issue
any
such
permit.
(
iv)
The
requirements
of
the
program
will
be
applied
in
accordance
with
the
principles
set
out
in
paragraphs
(
a)(
2)(
iv)(
a)
through
(
f)
of
this
section.
(
a)
Except
as
otherwise
provided
in
paragraphs
(
a)(
2)(
v)
and
(
vi)
of
this
section,
and
consistent
with
the
definition
of
major
modification
contained
in
paragraph
(
b)(
2)
of
this
section,
a
project
is
a
major
modification
for
a
regulated
NSR
pollutant
if
it
causes
two
types
of
emissions
increases
a
significant
emissions
increase
(
as
defined
in
paragraph
(
b)(
40)
of
this
section),
and
a
significant
net
emissions
increase
(
as
defined
in
paragraphs
(
b)(
3)
and
(
b)(
23)
of
this
section).
The
project
is
not
a
major
modification
if
it
does
not
cause
a
significant
emissions
increase.
If
the
project
causes
a
significant
emissions
increase,
then
the
project
is
a
major
modification
only
if
it
also
results
in
a
significant
net
emissions
increase.
(
b)
The
procedure
for
calculating
(
before
beginning
actual
construction)
whether
a
significant
emissions
increase
(
i.
e.,
the
first
step
of
the
process)
will
occur
depends
upon
the
type
of
emissions
units
being
modified,
according
to
paragraphs
(
a)(
2)(
iv)(
c)
through
(
f)
of
this
section.
The
procedure
for
calculating
(
before
beginning
actual
construction)
whether
a
significant
net
emissions
increase
will
occur
at
the
major
stationary
source
(
i.
e.,
the
second
step
of
the
process)
is
contained
in
the
definition
in
paragraph
(
b)(
3)
of
this
section.
Regardless
of
any
such
preconstruction
projections,
a
major
modification
results
if
the
project
causes
a
significant
emissions
increase
and
a
significant
net
emissions
increase.
(
c)
Actual
to
projected
actual
applicability
test
for
projects
that
only
involve
existing
emissions
units.
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
is
projected
to
occur
if
the
sum
of
the
difference
between
the
projected
actual
emissions
(
as
defined
in
paragraph
(
b)(
41)
of
this
section)
and
the
baseline
actual
emissions
(
as
defined
in
paragraphs
(
b)(
48)(
i)
and
(
ii)
of
this
section),
for
each
existing
emissions
unit,
equals
or
exceeds
the
significant
amount
for
that
pollutant
(
as
defined
in
paragraph
(
b)(
23)
of
this
section).
(
d)
Actual
to
potential
test
for
projects
that
only
involve
construction
of
a
new
emissions
unit(
s).
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
is
projected
to
occur
if
the
sum
of
the
difference
between
the
potential
to
emit
(
as
defined
in
paragraph
(
b)(
4)
of
this
section)
from
each
new
emissions
unit
following
completion
of
the
project
and
the
baseline
actual
emissions
(
as
defined
in
paragraph
(
b)(
48)(
iii)
of
this
section)
of
these
units
before
the
project
equals
or
exceeds
the
significant
amount
for
that
pollutant
(
as
defined
in
paragraph
(
b)(
23)
of
this
section).
(
e)
Emission
test
for
projects
that
involve
Clean
Units.
For
a
project
that
will
be
constructed
and
operated
at
a
Clean
Unit
without
causing
the
emissions
unit
to
lose
its
Clean
Unit
designation,
no
emissions
increase
is
deemed
to
occur.
(
f)
Hybrid
test
for
projects
that
involve
multiple
types
of
emissions
units.
A
significant
emissions
increase
of
a
regulated
NSR
pollutant
is
projected
to
occur
if
the
sum
of
the
emissions
increases
for
each
emissions
unit,
using
the
method
specified
in
paragraphs
(
a)(
2)(
iv)(
c)
through
(
e)
of
this
section
as
applicable
with
respect
to
each
emissions
unit,
for
each
type
of
emissions
unit
equals
or
exceeds
the
significant
amount
for
that
pollutant
(
as
defined
in
paragraph
(
b)(
23)
of
this
section).
For
example,
if
a
project
involves
both
an
existing
emissions
unit
and
a
Clean
Unit,
the
projected
increase
is
determined
by
summing
the
values
determined
using
the
method
specified
in
paragraph
(
a)(
2)(
iv)(
c)
of
this
section
for
the
existing
unit
and
using
the
method
specified
in
paragraph
(
a)(
2)(
iv)(
e)
of
this
section
for
the
Clean
Unit.
(
v)
For
any
major
stationary
source
for
a
PAL
for
a
regulated
NSR
pollutant,
the
major
stationary
source
shall
comply
with
the
requirements
under
paragraph
(
aa)
of
this
section.
(
vi)
An
owner
or
operator
undertaking
a
PCP
(
as
defined
in
paragraph
(
b)(
32)
of
this
section)
shall
comply
with
the
requirements
under
paragraph
(
z)
of
this
section.
*
*
*
*
*
(
b)
*
*
*
(
2)(
i)
Major
modification
means
any
physical
change
in
or
change
in
the
method
of
operation
of
a
major
stationary
source
that
would
result
in:
a
significant
emissions
increase
(
as
defined
in
paragraph
(
b)(
40)
of
this
section)
of
a
regulated
NSR
pollutant
(
as
defined
in
paragraph
(
b)(
50)
of
this
section);
and
a
significant
net
emissions
increase
of
that
pollutant
from
the
major
stationary
source.
(
ii)
Any
significant
emissions
increase
(
as
defined
in
paragraph
(
b)(
40)
of
this
section)
from
any
emissions
units
or
net
emissions
increase
(
as
defined
in
paragraph
(
b)(
3)
of
this
section)
at
a
major
stationary
source
that
is
significant
for
volatile
organic
compounds
shall
be
considered
significant
for
ozone.
(
iii)
*
*
*
(
h)
The
addition,
replacement,
or
use
of
a
PCP,
as
defined
in
paragraph
(
b)(
32)
of
this
section,
at
an
existing
emissions
unit
meeting
the
requirements
of
paragraph
(
z)
of
this
section.
A
replacement
control
technology
must
provide
more
effective
emission
control
than
that
of
the
replaced
control
technology
to
qualify
for
this
exclusion.
*
*
*
*
*
(
iv)
This
definition
shall
not
apply
with
respect
to
a
particular
regulated
NSR
pollutant
when
the
major
stationary
source
is
complying
with
the
requirements
under
paragraph
(
aa)
of
this
section
for
a
PAL
for
that
pollutant.
Instead,
the
definition
at
paragraph
(
aa)(
2)(
viii)
of
this
section
shall
apply.
(
3)(
i)
Net
emissions
increase
means,
with
respect
to
any
regulated
NSR
pollutant
emitted
by
a
major
stationary
source,
the
amount
by
which
the
sum
of
the
following
exceeds
zero:
(
a)
The
increase
in
emissions
from
a
particular
physical
change
or
change
in
the
method
of
operation
at
a
stationary
source
as
calculated
pursuant
to
paragraph
(
a)(
2)(
iv)
of
this
section;
and
(
b)
Any
other
increases
and
decreases
in
actual
emissions
at
the
major
stationary
source
that
are
contemporaneous
with
the
particular
change
and
are
otherwise
creditable.
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Rules
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Regulations
Baseline
actual
emissions
for
calculating
increases
and
decreases
under
this
paragraph
(
b)(
3)(
i)(
b)
shall
be
determined
as
provided
in
paragraph
(
b)(
48)
of
this
section,
except
that
paragraphs
(
b)(
48)(
i)(
c)
and
(
b)(
48)(
ii)(
d)
of
this
section
shall
not
apply.
*
*
*
*
*
(
iii)
An
increase
or
decrease
in
actual
emissions
is
creditable
only
if:
(
a)
The
Administrator
or
other
reviewing
authority
has
not
relied
on
it
in
issuing
a
permit
for
the
source
under
this
section,
which
permit
is
in
effect
when
the
increase
in
actual
emissions
from
the
particular
change
occurs;
and
(
b)
The
increase
or
decrease
in
emissions
did
not
occur
at
a
Clean
Unit
except
as
provided
in
paragraphs
(
x)(
8)
and
(
y)(
10)
of
this
section.
(
iv)
An
increase
or
decrease
in
actual
emissions
of
sulfur
dioxide,
particulate
matter,
or
nitrogen
oxides
that
occurs
before
the
applicable
minor
source
baseline
date
is
creditable
only
if
it
is
required
to
be
considered
in
calculating
the
amount
of
maximum
allowable
increases
remaining
available.
*
*
*
*
*
(
vi)
*
*
*
(
b)
It
is
enforceable
as
a
practical
matter
at
and
after
the
time
that
actual
construction
on
the
particular
change
begins.
(
c)
It
has
approximately
the
same
qualitative
significance
for
public
health
and
welfare
as
that
attributed
to
the
increase
from
the
particular
change;
and
(
d)
The
decrease
in
actual
emissions
did
not
result
from
the
installation
of
add
on
control
technology
or
application
of
pollution
prevention
practices
that
were
relied
on
in
designating
an
emissions
unit
as
a
Clean
Unit
under
paragraph
(
y)
of
this
section
or
under
regulations
approved
pursuant
to
§
51.165(
d)
or
to
§
51.166(
u)
of
this
chapter.
That
is,
once
an
emissions
unit
has
been
designated
as
a
Clean
Unit,
the
owner
or
operator
cannot
later
use
the
emissions
reduction
from
the
air
pollution
control
measures
that
the
designation
is
based
on
in
calculating
the
net
emissions
increase
for
another
emissions
unit
(
i.
e.,
must
not
use
that
reduction
in
a
``
netting
analysis''
for
another
emissions
unit).
However,
any
new
emission
reductions
that
were
not
relied
upon
in
a
PCP
excluded
pursuant
to
paragraph
(
z)
of
this
section
or
for
a
Clean
Unit
designation
are
creditable
to
the
extent
they
meet
the
requirements
in
paragraph
(
z)(
6)(
iv)
of
this
section
for
the
PCP
and
paragraphs
(
x)(
8)
or
(
y)(
10)
of
this
section
for
a
Clean
Unit.
*
*
*
*
*
(
ix)
Paragraph
(
b)(
21)(
ii)
of
this
section
shall
not
apply
for
determining
creditable
increases
and
decreases.
(
7)
Emissions
unit
means
any
part
of
a
stationary
source
that
emits
or
would
have
the
potential
to
emit
any
regulated
NSR
pollutant
and
includes
an
electric
utility
steam
generating
unit
as
defined
in
paragraph
(
b)(
31)
of
this
section.
For
purposes
of
this
section,
there
are
two
types
of
emissions
units
as
described
in
paragraphs
(
b)(
7)(
i)
and
(
ii)
of
this
section.
(
i)
A
new
emissions
unit
is
any
emissions
unit
that
is
(
or
will
be)
newly
constructed
and
that
has
existed
for
less
than
2
years
from
the
date
such
emissions
unit
first
operated.
(
ii)
An
existing
emissions
unit
is
any
emissions
unit
that
does
not
meet
the
requirements
in
paragraph
(
b)(
7)(
i)
of
this
section.
(
8)
Construction
means
any
physical
change
or
change
in
the
method
of
operation
(
including
fabrication,
erection,
installation,
demolition,
or
modification
of
an
emissions
unit)
that
would
result
in
a
change
in
emissions.
*
*
*
*
*
(
13)(
i)
Baseline
concentration
means
that
ambient
concentration
level
that
exists
in
the
baseline
area
at
the
time
of
the
applicable
minor
source
baseline
date.
A
baseline
concentration
is
determined
for
each
pollutant
for
which
a
minor
source
baseline
date
is
established
and
shall
include:
(
a)
The
actual
emissions,
as
defined
in
paragraph
(
b)(
21)
of
this
section,
representative
of
sources
in
existence
on
the
applicable
minor
source
baseline
date,
except
as
provided
in
paragraph
(
b)(
13)(
ii)
of
this
section;
and
(
b)
The
allowable
emissions
of
major
stationary
sources
that
commenced
construction
before
the
major
source
baseline
date,
but
were
not
in
operation
by
the
applicable
minor
source
baseline
date.
(
ii)
The
following
will
not
be
included
in
the
baseline
concentration
and
will
affect
the
applicable
maximum
allowable
increase(
s):
(
a)
Actual
emissions,
as
defined
in
paragraph
(
b)(
21)
of
this
section,
from
any
major
stationary
source
on
which
construction
commenced
after
the
major
source
baseline
date;
and
(
b)
Actual
emissions
increases
and
decreases,
as
defined
in
paragraph
(
b)(
21)
of
this
section,
at
any
stationary
source
occurring
after
the
minor
source
baseline
date.
*
*
*
*
*
(
21)(
i)
Actual
emissions
means
the
actual
rate
of
emissions
of
a
regulated
NSR
pollutant
from
an
emissions
unit,
as
determined
in
accordance
with
paragraphs
(
b)(
21)(
ii)
through
(
iv)
of
this
section,
except
that
this
definition
shall
not
apply
for
calculating
whether
a
significant
emissions
increase
has
occurred,
or
for
establishing
a
PAL
under
paragraph
(
aa)
of
this
section.
Instead,
paragraphs
(
b)(
41)
and
(
b)(
48)
of
this
section
shall
apply
for
those
purposes.
(
ii)
In
general,
actual
emissions
as
of
a
particular
date
shall
equal
the
average
rate,
in
tons
per
year,
at
which
the
unit
actually
emitted
the
pollutant
during
a
consecutive
24
month
period
which
precedes
the
particular
date
and
which
is
representative
of
normal
source
operation.
The
Administrator
shall
allow
the
use
of
a
different
time
period
upon
a
determination
that
it
is
more
representative
of
normal
source
operation.
Actual
emissions
shall
be
calculated
using
the
unit's
actual
operating
hours,
production
rates,
and
types
of
materials
processed,
stored,
or
combusted
during
the
selected
time
period.
(
iii)
The
Administrator
may
presume
that
source
specific
allowable
emissions
for
the
unit
are
equivalent
to
the
actual
emissions
of
the
unit.
(
iv)
For
any
emissions
unit
that
has
not
begun
normal
operations
on
the
particular
date,
actual
emissions
shall
equal
the
potential
to
emit
of
the
unit
on
that
date.
*
*
*
*
*
(
32)
Pollution
control
project
(
PCP)
means
any
activity,
set
of
work
practices
or
project
(
including
pollution
prevention
as
defined
under
paragraph
(
b)(
39)
of
this
section)
undertaken
at
an
existing
emissions
unit
that
reduces
emissions
of
air
pollutants
from
such
unit.
Such
qualifying
activities
or
projects
can
include
the
replacement
or
upgrade
of
an
existing
emissions
control
technology
with
a
more
effective
unit.
Other
changes
that
may
occur
at
the
source
are
not
considered
part
of
the
PCP
if
they
are
not
necessary
to
reduce
emissions
through
the
PCP.
Projects
listed
in
paragraphs
(
b)(
32)(
i)
through
(
vi)
of
this
section
are
presumed
to
be
environmentally
beneficial
pursuant
to
paragraph
(
z)(
2)(
i)
of
this
section.
Projects
not
listed
in
these
paragraphs
may
qualify
for
a
case
specific
PCP
exclusion
pursuant
to
the
requirements
of
paragraphs
(
z)(
2)
and
(
z)(
5)
of
this
section.
(
i)
Conventional
or
advanced
flue
gas
desulfurization
or
sorbent
injection
for
control
of
SO2.
(
ii)
Electrostatic
precipitators,
baghouses,
high
efficiency
multiclones,
or
scrubbers
for
control
of
particulate
matter
or
other
pollutants.
(
iii)
Flue
gas
recirculation,
low
NOX
burners
or
combustors,
selective
non
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Rules
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Regulations
catalytic
reduction,
selective
catalytic
reduction,
low
emission
combustion
(
for
IC
engines),
and
oxidation/
absorption
catalyst
for
control
of
NOX.
(
iv)
Regenerative
thermal
oxidizers,
catalytic
oxidizers,
condensers,
thermal
incinerators,
hydrocarbon
combustion
flares,
biofiltration,
absorbers
and
adsorbers,
and
floating
roofs
for
storage
vessels
for
control
of
volatile
organic
compounds
or
hazardous
air
pollutants.
For
the
purpose
of
this
section,
``
hydrocarbon
combustion
flare''
means
either
a
flare
used
to
comply
with
an
applicable
NSPS
or
MACT
standard
(
including
uses
of
flares
during
startup,
shutdown,
or
malfunction
permitted
under
such
a
standard),
or
a
flare
that
serves
to
control
emissions
of
waste
streams
comprised
predominately
of
hydrocarbons
and
containing
no
more
than
230
mg/
dscm
hydrogen
sulfide.
(
v)
Activities
or
projects
undertaken
to
accommodate
switching
(
or
partially
switching)
to
an
inherently
less
polluting
fuel,
to
be
limited
to
the
following
fuel
switches:
(
a)
Switching
from
a
heavier
grade
of
fuel
oil
to
a
lighter
fuel
oil,
or
any
grade
of
oil
to
0.05
percent
sulfur
diesel
(
i.
e.,
from
a
higher
sulfur
content
#
2
fuel
or
from
#
6
fuel,
to
CA
0.05
percent
sulfur
#
2
diesel);
(
b)
Switching
from
coal,
oil,
or
any
solid
fuel
to
natural
gas,
propane,
or
gasified
coal;
(
c)
Switching
from
coal
to
wood,
excluding
construction
or
demolition
waste,
chemical
or
pesticide
treated
wood,
and
other
forms
of
``
unclean''
wood;
(
d)
Switching
from
coal
to
#
2
fuel
oil
(
0.5
percent
maximum
sulfur
content);
and
(
e)
Switching
from
high
sulfur
coal
to
low
sulfur
coal
(
maximum
1.2
percent
sulfur
content).
(
vi)
Activities
or
projects
undertaken
to
accommodate
switching
from
the
use
of
one
ozone
depleting
substance
(
ODS)
to
the
use
of
a
substance
with
a
lower
or
zero
ozone
depletion
potential
(
ODP,)
including
changes
to
equipment
needed
to
accommodate
the
activity
or
project,
that
meet
the
requirements
of
paragraphs
(
b)(
32)(
vi)(
a)
and
(
b)
of
this
section.
(
a)
The
productive
capacity
of
the
equipment
is
not
increased
as
a
result
of
the
activity
or
project.
(
b)
The
projected
usage
of
the
new
substance
is
lower,
on
an
ODP
weighted
basis,
than
the
baseline
usage
of
the
replaced
ODS.
To
make
this
determination,
follow
the
procedure
in
paragraphs
(
b)(
32)(
vi)(
b)(
1)
through
(
4)
of
this
section.
(
1)
Determine
the
ODP
of
the
substances
by
consulting
40
CFR
part
82,
subpart
A,
appendices
A
and
B.
(
2)
Calculate
the
replaced
ODPweighted
amount
by
multiplying
the
baseline
actual
usage
(
using
the
annualized
average
of
any
24
consecutive
months
of
usage
within
the
past
10
years)
by
the
ODP
of
the
replaced
ODS.
(
3)
Calculate
the
projected
ODPweighted
amount
by
multiplying
the
projected
actual
usage
of
the
new
substance
by
its
ODP.
(
4)
If
the
value
calculated
in
paragraph
(
b)(
32)(
vi)(
b)(
2)
of
this
section
is
more
than
the
value
calculated
in
paragraph
(
b)(
32)(
vi)(
b)(
3)
of
this
section,
then
the
projected
use
of
the
new
substance
is
lower,
on
an
ODPweighted
basis,
than
the
baseline
usage
of
the
replaced
ODS.
(
33)
[
Reserved]
*
*
*
*
*
(
39)
Pollution
prevention
means
any
activity
that
through
process
changes,
product
reformulation
or
redesign,
or
substitution
of
less
polluting
raw
materials,
eliminates
or
reduces
the
release
of
air
pollutants
(
including
fugitive
emissions)
and
other
pollutants
to
the
environment
prior
to
recycling,
treatment,
or
disposal;
it
does
not
mean
recycling
(
other
than
certain
``
in
process
recycling''
practices),
energy
recovery,
treatment,
or
disposal.
(
40)
Significant
emissions
increase
means,
for
a
regulated
NSR
pollutant,
an
increase
in
emissions
that
is
significant
(
as
defined
in
paragraph
(
b)(
23)
of
this
section)
for
that
pollutant.
(
41)(
i)
Projected
actual
emissions
means
the
maximum
annual
rate,
in
tons
per
year,
at
which
an
existing
emissions
unit
is
projected
to
emit
a
regulated
NSR
pollutant
in
any
one
of
the
5
years
(
12
month
period)
following
the
date
the
unit
resumes
regular
operation
after
the
project,
or
in
any
one
of
the
10
years
following
that
date,
if
the
project
involves
increasing
the
emissions
unit's
design
capacity
or
its
potential
to
emit
that
regulated
NSR
pollutant
and
full
utilization
of
the
unit
would
result
in
a
significant
emissions
increase
or
a
significant
net
emissions
increase
at
the
major
stationary
source.
(
ii)
In
determining
the
projected
actual
emissions
under
paragraph
(
b)(
41)(
i)
of
this
section
(
before
beginning
actual
construction),
the
owner
or
operator
of
the
major
stationary
source:
(
a)
Shall
consider
all
relevant
information,
including
but
not
limited
to,
historical
operational
data,
the
company's
own
representations,
the
company's
expected
business
activity
and
the
company's
highest
projections
of
business
activity,
the
company's
filings
with
the
State
or
Federal
regulatory
authorities,
and
compliance
plans
under
the
approved
State
Implementation
Plan;
and
(
b)
Shall
include
fugitive
emissions
to
the
extent
quantifiable
and
emissions
associated
with
startups,
shutdowns,
and
malfunctions;
and
(
c)
Shall
exclude,
in
calculating
any
increase
in
emissions
that
results
from
he
particular
project,
that
portion
of
the
unit's
emissions
following
the
project
that
an
existing
unit
could
have
accommodated
during
the
consecutive
24
month
period
used
to
establish
the
baseline
actual
emissions
under
paragraph
(
b)(
48)
of
this
section
and
that
are
also
unrelated
to
the
particular
project,
including
any
increased
utilization
due
to
product
demand
growth;
or
(
d)
In
lieu
of
using
the
method
set
out
in
paragraphs
(
a)(
41)(
ii)(
a)
through
(
c)
of
this
section,
may
elect
to
use
the
emissions
unit's
potential
to
emit,
in
tons
per
year,
as
defined
under
paragraph
(
b)(
4)
of
this
section.
(
42)
Clean
Unit
means
any
emissions
unit
that
has
been
issued
a
major
NSR
permit
that
requires
compliance
with
BACT
or
LAER,
is
complying
with
such
BACT/
LAER
requirements,
and
qualifies
as
a
Clean
Unit
pursuant
to
paragraph
(
x)
of
this
section;
or
any
emissions
unit
that
has
been
designated
by
the
Administrator
as
a
Clean
Unit,
based
on
the
criteria
in
paragraphs
(
y)(
3)(
i)
through
(
iv)
of
this
section;
or
any
emissions
unit
that
has
been
issued
a
major
NSR
permit
that
requires
compliance
with
BACT
or
LAER,
is
complying
with
such
BACT/
LAER
requirements,
and
qualifies
as
a
Clean
Unit
pursuant
to
regulations
approved
into
the
State
Implementation
Plan
in
accordance
with
§
51.165(
c)
or
§
51.166(
u)
of
this
chapter;
or
any
emissions
unit
that
has
been
designated
by
the
reviewing
authority
as
a
Clean
Unit
in
accordance
with
regulations
approved
into
the
plan
to
carry
out
§
51.165(
d)
or
§
51.166(
u)
of
this
chapter.
(
43)
Prevention
of
Significant
Deterioration
(
PSD)
program
means
the
EPA
implemented
major
source
preconstruction
permit
programs
under
this
section
or
a
major
source
preconstruction
permit
program
that
has
been
approved
by
the
Administrator
and
incorporated
into
the
State
Implementation
Plan
pursuant
to
§
51.166
of
this
chapter
to
implement
the
requirements
of
that
section.
Any
permit
issued
under
such
a
program
is
a
major
NSR
permit.
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(
44)
Continuous
emissions
monitoring
system
(
CEMS)
means
all
of
the
equipment
that
may
be
required
to
meet
the
data
acquisition
and
availability
requirements
of
this
section,
to
sample,
condition
(
if
applicable),
analyze,
and
provide
a
record
of
emissions
on
a
continuous
basis.
(
45)
Predictive
emissions
monitoring
system
(
PEMS)
means
all
of
the
equipment
necessary
to
monitor
process
and
control
device
operational
parameters
(
for
example,
control
device
secondary
voltages
and
electric
currents)
and
other
information
(
for
example,
gas
flow
rate,
O2
or
CO2
concentrations),
and
calculate
and
record
the
mass
emissions
rate
(
for
example,
lb/
hr)
on
a
continuous
basis.
(
46)
Continuous
parameter
monitoring
system
(
CPMS)
means
all
of
the
equipment
necessary
to
meet
the
data
acquisition
and
availability
requirements
of
this
section,
to
monitor
process
and
control
device
operational
parameters
(
for
example,
control
device
secondary
voltages
and
electric
currents)
and
other
information
(
for
example,
gas
flow
rate,
O2
or
CO2
concentrations),
and
to
record
average
operational
parameter
value(
s)
on
a
continuous
basis.
(
47)
Continuous
emissions
rate
monitoring
system
(
CERMS)
means
the
total
equipment
required
for
the
determination
and
recording
of
the
pollutant
mass
emissions
rate
(
in
terms
of
mass
per
unit
of
time).
(
48)
Baseline
actual
emissions
means
the
rate
of
emissions,
in
tons
per
year,
of
a
regulated
NSR
pollutant,
as
determined
in
accordance
with
paragraphs
(
b)(
48)(
i)
through
(
iv)
of
this
section.
(
i)
For
any
existing
electric
utility
steam
generating
unit,
baseline
actual
emissions
means
the
average
rate,
in
tons
per
year,
at
which
the
unit
actually
emitted
the
pollutant
during
any
consecutive
24
month
period
selected
by
the
owner
or
operator
within
the
5
year
period
immediately
preceding
when
the
owner
or
operator
begins
actual
construction
of
the
project.
The
Administrator
shall
allow
the
use
of
a
different
time
period
upon
a
determination
that
it
is
more
representative
of
normal
source
operation.
(
a)
The
average
rate
shall
include
fugitive
emissions
to
the
extent
quantifiable,
and
emissions
associated
with
startups,
shutdowns,
and
malfunctions.
(
b)
The
average
rate
shall
be
adjusted
downward
to
exclude
any
noncompliant
emissions
that
occurred
while
the
source
was
operating
above
any
emission
limitation
that
was
legally
enforceable
during
the
consecutive
24
month
period.
(
c)
For
a
regulated
NSR
pollutant,
when
a
project
involves
multiple
emissions
units,
only
one
consecutive
24
month
period
must
be
used
to
determine
the
baseline
actual
emissions
for
the
emissions
units
being
changed.
A
different
consecutive
24
month
period
can
be
used
For
each
regulated
NSR
pollutant.
(
d)
The
average
rate
shall
not
be
based
on
any
consecutive
24
month
period
for
which
there
is
inadequate
information
for
determining
annual
emissions,
in
tons
per
year,
and
for
adjusting
this
amount
if
required
by
paragraph
(
b)(
48)(
i)(
b)
of
this
section.
(
ii)
For
an
existing
emissions
unit
(
other
than
an
electric
utility
steam
generating
unit),
baseline
actual
emissions
means
the
average
rate,
in
tons
per
year,
at
which
the
emissions
unit
actually
emitted
the
pollutant
during
any
consecutive
24
month
period
selected
by
the
owner
or
operator
within
the
10
year
period
immediately
preceding
either
the
date
the
owner
or
operator
begins
actual
construction
of
the
project,
or
the
date
a
complete
permit
application
is
received
by
the
Administrator
for
a
permit
required
under
this
section
or
by
the
reviewing
authority
for
a
permit
required
by
a
plan,
whichever
is
earlier,
except
that
the
10
year
period
shall
not
include
any
period
earlier
than
November
15,
1990.
(
a)
The
average
rate
shall
include
fugitive
emissions
to
the
extent
quantifiable,
and
emissions
associated
with
startups,
shutdowns,
and
malfunctions.
(
b)
The
average
rate
shall
be
adjusted
downward
to
exclude
any
noncompliant
emissions
that
occurred
while
the
source
was
operating
above
an
emission
limitation
that
was
legally
enforceable
during
the
consecutive
24
month
period.
(
c)
The
average
rate
shall
be
adjusted
downward
to
exclude
any
emissions
that
would
have
exceeded
an
emission
limitation
with
which
the
major
stationary
source
must
currently
comply,
had
such
major
stationary
source
been
required
to
comply
with
such
limitations
during
the
consecutive
24
month
period.
However,
if
an
emission
limitation
is
part
of
a
maximum
achievable
control
technology
standard
that
the
Administrator
proposed
or
promulgated
under
part
63
of
this
chapter,
the
baseline
actual
emissions
need
only
be
adjusted
if
the
State
has
taken
credit
for
such
emissions
reductions
in
an
attainment
demonstration
or
maintenance
plan
consistent
with
the
requirements
of
§
51.165(
a)(
3)(
ii)(
G)
of
this
chapter.
(
d)
For
a
regulated
NSR
pollutant,
when
a
project
involves
multiple
emissions
units,
only
one
consecutive
24
month
period
must
be
used
to
determine
the
baseline
actual
emissions
for
all
the
emissions
units
being
changed.
A
different
consecutive
24
month
period
can
be
used
For
each
regulated
NSR
pollutant.
(
e)
The
average
rate
shall
not
be
based
on
any
consecutive
24
month
period
for
which
there
is
inadequate
information
for
determining
annual
emissions,
in
tons
per
year,
and
for
adjusting
this
amount
if
required
by
paragraphs
(
b)(
48)(
ii)(
b)
and
(
c)
of
this
section.
(
iii)
For
a
new
emissions
unit,
the
baseline
actual
emissions
for
purposes
of
determining
the
emissions
increase
that
will
result
from
the
initial
construction
and
operation
of
such
unit
shall
equal
zero;
and
thereafter,
for
all
other
purposes,
shall
equal
the
unit's
potential
to
emit.
(
iv)
For
a
PAL
for
a
stationary
source,
the
baseline
actual
emissions
shall
be
calculated
for
existing
electric
utility
steam
generating
units
in
accordance
with
the
procedures
contained
in
paragraph
(
b)(
48)(
i)
of
this
section,
for
other
existing
emissions
units
in
accordance
with
the
procedures
contained
in
paragraph
(
b)(
48)(
ii)
of
this
section,
and
for
a
new
emissions
unit
in
accordance
with
the
procedures
contained
in
paragraph
(
b)(
48)(
iii)
of
this
section.
(
49)
[
Reserved]
(
50)
Regulated
NSR
pollutant,
for
purposes
of
this
section,
means
the
following:
(
i)
Any
pollutant
for
which
a
national
ambient
air
quality
standard
has
been
promulgated
and
any
constituents
or
precursors
for
such
pollutants
identified
by
the
Administrator
(
e.
g.,
volatile
organic
compounds
are
precursors
for
ozone);
(
ii)
Any
pollutant
that
is
subject
to
any
standard
promulgated
under
section
111
of
the
Act;
(
iii)
Any
Class
I
or
II
substance
subject
to
a
standard
promulgated
under
or
established
by
title
VI
of
the
Act;
or
(
iv)
Any
pollutant
that
otherwise
is
subject
to
regulation
under
the
Act;
except
that
any
or
all
hazardous
air
pollutants
either
listed
in
section
112
of
the
Act
or
added
to
the
list
pursuant
to
section
112(
b)(
2)
of
the
Act,
which
have
not
been
delisted
pursuant
to
section
112(
b)(
3)
of
the
Act,
are
not
regulated
NSR
pollutants
unless
the
listed
hazardous
air
pollutant
is
also
regulated
as
a
constituent
or
precursor
of
a
general
pollutant
listed
under
section
108
of
the
Act.
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Vol.
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/
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December
31,
2002
/
Rules
and
Regulations
(
51)
Reviewing
authority
means
the
State
air
pollution
control
agency,
local
agency,
other
State
agency,
Indian
tribe,
or
other
agency
authorized
by
the
Administrator
to
carry
out
a
permit
program
under
§
51.165
and
§
51.166
of
this
chapter,
or
the
Administrator
in
the
case
of
EPA
implemented
permit
programs
under
this
section.
(
52)
Project
means
a
physical
change
in,
or
change
in
the
method
of
operation
of,
an
existing
major
stationary
source.
(
53)
Lowest
achievable
emission
rate
(
LAER)
is
as
defined
in
§
51.165(
a)(
1)(
xiii)
of
this
chapter.
(
54)
Reasonably
available
control
technology
(
RACT)
is
as
defined
in
§
51.100(
o)
of
this
chapter.
*
*
*
*
*
(
i)
Exemptions.
*
*
*
*
*
*
*
*
(
r)
*
*
*
(
5)
[
Reserved]
(
6)
The
provisions
of
this
paragraph
(
r)(
6)
apply
to
projects
at
an
existing
emissions
unit
at
a
major
stationary
source
(
other
than
projects
at
a
Clean
Unit
or
at
a
source
with
a
PAL)
in
circumstances
where
there
is
a
reasonable
possibility
that
a
project
that
is
not
a
part
of
a
major
modification
may
result
in
a
significant
emissions
increase
and
the
owner
or
operator
elects
to
use
the
method
specified
in
paragraphs
(
b)(
41)(
ii)(
a)
through
(
c)
of
this
section
for
calculating
projected
actual
emissions.
(
i)
Before
beginning
actual
construction
of
the
project,
the
owner
or
operator
shall
document
and
maintain
a
record
of
the
following
information:
(
a)
A
description
of
the
project;
(
b)
Identification
of
the
emissions
unit(
s)
whose
emissions
of
a
regulated
NSR
pollutant
could
be
affected
by
the
project;
and
(
c)
A
description
of
the
applicability
test
used
to
determine
that
the
project
is
not
a
major
modification
for
any
regulated
NSR
pollutant,
including
the
baseline
actual
emissions,
the
projected
actual
emissions,
the
amount
of
emissions
excluded
under
paragraph
(
b)(
41)(
ii)(
c)
of
this
section
and
an
explanation
for
why
such
amount
was
excluded,
and
any
netting
calculations,
if
applicable.
(
ii)
If
the
emissions
unit
is
an
existing
electric
utility
steam
generating
unit,
before
beginning
actual
construction,
the
owner
or
operator
shall
provide
a
copy
of
the
information
set
out
in
paragraph
(
r)(
6)(
i)
of
this
section
to
the
Administrator.
Nothing
in
this
paragraph
(
r)(
6)(
ii)
shall
be
construed
to
require
the
owner
or
operator
of
such
a
unit
to
obtain
any
determination
from
the
Administrator
before
beginning
actual
construction.
(
iii)
The
owner
or
operator
shall
monitor
the
emissions
of
any
regulated
NSR
pollutant
that
could
increase
as
a
result
of
the
project
and
that
is
emitted
by
any
emissions
unit
identified
in
paragraph
(
r)(
6)(
i)(
b)
of
this
section;
and
calculate
and
maintain
a
record
of
the
annual
emissions,
in
tons
per
year
on
a
calendar
year
basis,
for
a
period
of
5
years
following
resumption
of
regular
operations
after
the
change,
or
for
a
period
of
10
years
following
resumption
of
regular
operations
after
the
change
if
the
project
increases
the
design
capacity
of
or
potential
to
emit
that
regulated
NSR
pollutant
at
such
emissions
unit.
(
iv)
If
the
unit
is
an
existing
electric
utility
steam
generating
unit,
the
owner
or
operator
shall
submit
a
report
to
the
Administrator
within
60
days
after
the
end
of
each
year
during
which
records
must
be
generated
under
paragraph
(
r)(
6)(
iii)
of
this
section
setting
out
the
unit's
annual
emissions
during
the
calendar
year
that
preceded
submission
of
the
report.
(
v)
If
the
unit
is
an
existing
unit
other
than
an
electric
utility
steam
generating
unit,
the
owner
or
operator
shall
submit
a
report
to
the
Administrator
if
the
annual
emissions,
in
tons
per
year,
from
the
project
identified
in
paragraph
(
r)(
6)(
i)
of
this
section,
exceed
the
baseline
actual
emissions
(
as
documented
and
maintained
pursuant
to
paragraph
(
r)(
6)(
i)(
c)
of
this
section),
by
a
significant
amount
(
as
defined
in
paragraph
(
b)(
23)
of
this
section)
for
that
regulated
NSR
pollutant,
and
if
such
emissions
differ
from
the
preconstruction
projection
as
documented
and
maintained
pursuant
to
paragraph
(
r)(
6)(
i)(
c)
of
this
section.
Such
report
shall
be
submitted
to
the
Administrator
within
60
days
after
the
end
of
such
year.
The
report
shall
contain
the
following:
(
a)
The
name,
address
and
telephone
number
of
the
major
stationary
source;
(
b)
The
annual
emissions
as
calculated
pursuant
to
paragraph
(
r)(
6)(
iii)
of
this
section;
and
(
c)
Any
other
information
that
the
owner
or
operator
wishes
to
include
in
the
report
(
e.
g.,
an
explanation
as
to
why
the
emissions
differ
from
the
preconstruction
projection).
(
7)
The
owner
or
operator
of
the
source
shall
make
the
information
required
to
be
documented
and
maintained
pursuant
to
paragraph
(
r)(
6)
of
this
section
available
for
review
upon
a
request
for
inspection
by
the
Administrator
or
the
general
public
pursuant
to
the
requirements
contained
in
§
70.4(
b)(
3)(
viii)
of
this
chapter.
*
*
*
*
*
(
x)
Clean
Unit
Test
for
emissions
units
that
are
subject
to
BACT
or
LAER.
An
owner
or
operator
of
a
major
stationary
source
has
the
option
of
using
the
Clean
Unit
Test
to
determine
whether
emissions
increases
at
a
Clean
Unit
are
part
of
a
project
that
is
a
major
modification
according
to
the
provisions
in
paragraphs
(
x)(
1)
through
(
9)
of
this
section.
(
1)
Applicability.
The
provisions
of
this
paragraph
(
x)
apply
to
any
emissions
unit
for
which
a
reviewing
authority
has
issued
a
major
NSR
permit
within
the
last
10
years.
(
2)
General
provisions
for
Clean
Units.
The
provisions
in
paragraphs
(
x)(
2)(
i)
through
(
iv)
of
this
section
apply
to
a
Clean
Unit.
(
i)
Any
project
for
which
the
owner
or
operator
begins
actual
construction
after
the
effective
date
of
the
Clean
Unit
designation
(
as
determined
in
accordance
with
paragraph
(
x)(
4)
of
this
section)
and
before
the
expiration
date
(
as
determined
in
accordance
with
paragraph
(
x)(
5)
of
this
section)
will
be
considered
to
have
occurred
while
the
emissions
unit
was
a
Clean
Unit.
(
ii)
If
a
project
at
a
Clean
Unit
does
not
cause
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
were
adopted
in
conjunction
with
BACT
and
the
project
would
not
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT
determination
as
specified
in
paragraph
(
x)(
6)(
iv)
of
this
section,
the
emissions
unit
remains
a
Clean
Unit.
(
iii)
If
a
project
causes
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
were
adopted
in
conjunction
with
BACT
or
the
project
would
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT
determination
as
specified
in
paragraph
(
x)(
6)(
iv)
of
this
section,
then
the
emissions
unit
loses
its
designation
as
a
Clean
Unit
upon
issuance
of
the
necessary
permit
revisions
(
unless
the
unit
re
qualifies
as
a
Clean
Unit
pursuant
to
paragraph
(
x)(
3)(
iii)
of
this
section).
If
the
owner
or
operator
begins
actual
construction
on
the
project
without
first
applying
to
revise
the
emissions
unit's
permit,
the
Clean
Unit
designation
ends
immediately
prior
to
the
time
when
actual
construction
begins.
(
iv)
A
project
that
causes
an
emissions
unit
to
lose
its
designation
as
a
Clean
Unit
is
subject
to
the
applicability
requirements
of
paragraphs
(
a)(
2)(
iv)(
a)
through
(
d)
and
paragraph
(
a)(
2)(
iv)(
f)
of
this
section
as
if
the
emissions
unit
is
not
a
Clean
Unit.
(
3)
Qualifying
or
re
qualifying
to
use
the
Clean
Unit
Applicability
Test.
An
emissions
unit
automatically
qualifies
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Vol.
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251
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Tuesday,
December
31,
2002
/
Rules
and
Regulations
as
a
Clean
Unit
when
the
unit
meets
the
criteria
in
paragraphs
(
x)(
3)(
i)
and
(
ii)
of
this
section.
After
the
original
Clean
Unit
expires
in
accordance
with
paragraph
(
x)(
5)
of
this
section
or
is
lost
pursuant
to
paragraph
(
x)(
2)(
iii)
of
this
section,
such
emissions
unit
may
requalify
as
a
Clean
Unit
under
either
paragraph
(
x)(
3)(
iii)
of
this
section,
or
under
the
Clean
Unit
provisions
in
paragraph
(
y)
of
this
section.
To
requalify
as
a
Clean
Unit
under
paragraph
(
x)(
3)(
iii)
of
this
section,
the
emissions
unit
must
obtain
a
new
major
NSR
permit
issued
through
the
applicable
PSD
program
and
meet
all
the
criteria
in
paragraph
(
x)(
3)(
iii)
of
this
section.
The
Clean
Unit
designation
applies
individually
for
each
pollutant
emitted
by
the
emissions
unit.
(
i)
Permitting
requirement.
The
emissions
unit
must
have
received
a
major
NSR
permit
within
the
last
10
years.
The
owner
or
operator
must
maintain
and
be
able
to
provide
information
that
would
demonstrate
that
this
permitting
requirement
is
met.
(
ii)
Qualifying
air
pollution
control
technologies.
Air
pollutant
emissions
from
the
emissions
unit
must
be
reduced
through
the
use
of
air
pollution
control
technology
(
which
includes
pollution
prevention
as
defined
under
paragraph
(
b)(
39)
of
this
section
or
work
practices)
that
meets
both
the
following
requirements
in
paragraphs
(
x)(
3)(
ii)(
a)
and
(
b)
of
this
section.
(
a)
The
control
technology
achieves
the
BACT
or
LAER
level
of
emissions
reductions
as
determined
through
issuance
of
a
major
NSR
permit
within
the
past
10
years.
However,
the
emissions
unit
is
not
eligible
for
the
Clean
Unit
designation
if
the
BACT
determination
resulted
in
no
requirement
to
reduce
emissions
below
the
level
of
a
standard,
uncontrolled,
new
emissions
unit
of
the
same
type.
(
b)
The
owner
or
operator
made
an
investment
to
install
the
control
technology.
For
the
purpose
of
this
determination,
an
investment
includes
expenses
to
research
the
application
of
a
pollution
prevention
technique
to
the
emissions
unit
or
expenses
to
apply
a
pollution
prevention
technique
to
an
emissions
unit.
(
iii)
Re
qualifying
for
the
Clean
Unit
designation.
The
emissions
unit
must
obtain
a
new
major
NSR
permit
that
requires
compliance
with
the
currentday
BACT
(
or
LAER),
and
the
emissions
unit
must
meet
the
requirements
in
paragraphs
(
x)(
3)(
i)
and
(
x)(
3)(
ii)
of
this
section.
(
4)
Effective
date
of
the
Clean
Unit
designation.
The
effective
date
of
an
emissions
unit's
Clean
Unit
designation
(
that
is,
the
date
on
which
the
owner
or
operator
may
begin
to
use
the
Clean
Unit
Test
to
determine
whether
a
project
at
the
emissions
unit
is
a
major
modification)
is
determined
according
to
the
applicable
paragraph
(
x)(
4)(
i)
or
(
x)(
4)(
ii)
of
this
section.
(
i)
Original
Clean
Unit
designation,
and
emissions
units
that
re
qualify
as
Clean
Units
by
implementing
new
control
technology
to
meet
current
day
BACT.
The
effective
date
is
the
date
the
emissions
unit's
air
pollution
control
technology
is
placed
into
service,
or
3
years
after
the
issuance
date
of
the
major
NSR
permit,
whichever
is
earlier,
but
no
sooner
than
March
3,
2003,
that
is
the
date
these
provisions
become
effective.
(
ii)
Emissions
units
that
re
qualify
for
the
Clean
Unit
designation
using
an
existing
control
technology.
The
effective
date
is
the
date
the
new,
major
NSR
permit
is
issued.
(
5)
Clean
Unit
expiration.
An
emissions
unit's
Clean
Unit
designation
expires
(
that
is,
the
date
on
which
the
owner
or
operator
may
no
longer
use
the
Clean
Unit
Test
to
determine
whether
a
project
affecting
the
emissions
unit
is,
or
is
part
of,
a
major
modification)
according
to
the
applicable
paragraph
(
x)(
5)(
i)
or
(
ii)
of
this
section.
(
i)
Original
Clean
Unit
designation,
and
emissions
units
that
re
qualify
by
implementing
new
control
technology
to
meet
current
day
BACT.
For
any
emissions
unit
that
automatically
qualifies
as
a
Clean
Unit
under
paragraphs
(
x)(
3)(
i)
and
(
ii)
of
this
section
or
re
qualifies
by
implementing
new
control
technology
to
meet
currentday
BACT
under
paragraph
(
x)(
3)(
iii)
of
this
section,
the
Clean
Unit
designation
expires
10
years
after
the
effective
date,
or
the
date
the
equipment
went
into
service,
whichever
is
earlier;
or,
it
expires
at
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
the
Clean
Unit
designation
in
paragraph
(
x)(
7)
of
this
section.
(
ii)
Emissions
units
that
re
qualify
for
the
Clean
Unit
designation
using
an
existing
control
technology.
For
any
emissions
unit
that
re
qualifies
as
a
Clean
Unit
under
paragraph
(
x)(
3)(
iii)
of
this
section
using
an
existing
control
technology,
the
Clean
Unit
designation
expires
10
years
after
the
effective
date;
or,
it
expires
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
the
Clean
Unit
designation
in
paragraph
(
x)(
7)
of
this
section.
(
6)
Required
title
V
permit
content
for
a
Clean
Unit.
After
the
effective
date
of
the
Clean
Unit
designation,
and
in
accordance
with
the
provisions
of
the
applicable
title
V
permit
program
under
part
70
or
part
71
of
this
chapter,
but
no
later
than
when
the
title
V
permit
is
renewed,
the
title
V
permit
for
the
major
stationary
source
must
include
the
following
terms
and
conditions
in
paragraphs
(
x)(
6)(
i)
through
(
vi)
of
this
section
related
to
the
Clean
Unit.
(
i)
A
statement
indicating
that
the
emissions
unit
qualifies
as
a
Clean
Unit
and
identifying
the
pollutant(
s)
for
which
this
designation
applies.
(
ii)
The
effective
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
Clean
Unit
designation
is
initially
recorded
in
the
title
V
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
the
permit
must
describe
the
event
that
will
determine
the
effective
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
effective
date
is
determined,
the
owner
or
operator
must
notify
the
Administrator
of
the
exact
date.
This
specific
effective
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iii)
The
expiration
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
Clean
Unit
designation
is
initially
recorded
into
the
title
V
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
then
the
permit
must
describe
the
event
that
will
determine
the
expiration
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
expiration
date
is
determined,
the
owner
or
operator
must
notify
the
Administrator
of
the
exact
date.
The
expiration
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iv)
All
emission
limitations
and
work
practice
requirements
adopted
in
conjunction
with
BACT,
and
any
physical
or
operational
characteristics
which
formed
the
basis
for
the
BACT
determination
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
v)
Monitoring,
recordkeeping,
and
reporting
requirements
as
necessary
to
demonstrate
that
the
emissions
unit
continues
to
meet
the
criteria
for
maintaining
the
Clean
Unit
designation.
(
See
paragraph
(
x)(
7)
of
this
section.)
(
vi)
Terms
reflecting
the
owner
or
operator's
duties
to
maintain
the
Clean
Unit
designation
and
the
consequences
of
failing
to
do
so,
as
presented
in
paragraph
(
x)(
7)
of
this
section.
(
7)
Maintaining
the
Clean
Unit
designation.
To
maintain
the
Clean
Unit
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
designation,
the
owner
or
operator
must
conform
to
all
the
restrictions
listed
in
paragraphs
(
x)(
7)(
i)
through
(
iii)
of
this
section.
This
paragraph
(
x)(
7)
applies
independently
to
each
pollutant
for
which
the
emissions
unit
has
the
Clean
Unit
designation.
That
is,
failing
to
conform
to
the
restrictions
for
one
pollutant
affects
the
Clean
Unit
designation
only
for
that
pollutant.
(
i)
The
Clean
Unit
must
comply
with
the
emission
limitation(
s)
and/
or
work
practice
requirements
adopted
in
conjunction
with
the
BACT
that
is
recorded
in
the
major
NSR
permit,
and
subsequently
reflected
in
the
title
V
permit.
The
owner
or
operator
may
not
make
a
physical
change
in
or
change
in
the
method
of
operation
of
the
Clean
Unit
that
causes
the
emissions
unit
to
function
in
a
manner
that
is
inconsistent
with
the
physical
or
operational
characteristics
that
formed
the
basis
for
the
BACT
determination
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
ii)
The
Clean
Unit
must
comply
with
any
terms
and
conditions
in
the
title
V
permit
related
to
the
unit's
Clean
Unit
designation.
(
iii)
The
Clean
Unit
must
continue
to
control
emissions
using
the
specific
air
pollution
control
technology
that
was
the
basis
for
its
Clean
Unit
designation.
If
the
emissions
unit
or
control
technology
is
replaced,
then
the
Clean
Unit
designation
ends.
(
8)
Netting
at
Clean
Units.
Emissions
changes
that
occur
at
a
Clean
Unit
must
not
be
included
in
calculating
a
significant
net
emissions
increase
(
that
is,
must
not
be
used
in
a
``
netting
analysis''),
unless
such
use
occurs
before
the
effective
date
of
the
Clean
Unit
designation,
or
after
the
Clean
Unit
designation
expires;
or,
unless
the
emissions
unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit.
However,
if
the
Clean
Unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit,
then
the
owner
or
operator
may
generate
a
credit
for
the
difference
between
the
level
that
qualified
the
unit
as
a
Clean
Unit
and
the
new
emissions
limit
if
such
reductions
are
surplus,
quantifiable,
and
permanent.
For
purposes
of
generating
offsets,
the
reductions
must
also
be
federally
enforceable.
For
purposes
of
determining
creditable
net
emissions
increases
and
decreases,
the
reductions
must
also
be
enforceable
as
a
practical
matter.
(
9)
Effect
of
redesignation
on
the
Clean
Unit
designation.
The
Clean
Unit
designation
of
an
emissions
unit
is
not
affected
by
re
designation
of
the
attainment
status
of
the
area
in
which
it
is
located.
That
is,
if
a
Clean
Unit
is
located
in
an
attainment
area
and
the
area
is
redesignated
to
nonattainment,
its
Clean
Unit
designation
is
not
affected.
Similarly,
redesignation
from
nonattainment
to
attainment
does
not
affect
the
Clean
Unit
designation.
However,
if
an
existing
Clean
Unit
designation
expires,
it
must
re
qualify
under
the
requirements
that
are
currently
applicable
in
the
area.
(
y)
Clean
Unit
provisions
for
emissions
units
that
achieve
an
emission
limitation
comparable
to
BACT.
An
owner
or
operator
of
a
major
stationary
source
has
the
option
of
using
the
Clean
Unit
Test
to
determine
whether
emissions
increases
at
a
Clean
Unit
are
part
of
a
project
that
is
a
major
modification
according
to
the
provisions
in
paragraphs
(
y)(
1)
through
(
11)
of
this
section.
(
1)
Applicability.
The
provisions
of
this
paragraph
(
y)
apply
to
emissions
units
which
do
not
qualify
as
Clean
Units
under
paragraph
(
x)
of
this
section,
but
which
are
achieving
a
level
of
emissions
control
comparable
to
BACT,
as
determined
by
the
Administrator
in
accordance
with
this
paragraph
(
y).
(
2)
General
provisions
for
Clean
Units.
The
provisions
in
paragraphs
(
y)(
2)(
i)
through
(
iv)
of
this
section
apply
to
a
Clean
Unit
(
designated
under
this
paragraph
(
y)).
(
i)
Any
project
for
which
the
owner
or
operator
begins
actual
construction
after
the
effective
date
of
the
Clean
Unit
designation
(
as
determined
in
accordance
with
paragraph
(
y)(
5)
of
this
section)
and
before
the
expiration
date
(
as
determined
in
accordance
with
paragraph
(
y)(
6)
of
this
section)
will
be
considered
to
have
occurred
while
the
emissions
unit
was
a
Clean
Unit.
(
ii)
If
a
project
at
a
Clean
Unit
does
not
cause
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
have
been
determined
(
pursuant
to
paragraph
(
y)(
4)
of
this
section)
to
be
comparable
to
BACT,
and
the
project
would
not
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
determining
that
the
emissions
unit's
control
technology
achieves
a
level
of
emissions
control
comparable
to
BACT
as
specified
in
paragraph
(
y)(
8)(
iv)
of
this
section,
the
emissions
unit
remains
a
Clean
Unit.
(
iii)
If
a
project
causes
the
need
for
a
change
in
the
emission
limitations
or
work
practice
requirements
in
the
permit
for
the
unit
that
have
been
determined
(
pursuant
to
paragraph
(
y)(
4)
of
this
section)
to
be
comparable
to
BACT,
or
the
project
would
alter
any
physical
or
operational
characteristics
that
formed
the
basis
for
determining
that
the
emissions
unit's
control
technology
achieves
a
level
of
emissions
control
comparable
to
BACT
as
specified
in
paragraph
(
y)(
8)(
iv)
of
this
section,
then
the
emissions
unit
loses
its
designation
as
a
Clean
Unit
upon
issuance
of
the
necessary
permit
revisions
(
unless
the
unit
re
qualifies
as
a
Clean
Unit
pursuant
to
paragraph
(
u)(
3)(
iv)
of
this
section).
If
the
owner
or
operator
begins
actual
construction
on
the
project
without
first
applying
to
revise
the
emissions
unit's
permit,
the
Clean
Unit
designation
ends
immediately
prior
to
the
time
when
actual
construction
begins.
(
iv)
A
project
that
causes
an
emissions
unit
to
lose
its
designation
as
a
Clean
Unit
is
subject
to
the
applicability
requirements
of
paragraphs
(
a)(
2)(
iv)(
a)
through
(
d)
and
paragraph
(
a)(
2)(
iv)(
f)
of
this
section
as
if
the
emissions
unit
is
not
a
Clean
Unit.
(
3)
Qualifying
or
re
qualifying
to
use
the
Clean
Unit
applicability
test.
An
emissions
unit
qualifies
as
a
Clean
Unit
when
the
unit
meets
the
criteria
in
paragraphs
(
y)(
3)(
i)
through
(
iii)
of
this
section.
After
the
original
Clean
Unit
designation
expires
in
accordance
with
paragraph
(
y)(
6)
of
this
section
or
is
lost
pursuant
to
paragraph
(
y)(
2)(
iii)
of
this
section,
such
emissions
unit
may
requalify
as
a
Clean
Unit
under
either
paragraph
(
y)(
3)(
iv)
of
this
section,
or
under
the
Clean
Unit
provisions
in
paragraph
(
x)
of
this
section.
To
requalify
as
a
Clean
Unit
under
paragraph
(
y)(
3)(
iv)
of
this
section,
the
emissions
unit
must
obtain
a
new
permit
issued
pursuant
to
the
requirements
in
paragraphs
(
y)(
7)
and
(
8)
of
this
section
and
meet
all
the
criteria
in
paragraph
(
y)(
3)(
iv)
of
this
section.
The
Administrator
will
make
a
separate
Clean
Unit
designation
for
each
pollutant
emitted
by
the
emissions
unit
for
which
the
emissions
unit
qualifies
as
a
Clean
Unit.
(
i)
Qualifying
air
pollution
control
technologies.
Air
pollutant
emissions
from
the
emissions
unit
must
be
reduced
through
the
use
of
air
pollution
control
technology
(
which
includes
pollution
prevention
as
defined
under
paragraph
(
b)(
39)
of
this
section
or
work
practices)
that
meets
both
the
following
requirements
in
paragraphs
(
y)(
3)(
i)(
a)
and
(
b)
of
this
section.
(
a)
The
owner
or
operator
has
demonstrated
that
the
emissions
unit's
control
technology
is
comparable
to
BACT
according
to
the
requirements
of
paragraph
(
y)(
4)
of
this
section.
However,
the
emissions
unit
is
not
eligible
for
a
Clean
Unit
designation
if
its
emissions
are
not
reduced
below
the
level
of
a
standard,
uncontrolled
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emissions
unit
of
the
same
type
(
e.
g.,
if
the
BACT
determinations
to
which
it
is
compared
have
resulted
in
a
determination
that
no
control
measures
are
required).
(
b)
The
owner
or
operator
made
an
investment
to
install
the
control
technology.
For
the
purpose
of
this
determination,
an
investment
includes
expenses
to
research
the
application
of
a
pollution
prevention
technique
to
the
emissions
unit
or
to
retool
the
unit
to
apply
a
pollution
prevention
technique.
(
ii)
Impact
of
emissions
from
the
unit.
The
Administrator
must
determine
that
the
allowable
emissions
from
the
emissions
unit
will
not
cause
or
contribute
to
a
violation
of
any
national
ambient
air
quality
standard
or
PSD
increment,
or
adversely
impact
an
air
quality
related
value
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
and
for
which
information
is
available
to
the
general
public.
(
iii)
Date
of
installation.
An
emissions
unit
may
qualify
as
a
Clean
Unit
even
if
the
control
technology,
on
which
the
Clean
Unit
designation
is
based,
was
installed
before
March
3,
2003.
However,
for
such
emissions
units,
the
owner
or
operator
must
apply
for
the
Clean
Unit
designation
before
December
31,
2004.
For
technologies
installed
on
and
after
March
3,
2003,
the
owner
or
operator
must
apply
for
the
Clean
Unit
designation
at
the
time
the
control
technology
is
installed.
(
iv)
Re
qualifying
as
a
Clean
Unit.
The
emissions
unit
must
obtain
a
new
permit
(
pursuant
to
requirements
in
paragraphs
(
y)(
7)
and
(
8)
of
this
section)
that
demonstrates
that
the
emissions
unit's
control
technology
is
achieving
a
level
of
emission
control
comparable
to
current
day
BACT,
and
the
emissions
unit
must
meet
the
requirements
in
paragraphs
(
y)(
3)(
i)(
a)
and
(
y)(
3)(
ii)
of
this
section.
(
4)
Demonstrating
control
effectiveness
comparable
to
BACT.
The
owner
or
operator
may
demonstrate
that
the
emissions
unit's
control
technology
is
comparable
to
BACT
for
purposes
of
paragraph
(
y)(
3)(
i)
of
this
section
according
to
either
paragraph
(
y)(
4)(
i)
or
(
ii)
of
this
section.
Paragraph
(
y)(
4)(
iii)
of
this
section
specifies
the
time
for
making
this
comparison.
(
i)
Comparison
to
previous
BACT
and
LAER
determinations.
The
Administrator
maintains
an
on
line
data
base
of
previous
determinations
of
RACT,
BACT,
and
LAER
in
the
RACT/
BACT/
LAER
Clearinghouse
(
RBLC).
The
emissions
unit's
control
technology
is
presumed
to
be
comparable
to
BACT
if
it
achieves
an
emission
limitation
that
is
equal
to
or
better
than
the
average
of
the
emission
limitations
achieved
by
all
the
sources
for
which
a
BACT
or
LAER
determination
has
been
made
within
the
preceding
5
years
and
entered
into
the
RBLC,
and
for
which
it
is
technically
feasible
to
apply
the
BACT
or
LAER
control
technology
to
the
emissions
unit.
The
Administrator
shall
also
compare
this
presumption
to
any
additional
BACT
or
LAER
determinations
of
which
he
or
she
is
aware,
and
shall
consider
any
information
on
achieved
in
practice
pollution
control
technologies
provided
during
the
public
comment
period,
to
determine
whether
any
presumptive
determination
that
the
control
technology
is
comparable
to
BACT
is
correct.
(
ii)
The
substantially
as
effective
test.
The
owner
or
operator
may
demonstrate
that
the
emissions
unit's
control
technology
is
substantially
as
effective
as
BACT.
In
addition,
any
other
person
may
present
evidence
related
to
whether
the
control
technology
is
substantially
as
effective
as
BACT
during
the
public
participation
process
required
under
paragraph
(
y)(
7)
of
this
section.
The
Administrator
shall
consider
such
evidence
on
a
case
by
case
basis
and
determine
whether
the
emissions
unit's
air
pollution
control
technology
is
substantially
as
effective
as
BACT.
(
iii)
Time
of
comparison.
(
a)
Emissions
units
with
control
technologies
that
are
installed
before
March
3,
2003.
The
owner
or
operator
of
an
emissions
unit
whose
control
technology
is
installed
before
March
3,
2003
may,
at
its
option,
either
demonstrate
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
the
BACT
requirements
that
applied
at
the
time
the
control
technology
was
installed,
or
demonstrate
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
current
day
BACT
requirements.
The
expiration
date
of
the
Clean
Unit
designation
will
depend
on
which
option
the
owner
or
operator
uses,
as
specified
in
paragraph
(
y)(
6)
of
this
section.
(
b)
Emissions
units
with
control
technologies
that
are
installed
on
and
after
March
3,
2003.
The
owner
or
operator
must
demonstrate
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
current
day
BACT
requirements.
(
5)
Effective
date
of
the
Clean
Unit
designation.
The
effective
date
of
an
emissions
unit's
Clean
Unit
designation
(
that
is,
the
date
on
which
the
owner
or
operator
may
begin
to
use
the
Clean
Unit
Test
to
determine
whether
a
project
involving
the
emissions
unit
is
a
major
modification)
is
the
date
that
the
permit
required
by
paragraph
(
y)(
7)
of
this
section
is
issued
or
the
date
that
the
emissions
unit's
air
pollution
control
technology
is
placed
into
service,
whichever
is
later.
(
6)
Clean
Unit
expiration.
If
the
owner
or
operator
demonstrates
that
the
emission
limitation
achieved
by
the
emissions
unit's
control
technology
is
comparable
to
the
BACT
requirements
that
applied
at
the
time
the
control
technology
was
installed,
then
the
Clean
Unit
designation
expires
10
years
from
the
date
that
the
control
technology
was
installed.
For
all
other
emissions
units,
the
Clean
Unit
designation
expires
10
years
from
the
effective
date
of
the
Clean
Unit
designation,
as
determined
according
to
paragraph
(
y)(
5)
of
this
section.
In
addition,
for
all
emissions
units,
the
Clean
Unit
designation
expires
any
time
the
owner
or
operator
fails
to
comply
with
the
provisions
for
maintaining
the
Clean
Unit
designation
in
paragraph
(
y)(
9)
of
this
section.
(
7)
Procedures
for
designating
emissions
units
as
Clean
Units.
The
Administrator
shall
designate
an
emissions
unit
a
Clean
Unit
only
by
issuing
a
permit
through
a
permitting
program
that
has
been
approved
by
the
Administrator
and
that
conforms
with
the
requirements
of
§
§
51.160
through
51.164
of
this
chapter
including
requirements
for
public
notice
of
the
proposed
Clean
Unit
designation
and
opportunity
for
public
comment.
Such
permit
must
also
meet
the
requirements
in
paragraph
(
y)(
8)
of
this
section.
(
8)
Required
permit
content.
The
permit
required
by
paragraph
(
y)(
7)
of
this
section
shall
include
the
terms
and
conditions
set
forth
in
paragraphs
(
y)(
8)(
i)
through
(
vi)
of
this
section.
Such
terms
and
conditions
shall
be
incorporated
into
the
major
stationary
source's
title
V
permit
in
accordance
with
the
provisions
of
the
applicable
title
V
permit
program
under
part
70
or
part
71
of
this
chapter,
but
no
later
than
when
the
title
V
permit
is
renewed.
(
i)
A
statement
indicating
that
the
emissions
unit
qualifies
as
a
Clean
Unit
and
identifying
the
pollutant(
s)
for
which
this
designation
applies.
(
ii)
The
effective
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
Administrator
issues
the
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
then
the
permit
must
describe
the
event
that
will
determine
the
effective
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
effective
date
is
known,
then
the
owner
or
operator
must
notify
the
Administrator
of
the
exact
date.
This
specific
effective
date
must
be
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added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iii)
The
expiration
date
of
the
Clean
Unit
designation.
If
this
date
is
not
known
when
the
Administrator
issues
the
permit
(
e.
g.,
because
the
air
pollution
control
technology
is
not
yet
in
service),
then
the
permit
must
describe
the
event
that
will
determine
the
expiration
date
(
e.
g.,
the
date
the
control
technology
is
placed
into
service).
Once
the
expiration
date
is
known,
then
the
owner
or
operator
must
notify
the
Administrator
of
the
exact
date.
The
expiration
date
must
be
added
to
the
source's
title
V
permit
at
the
first
opportunity,
such
as
a
modification,
revision,
reopening,
or
renewal
of
the
title
V
permit
for
any
reason,
whichever
comes
first,
but
in
no
case
later
than
the
next
renewal.
(
iv)
All
emission
limitations
and
work
practice
requirements
adopted
in
conjunction
with
emission
limitations
necessary
to
assure
that
the
control
technology
continues
to
achieve
an
emission
limitation
comparable
to
BACT,
and
any
physical
or
operational
characteristics
that
formed
the
basis
for
determining
that
the
emissions
unit's
control
technology
achieves
a
level
of
emissions
control
comparable
to
BACT
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
v)
Monitoring,
recordkeeping,
and
reporting
requirements
as
necessary
to
demonstrate
that
the
emissions
unit
continues
to
meet
the
criteria
for
maintaining
its
Clean
Unit
designation.
(
See
paragraph
(
y)(
9)
of
this
section.)
(
vi)
Terms
reflecting
the
owner
or
operator's
duties
to
maintain
the
Clean
Unit
designation
and
the
consequences
of
failing
to
do
so,
as
presented
in
paragraph
(
y)(
9)
of
this
section.
(
9)
Maintaining
a
Clean
Unit
designation.
To
maintain
the
Clean
Unit
designation,
the
owner
or
operator
must
conform
to
all
the
restrictions
listed
in
paragraphs
(
y)(
9)(
i)
through
(
v)
of
this
section.
This
paragraph
(
y)(
9)
applies
independently
to
each
pollutant
for
which
the
Administrator
has
designated
the
emissions
unit
a
Clean
Unit.
That
is,
failing
to
conform
to
the
restrictions
for
one
pollutant
affects
the
Clean
Unit
designation
only
for
that
pollutant.
(
i)
The
Clean
Unit
must
comply
with
the
emission
limitation(
s)
and/
or
work
practice
requirements
adopted
to
ensure
that
the
control
technology
continues
to
achieve
emission
control
comparable
to
BACT.
(
ii)
The
owner
or
operator
may
not
make
a
physical
change
in
or
change
in
the
method
of
operation
of
the
Clean
Unit
that
causes
the
emissions
unit
to
function
in
a
manner
that
is
inconsistent
with
the
physical
or
operational
characteristics
that
formed
the
basis
for
the
determination
that
the
control
technology
is
achieving
a
level
of
emission
control
that
is
comparable
to
BACT
(
e.
g.,
possibly
the
emissions
unit's
capacity
or
throughput).
(
iii)
[
Reserved]
(
iv)
The
Clean
Unit
must
comply
with
any
terms
and
conditions
in
the
title
V
permit
related
to
the
unit's
Clean
Unit
designation.
(
v)
The
Clean
Unit
must
continue
to
control
emissions
using
the
specific
air
pollution
control
technology
that
was
the
basis
for
its
Clean
Unit
designation.
If
the
emissions
unit
or
control
technology
is
replaced,
then
the
Clean
Unit
designation
ends.
(
10)
Netting
at
Clean
Units.
Emissions
changes
that
occur
at
a
Clean
Unit
must
not
be
included
in
calculating
a
significant
net
emissions
increase
(
that
is,
must
not
be
used
in
a
``
netting
analysis'')
unless
such
use
occurs
before
March
3,
2003
or
after
the
Clean
Unit
designation
expires;
or,
unless
the
emissions
unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit.
However,
if
the
Clean
Unit
reduces
emissions
below
the
level
that
qualified
the
unit
as
a
Clean
Unit,
then
the
owner
or
operator
may
generate
a
credit
for
the
difference
between
the
level
that
qualified
the
unit
as
a
Clean
Unit
and
the
emissions
unit's
new
emissions
limit
if
such
reductions
are
surplus,
quantifiable,
and
permanent.
For
purposes
of
generating
offsets,
the
reductions
must
also
be
federally
enforceable.
For
purposes
of
determining
creditable
net
emissions
increases
and
decreases,
the
reductions
must
also
be
enforceable
as
a
practical
matter.
(
11)
Effect
of
redesignation
on
a
Clean
Unit
designation.
The
Clean
Unit
designation
of
an
emissions
unit
is
not
affected
by
redesignation
of
the
attainment
status
of
the
area
in
which
it
is
located.
That
is,
if
a
Clean
Unit
is
located
in
an
attainment
area
and
the
area
is
redesignated
to
nonattainment,
its
Clean
Unit
designation
is
not
affected.
Similarly,
redesignation
from
nonattainment
to
attainment
does
not
affect
the
Clean
Unit
designation.
However,
if
a
Clean
Unit's
designation
expires
or
is
lost
pursuant
to
paragraphs
(
x)(
2)(
iii)
and
(
y)(
2)(
iii)
of
this
section,
it
must
re
qualify
under
the
requirements
that
are
currently
applicable.
(
z)
PCP
exclusion
procedural
requirements.
PCPs
shall
be
provided
according
to
the
provisions
in
paragraphs
(
z)(
1)
through
(
6)
of
this
section.
(
1)
Before
an
owner
or
operator
begins
actual
construction
of
a
PCP,
the
owner
or
operator
must
either
submit
a
notice
to
the
Administrator
if
the
project
is
listed
in
paragraphs
(
b)(
32)(
i)
through
(
vi)
of
this
section,
or
if
the
project
is
not
listed
in
paragraphs
(
b)(
32)(
i)
through
(
vi)
of
this
section,
then
the
owner
or
operator
must
submit
a
permit
application
and
obtain
approval
to
use
the
PCP
exclusion
from
the
Administrator
consistent
with
the
requirements
in
paragraph
(
z)(
5)
of
this
section.
Regardless
of
whether
the
owner
or
operator
submits
a
notice
or
a
permit
application,
the
project
must
meet
the
requirements
in
paragraph
(
z)(
2)
of
this
section,
and
the
notice
or
permit
application
must
contain
the
information
required
in
paragraph
(
z)(
3)
of
this
section.
(
2)
Any
project
that
relies
on
the
PCP
exclusion
must
meet
the
requirements
of
paragraphs
(
z)(
2)(
i)
and
(
ii)
of
this
section.
(
i)
Environmentally
beneficial
analysis.
The
environmental
benefit
from
the
emissions
reductions
of
pollutants
regulated
under
the
Act
must
outweigh
the
environmental
detriment
of
emissions
increases
in
pollutants
regulated
under
the
Act.
A
statement
that
a
technology
from
paragraphs
(
b)(
32)(
i)
through
(
vi)
of
this
section
is
being
used
shall
be
presumed
to
satisfy
this
requirement.
(
ii)
Air
quality
analysis.
The
emissions
increases
from
the
project
will
not
cause
or
contribute
to
a
violation
of
any
national
ambient
air
quality
standard
or
PSD
increment,
or
adversely
impact
an
air
quality
related
value
(
such
as
visibility)
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
and
for
which
information
is
available
to
the
general
public.
(
3)
Content
of
notice
or
permit
application.
In
the
notice
or
permit
application
sent
to
the
Administrator,
the
owner
or
operator
must
include,
at
a
minimum,
the
information
listed
in
paragraphs
(
z)(
3)(
i)
through
(
v)
of
this
section.
(
i)
A
description
of
the
project.
(
ii)
The
potential
emissions
increases
and
decreases
of
any
pollutant
regulated
under
the
Act
and
the
projected
emissions
increases
and
decreases
using
the
methodology
in
paragraph
(
a)(
2)(
iv)
of
this
section,
that
will
result
from
the
project,
and
a
copy
of
the
environmentally
beneficial
analysis
required
by
paragraph
(
z)(
2)(
i)
of
this
section.
(
iii)
A
description
of
monitoring
and
recordkeeping,
and
all
other
methods,
to
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Rules
and
Regulations
be
used
on
an
ongoing
basis
to
demonstrate
that
the
project
is
environmentally
beneficial.
Methods
should
be
sufficient
to
meet
the
requirements
in
part
70
and
part
71
of
this
chapter.
(
iv)
A
certification
that
the
project
will
be
designed
and
operated
in
a
manner
that
is
consistent
with
proper
industry
and
engineering
practices,
in
a
manner
that
is
consistent
with
the
environmentally
beneficial
analysis
and
air
quality
analysis
required
by
paragraphs
(
z)(
2)(
i)
and
(
ii)
of
this
section,
with
information
submitted
in
the
notice
or
permit
application,
and
in
such
a
way
as
to
minimize,
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy,
emissions
of
collateral
pollutants.
(
v)
Demonstration
that
the
PCP
will
not
have
an
adverse
air
quality
impact
(
e.
g.,
modeling,
screening
level
modeling
results,
or
a
statement
that
the
collateral
emissions
increase
is
included
within
the
parameters
used
in
the
most
recent
modeling
exercise)
as
required
by
paragraph
(
z)(
2)(
ii)
of
this
section.
An
air
quality
impact
analysis
is
not
required
for
any
pollutant
that
will
not
experience
a
significant
emissions
increase
as
a
result
of
the
project.
(
4)
Notice
process
for
listed
projects.
For
projects
listed
in
paragraphs
(
b)(
32)(
i)
through
(
vi)
of
this
section,
the
owner
or
operator
may
begin
actual
construction
of
the
project
immediately
after
notice
is
sent
to
the
Administrator
(
unless
otherwise
prohibited
under
requirements
of
the
applicable
State
Implementation
Plan).
The
owner
or
operator
shall
respond
to
any
requests
by
the
Administrator
for
additional
information
that
the
Administrator
determines
is
necessary
to
evaluate
the
suitability
of
the
project
for
the
PCP
exclusion.
(
5)
Permit
process
for
unlisted
projects.
Before
an
owner
or
operator
may
begin
actual
construction
of
a
PCP
project
that
is
not
listed
in
paragraphs
(
b)(
32)(
i)
through
(
vi)
of
this
section,
the
project
must
be
approved
by
the
Administrator
and
recorded
in
a
State
Implementation
Plan
approved
permit
or
title
V
permit
using
procedures
that
are
consistent
with
§
§
51.160
and
51.161
of
this
chapter.
This
includes
the
requirement
that
the
Administrator
provide
the
public
with
notice
of
the
proposed
approval,
with
access
to
the
environmentally
beneficial
analysis
and
the
air
quality
analysis,
and
provide
at
least
a
30
day
period
for
the
public
and
the
Administrator
to
submit
comments.
The
Administrator
must
address
all
material
comments
received
by
the
end
of
the
comment
period
before
taking
final
action
on
the
permit.
(
6)
Operational
requirements.
Upon
installation
of
the
PCP,
the
owner
or
operator
must
comply
with
the
requirements
of
paragraphs
(
z)(
6)(
i)
through
(
iv)
of
this
section.
(
i)
General
duty.
The
owner
or
operator
must
operate
the
PCP
in
a
manner
consistent
with
proper
industry
and
engineering
practices,
in
a
manner
that
is
consistent
with
the
environmentally
beneficial
analysis
and
air
quality
analysis
required
by
paragraphs
(
z)(
2)(
i)
and
(
ii)
of
this
section,
with
information
submitted
in
the
notice
or
permit
application
required
by
paragraph
(
z)(
3)
of
this
section,
and
in
such
a
way
as
to
minimize,
within
the
physical
configuration
and
operational
standards
usually
associated
with
the
emissions
control
device
or
strategy,
emissions
of
collateral
pollutants.
(
ii)
Recordkeeping.
The
owner
or
operator
must
maintain
copies
on
site
of
the
environmentally
beneficial
analysis,
the
air
quality
impacts
analysis,
and
monitoring
and
other
emission
records
to
prove
that
the
PCP
operated
consistent
with
the
general
duty
requirements
in
paragraph
(
z)(
6)(
i)
of
this
section.
(
iii)
Permit
requirements.
The
owner
or
operator
must
comply
with
any
provisions
in
the
State
Implementation
Plan
approved
permit
or
title
V
permit
related
to
use
and
approval
of
the
PCP
exclusion.
(
iv)
Generation
of
emission
reduction
credits.
Emission
reductions
created
by
a
PCP
shall
not
be
included
in
calculating
a
significant
net
emissions
increase
unless
the
emissions
unit
further
reduces
emissions
after
qualifying
for
the
PCP
exclusion
(
e.
g.,
taking
an
operational
restriction
on
the
hours
of
operation).
The
owner
or
operator
may
generate
a
credit
for
the
difference
between
the
level
of
reduction
which
was
used
to
qualify
for
the
PCP
exclusion
and
the
new
emissions
limit
if
such
reductions
are
surplus,
quantifiable,
and
permanent.
For
purposes
of
generating
offsets,
the
reductions
must
also
be
federally
enforceable.
For
purposes
of
determining
creditable
net
emissions
increases
and
decreases,
the
reductions
must
also
be
enforceable
as
a
practical
matter.
(
aa)
Actuals
PALs.
The
provisions
in
paragraphs
(
aa)(
1)
through
(
15)
of
this
section
govern
actuals
PALs.
(
1)
Applicability.
(
i)
The
Administrator
may
approve
the
use
of
an
actuals
PAL
for
any
existing
major
stationary
source
if
the
PAL
meets
the
requirements
in
paragraphs
(
aa)(
1)
through
(
15)
of
this
section.
The
term
``
PAL''
shall
mean
``
actuals
PAL''
throughout
paragraph
(
aa)
of
this
section.
(
ii)
Any
physical
change
in
or
change
in
the
method
of
operation
of
a
major
stationary
source
that
maintains
its
total
source
wide
emissions
below
the
PAL
level,
meets
the
requirements
in
paragraphs
(
aa)(
1)
through
(
15)
of
this
section,
and
complies
with
the
PAL
permit:
(
a)
Is
not
a
major
modification
for
the
PAL
pollutant;
(
b)
Does
not
have
to
be
approved
through
the
PSD
program;
and
(
c)
Is
not
subject
to
the
provisions
in
paragraph
(
r)(
4)
of
this
section
(
restrictions
on
relaxing
enforceable
emission
limitations
that
the
major
stationary
source
used
to
avoid
applicability
of
the
major
NSR
program).
(
iii)
Except
as
provided
under
paragraph
(
aa)(
1)(
ii)(
c)
of
this
section,
a
major
stationary
source
shall
continue
to
comply
with
all
applicable
Federal
or
State
requirements,
emission
limitations,
and
work
practice
requirements
that
were
established
prior
to
the
effective
date
of
the
PAL.
(
2)
Definitions.
For
the
purposes
of
this
section,
the
definitions
in
paragraphs
(
aa)(
2)(
i)
through
(
xi)
of
this
section
apply.
When
a
term
is
not
defined
in
these
paragraphs,
it
shall
have
the
meaning
given
in
paragraph
(
b)
of
this
section
or
in
the
Act.
(
i)
Actuals
PAL
for
a
major
stationary
source
means
a
PAL
based
on
the
baseline
actual
emissions
(
as
defined
in
paragraph
(
b)(
48)
of
this
section)
of
all
emissions
units
(
as
defined
in
paragraph
(
b)(
7)
of
this
section)
at
the
source,
that
emit
or
have
the
potential
to
emit
the
PAL
pollutant.
(
ii)
Allowable
emissions
means
``
allowable
emissions''
as
defined
in
paragraph
(
b)(
16)
of
this
section,
except
as
this
definition
is
modified
according
to
paragraphs
(
aa)(
2)(
ii)(
a)
and
(
b)
of
this
section.
(
a)
The
allowable
emissions
for
any
emissions
unit
shall
be
calculated
considering
any
emission
limitations
that
are
enforceable
as
a
practical
matter
on
the
emissions
unit's
potential
to
emit.
(
b)
An
emissions
unit's
potential
to
emit
shall
be
determined
using
the
definition
in
paragraph
(
b)(
4)
of
this
section,
except
that
the
words
``
or
enforceable
as
a
practical
matter''
should
be
added
after
``
federally
enforceable.''
(
iii)
Small
emissions
unit
means
an
emissions
unit
that
emits
or
has
the
potential
to
emit
the
PAL
pollutant
in
an
amount
less
than
the
significant
level
for
that
PAL
pollutant,
as
defined
in
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251
/
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December
31,
2002
/
Rules
and
Regulations
paragraph
(
b)(
23)
of
this
section
or
in
the
Act,
whichever
is
lower.
(
iv)
Major
emissions
unit
means:
(
a)
Any
emissions
unit
that
emits
or
has
the
potential
to
emit
100
tons
per
year
or
more
of
the
PAL
pollutant
in
an
attainment
area;
or
(
b)
Any
emissions
unit
that
emits
or
has
the
potential
to
emit
the
PAL
pollutant
in
an
amount
that
is
equal
to
or
greater
than
the
major
source
threshold
for
the
PAL
pollutant
as
defined
by
the
Act
for
nonattainment
areas.
For
example,
in
accordance
with
the
definition
of
major
stationary
source
in
section
182(
c)
of
the
Act,
an
emissions
unit
would
be
a
major
emissions
unit
for
VOC
if
the
emissions
unit
is
located
in
a
serious
ozone
nonattainment
area
and
it
emits
or
has
the
potential
to
emit
50
or
more
tons
of
VOC
per
year.
(
v)
Plantwide
applicability
limitation
(
PAL)
means
an
emission
limitation
expressed
in
tons
per
year,
for
a
pollutant
at
a
major
stationary
source,
that
is
enforceable
as
a
practical
matter
and
established
source
wide
in
accordance
with
paragraphs
(
aa)(
1)
through
(
15)
of
this
section.
(
vi)
PAL
effective
date
generally
means
the
date
of
issuance
of
the
PAL
permit.
However,
the
PAL
effective
date
for
an
increased
PAL
is
the
date
any
emissions
unit
that
is
part
of
the
PAL
major
modification
becomes
operational
and
begins
to
emit
the
PAL
pollutant.
(
vii)
PAL
effective
period
means
the
period
beginning
with
the
PAL
effective
date
and
ending
10
years
later.
(
viii)
PAL
major
modification
means,
notwithstanding
paragraphs
(
b)(
2)
and
(
b)(
3)
of
this
section
(
the
definitions
for
major
modification
and
net
emissions
increase),
any
physical
change
in
or
change
in
the
method
of
operation
of
the
PAL
source
that
causes
it
to
emit
the
PAL
pollutant
at
a
level
equal
to
or
greater
than
the
PAL.
(
ix)
PAL
permit
means
the
major
NSR
permit,
the
minor
NSR
permit,
or
the
State
operating
permit
under
a
program
that
is
approved
into
the
State
Implementation
Plan,
or
the
title
V
permit
issued
by
the
Administrator
that
establishes
a
PAL
for
a
major
stationary
source.
(
x)
PAL
pollutant
means
the
pollutant
for
which
a
PAL
is
established
at
a
major
stationary
source.
(
xi)
Significant
emissions
unit
means
an
emissions
unit
that
emits
or
has
the
potential
to
emit
a
PAL
pollutant
in
an
amount
that
is
equal
to
or
greater
than
the
significant
level
(
as
defined
in
paragraph
(
b)(
23)
of
this
section
or
in
the
Act,
whichever
is
lower)
for
that
PAL
pollutant,
but
less
than
the
amount
that
would
qualify
the
unit
as
a
major
emissions
unit
as
defined
in
paragraph
(
aa)(
2)(
iv)
of
this
section.
(
3)
Permit
application
requirements.
As
part
of
a
permit
application
requesting
a
PAL,
the
owner
or
operator
of
a
major
stationary
source
shall
submit
the
following
information
to
the
Administrator
for
approval:
(
i)
A
list
of
all
emissions
units
at
the
source
designated
as
small,
significant
or
major
based
on
their
potential
to
emit.
In
addition,
the
owner
or
operator
of
the
source
shall
indicate
which,
if
any,
Federal
or
State
applicable
requirements,
emission
limitations,
or
work
practices
apply
to
each
unit.
(
ii)
Calculations
of
the
baseline
actual
emissions
(
with
supporting
documentation).
Baseline
actual
emissions
are
to
include
emissions
associated
not
only
with
operation
of
the
unit,
but
also
emissions
associated
with
startup,
shutdown,
and
malfunction.
(
iii)
The
calculation
procedures
that
the
major
stationary
source
owner
or
operator
proposes
to
use
to
convert
the
monitoring
system
data
to
monthly
emissions
and
annual
emissions
based
on
a
12
month
rolling
total
for
each
month
as
required
by
paragraph
(
aa)(
13)(
i)
of
this
section.
(
4)
General
requirements
for
establishing
PALs.
(
i)
The
Administrator
is
allowed
to
establish
a
PAL
at
a
major
stationary
source,
provided
that
at
a
minimum,
the
requirements
in
paragraphs
(
aa)(
4)(
i)(
a)
through
(
g)
of
this
section
are
met.
(
a)
The
PAL
shall
impose
an
annual
emission
limitation
in
tons
per
year,
that
is
enforceable
as
a
practical
matter,
for
the
entire
major
stationary
source.
For
each
month
during
the
PAL
effective
period
after
the
first
12
months
of
establishing
a
PAL,
the
major
stationary
source
owner
or
operator
shall
show
that
the
sum
of
the
monthly
emissions
from
each
emissions
unit
under
the
PAL
for
the
previous
12
consecutive
months
is
less
than
the
PAL
(
a
12
month
average,
rolled
monthly).
For
each
month
during
the
first
11
months
from
the
PAL
effective
date,
the
major
stationary
source
owner
or
operator
shall
show
that
the
sum
of
the
preceding
monthly
emissions
from
the
PAL
effective
date
for
each
emissions
unit
under
the
PAL
is
less
than
the
PAL.
(
b)
The
PAL
shall
be
established
in
a
PAL
permit
that
meets
the
public
participation
requirements
in
paragraph
(
aa)(
5)
of
this
section.
(
c)
The
PAL
permit
shall
contain
all
the
requirements
of
paragraph
(
aa)(
7)
of
this
section.
(
d)
The
PAL
shall
include
fugitive
emissions,
to
the
extent
quantifiable,
from
all
emissions
units
that
emit
or
have
the
potential
to
emit
the
PAL
pollutant
at
the
major
stationary
source.
(
e)
Each
PAL
shall
regulate
emissions
of
only
one
pollutant.
(
f)
Each
PAL
shall
have
a
PAL
effective
period
of
10
years.
(
g)
The
owner
or
operator
of
the
major
stationary
source
with
a
PAL
shall
comply
with
the
monitoring,
recordkeeping,
and
reporting
requirements
provided
in
paragraphs
(
aa)(
12)
through
(
14)
of
this
section
for
each
emissions
unit
under
the
PAL
through
the
PAL
effective
period.
(
ii)
At
no
time
(
during
or
after
the
PAL
effective
period)
are
emissions
reductions
of
a
PAL
pollutant
that
occur
during
the
PAL
effective
period
creditable
as
decreases
for
purposes
of
offsets
under
§
51.165(
a)(
3)(
ii)
of
this
chapter
unless
the
level
of
the
PAL
is
reduced
by
the
amount
of
such
emissions
reductions
and
such
reductions
would
be
creditable
in
the
absence
of
the
PAL.
(
5)
Public
participation
requirements
for
PALs.
PALs
for
existing
major
stationary
sources
shall
be
established,
renewed,
or
increased
through
a
procedure
that
is
consistent
with
§
§
51.160
and
51.161
of
this
chapter.
This
includes
the
requirement
that
the
Administrator
provide
the
public
with
notice
of
the
proposed
approval
of
a
PAL
permit
and
at
least
a
30
day
period
for
submittal
of
public
comment.
The
Administrator
must
address
all
material
comments
before
taking
final
action
on
the
permit.
(
6)
Setting
the
10
year
actuals
PAL
level.
The
actuals
PAL
level
for
a
major
stationary
source
shall
be
established
as
the
sum
of
the
baseline
actual
emissions
(
as
defined
in
paragraph
(
b)(
48)
of
this
section)
of
the
PAL
pollutant
for
each
emissions
unit
at
the
source;
plus
an
amount
equal
to
the
applicable
significant
level
for
the
PAL
pollutant
under
paragraph
(
b)(
23)
of
this
section
or
under
the
Act,
whichever
is
lower.
When
establishing
the
actuals
PAL
level,
for
a
PAL
pollutant,
only
one
consecutive
24
month
period
must
be
used
to
determine
the
baseline
actual
emissions
for
all
existing
emissions
units.
However,
a
different
consecutive
24
month
period
may
be
used
for
each
different
PAL
pollutant.
Emissions
associated
with
units
that
were
permanently
shutdown
after
this
24
month
period
must
be
subtracted
from
the
PAL
level.
Emissions
from
units
on
which
actual
construction
began
after
the
24
month
period
must
be
added
to
the
PAL
level
in
an
amount
equal
to
the
potential
to
emit
of
the
units.
The
Administrator
shall
specify
a
reduced
PAL
level(
s)
(
in
tons/
yr)
in
the
PAL
permit
to
become
effective
on
the
future
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/
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December
31,
2002
/
Rules
and
Regulations
compliance
date(
s)
of
any
applicable
Federal
or
State
regulatory
requirement(
s)
that
the
Administrator
is
aware
of
prior
to
issuance
of
the
PAL
permit.
For
instance,
if
the
source
owner
or
operator
will
be
required
to
reduce
emissions
from
industrial
boilers
in
half
from
baseline
emissions
of
60
ppm
NOX
to
a
new
rule
limit
of
30
ppm,
then
the
permit
shall
contain
a
future
effective
PAL
level
that
is
equal
to
the
current
PAL
level
reduced
by
half
of
the
original
baseline
emissions
of
such
unit(
s).
(
7)
Contents
of
the
PAL
permit.
The
PAL
permit
must
contain,
at
a
minimum,
the
information
in
paragraphs
(
aa)(
7)(
i)
through
(
x)
of
this
section.
(
i)
The
PAL
pollutant
and
the
applicable
source
wide
emission
limitation
in
tons
per
year.
(
ii)
The
PAL
permit
effective
date
and
the
expiration
date
of
the
PAL
(
PAL
effective
period).
(
iii)
Specification
in
the
PAL
permit
that
if
a
major
stationary
source
owner
or
operator
applies
to
renew
a
PAL
in
accordance
with
paragraph
(
aa)(
10)
of
this
section
before
the
end
of
the
PAL
effective
period,
then
the
PAL
shall
not
expire
at
the
end
of
the
PAL
effective
period.
It
shall
remain
in
effect
until
a
revised
PAL
permit
is
issued
by
a
reviewing
authority.
(
iv)
A
requirement
that
emission
calculations
for
compliance
purposes
must
include
emissions
from
startups,
shutdowns,
and
malfunctions.
(
v)
A
requirement
that,
once
the
PAL
expires,
the
major
stationary
source
is
subject
to
the
requirements
of
paragraph
(
aa)(
9)
of
this
section.
(
vi)
The
calculation
procedures
that
the
major
stationary
source
owner
or
operator
shall
use
to
convert
the
monitoring
system
data
to
monthly
emissions
and
annual
emissions
based
on
a
12
month
rolling
total
as
required
by
paragraph
(
aa)(
13)(
i)
of
this
section.
(
vii)
A
requirement
that
the
major
stationary
source
owner
or
operator
monitor
all
emissions
units
in
accordance
with
the
provisions
under
paragraph
(
aa)(
12)
of
this
section.
(
viii)
A
requirement
to
retain
the
records
required
under
paragraph
(
aa)(
13)
of
this
section
on
site.
Such
records
may
be
retained
in
an
electronic
format.
(
ix)
A
requirement
to
submit
the
reports
required
under
paragraph
(
aa)(
14)
of
this
section
by
the
required
deadlines.
(
x)
Any
other
requirements
that
the
Administrator
deems
necessary
to
implement
and
enforce
the
PAL.
(
8)
PAL
effective
period
and
reopening
of
the
PAL
permit.
The
requirements
in
paragraphs
(
aa)(
8)(
i)
and
(
ii)
of
this
section
apply
to
actuals
PALs.
(
i)
PAL
effective
period.
The
Administrator
shall
specify
a
PAL
effective
period
of
10
years.
(
ii)
Reopening
of
the
PAL
permit.
(
a)
During
the
PAL
effective
period,
the
Administrator
must
reopen
the
PAL
permit
to:
(
1)
Correct
typographical/
calculation
errors
made
in
setting
the
PAL
or
reflect
a
more
accurate
determination
of
emissions
used
to
establish
the
PAL;
(
2)
Reduce
the
PAL
if
the
owner
or
operator
of
the
major
stationary
source
creates
creditable
emissions
reductions
for
use
as
offsets
under
§
51.165(
a)(
3)(
ii)
of
this
chapter;
and
(
3)
Revise
the
PAL
to
reflect
an
increase
in
the
PAL
as
provided
under
paragraph
(
aa)(
11)
of
this
section.
(
b)
The
Administrator
shall
have
discretion
to
reopen
the
PAL
permit
for
the
following:
(
1)
Reduce
the
PAL
to
reflect
newly
applicable
Federal
requirements
(
for
example,
NSPS)
with
compliance
dates
after
the
PAL
effective
date;
(
2)
Reduce
the
PAL
consistent
with
any
other
requirement,
that
is
enforceable
as
a
practical
matter,
and
that
the
State
may
impose
on
the
major
stationary
source
under
the
State
Implementation
Plan;
and
(
3)
Reduce
the
PAL
if
the
reviewing
authority
determines
that
a
reduction
is
necessary
to
avoid
causing
or
contributing
to
a
NAAQS
or
PSD
increment
violation,
or
to
an
adverse
impact
on
an
air
quality
related
value
that
has
been
identified
for
a
Federal
Class
I
area
by
a
Federal
Land
Manager
and
for
which
information
is
available
to
the
general
public.
(
c)
Except
for
the
permit
reopening
in
paragraph
(
aa)(
8)(
ii)(
a)(
1)
of
this
section
for
the
correction
of
typographical/
calculation
errors
that
do
not
increase
the
PAL
level,
all
other
reopenings
shall
be
carried
out
in
accordance
with
the
public
participation
requirements
of
paragraph
(
aa)(
5)
of
this
section.
(
9)
Expiration
of
a
PAL.
Any
PAL
that
is
not
renewed
in
accordance
with
the
procedures
in
paragraph
(
aa)(
10)
of
this
section
shall
expire
at
the
end
of
the
PAL
effective
period,
and
the
requirements
in
paragraphs
(
aa)(
9)(
i)
through
(
v)
of
this
section
shall
apply.
(
i)
Each
emissions
unit
(
or
each
group
of
emissions
units)
that
existed
under
the
PAL
shall
comply
with
an
allowable
emission
limitation
under
a
revised
permit
established
according
to
the
procedures
in
paragraphs
(
aa)(
9)(
i)(
a)
and
(
b)
of
this
section.
(
a)
Within
the
time
frame
specified
for
PAL
renewals
in
paragraph
(
aa)(
10)(
ii)
of
this
section,
the
major
stationary
source
shall
submit
a
proposed
allowable
emission
limitation
for
each
emissions
unit
(
or
each
group
of
emissions
units,
if
such
a
distribution
is
more
appropriate
as
decided
by
the
Administrator)
by
distributing
the
PAL
allowable
emissions
for
the
major
stationary
source
among
each
of
the
emissions
units
that
existed
under
the
PAL.
If
the
PAL
had
not
yet
been
adjusted
for
an
applicable
requirement
that
became
effective
during
the
PAL
effective
period,
as
required
under
paragraph
(
aa)(
10)(
v)
of
this
section,
such
distribution
shall
be
made
as
if
the
PAL
had
been
adjusted.
(
b)
The
Administrator
shall
decide
whether
and
how
the
PAL
allowable
emissions
will
be
distributed
and
issue
a
revised
permit
incorporating
allowable
limits
for
each
emissions
unit,
or
each
group
of
emissions
units,
as
the
Administrator
determines
is
appropriate.
(
ii)
Each
emissions
unit(
s)
shall
comply
with
the
allowable
emission
limitation
on
a
12
month
rolling
basis.
The
Administrator
may
approve
the
use
of
monitoring
systems
(
source
testing,
emission
factors,
etc.)
other
than
CEMS,
CERMS,
PEMS,
or
CPMS
to
demonstrate
compliance
with
the
allowable
emission
limitation.
(
iii)
Until
the
Administrator
issues
the
revised
permit
incorporating
allowable
limits
for
each
emissions
unit,
or
each
group
of
emissions
units,
as
required
under
paragraph
(
aa)(
9)(
i)(
b)
of
this
section,
the
source
shall
continue
to
comply
with
a
source
wide,
multi
unit
emissions
cap
equivalent
to
the
level
of
the
PAL
emission
limitation.
(
iv)
Any
physical
change
or
change
in
the
method
of
operation
at
the
major
stationary
source
will
be
subject
to
major
NSR
requirements
if
such
change
meets
the
definition
of
major
modification
in
paragraph
(
b)(
2)
of
this
section.
(
v)
The
major
stationary
source
owner
or
operator
shall
continue
to
comply
with
any
State
or
Federal
applicable
requirements
(
BACT,
RACT,
NSPS,
etc.)
that
may
have
applied
either
during
the
PAL
effective
period
or
prior
to
the
PAL
effective
period
except
for
those
emission
limitations
that
had
been
established
pursuant
to
paragraph
(
r)(
4)
of
this
section,
but
were
eliminated
by
the
PAL
in
accordance
with
the
provisions
in
paragraph
(
aa)(
1)(
ii)(
c)
of
this
section.
(
10)
Renewal
of
a
PAL.
(
i)
The
Administrator
shall
follow
the
procedures
specified
in
paragraph
(
aa)(
5)
of
this
section
in
approving
any
request
to
renew
a
PAL
for
a
major
stationary
source,
and
shall
provide
both
the
proposed
PAL
level
and
a
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251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
written
rationale
for
the
proposed
PAL
level
to
the
public
for
review
and
comment.
During
such
public
review,
any
person
may
propose
a
PAL
level
for
the
source
for
consideration
by
the
Administrator.
(
ii)
Application
deadline.
A
major
stationary
source
owner
or
operator
shall
submit
a
timely
application
to
the
Administrator
to
request
renewal
of
a
PAL.
A
timely
application
is
one
that
is
submitted
at
least
6
months
prior
to,
but
not
earlier
than
18
months
from,
the
date
of
permit
expiration.
This
deadline
for
application
submittal
is
to
ensure
that
the
permit
will
not
expire
before
the
permit
is
renewed.
If
the
owner
or
operator
of
a
major
stationary
source
submits
a
complete
application
to
renew
the
PAL
within
this
time
period,
then
the
PAL
shall
continue
to
be
effective
until
the
revised
permit
with
the
renewed
PAL
is
issued.
(
iii)
Application
requirements.
The
application
to
renew
a
PAL
permit
shall
contain
the
information
required
in
paragraphs
(
aa)(
10)(
iii)(
a)
through
(
d)
of
this
section.
(
a)
The
information
required
in
paragraphs
(
aa)(
3)(
i)
through
(
iii)
of
this
section.
(
b)
A
proposed
PAL
level.
(
c)
The
sum
of
the
potential
to
emit
of
all
emissions
units
under
the
PAL
(
with
supporting
documentation).
(
d)
Any
other
information
the
owner
or
operator
wishes
the
Administrator
to
consider
in
determining
the
appropriate
level
for
renewing
the
PAL.
(
iv)
PAL
adjustment.
In
determining
whether
and
how
to
adjust
the
PAL,
the
Administrator
shall
consider
the
options
outlined
in
paragraphs
(
aa)(
10)(
iv)(
a)
and
(
b)
of
this
section.
However,
in
no
case
may
any
such
adjustment
fail
to
comply
with
paragraph
(
aa)(
10)(
iv)(
c)
of
this
section.
(
a)
If
the
emissions
level
calculated
in
accordance
with
paragraph
(
aa)(
6)
of
this
section
is
equal
to
or
greater
than
80
percent
of
the
PAL
level,
the
Administrator
may
renew
the
PAL
at
the
same
level
without
considering
the
factors
set
forth
in
paragraph
(
aa)(
10)(
iv)(
b)
of
this
section;
or
(
b)
The
Administrator
may
set
the
PAL
at
a
level
that
he
or
she
determines
to
be
more
representative
of
the
source's
baseline
actual
emissions,
or
that
he
or
she
determines
to
be
more
appropriate
considering
air
quality
needs,
advances
in
control
technology,
anticipated
economic
growth
in
the
area,
desire
to
reward
or
encourage
the
source's
voluntary
emissions
reductions,
or
other
factors
as
specifically
identified
by
the
Administrator
in
his
or
her
written
rationale.
(
c)
Notwithstanding
paragraphs
(
aa)(
10)(
iv)(
a)
and
(
b)
of
this
section:
(
1)
If
the
potential
to
emit
of
the
major
stationary
source
is
less
than
the
PAL,
the
Administrator
shall
adjust
the
PAL
to
a
level
no
greater
than
the
potential
to
emit
of
the
source;
and
(
2)
The
Administrator
shall
not
approve
a
renewed
PAL
level
higher
than
the
current
PAL,
unless
the
major
stationary
source
has
complied
with
the
provisions
of
paragraph
(
aa)(
11)
of
this
section
(
increasing
a
PAL).
(
v)
If
the
compliance
date
for
a
State
or
Federal
requirement
that
applies
to
the
PAL
source
occurs
during
the
PAL
effective
period,
and
if
the
Administrator
has
not
already
adjusted
for
such
requirement,
the
PAL
shall
be
adjusted
at
the
time
of
PAL
permit
renewal
or
title
V
permit
renewal,
whichever
occurs
first.
(
11)
Increasing
a
PAL
during
the
PAL
effective
period.
(
i)
The
Administrator
may
increase
a
PAL
emission
limitation
only
if
the
major
stationary
source
complies
with
the
provisions
in
paragraphs
(
aa)(
11)(
i)(
a)
through
(
d)
of
this
section.
(
a)
The
owner
or
operator
of
the
major
stationary
source
shall
submit
a
complete
application
to
request
an
increase
in
the
PAL
limit
for
a
PAL
major
modification.
Such
application
shall
identify
the
emissions
unit(
s)
contributing
to
the
increase
in
emissions
so
as
to
cause
the
major
stationary
source's
emissions
to
equal
or
exceed
its
PAL.
(
b)
As
part
of
this
application,
the
major
stationary
source
owner
or
operator
shall
demonstrate
that
the
sum
of
the
baseline
actual
emissions
of
the
small
emissions
units,
plus
the
sum
of
the
baseline
actual
emissions
of
the
significant
and
major
emissions
units
assuming
application
of
BACT
equivalent
controls,
plus
the
sum
of
the
allowable
emissions
of
the
new
or
modified
emissions
unit(
s)
exceeds
the
PAL.
The
level
of
control
that
would
result
from
BACT
equivalent
controls
on
each
significant
or
major
emissions
unit
shall
be
determined
by
conducting
a
new
BACT
analysis
at
the
time
the
application
is
submitted,
unless
the
emissions
unit
is
currently
required
to
comply
with
a
BACT
or
LAER
requirement
that
was
established
within
the
preceding
10
years.
In
such
a
case,
the
assumed
control
level
for
that
emissions
unit
shall
be
equal
to
the
level
of
BACT
or
LAER
with
which
that
emissions
unit
must
currently
comply.
(
c)
The
owner
or
operator
obtains
a
major
NSR
permit
for
all
emissions
unit(
s)
identified
in
paragraph
(
aa)(
11)(
i)(
a)
of
this
section,
regardless
of
the
magnitude
of
the
emissions
increase
resulting
from
them
(
that
is,
no
significant
levels
apply).
These
emissions
unit(
s)
shall
comply
with
any
emissions
requirements
resulting
from
the
major
NSR
process
(
for
example,
BACT),
even
though
they
have
also
become
subject
to
the
PAL
or
continue
to
be
subject
to
the
PAL.
(
d)
The
PAL
permit
shall
require
that
the
increased
PAL
level
shall
be
effective
on
the
day
any
emissions
unit
that
is
part
of
the
PAL
major
modification
becomes
operational
and
begins
to
emit
the
PAL
pollutant.
(
ii)
The
Administrator
shall
calculate
the
new
PAL
as
the
sum
of
the
allowable
emissions
for
each
modified
or
new
emissions
unit,
plus
the
sum
of
the
baseline
actual
emissions
of
the
significant
and
major
emissions
units
(
assuming
application
of
BACT
equivalent
controls
as
determined
in
accordance
with
paragraph
(
aa)(
11)(
i)(
b)),
plus
the
sum
of
the
baseline
actual
emissions
of
the
small
emissions
units.
(
iii)
The
PAL
permit
shall
be
revised
to
reflect
the
increased
PAL
level
pursuant
to
the
public
notice
requirements
of
paragraph
(
aa)(
5)
of
this
section.
(
12)
Monitoring
requirements
for
PALs.
(
i)
General
requirements.
(
a)
Each
PAL
permit
must
contain
enforceable
requirements
for
the
monitoring
system
that
accurately
determines
plantwide
emissions
of
the
PAL
pollutant
in
terms
of
mass
per
unit
of
time.
Any
monitoring
system
authorized
for
use
in
the
PAL
permit
must
be
based
on
sound
science
and
meet
generally
acceptable
scientific
procedures
for
data
quality
and
manipulation.
Additionally,
the
information
generated
by
such
system
must
meet
minimum
legal
requirements
for
admissibility
in
a
judicial
proceeding
to
enforce
the
PAL
permit.
(
b)
The
PAL
monitoring
system
must
employ
one
or
more
of
the
four
general
monitoring
approaches
meeting
the
minimum
requirements
set
forth
in
paragraphs
(
aa)(
12)(
ii)(
a)
through
(
d)
of
this
section
and
must
be
approved
by
the
Administrator.
(
c)
Notwithstanding
paragraph
(
aa)(
12)(
i)(
b)
of
this
section,
you
may
also
employ
an
alternative
monitoring
approach
that
meets
paragraph
(
aa)(
12)(
i)(
a)
of
this
section
if
approved
by
the
Administrator.
(
d)
Failure
to
use
a
monitoring
system
that
meets
the
requirements
of
this
section
renders
the
PAL
invalid.
(
ii)
Minimum
performance
requirements
for
approved
monitoring
approaches.
The
following
are
acceptable
general
monitoring
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/
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67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
approaches
when
conducted
in
accordance
with
the
minimum
requirements
in
paragraphs
(
aa)(
12)(
iii)
through
(
ix)
of
this
section:
(
a)
Mass
balance
calculations
for
activities
using
coatings
or
solvents;
(
b)
CEMS;
(
c)
CPMS
or
PEMS;
and
(
d)
Emission
factors.
(
iii)
Mass
balance
calculations.
An
owner
or
operator
using
mass
balance
calculations
to
monitor
PAL
pollutant
emissions
from
activities
using
coating
or
solvents
shall
meet
the
following
requirements:
(
a)
Provide
a
demonstrated
means
of
validating
the
published
content
of
the
PAL
pollutant
that
is
contained
in
or
created
by
all
materials
used
in
or
at
the
emissions
unit;
(
b)
Assume
that
the
emissions
unit
emits
all
of
the
PAL
pollutant
that
is
contained
in
or
created
by
any
raw
material
or
fuel
used
in
or
at
the
emissions
unit,
if
it
cannot
otherwise
be
accounted
for
in
the
process;
and
(
c)
Where
the
vendor
of
a
material
or
fuel,
which
is
used
in
or
at
the
emissions
unit,
publishes
a
range
of
pollutant
content
from
such
material,
the
owner
or
operator
must
use
the
highest
value
of
the
range
to
calculate
the
PAL
pollutant
emissions
unless
the
Administrator
determines
there
is
sitespecific
data
or
a
site
specific
monitoring
program
to
support
another
content
within
the
range.
(
iv)
CEMS.
An
owner
or
operator
using
CEMS
to
monitor
PAL
pollutant
emissions
shall
meet
the
following
requirements:
(
a)
CEMS
must
comply
with
applicable
Performance
Specifications
found
in
40
CFR
part
60,
appendix
B;
and
(
b)
CEMS
must
sample,
analyze
and
record
data
at
least
every
15
minutes
while
the
emissions
unit
is
operating.
(
v)
CPMS
or
PEMS.
An
owner
or
operator
using
CPMS
or
PEMS
to
monitor
PAL
pollutant
emissions
shall
meet
the
following
requirements:
(
a)
The
CPMS
or
the
PEMS
must
be
based
on
current
site
specific
data
demonstrating
a
correlation
between
the
monitored
parameter(
s)
and
the
PAL
pollutant
emissions
across
the
range
of
operation
of
the
emissions
unit;
and
(
b)
Each
CPMS
or
PEMS
must
sample,
analyze,
and
record
data
at
least
every
15
minutes,
or
at
another
less
frequent
interval
approved
by
the
Administrator,
while
the
emissions
unit
is
operating.
(
vi)
Emission
factors.
An
owner
or
operator
using
emission
factors
to
monitor
PAL
pollutant
emissions
shall
meet
the
following
requirements:
(
a)
All
emission
factors
shall
be
adjusted,
if
appropriate,
to
account
for
the
degree
of
uncertainty
or
limitations
in
the
factors'
development;
(
b)
The
emissions
unit
shall
operate
within
the
designated
range
of
use
for
the
emission
factor,
if
applicable;
and
(
c)
If
technically
practicable,
the
owner
or
operator
of
a
significant
emissions
unit
that
relies
on
an
emission
factor
to
calculate
PAL
pollutant
emissions
shall
conduct
validation
testing
to
determine
a
sitespecific
emission
factor
within
6
months
of
PAL
permit
issuance,
unless
the
Administrator
determines
that
testing
is
not
required.
(
vii)
A
source
owner
or
operator
must
record
and
report
maximum
potential
emissions
without
considering
enforceable
emission
limitations
or
operational
restrictions
for
an
emissions
unit
during
any
period
of
time
that
there
is
no
monitoring
data,
unless
another
method
for
determining
emissions
during
such
periods
is
specified
in
the
PAL
permit.
(
viii)
Notwithstanding
the
requirements
in
paragraphs
(
aa)(
12)(
iii)
through
(
vii)
of
this
section,
where
an
owner
or
operator
of
an
emissions
unit
cannot
demonstrate
a
correlation
between
the
monitored
parameter(
s)
and
the
PAL
pollutant
emissions
rate
at
all
operating
points
of
the
emissions
unit,
the
Administrator
shall,
at
the
time
of
permit
issuance:
(
a)
Establish
default
value(
s)
for
determining
compliance
with
the
PAL
based
on
the
highest
potential
emissions
reasonably
estimated
at
such
operating
point(
s);
or
(
b)
Determine
that
operation
of
the
emissions
unit
during
operating
conditions
when
there
is
no
correlation
between
monitored
parameter(
s)
and
the
PAL
pollutant
emissions
is
a
violation
of
the
PAL.
(
ix)
Re
validation.
All
data
used
to
establish
the
PAL
pollutant
must
be
revalidated
through
performance
testing
or
other
scientifically
valid
means
approved
by
the
Administrator.
Such
testing
must
occur
at
least
once
every
5
years
after
issuance
of
the
PAL.
(
13)
Recordkeeping
requirements.
(
i)
The
PAL
permit
shall
require
an
owner
or
operator
to
retain
a
copy
of
all
records
necessary
to
determine
compliance
with
any
requirement
of
paragraph
(
aa)
of
this
section
and
of
the
PAL,
including
a
determination
of
each
emissions
unit's
12
month
rolling
total
emissions,
for
5
years
from
the
date
of
such
record.
(
ii)
The
PAL
permit
shall
require
an
owner
or
operator
to
retain
a
copy
of
the
following
records
for
the
duration
of
the
PAL
effective
period
plus
5
years:
(
a)
A
copy
of
the
PAL
permit
application
and
any
applications
for
revisions
to
the
PAL;
and
(
b)
Each
annual
certification
of
compliance
pursuant
to
title
V
and
the
data
relied
on
in
certifying
the
compliance.
(
14)
Reporting
and
notification
requirements.
The
owner
or
operator
shall
submit
semi
annual
monitoring
reports
and
prompt
deviation
reports
to
the
Administrator
in
accordance
with
the
applicable
title
V
operating
permit
program.
The
reports
shall
meet
the
requirements
in
paragraphs
(
aa)(
14)(
i)
through
(
iii)
of
this
section.
(
i)
Semi
annual
report.
The
semiannual
report
shall
be
submitted
to
the
Administrator
within
30
days
of
the
end
of
each
reporting
period.
This
report
shall
contain
the
information
required
in
paragraphs
(
aa)(
14)(
i)(
a)
through
(
g)
of
this
section.
(
a)
The
identification
of
owner
and
operator
and
the
permit
number.
(
b)
Total
annual
emissions
(
tons/
year)
based
on
a
12
month
rolling
total
for
each
month
in
the
reporting
period
recorded
pursuant
to
paragraph
(
aa)(
13)(
i)
of
this
section.
(
c)
All
data
relied
upon,
including,
but
not
limited
to,
any
Quality
Assurance
or
Quality
Control
data,
in
calculating
the
monthly
and
annual
PAL
pollutant
emissions.
(
d)
A
list
of
any
emissions
units
modified
or
added
to
the
major
stationary
source
during
the
preceding
6
month
period.
(
e)
The
number,
duration,
and
cause
of
any
deviations
or
monitoring
malfunctions
(
other
than
the
time
associated
with
zero
and
span
calibration
checks),
and
any
corrective
action
taken.
(
f)
A
notification
of
a
shutdown
of
any
monitoring
system,
whether
the
shutdown
was
permanent
or
temporary,
the
reason
for
the
shutdown,
the
anticipated
date
that
the
monitoring
system
will
be
fully
operational
or
replaced
with
another
monitoring
system,
and
whether
the
emissions
unit
monitored
by
the
monitoring
system
continued
to
operate,
and
the
calculation
of
the
emissions
of
the
pollutant
or
the
number
determined
by
method
included
in
the
permit,
as
provided
by
(
aa)(
12)(
vii).
(
g)
A
signed
statement
by
the
responsible
official
(
as
defined
by
the
applicable
title
V
operating
permit
program)
certifying
the
truth,
accuracy,
and
completeness
of
the
information
provided
in
the
report.
(
ii)
Deviation
report.
The
major
stationary
source
owner
or
operator
shall
promptly
submit
reports
of
any
deviations
or
exceedance
of
the
PAL
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Federal
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
requirements,
including
periods
where
no
monitoring
is
available.
A
report
submitted
pursuant
to
§
70.6(
a)(
3)(
iii)(
B)
of
this
chapter
shall
satisfy
this
reporting
requirement.
The
deviation
reports
shall
be
submitted
within
the
time
limits
prescribed
by
the
applicable
program
implementing
§
70.6(
a)(
3)(
iii)(
B)
of
this
chapter.
The
reports
shall
contain
the
following
information:
(
a)
The
identification
of
owner
and
operator
and
the
permit
number;
(
b)
The
PAL
requirement
that
experienced
the
deviation
or
that
was
exceeded;
(
c)
Emissions
resulting
from
the
deviation
or
the
exceedance;
and
(
d)
A
signed
statement
by
the
responsible
official
(
as
defined
by
the
applicable
title
V
operating
permit
program)
certifying
the
truth,
accuracy,
and
completeness
of
the
information
provided
in
the
report.
(
iii)
Re
validation
results.
The
owner
or
operator
shall
submit
to
the
Administrator
the
results
of
any
revalidation
test
or
method
within
3
months
after
completion
of
such
test
or
method.
(
15)
Transition
requirements.
(
i)
The
Administrator
may
not
issue
a
PAL
that
does
not
comply
with
the
requirements
in
paragraphs
(
aa)(
1)
through
(
15)
of
this
section
after
March
3,
2003.
(
ii)
The
Administrator
may
supersede
any
PAL
that
was
established
prior
to
March
3,
2003
with
a
PAL
that
complies
with
the
requirements
of
paragraphs
(
aa)(
1)
through
(
15)
of
this
section.
(
bb)
If
any
provision
of
this
section,
or
the
application
of
such
provision
to
any
person
or
circumstance,
is
held
invalid,
the
remainder
of
this
section,
or
the
application
of
such
provision
to
persons
or
circumstances
other
than
those
as
to
which
it
is
held
invalid,
shall
not
be
affected
thereby.
[
FR
Doc.
02
31899
Filed
12
30
02;
8:
45
am]
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| epa | 2024-06-07T20:31:39.497709 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0004-0291/content.txt"
} |
EPA-HQ-OAR-2001-0012-0180 | Supporting & Related Material | "2002-05-06T04:00:00" | null | epa | 2024-06-07T20:31:39.621684 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0012-0180/content.txt"
} |
|
EPA-HQ-OAR-2001-0012-0181 | Supporting & Related Material | "2002-05-28T04:00:00" | null | epa | 2024-06-07T20:31:39.622517 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0012-0181/content.txt"
} |
|
EPA-HQ-OAR-2001-0012-0182 | Supporting & Related Material | "2002-07-05T04:00:00" | null | epa | 2024-06-07T20:31:39.623336 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0012-0182/content.txt"
} |
|
EPA-HQ-OAR-2001-0012-0189 | Supporting & Related Material | "2002-10-11T04:00:00" | null | Monitoring
Inspection
Report
(40
CFR
194.42)
Of
The
Waste
Isolation
Pilot
Plant
March
24
25,1999
Page
1
Table
of
Contents
1
.O
Executive
Summary
2.0
Background
3.0
Scope
4.0
Inspection
Team,
Observers,
and
Participants
5.0
Performance
of
the
inspections
5
.1
Monitoring
of
Geomechanical
Parameters
5.2
Monitoring
of
Hydrological
Parameters
5.3
Monitoring
of
Waste
Activity
Parameters
5.4
Monitoring
of
Drilling
Related
Parameters
5.5
Monitoring
of
Subsidence
Parameters
6.0
Summary
of
findings,
observation,
concerns,
and
recommendations
Attachments
Attachment
A.
1
Inspection
Plan
Attachment
A.
2
Inspection
Checklist
Attachment
B.
Opening
and
Closing
Sign
Up
Sheets
Attachment
C.
Documents
Reviewed
Attachment
D.
1
Geomechanical
Documents
Reviewed
Attachment
D.
2
Hydrological
Documents
Reviewed
Attachment
D
.3
Waste
Activity
Documents
Reviewed
Attachment
D.
4
Drilling
Related
Documents
Reviewed
Attachment
D.
5
Subsidence
Documents
Reviewed
Attachment
D.
6
Other
Documents
Reviewed
Page
2
Page
4
4
5
5
6
7
7
8
8
9
9
1.0
Executive
Summary
The
U.
S.
Environmental
Protection
Agency
(EPA)
conducted
an
inspection
of
the
Department
of
Energy
(DOE)
Waste
Isolation
Pilot
Plant
(WIPP)
March
24
25,
1999,
as
part
of
its
continuing
oversight
program.
The
purpose
of
this
inspection
was
to
verifj
that
DOE
is
monitoring
the
ten
parameters
listed
in
the
WIPP
Compliance
Certification
Application
(CCA),
Volume
1,
Section
7.0,
Table
7
7
(See
Table
1).
The
inspection
examined
implementation
of
monitoring
for
geomechanical,
hydrological,
waste
activity,
drilling
related,
and
subsidence
parameters.
The
inspectors
toured
locations
where
measurements
are
taken,
reviewed
parameter
databases,
and
reviewed
documents
and
procedures
directing
these
monitoring
activities.
The
EPA
inspectors
found
that
DOE
through
its
contractor,
Westinghouse,
has
effectively
implemented
the
monitoring
program
at
WIPP.
As
determined
in
the
certification
decision,
May
13,
1998,
the
program
has
adequate
documentation/
procedures
governing
the
program.
The
inspection
team
also
confirmed
that
DOE'S
program
requires
reporting
the
results
of
these
various
monitoring
programs
on
an
annual
basis,
as
committed
to
in
the
CCA.
2.0
Background
The
Compliance
Criteria
at
Section
194.42
require
DOE
to
"conduct
an
analysis
of
the
effects
of
disposal
system
parameters
on
the
containment
of
waste
in
the
disposal
system"
(40
CFR
194.42
(a)).
The
results
of
this
analysis
is
to
be
include
in
the
CCA
and
is
to
be
used
to
develop
pre
closure
and
post
closure
monitoring
requirements.
Volume
1,
Section
7.0
of
the
CCA
documents
DOE
analysis,
Table
7
7
ofthe
CCA
(Document
COB
DOE
194#
1,
Attachment
D.
6)
lists
the
ten
parameters
that
DOE
discovered
may
impact
the
disposal
system.
These
parameters
are
grouped
into
major
categories
and
listed
in
Table
1.
Geomechanicat
Parameters
Waste
Activity
Pararneter
Creep
closure,
Waste
Activity
Extent
of
deformation,
Initiation
of
brittle
deformation,
and
DispIacernent
of
defurmatian
features.
Subsidence
Parameter
Subsidence
measurements
Hydrological
Parameters
Drilling
Related
Parameters
Culebra
groundwater
composition
and
Change
in
Culebrs
groundwater
flow
Drifling
rate
and
The
probability
of
encountering
a
direction.
Castile
brine
reservoir.
Page
3
EPA
approved
these
ten
monitoring
parameters
in
the
certification
rulemaking.
Section
194.42(
c)
requires
DOE
to
have
an
implemented
program
before
emplacement
of
waste
can
begin
during
the
management
and
storage
phase
of
operation.
This
inspection
was
done
to
veri@
implementation
of
the
monitoring
program
at
WIPP.
Chuck
Byrum
Nick
Stone
3.0
Scope
Inspection
Team
Leader
EPA
Inspector
EPA
Inspection
activities
included
an
examination
of
monitoring
and
sampling
equipment
both
on
and
off
site,
and
in
the
underground.
A
review
of
sampling
procedures
and
measurement
techniques
was
conducted.
4.0
Inspection
Team,
Observers,
and
Participants
The
inspection
team
consisted
of
two
representatives
of
the
EPA
Administrator.
Observers
from
the
Environmental
Evaluation
Group
(EEG),
Jim
Kenney
and
Bill
Bartlett,
were
also
present.
Page
4
Numerous
DOE
staff
members
and
contractors
participated
in
the
inspection.
Ron
Richardson
Ken
Mikus
Stew
art
Jones
I
Cynthia
Zlonar
I
ES&
H
WID
Waste
Ops
WID
ES&
H
WID
1
DOEKAO
1
Linda
Jo
Dalton
I
Bob
Billett
ES&
H
WID
I
ES&
H
I
Benny
Hooda
I
ES&
H
I
lReyCarrasc0
1
Geo.
Engr.
(WID
I
1
ES&
H
I
The
inspection
began
on
Wednesday,
March
24,
1999,
with
a
presentation
by
DOE
CAO
and
WID
about
the
present
status
of
the
WlPP
monitoring
program.
Site
personnel
discussed
the
monitoring
of
waste
activity,
geotechnical
parameters,
subsidence
monitoring,
environmental
monitoring
such
as
water
levels,
and
drilling
related
parameters.
The
inspection
team
toured
and
reviewed
various
activities
to
veri@
effective
implementation
of
the
plans
and
procedures
presented
during
the
oral
presentations.
The
team
reviewed
the
WIPP
Waste
Information
System
(WWIS)
used
to
capture
the
activity
of
waste
shipped
from
the
various
generator
sites,
The
team
reviewed
the
Delaware
Basin
Drilling
Surveillance
program,
and
the
Ground
Control
Monitoring
program.
The
inspection
team
reviewed
the
ground
water
monitoring
program
during
the
40
CFR
19
1.03,
Subpart
A
inspection
held
on
March
22
23,
1999.
5.0
Performance
of
the
Inspection
The
EPA
inspectors
reviewed
three
hndamental
areas
to
veri@
implementation
of
the
DOE
monitoring
program
during
the
management
and
storage
phase,
1)
written
plans
and
Page
5
procedures,
2)
quality
assurance
procedures
and
records,
and
3
)
results
of
the
monitoring
program
in
the
form
of
raw
data,
intermediate
reports,
and
final
annual
reports,
if
appropriate.
On
February
9
1
1,
1999,
the
EPA
QA
Team
performed
an
annual
inspection
of
the
DOE/
WID
quality
assurance
programs.
The
DOE/
WID
programs
were
found
to
be
adequately
maintained.
The
inspection
checklist
in
Attachment
A.
2
provides
details
on
inspection
activities.
5.1
Monitoring
of
Geomechanical
Parameters
DOE
committed
to
measure
four
geomechanical
parameters
in
the
CCA;
creep
closure,
extent
of
deformation,
initiation
of
brittle
deformation,
and
displacement
of
deformation
features.
WlPP
has
four
programs
that
supply
information
for
these
four
parameters;
the
geomechanical
monitoring
program,
the
geosciences
program,
the
ground
control
program,
and
the
rock
mechanics
program.
These
programs
are
documented
in
the
"Geotechnical
Engineering
Program
Plan"
(WP
7
1,
Attachment
D.
l,
COB
194.
X).
The
results
of
the
Geotechnical
Engineering
Program
are
documented
in
the
Geotechnical
Analysis
Report
for
July
1996
June
1997
(Attachment
D.
1,
COB
194.
P).
Rey
Carrasco,
contractor
for
DOE,
in
the
opening
meeting
discussed
how
the
four
geomechanical
parameters
are
measured
and
discussed
the
instrumentation
used
to
measure
the
response
of
shafts
and
underground
openings
(Attachment
D.
1,
COB
194C).
The
inspection
team
toured
and
reviewed
underground
instrumentation,
the
computer
data
base,
and
field
data
sheets
used
to
record
raw
measurement
data
(Attachment
D.
1,
COB
194L.
1
to
L.
6).
Mr.
Carrasco
showed
the
inspection
team
the
input
of
data
into
the
computer
database
and
examined
the
output
checkprint
(Attachment
D.
1,
COB
194M)
to
veri@
implementation
of
the
measurement
plan.
5.2
Monitoring
of
Hydrological
Parameters
DOE
committed
to
measure
two
hydrological
parameters
in
the
CCA;
Culebra
groundwater
composition
and
changes
in
the
Culebra
groundwater
flow
direction.
These
parameters
and
related
parameters
are
measured
and
documented
in
the
WIPP
environmental
monitoring
program.
These
programs
are
documented
in
the
Groundwater
Surveillance
Program
Pan
(WP
02
1,
Attachment
D.
2,
COB
194.
W).
The
results
of
this
program
are
documented
in
the
Waste
Isolation
Pilot
Plant
Site
Environmental
Report
Calendar
Year
1997
(Attachment
D.
2,
COB
194.
T).
In
the
opening
meeting
Stewart
Jones,
contractor
for
DOE,
discussed
the
program
used
to
measure
and
document
the
hydrological
parameters.
Mr.
Jones
discussed
the
measurement
methods
used
to
measure
groundwater
composition
and
used
to
measure
values
used
to
derive
the
direction
of
groundwater
Bow
(Attachment
D.
2,
COB
194W).
.
Page
6
The
inspection
team
reviewed
water
level
measurements
for
the
month
of
March
(Attachment
D.
2,
COB
1944.1
to
43).
The
team
reviewed
the
raw
data
sheets
recorded
in
the
field
and
the
quality
assurance
cross
check,
CHECKPRINT,
procedures
(Attachment
D.
2,
COB
194R).
The
inspection
team
also
toured
the
WQSP
2
groundwater
sampling
well
and
the
mobile
chemistry
laboratory.
Mi.
Jones
and
other
contractor
staff
presented
a
detailed
explanation
of
groundwater
composition
measurement
procedures,
such
as
dissolved
minerals,
and
quality
assurance
requirements.
5.3
Monitoring
of
Waste
Activity
Parameters
DOE
committed
to
measure
waste
activity
in
the
CCA.
This
parameter
is
part
of
the
extensive
database
collected
for
each
container
shipped
to
WIPP
and
is
stored
in
the
W
P
Waste
Information
System
(WWIS).
The
WWIS
is
a
software
system
that
screens
waste
container
data
and
provides
reports
on
the
TRU
waste
sent
to
WIPP.
The
requirements
for
the
WWIS
are
discussed
in
"WIPP
Waste
Information
System
Program"
(WP
05
WA.
02,
Attachment
D.
3,
COB
1
9
4
9
.
The
facility
demonstrated
that
the
WWIS
can
receive
data
and
that
the
WWIS
can
generate
reports.
The
CAO
has
committed
to
annual
waste
activity
reports.
Ken
Mikus,
contractor
for
DOE,
discussed
how
the
WWIS
is
used
to
record
waste
activity
information
provided
by
the
generator
sites
and
how
the
computer
database
that
is
created
is
used
to
produce
the
necessary
reports.
The
inspection
team
toured
the
WWIS
computer
system
where
Mr.
Mikus
demonstrated
the
transmission
of
data
from
the
Los
Alamos
Laboratory
generator
site
and
how
this
information
is
used
to
develop
different
waste
activity
reports
(Attachment
D.
3,
COB
194G.
5.4
Monitoring
of
Drilling
Related
Parameters
DOE
committed
to
measure
two
drilling
related
parameters
in
the
CCA;
the
drilling
rate
and
the
probability
of
encountering
a
Castile
brine
reservoir.
These
parameters
are
measured
as
part
of
the
"Delaware
Basin
Drilling
Surveillance
Program"
(WP
02
PC.
02,
Attachment
D.
4,
COB
194.1).
This
surveillance
program
measures
or
records
many
parameters
related
to
drilling
activities
around
the
WIPP
site.
The
results
of
the
surveillance
program
is
documented
annually
in
the
Delaware
Basin
Drilling
Surveillance
Program
Annual
Report
for
October
1997
through
September
1998
(Attachment
D.
4,
COB
194.
K).
During
the
opening
meeting
David
Hughes,
contractor
for
DOE,
discussed
the
program
used
to
measure
the
drilling
rate
and
used
to
derive
the
probability
of
encountering
a
Castile
brine
reservoir.
He
discussed
the
information
sources,
such
as
Dwight's
Petroleum
commercial
information
and
the
state
of
New
Mexico
Oil
Conservation
Division.
Mr.
Hughes
explained
the
Page
7
data
collected
and
placed
in
the
well
information
database
and
the
quality
assurance
requirements
(Attachment
D.
4,
COB
194F).
Mr.
Hughes
provided
the
inspection
team
a
hands
on
demonstration
of
the
computer
database
system
and
showed
examples
of
maps
produced
and
reports
generated
from
the
system
(Attachment
D.
4,
COB
194J).
5.5
Monitoring
of
Subsidence
Parameters
DOE
committed
to
measure
the
subsidence
at
the
WIPP
site
in
the
CCA.
This
parameter
is
documented
as
part
of
the
of
the
"WIF'P
Underground
and
Surface
Surveying
Program"
(WP09
ES.
01,
Attachment
D.
5,
COB
194.
U).
The
DOE
will
perform
the
subsidence
survey
at
the
site
annually
during
pre
closure
operations.
The
results
of
this
program
are
to
be
reported
annually
in
the
WIPP
Subsidence
Monument
Leveling
Survey
1998
(Attachment
D.
5,
COB
194.0).
During
the
opening
meeting
Rey
Carrasco,
contractor
for
DOE,
discussed
the
subsidence
parameter
measurements
program
(Attachment
D.
5,
COB
194D).
Mr.
Carrasco
explained
how
horizontal
and
vertical
surveys
would
be
performed
and
the
quality
assurance
requirements
for
these
surveys.
Mr
Carrasco
and
his
staff
demonstrated
to
the
inspection
team
the
survey
equipment
used,
the
methods
used
to
record
and
check
field
data,
how
these
data
are
input
into
the
computer
database
and
are
used
to
produce
the
needed
reports.
6.0
Summary
of
finding,
observation,
concerns,
and
recommendations.
EPA
performed
this
inspection
to
verify
that
DOE/
WLD
has
implemented
a
program
at
the
WIPP
site
to
monitor
the
ten
parameters
it
found
to
be
important
in
the
CCA.
During
this
inspection
the
inspectors
found
that
DOE
has
adequately
implemented
programs
to
monitoring
these
ten
parameters
during
pre
closure
operations.
DOEiWID
also
plans
to
report
the
results
of
these
monitoring
activities
as
committed
to
in
the
CCA
documentation.
Page
8
Attachment
A.
1
40
CFR
194.42
Inspection
Plan
Purpose:
Veri@
that
the
Department
of
Energy
(DOE)
can
demonstrate
that
the
Waste
Isolation
Pilot
Plant
(WIPP)
is
monitoring
the
parameter
commitments
made
in
the
documentation
to
support
the
EPA's
certification
decision,
in
particular
CCA,
Volume
1,
Section
7.0
and
Appendix
MON.
This
inspection
is
conducted
under
the
authority
of
40
CFR
5
194.2
1.
This
inspection
is
part
of
EPA's
continued
oversight
to
ensure
that
WIPP
can,
in
fact,
monitor
the
performance
of
significant
parameters
of
the
disposal
system.
Scope:
Inspection
activities
will
include
an
examination
of
monitoring
and
sampling
equipment
both
on
and
off
site,
and
in
the
underground.
A
review
of
sampling
procedures
and
measurement
techniques
may
be
conducted.
Quality
assurance
procedures
and
documentation
for
each
of
these
activities
may
also
be
reviewed.
Startup
Issues:
The
specific
purpose
of
this
inspection
is
to
veri@
and
confirm
that
WIPP
has
complied
with
the
requirements
of
40
CFR
194.42.
As
stated
in
40
CFR
194.42(
c)
I.
,
.in
no
case
shall
waste
be
emplaced
in
the
disposal
system
prior
to
the
implementation
of
pre
closure
monitoring."
Therefore,
the
EPA
believes
it
is
appropriate
to
veri@
the
adequate
implementation
of
pre
closure
monitoring
before
the
first
receipt
of
waste
at
WIPP.
Location:
This
inspection
will
be
held
at
the
WIPP
facility
location
twenty
six
miles
south
east
of
Carlsbad,
New
Mexico
and
the
surrounding
vicinity
as
needed.
Duration:
The
EPA
expects
to
complete
its
inspection,
with
DOE'S
cooperation,
in
one
day.
The
day
will
begin
with
an
opening
meeting
at
8:
OO
a.
m.
and
end
at
5:
OO
p.
m.
with
a
closeout
session.
Date:
Expected
to
be
held
during
the
week
of
March
22,
1999.
Attachment
A.
2
40
CFR
194.42
Inspection
Check
List
40
CFR
194.42
DOE
WIPP
Monitoring
Commitments
Checklist
L
_
~
Pre
closure
Monitoring
Commitments
Question
Does
DOE
demonstrate
that
they
have
implemented
plans/
programs/
procedures
to
measure
a)
Creep
Closure;
b)
Extent
of
Deformation;
c)
Initiation
of
Brittle
Deformation
and
d)
Displacement
of
Deformation
Features
during
the
pre
closure
phase
of
operations
as
specified
in
the
CCA
part
of
the
geomechanical
monitoring
system?
(CCA?
Volume
1,
Table
7
7;
App
MON,
Table
MON
1)
40
CFR
194.42
(c)
and
(e)
~
Does
DOE
demonstrate
that
they
have
implemented
an
effective
quality
assurance
program
for
item
1
above?
40
CFR
194.22
Does
DOE
demonstrate
that
the
results
of
the
geotechnical
investigations
are
reported
annually?
(CCA,
App.
MON,
Page
MON
10)
~~
~~
Comment
(Objective
Evidence)
Item
#28,
below,
documents
the
program
planned
to
measure,
document,
report,
and
QA
these
four
activities.
Section
3.0,
item
#28
documents
the
Geomechanical
Monitoring
Program
and
records
the
activities
associated
with
this
program,
the
methods
planned
to
be
used,
and
the
reporting
plans.
Section
4.0,
item
#28
documents
the
quality
assurance
requirements
of
these
actrvities.
Items
#16
and
#17
are
examples
of
raw
data
collection
and
vedication.
Items
#18
and
#19
are
examples
of
results
of
these
monitoring
activities.
The
inspection
team
toured
and
reviewed
the
computer
system
and
database
systems
used
to
collect
and
process
these
data.
EPA
performed
a
quality
assurance
inspection
February
9
1
1,
1999,
and
found
the
program
at
DOE/
WID
adequate.
__~~
~~
Item
#28,
page
8
requires
that
analysis
will
be
performed
annually
and
the
results
will
be
published
in
the
geotechnical
analysis
report.
Result
Sat.
Sat.
Sat.
Documents
Reviewed:
#7
WIPP
Geotechnical
Engineering
Monitoring
Presentation
by
Rey
Carrasco
#28
WIPP
Geotechnical
Engineering
Program
Plan
W
07
0
1,
Revision
2
#16
Sample
raw
data
GIS
Field
Data
Sheets,
Room
Closure
Measurements
#17
Sample
raw
data
CVPT
Field
Data
Checkprint
#
18
Long
Term
Ground
Control
Plan
for
the
Waste
Isolation
Pilot
Plant
#19
Geotechnical
Analysis
Report
for
July
1996
June
1997
40
CFR
194.42
DOE
WIPP
Monitoring
Commitments
Checklist
#
..........
..........
....................
.........
..........
..........
..........
.........
.........
..........
..........
....................
............
............
....
......
..........
1
2
3
Pre
closure
Monitoring
Commitments
Question
Does
DOE
demonstrate
that
they
have
implemented
planslprogramsiprocedures
to
measure
a)
Culebra
Groundwater
Composition;
b)
Change
in
Culebra
Groundwater
Flow
Direction
during
the
pre
closure
phase
of
operations
as
specified
in
the
CCA
part
of
WIF'P's
groundwater
monitoring
plan?
(CCA,
Volume
1;
Table
7
7;
App
MON,
Table
MON
1)
40
CFR
194.42
(c)
and
(e)
Does
DOE
demonstrate
that
they
have
implemented
an
effective
quality
assurance
program
for
item
1
above?
(CCA,
App
MON,
Page
MON
22)
40
CFR
194.22
Does
DOE
demonstrate
that
the
results
of
the
groundwater
monitoring
program
are
reported
annually
'?
(CCA.
App.
MON,
Page
MON
22)
Comment
(Objective
Evidence)
Item
#27,
below,
documents
the
program
planned
to
measure,
document,
report,
and
QA
these
two
activities.
Item
#27
documents
the
Groundwater
Surveillance
Program
Plan
and
records
the
activities
associated
with
this
program,
the
methods
planned
to
be
used,
and
the
reporting
plans.
Section
4.0,
item
#27
documents
the
quality
assurance
requirements
of
these
activities.
Item
#22
is
an
example
of
actual
water
level
measurements.
Item
#21
is
an
computer
print
out
of
these
measurements
and
item
#23
is
a
checkprint
of
these
same
measurements
with
a
signature
verifying
QA
review.
Item
#23
is
an
example
of
results
of
these
monitoring
activities.
The
inspection
team
toured
and
review.:
+he
WQSP
2
borehole
location
to
evaluate
water
measurement
techniques.
The
team
also
evaluated
the
chemical
analysis
performed
in
the
mobile
laboratory.
~~
~
~
EPA
performed
a
quality
assurance
inspection
February
9
1
1,
1999,
and
found
the
program
at
DOE/
WD
adequate.
Item
#27,
page
28
documents
that
results
of
monitoring
will
be
reported
annually
and
will
be
published
in
the
Annual
Site
Environmental
Report
(ASER).
Result
Sat.
Sat.
Sat.
Documents
Reviewed:
#9
Environmental
Monitoring
40
CFR
194
Presentation
by
Stewart
Jones
#27
Groundwater
Surveillance
Program
Plan
WP
02
1,
Revision
3
#21
Computer
printouts
of
water
level
measurements
measured
during
the
month
of
March
1999
#22
Actual
field
copies
of
raw
data
of
water
levels
measured
in
March
1999
#23
Samples
of
signed
quality
assurance
check
prints
of
water
level
measurements
during
the
month
of
March
#21
Waste
Isolation
Pilot
Plant
Site
Environmental
Report
Calendar
Year
1997
1999
40
CFR
194.42
DOE
WIPP
Monitoring
Commitments
Checklist
#
.................
...................
............
....................
....................
....................
............
.......
.~,.:.:.:.:.
y,.:.:
..........
.......
1
2
3
Pre
closure
Monitaring
€ornmitments
Question
Does
DOE
demonstrate
that
they
have
implemented
plans/
programs/
procedures
to
measure
a>
Waste
Activity?
(CCA,
Volume
1,
Table
7
7;
App
MON,
Table
MON
1)
40
CFR
194.42
(c)
and
(e)
Does
DOE
demonstrate
that
they
have
implemented
an
effective
quality
assurance
program
for
item
I?
(CCA,
App
WAP,
page
C
30)
40
CFR
194.22
~~
Does
DOE
demonstrate
that
the
results
of
the
waste
activity
parameters
are
reported
annually'?
(CCA
Volume.
Section
7.2.4
Reporting)
Comment
(Objective
Evidence)
WWIS
will
be
used
to
measure
and
store
waste
activity
among
other
things.
Item
#26,
below,
documents
the
program
planned
to
measure,
document,
report,
and
QA
this
activity.
Item
#26
documents
the
WWIS
Program
and
records
the
activities
associated
with
this
program,
the
methods
planned
to
be
used,
and
the
reporting
plans.
Item
#I
1
is
an
example
of
the
Waste
Container
Report
for
LANL
waste
shipped
on
March
25,
1999
and
item
#I2
is
an
example
of
the
Nuclide
Report
for
test
waste
data.
The
inspection
team
toured
and
reviewed
the
WWIS
computer
system
and
the
database
computer
program.
The
team
reviewed
the
query
capabilities
of
the
system
to
produce
waste
activity
reports.
~~~
EPA
performed
a
quality
assurance
inspection
February
9
1
1.
1999,
and
found
the
program
at
DOE/
WID
adequate.
Item
#26,
page
19
documents
that
results
of
monitoring
will
be
reported
annually.
Documents
Reviewed:
#6
WIPP
Waste
Information
System
(WWIS)
Presentation
by
Ken
Mikus
#26
WIPP
Waste
Information
System
Program
WP
05
WA.
02,
Revision
0
#I
1
Sample
'Waste
Container
Data
Report'
from
the
WWIS
#I2
Samole
'Nuclide
Report'
from
the
WWIS
Result
Sat.
Sat.
Sat.
40
CFR
194.42
DOE
WWP
Monitoring
Commitments
Checklist
#
I
2
3
Pre
closure
and
Post
Closure
Monitoring
Commifments
Question
Does
DOE
demonstrate
that
they
have
implemented
plans/
programs/
procedures
to
measure
a)
Drilling
Rate;
and
b)
Probability
of
Encountering
a
Castile
Brine
Reservoir?
(CCA,
Volume
1,
Table
7
7;
App
MON,
Table
MON
1)
40
CFR
194.42
(c)
and
(e)
Does
DOE
demonstrate
that
they
have
implemented
an
effective
quality
assurance
program
for
item
1
above'?
(CCA,
App
DMP,
page
DMP
9)
40
CFR
194.22
~~
__~~
~
~~
Does
DOE
demonstrate
that
the
results
of
the
drilling
related
parameters
are
reported
annually?
(CCA
Volume,
Section
7.2.4
Reporting;
App
DMF,
page
DMP
9)
~~
~
Comment
(Objective
Evidence)
ltem
#13,
below,
documents
the
program
planned
to
measure,
document,
report,
and
QA
these
two
activities.
Item
#
13
documents
the
Delaware
Basin
Drilling
Surveillance
Plan
and
records
the
activities
associated
with
this
program,
the
methods
planned
to
be
used,
and
the
reporting
plans.
Section
6.0,
item
#13
documents
the
quality
assurance
requirements
of
these
activities.
Item
#
14
is
an
example
of
the
information
recorded
and
stored
in
the
drilled
hole
database.
Item
#
15
is
a
copy
of
the
annual
report;
page
15
shows
the
1998
calculation
of
the
dnlling
rate
and
page
shows
a
discussion
of
Castile
brine
pockets.
The
inspection
team
toured
and
reviewed
the
computer
and
database
system
used
to
record
and
store
drill
hole
data.
The
team
reviewed
the
report
and
mapping
capabilities
of
the
computer
system..
EPA
performed
a
quality
assurance
inspection
February
9
1
1,
1999,
and
found
the
program
at
DOE/
WID
adequate.
Item
#13.
page
5
documents
that
results
of
monitoring
will
be
reported
annually.
Documents
Reviewed:
#10
Delaware
Basin
Surveillance
Plan
Presented
by
David
Hughes
#13
Delaware
Basin
Drilling
Surveillance
Plan
WF'
02
PC.
02,
Revision
0
#14
Sample
print
out
from
the
drilling
surveillance
computer
database
#15
Delaware
Basin
Drilling
Surveillance
Program
Annual
Report
for
October
1997
through
September
1998
Result
Sat.
Sat.
Sat.
40
CFR
194.42
DOE
WIPP
Monitoring
Commitments
Checklist
#
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
..
.........
.::.
v
.
.
.
.
.
.
.
.
1
2
3
Pre
closure
and
Poet
CIosure
Monitoring
Commitments
Question
Does
DOE
demonstrate
that
they
have
implemented
plans/
programs/
procedures
to
measure
a)
Subsidence
measurements?
(CCA,
Volume
1,
Table
7
7;
App
MON,
Table
MON
I)
40
CFR
194.42
(c)
and
(e)
Does
DOE
demonstrate
that
they
have
implemented
an
effective
quality
assurance
program
for
item
I?
40
CFR
194.22
Does
DOE
demonstrate
that
the
results
of
the
subsidence
measurements
are
reported
annuallv?
(CCA
Volume,
Section
7.2.4
Reporting)
~
~~~
Comment
(Objective
Evidence)
Item
#25,
below,
documents
the
program
planned
to
measure,
document,
report,
and
QA
these
two
activities.
Item
#25
documents
the
WIPP
Underground
&
Surface
Surveying
Program
and
records
the
activities
associated
with
this
program,
the
methods
planned
to
be
used,
and
the
reporting
plans.
Section
4.0,
item
#25
documents
the
quality
assurance
requirements
of
these
activities.
Item
#20
is
a
copy
of
the
annual
report
for
1998.
The
inspection
team
toured
and
reviewed
the
computer
and
database
system
used
to
record
and
store
subsidence
survey
data.
The
team
reviewed
the
report
and
mapping
capabilities
of
the
computer
system..
EPA
performed
a
quality
assurance
inspection
February
9
1
1,
1999,
and
found
the
program
at
DOE/
WID
adequate.
Item
#25,
page
11
documents
that
results
of
monitoring
will
be
reported
annually
Documents
Reviewed:
#8
WIPP
Subsidence
Monitoring
Presented
by
Rey
Carrasco
#25
WIPP
Underground
and
Surface
Surveying
Program
WP
09
ES.
O1,
Revisi'on
1
#20
WIPP
Subsidence
Monument
Leveling
survey
1998
Result
Sat.
Sat.
Sat.
I
Attachment
B
Opening
and
Closing
Sign
Up
Sheets
ENVIRONMENTAL
PROTECTION
AGENCY
CFR
194.42
OPENING
MEETING
ATTENDANCE
n
March
24,
1999
PRINTED
NAME
_L
/
t
Tw
9`
s
PHONE
NUMBER
a
34,893
3/
ENVIRONMENTAL
PROTECTION
AGENCY
March
25,
1999
CFR
194.42
CLOSE
OUT
MEETING
ATTENDANCE
Attachment
C
Documents
Reviewed
4
I
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m
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I
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Attachment
D.
1
Geomechanical
Documents
Reviewed
1
Effective
Date:
0311
619
WP
07
01
Revision
2
WIPP
Geotechnical
Engineering
Program
Plan
Cognizant
Section:
Geotechnical
Enaineerina
Approved
By:
S.
J.
Patchet
Cognizant
Department:
Enaineerina
Approved
By:
J.
J.
Garcia
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
TABLE
OF
CONTENTS
.
I
1
.O
INTRODUCTION
....................................................................................................
1
.1
Backaround
1
1.2
Geosciences
Pfoclram
.....................................................................................
2
1.3
Geomechanical
Monitorina
Prosram
...........................................................
2
1.4
Rock
Mechanics
Proaram
.............................................................................
2
1.5
Ground
Control
Proaram
..............................................................................
2
2.0
ADMlNlSTRATlON
3
2.1
Oraanization
....................................................................................................
3
2.2
Responsibilities
3
2.3
Trainina
and
Qualifications
..........................................................................
3
.....................................................................................................
.................................................................................................
...........................................................................................
.;.
3.0
TECHNICAL
PROGRAM
DESCRIPTION
...............................................................
3
3
3.1
Geosciences
Proqram
.....................................................................................
3
3.1
.I
Background
.........................................................................................
4
3.1.2
Purpose
...............................................................................................
3.1.3
Scope
4
3.1.4
Methods
4
3.2
Geomechanical
Monitorina
Prosram
...........................................................
5
6
3.2.1
Background
........................................................................................
6
3.2.2
Purpose'
..............................................................................................
6
3.2.3
Scope
..................................................................................................
3.2.4
Methods
7
3.3
Rock
Mechanics
Proclrarn
...........................................................................
10
3.3.1
Background
10
3.3.2
Purpose
10
3.3.3
Scope
10
3.3.4
Methods
11
Ground
Control
Prosram
............................................................................
12
13
3.4.1
Background
......................................................................................
3.4.2
Purpose
13
3.4.3
Scope
14
3.4.4
Methods
14
..................................................................................................
..............................................................................................
..........................................................................................
....
......................................................................................
............................................................................................
................................................................................................
.............................................................................................
3.4
............................................................................................
................................................................................................
.............................................................................................
4.0
QUALITY
ASSURANCE
15
........................................................................................
4.1
Desian
Control
15
15
4.2
Procurement
................................................................................................
15
4.3
Instructions,
Procedures
and
Drawinas
.........................................................
4.4
Document
Control
16
................
16
4.5
Control
of
Purchased
Material,
Equbment.
and
Services
:
............
4.6
Identification
and
Control
of
Items
16
4.7
Test
Control
16
.............................................................................................
.......................................................................................
............................................................
.................................................................................................
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
4.8
Software
Reauirements
..............................................................................
17
4.9
Control
of
Monitoring
and
Data
Collection
Equipment
..................................
18
4.1
0
4.1
1
Control
of
Nonconformina
Conditiondltems
.
.
.
.
.
.
.
.
.
.
.
.
...
.
.
.
.
_..
.
._.
.
....
.
18
4.12
Corrective
Actions
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
'.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
*
.
.
.
.
..
.
.
.
.
.
.
.
.
.
.
.
..
.
.
...
.
.
.
.
...
.
..
18
4.1
3
4.14
4.15
Handha.
Storaae.
and
Shirminq
.
....
....
...
....
..
...
.....
..
......
..........
.....
..
18
Records
Manaaement
.
.
.
..
.
.
.
.
.
.
..
..
.
..
.
..
.
.
.
.
.
.
...
.
...
.
.
.
.
...
.
.
.
.
.
...
._
....
.
...
...
.......
19
Audits
and
Independent
Assessments
.......
....
...
........
.
...
.._....
.............
19
Data
Reduction
and
Verification
..
.
..
.
..
..
.
.
.
.
..
.
.
....
..
...
.
.
.
.
.
............
......
.
.
19
19
5.0
REFERENCES
...............................................................,.............~.....................
ii
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
I
.O
INTRODUCTION
This
document
defines
the
field
programs
and
investigations
to
be
carried
out
by
tbe
Waste
Isolation
Division
(WID)
Geotechnical
Engineering
Section.
The
geotechnical
engineering
programs
are
designed
to
provide
scientific
information
necessary
to
establish
a
high
level
of
understanding
of
site
characteristics
and
to
assess
the
stability
and
performance
of
the
underground
facility.
Programs
currently
consist
of
the
following
activities:
Geosciences
Geomechanical
Monitoring
Ground
Control
Rock
Mechanics
These
programs
will
be
implemented
and
controlled
by
this
program
plan.
1.1
Backaround
The
programs
listed
in
Section
2
will
demonstrate
the
safe
disposal
of
transuranic
waste,
both
in
the
short
term
(during
the
operational
life
of
the
facility)
and
in
the
long
term
(following
decommissioning),
that
will
satisfy
the
appropriate
federal
regulations
governing
isolation
of
the
waste.
The
data
will
increase
confidence
,in
the
effectiveness
and
safety
of
the
underground
operations,
validate
the
design,
support
site
characterization
and
performance
assessment
activities,
and
support
activities
required
for
research
and
technological
development.
Drivers
for
these
programs
include
the
Consultation
and
Cooperation
Agreement
with
the
state
of
New
Mexico,
which
stipulates
continuing
studies
of
the
site
geology;
t
h
e
Environmental
Protection
Agency's
standards
for
management
of
transuranic
waste;
the
Resource
Conservation
and
Recovery
Act;
and
the
Mine
Safety
and
Health
Administration.
These
programs
implement
the
applicable
portions
of
systems
AUOO
and
EM00
System
Design
Description
(SOD).
The
programs
will
also
ensure
that
the
facility
operates
safely
and
that
data
are
available
to
make
decisions
for
managing
and
performing
engineering
and
operational
activities.
Field
activities
will
be
organized
into
four
programs
that
cover:
Geosciences
Rock
mechanics
evaluation
Ground
control
assessments
Data
collection
from
geomechanical
instrumentation
Each
field
program
will
be
controlled
by
a
program
plan
describing
the
general
scope
of
the
investigation,
its
methods,
and
quality
assurance
requirements.
...
Ill
WiPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
I
.2
Geosciences
Proaram
The
Geosciences
Program
will
continue
confirmation
of
site
suitability
based
on
field
activities
such
as
geologic
mapping
of
the
facility
horizon
excavations
and
logging
of
cores.
These
activities
will
be
used
to
characterize,
demonstrate
the
continuity
of,
and
document
the
geology
exposed
in
the
underground
excavations.
The
program
also
will
maintain
a
storage
facility
for
site
generated
geologic
samples
and
a
local
seismic
monitoring
system.
1.3
Geomechanical
Monitorina
Proaram
The
Geomechanical
Monitoring
Program
will
provide
data
on
the
Waste
Isolation
Pilot
Plant
(WIPP)
geotechnical
berformance
design
for
design
validation
and
the
short
term
and
long
term
behavior
of
underground
openings,
and
routine
evaluations
of
the
safety
and
stability
of
excavations.
Data
on
the
stability
and
closure
of
underground
excavations
will
be
used
to
identify
areas
of
potential
instability
and
allow
remedial
actions
to
be
taken.
Monitoring
of
geotechnical
parameters
will
be
performed
using
geomechanical
instruments,
including
tape
extensometer
stations,
convergence
meters,
borehole
extensometers,
piezometers,
strain
gauges,
load
cells,
crack
meters,
and
other
instruments
installed
in
the
shafts
and
drifts
of
the
WIPP
facility.
1.4Rock
Mechanics
Procrram
The
Rock
Mechanics
Program
will
assess
of
the
performance
of
the
underground
facility.
Data
from
geomechanical
monitoring
and
geosciences
observations
will
be
used
to
evaluate
the
current
and
future
performance
of
the
excavations.
Numerical
modeling
and
empirical
methods
will
be
used
to
evaluate
the
effects
of
proposed
design
changes
and
the
long
term
behavior
of
the
underground
facility.
1.5Ground
Control
Proararn
The
Ground
Control
Program
will
ensure
that
the
underground
is
safe
from
any
unexpected
roof
or
rib
falls.
It
will
provide
the
experience
necessary
to
design
ground
control
systems
for
the
host
rock,
to
monitor
ground
control
system
performance
through
data
and
observations,
and
to
allow
projections
to
be
made
regarding
future
ground
support
requirements.
2
WIPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
2.0ADMINISTRATION
2.1
Oraanization
The
WID
organizational
structure
is
described
in
the
WID
Quality
Assurance
Program
Description
(WP
13
1
).
Geotechnical
Engineering
reports
to
the
Engineering
Department
senior
manager.
2.2
Remonsibilities
The
Geotechnical
Engineering
manager
and
staff
are
responsible
for
achieving
and
maintaining
quality
in
the
geotechnical
engineering
programs.
2.3Trainina
and
Qualifications
Personnel
who
perform
specific
tasks
associated
with
geological
and
geotechnical
data
collection,
engineering
assessments,
and
quality
assurance/
quality
control
measures
will
be
trained
and
qualified
in
the
application
of
the
specific
requirements
to
complete
their
tasks.
The
minimum
training
requirements
for
engineering
personnel
are
identified
in
the
Engineering
Technical
Training
Requirements
Policy.
3.0TECHNlCAL
PROGRAM
DESCRIPTION
3.1
Geosciences
Proqram
The
Geosciences
Program
contains
activities
that
continue
confirmation
of
site
suitability
through
surface
and
underground
field
investigations.
These
activities
wiil
generate
data
used
in
monitoring
the
repository
and
in
rock
mechanics
studies.
Information
from
the
Geosciences
Program
will
be
used
to
document
the
existing
geologic
conditions
and
characteristics
and
to
monitor
for
changes
resulting
from
the
excavations.
Activities
associated
with
this
program
will
include
geologic
and
fracture
mapping,
maintenance
of
a
facility
for
the
storage
of
geologic
samples
(the
Core
Library),
seismic
monitoring
and
evaluation,
and
other
activities
performed
as
needed.
The
program
will
describe
the
general
scope
of
investigations,
the
methods,
and
program
requirements.
The
plan
will
be
updated
periodically
to
reflect
additions
and
changes
to
the
program.
3.1.1
Background
The
Los
Medanos
area
has
been
studied
since
1974
to
assess
site
capability
for
isolation
of
radioactive
waste.
The
present
WIPP
site
was
selected
in
1976
and
has
been
under
continuous
investigation
since
that
time
as
a
site
for
containment
and
isolation
of
transuranic
radioactive
waste.
Because
geology
is
the
principal
factor
in
the
isolation
of
the
waste
from
the
accessible
environment,
the
Geosciences
Program
provided
important
data
for
site
characterization
and
was
integral
to
the
decision
an
the
3
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
design
of
the
facility.
Extensive
geologic
characterization
of
drifts
and
shafts
was
performed
under
the
Site
and
Preliminary
Design
Validation
Program
for
confirmation
of
site
suitability.
The
program
provided
the
basis
for
the
decision
to
proceed
with
construction
of
the
WIPP
facility.
The
Geotechnical
Engineering
Geosciences
Program
was
developed
to
continue
confirmation
of
site
suitability
based
on
field
activities
such
as
geologic
mapping
of
the
facility
and
near
surface
stratigraphic
horizons,
core
logging,
and
geophysical
surveys.
These
activities
characterize,
demonstrate
the
continuity
of,
and
document
the
geology
at
the
site.
The
program
maintains
a
library
of
site
generated
geologic
samples
and
quarterly
reporting
of
the
results
of
local
seismic
monitoring.
The
program
is
also
responsible
for
the
collection
of
geologic
and
structural
data
and
other
section
activities
as
required.
3.1.2
Purpose
The
purpose
of
the
Geosciences
Program
is
to
confirm
the
suitability
of
the
site
based
on
continuing
field
activities.
3.1.3
Scope
Site
investigations
will
be
performed
as
required,
or
as
determined
useful,
for
enhancement
of
the
site
geologic
characterization
knowledge
base.
Activities
will
include
reconnaissance
geologic
mapping
of
new
excavations,
detailed
geologic
mapping,
investigations
of
regional
exposures,
and
geologic
support
to
projects
conducted
by
other
site
participants.
The
activities
associated
with
the
Geosciences
Program
are
designed
to:
Provide
additional
site
geological
characterization
based
on
geologic
mapping
of
excavations
and
core
logging
Maintain
a
current
data
base
on
mineralogy,
chemistry,
and
textural
feature
characteristics
of
the
local
geology
Maintain
a
current
level
of
knowledge
on
the
geohydrology
of
the
Salado
and
Rustier
Formations
based
on
geologic,
hydrologic,
and
geochemical
data
Monitor
the
local
seismicity
using
a
series
of
surface
based
seismographs.
As
part
of
this
activity,
analyses
will
be
performed
to
determine
if
any
correlation
of
seismic
events
with
mining
or
petroleum
recovery
operations
can
be
estabtished
3.1.4
Methods
Routine
tasks
will
be
carried
out
according
to
approved
WlPP
procedures.
Activities
in
4
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
development
or
those
not
expected
to
be
performed
routinely
will
be
performed
in
accordance
with
industry
standards
or
individual
program
plans
that
supplement
this
program
plan.
Routine
Activities
Seismic
Monitoring
Seismic
monitoring
and
evaluation
will
be
carried
out
by
the
New
Mexico
Institute
of
Mining
and
Technology,
a
subcontractor
to
WID.
Geologic
Mapping
Geologic
mapping
will
be
performed
in
newly
excavated
areas
and
when
the
cognizant
engineer
or
Geotechnical
Engineering
manager
deems
it
necessary.
The
mapping
results
will
be
documented
in
the
annual
geotechnical
analysis
reports
and
appropriate
topical
reports.
All
drifts
and
rooms
in
which
geologic
mapping
was
not
conducted
will
be
visually
inspected
by
the
cognizant
engineer,
or
designee,
within
three
months
of
excavation
to
verify
that
the
exposed
rock
units
are
laterally
continuous
and
similar
to
those
exposed
in
the
mapped
areas
of
the
facility.
Any
unusual
features
will
be
reported
in
the
annual
geotechnical
analysis
reports.
Fracture
Mapping
Fracture
mapping
will
be
performed
and
carried
out
by
the
cognizant
engineer,
designee,
or
Geotechnical
Engineering
manager
at
locations
selected
in
accordance
with
accepted
industry
practice.
Observations
from
boreholes
and
excavated
surfaces
will
be
used
in
performance
assessments
of
the
underground
faci
I
ity.
Core
Library
Operations
Geotechnical
Engineering
will
maintain
a
repository
for
geologic
samples
that
have
been
determined
necessary
for
long
term
storage.
Approved
WlPP
procedures
define
the
proper
methods
for
maintaining
the
sample
repository,
the
submittal
of
core
to
the
Core
Library,
maintenance
of
the
Core
Storage
Facility
(inventory,
handling,
and
distribution),
authorization
for
access
to
view
the
core
on
site,
and
authorization
to
remove
samples
from
the
library.
Other
Activities
of
the
Geosciences
Proqram
Test
plans
will
be
developed
for
geoscience
activities
that
are
in
a
developmental
stage
or
are
not
routinely
performed.
They
will
include
or
reference
the
appropriate
proce
dures
to
ensure
that
all
necessary
steps
for
completion
are
carried
out.
The
plans
will
detail
specific
plans
that
describe
the
activity,
location,
procedure,
etc.
3.2Geomechanical
Monitorina
Proararn
The
Geomechanical
Monitoring
Program
will
monitor
the
geomechanical
response
of
the
underground
openings
after
mining.
It
will
also
monitor
geotechnical
instruments
5
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
installed
in
the
shafts
and
drifts
of
the
WlPP
facility.
Geotechnical
instrumentation
installed
in
the
shafts
and
underground
includes
tape
extensometer
points,
convergence
meters,
borehole
extensometers,
piezometers,
strain
gages,
load
cells,
and
crack
meters.
The
instrumentation
is
sensitive
enough
to
detect
small
changes
in
rock
displacements
and
rock
stresses.
Information
generated
by
this
program
will
be
documented
in
annual
geotechnical
analysis
reports.
The
data
will
be
documented
more
frequently
as
recommended
by
the
cognizant
engineer
or
manager.
An
assessment
of
convergence
measurements
and
geotechnical
observations
will
be
made
after
each
round
of
measurements.
The
results
of
this
assessment
will
be
distributed
to
affected
underground.
operations,
engineering,
and
safety
managers.
This
plan
describes
the
general
scope
of
the
investigation,
methods,
and
program
requirements,
and
will
be
updated
periodically
to
reflect
additions
and
changes.
3.2.1
Background
The
instrumentation
system
has
provided
data
on
the
performance
of
the
WlPP
design
for
design
validation
and
for
projecting
the
long
term
behavior
of
the
underground
openings,
and
routine
evaluation
of
safety
and
excavation
stability.
From
an
opera
tional
standpoint,
the
geomechanical
data
allow
the
identification
of
areas
of
potential
instability
and
for
remedial
action
to
be
taken.
To
determine
the
long
term
behavior
of
the
repository,
assessments
will
rely
heavily
on
the
extrapolation
of
in
situ
data,
taken
over
a
period
of
years,
to
predict
thousands
of
years
of
repository
performance.
The
engineering
performance
of
the
WIPP
host
rock
is
important
in
the
assessment
of
the
design
of
the
operating
facility
and
its
long
term
performance.
Of
significance
are
the
time
dependent
properties
of
the
salt.
Sandia
National
Laboratories
has
carried
out
extensive
experimental
work
to
establish
an
appropriate,
constitutive
relationship
for
salt
that
can
predict
its
in
situ
mechanical
performance.
To
validate
the
adequacy
of
the
facility
design,
field
data
from
geomechanical
instrumentation
are
used
to
determine
actual
mechanical
performance
of
the
shafts
and
excavations
at
the
facility
horizon.
3.2.2
Purpose
The
purpose
of
the
Geomechanical
Monitoring
Program
is
to
determine
the
geomech
anical
performance
of
the
underground
excavations
at
WIPP.
Data
on
stability
and
closure
are
needed
for
operational
considerations
and
for
performance
assessment.
3.2.3
Scope
The
activities
associated
with
the
Geotechnical
Monitoring
Program
are
designed
to:
6
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
Maintain
and
augment
the
geotechnical
instrumentation
system
in
the
WlPP
underground
and
upgrade
the
automatic
data
acquisition
system
as
necessary
0
Monitor
geotechnical
instrumentation
on
a
regular
basis
and
maintain
a
current
data
base
of
instrument
readings
Evaluate
the
geotechnical
instrumentation
data
and
prepare
regular
reports
that
document
the
data
and
analyses
describing
the
stability
and
performance
of
underground
openings
Recommend
corrective
or
preventive
measures
to
ensure
excavation
stability
and
safe
operation
of
the
facility
3.2.4
Methods
The
process
by
which
geomechanical
monitoring
of
an
area
is
initiated
may
vary
as
part
of
operational
excavation
monitoring
or
research
testing.
Proper
documentation
and
analysis
is
common
to
all.
Installation
and
monitoring
of
the
instruments
wifl
be
governed
by
approved
WlPP
procedures.
The
instrumentation
will
be
monitored
remotely
using
data
loggers
or
read
manually.
Routine
tasks
will
be
carried
out
according
to
approved
WIPP
procedures.
Activities
which
are
in
development,
or
which
are
not
expected
to
be
performed
routinely,
will
be
performed
in
accordance
with
industry
standards
or
individual
program
plans
that
supplement
this
program
plan.
Data
Acquisition
The
remotely
polled
instruments
are
connected
to
a
surface
computer
through
a
system
of
cables,
termination
boxes,
and
data
loggers.
The
manually
read
instruments
will
be
monitored
using
electronic
read
out
boxes
and
mechanical
measuring
devices.
The
data
will
be
collected
on
a
quarterly
basis
at
a
minimum,
but
more
frequent
readings
may
be
collected
as
determined
by
the
cognizant
engineer
or
manager.
Geomechanical
Data
Loqqincl
Svstem
The
system
consists
of
surface
computers,
modems,
data
loggers,
and
associated
interconnecting
cabling.
The
instrumentation
is
routed
to
local
termination
cabinets
or
accessor
boxes
at
various
locations
in
the
underground.
These
contain
the
electronic
hardware
needed
for
multiplexing,
signal
conditioning,
data
conversion,
and
communi
cating
with
the
surface
computers,
which
are
connected
by
a
dedicated
communica
tions
data
link
cable.
The
surface
computers
communicate
through
modems
using
a
series
of
communication
and
data
management
software.
programs,
The
data
from
the
instruments
will
be
maintained
in
individual
data
bases
for
each
instrument
type.
Instrumentation
7
WIPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
The
instrumentation
used
at
WIPP
is
widely
accepted
in
the
geotechnical
and
mining
industry.
Geomechanical
instrumentation
installed
in
the
shafts
and
underground
includes
tape
extensometer
points,
convergence
meters,
borehole
extensometers,
rockbolt
load
cells,
pressure
cells,
crack
meters,
strain
gauges,
and
piezometers.
The
instrumentation
is
sensitive
to
small
changes
in
rock
displacement
and
stress.
The
geomechanical
instruments
will
be
installed
and
monitored
in
accordance
with
approved
procedures
or
written
instructions.
Instrument
types,
monitoring
usage,
and
typical
installation
locations
are
listed
in
the
following
table.
Data
Analvsis
and
Dissemination
of
Data
The
frequency
of
analyses
of
geomechanical
data
will
be
based
on
the
requirements
established
in
design
documents
and
regulatory
requirements,
and
as
determined
by
the
geornechanical
instrumentation
cognizant
engineer.
A
comprehensive
analysis
of
the
data
will
be
performed
annually.
Results
of
t
h
e
analyses
will
be
published
in
geotechnical
analysis
reports.
Data
may
be
released
to
external
sources
more
8
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
frequently
with
consent
from
the
Department
of
Energy.
Assessments
of
the
convergence
measurements
and
other
geotechnical
observations
will
be
performed
after
each
round
of
complete
measurements.
Results
will
be
distributed
to
affected
underground
operations,
engineering,
and
safety
groups.
Data
analyses
may
be
performed
on
a
more
frequent
basis,
as
recommended
by
the
cognizant
engineer
or
manager.
Calibration
Measurement
and
data
collection
equipment
used
to
read
the
geotechnical
instruments
will
be
calibrated
in
accordance
with
approved
WlPP
procedures.
Frequency
of
calibration
will
be
based
on
manufacturer
recommendations
upon
receipt
of
the
measuring
device
at
the
WIPP
site,
or
as
determined
by
the
cognizant
engineer.
Calibration
records
will
be
kept
on
file
in
Geotechnical
Engineering.
Routine
Activities
Maintenance
will
be
performed
as
needed.
When
an
instrument
is
damaged
or
erroneous
readings
are
suspected,
the
instrument
will
be
physically
inspected
and
evaluated
for
repairs
or
replacement.
If
repair
efforts
are
unsuccessful,
that
instrument
will
be
documented
as
malfunctioning
and
monitoring
discontinued
until
the
instrument
has
been
replaced
or
abandoned.
Inspections
of
the
instrumentation
and
data
logging
components
will
be
performed
during
monitoring
activities,
These
inspections
check
the
physical
condition
of
the
instrumentation,
junction
boxes,
and
cabling
for
damage,
corrosion,
and
loose
parts.
Any
unusual
observations
or
deterioration
will
be
documented
on
the
Geotechnical
Instrumentation
System
field
data
sheets
and
the
cognizant
engineer
will
be
notified
of
existing
conditions.
The
inspection
results
and
performance
of
the
instrumentation
and
data
logging
components
will
be.
evaluated
by
comparing
the
monitoring
results
against
previous
readings.
These
evaluations
will
be
used
to
determine
whether
the
geomechanical
instrumentation
and
data
acquisition
system
are
performing
as
anticipated.
9
WlPP
Geotechnical
Engineering
Program
Plan
.
WP
07
01,
Rev.
2
Other
Activities
of
the
Geomechanical
Monitorinq
Proqram
Test
plans
will
be
developed
for
geomechanical
monitoring
activities
that
are
either
in
a
developmental
stage
or
not
routinely
performed.
These
plans
will
include
or
reference
the
appropriate
procedures
to
ensure
that
all
necessary
steps
to
complete
the
activity
are
carried
out
and
will
detail
specific
plans
that
describe
instrument
characteristics,
locations,
procedures,
etc.
These
activities
may
include
the
installation
and
monitoring
of
new
instrument
types
to
evaluate
their
adequacy
for
use
in
salt.
Changes
to
the
remote
monitoring
equipment
and
software
routines
will
be
documented
in
accordance
with
approved
WIPP
procedures.
3.3
Rock
Mechanics
Proaram
This
program
assesses
the
current
and
future
performance
of
the
underground
facility.
Its
statistical
and
empirical
data
methods
and
numerical
modeling
codes,
modified
for
use
in
salt
rock,
provide
the
process
for
analyzing
data
collected
from
geotechnical
instruments
and
visual
observations.
The
results
follow
approved
WlPP
procedures
and
will
be
published
in
annual
geotechnical
analysis
reports,
or
more
frequently
as
recommended
by
the
cognizant
engineer
or
manager.
This
program
plan
describes
the
general
scope,
methods,
and
program
requirements
of
investigations
and
will
be
updated
periodically
to
reflect
additions
and
changes.
3.3.1
Background
The
Rock
Mechanics
Program
assesses
of
the
performance
of
the
WlPP
design
for
design
validation
and
for
projecting
the
long
term
behavior
of
the
underground
openings
and
routine
evaluation
of
safety
and
excavation
stability.
From
an
operational
standpoint,
these
assessments
will
allow
the
identification
of
areas
of
potential
instability
and
the
application
of
remedial
actions,
if
necessary.
To
validate
the
adequacy
of
the
facility
design,
field
data
from
geomechanical
instrumentation
will
be
used
to
determine
actual
mechanical
performance
of
the
shafts
and
excavations
at
the
facility
horizon.
Analytical
methods,
such
as
numerical
modeling,
will
be
used
to
determine
the
potential
effects
of
mining
new
excavations,
excavation
sequence,
and
long
term
behavior
of
the
repository.
The
engineering
performance
of
the
WlPP
host
rock
is
important
to
assess
the
design
of
the
operating
facility
and
its
long
term
performance.
Of
significance
are
the
time
dependent
properties
of
the
salt.
Extensive
experimental
work
and
observa
tions
have
been
used
to
establish
an
appropriate,
constitutive
relationship
for
salt
that
is
used
to
predict
its
in
situ
mechanical
performance.
These
assessments
will
rely
heavily
on
the
extrapolation
of
in
situ
instrumentation
data
and
field
observations.
3.3.2
Purpose
10
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
The
Rock
Mechanics
Program
provides
the
capability
to
assess
the
geomechanical
response
of
the
surface
and
underground
facility
due
to
mining
of
the
underground.
3.3.3
Scope
The
activities
associated
with
the
Rock
Mechanics
Program
are
designed
to:
Assess
the
geotechnical
performance
of
the
underground
excavations
Assess
the
effectiveness
of
support
systems
installed
to
control
areas
of
potentially
unstable
ground
Assess
the
appropriateness
of
the
current
mine
design
and
periodically
evaluate
the
criteria
Provide
geotechnical
recommendations
for
the
development
of
mine
design
criteria
based
on
analytical
assessment
of
the
performance
of
the
existing
excavations
and
from
modeling
of
proposed
design
changes
Project
excavation
performance
based
on
new
mining,
ground
control
activities,
and
facility
aging
Predict
the
performance
of
underground
excavations
based
on
instrumentation
data
and
supplemented
by
analytical
studies
Maintain
a
library
of
numerical
modeling
codes
that
include
the
state
of
the
art
understanding
of
salt
rock
mechanics
Provide
recommendations
or
correctivelpreventive
measures
to
underground
operations
personnel
based
on
the
performance
and
expected
usage
of
the
underground
facility
3.3.4
Methods
The
processes
by
which
rock
mechanics
activities
are
completed
may
vary.
Evaluation
of
the
geomechanical
performance
of
the
underground
openings
will
use
numerical
analysis
techniques
commonly
used
in
the
mining
and
civil
engineering
industries.
The
use
of
these
techniques
will
be
governed
by
WlPP
approved
procedures
for
engineering
calculations
and
computer
software
control.
Routine
Activities
The
following
are
routine
activities
of
the
Rock
Mechanics
Program:
11
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
.
Geomechanical
Data
Assessment
Assessments
of
the
instrument
data
and
geologic
observations
will
be
performed
periodically
and
reported
in
the
annual
geotechnical
analysis
reports
and
other
more
frequent
topical
reports.
Complete
data
analyses
will
be
performed
at
least
once
a
year.
The
frequency
of
data
analyses
will
be
based
on
the
geotechnical
performance
of
the
excavations
and
their
operational
use.
The
geotechnical
data
will
be
evaluated
to
determine
whether
conditions
exist
which
warrant
closer
or,
possibly,
immediate
attention
from
a
ground
control
standpoint.
Geotechnical
assessments
measure
the
stability
of
the
openings
with
respect
to
operational
safety
and
long
term
performance.
Support
System
Performance
Evaluation
New
support
system
technologies
will
be
evaluated
as
they
become
available
and
will
be
used
as
they
are
proven.
Several
test
sections
of
support
systems
have
been
installed
and
are
being
monitored.
These
systems
are
instrumented
to
monitor
the
performance
of
the
system
components.
This
instrumentation,
in
conjunction
with
nearby
geomechanical
instrumentation,
allows
assessments
of
the
effectiveness
of
the
support
system
to
be
performed.
Numerical
Modeling
Material
modeling
codes
estimate
of
the
performance
of
the
salt
rock
material
based
on
the
material
properties
and
loading
conditions
provided
to
the
model.
These
models
can
be
used
to
determine
the
potential
effects
of
mining
new
excavations
on
the
facility
or
the
long
term
effect
of
an
excavation
on
nearby
openings.
The
accuracy
of
the
models
can
be
improved
by
modifying
the
code
to
more
accurately
represent
the
actual
physical
conditions.
These
modifications
may
include
mesh
refinement
and
the
use
of
input
data
that
more
accurately
describe
the
physical
properties
of
the
host
rock.
Other
Activities
of
the
Rock
Mechanics
Proaram
Test
plans
will
be
developed
for
rock
mechanics
activities
that
are
in
a
developmental
stage
or
are
not
routinely
performed.
These
plans
will
include
or
reference
the
appro
priate
procedures
to
ensure
that
all
necessary
steps
to
complete
the
activity
are
carried
out
and
will
detail
specific
plans
that
describe
the
activity,
location,
procedure,
etc.
These
activities
may
include
investigations
of
the
geomechanical
effect
of
new
mining
and
mine
design
changes
on
the
performance
of
the
underground
facility
and
subsidence
effects.
These
investigations
may
require
numerical
modeling,
materials
laboratory
testing,
and
field
observations.
The
results
will
be
used
to
incorporate
the
latest
understanding
of
the
host
rock
properties
into
the
modeling
codes
and
analytical
techniques.
3.4Ground
Control
Proqram
12
WIPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
The
Ground
Control
Program
provides
comprehensive
evaluation
of
the
ground
conditions
and
effectiveness
of
installed
support
systems
throughout
the
facility.
The
evaluations
will
be
based
on
visual
observations,
analyses
of
geomechanical
instru
mentation
data,
fracture
data
acquired
from
observation
boreholes,
and
rockbolt
failure
data.
The
design
of
new
support
systems
will
be
based
on
the
results
of
these
evaluations.
Ground
control
issues
have
been
addressed
since
excavation
began
at
WIPP.
fnitially
only
minor
spalls
were
observed.
However,
as
the
excavations
aged
and
issues
associated
with
the
roof
beam
began
to
develop,
most
of
the
facility
was
pattern
bolted
with
mechanical
anchor
rockbolts.
Because
these
bolts
provide
a
basically
rigid
support
system,
they
have
a
finite
life
and
supplemental
systems
are
required
in
areas
scheduled
for
decades
of
use.
The
support
systems
must
maintain
many
areas
of
the
underground
accessible
for
the
projected
life
of
the
facility.
The
information
generated
by
this
program
will
be
documented
in
annual
assessment
reports.
Assessment
of
the
performance
of
the
installed
ground
support
systems
are
performed
as
recommended
by
the
cognizant
engineer
or
manager.
The
results
of
these
assessments
will
be
distributed
to
affected
underground
operations,
engineering,
and
safety
manager
sections.
This
program
plan
describes
the
general
scope
of
the
ground
control
activities,
methods,
and
program
requirements,
and
will
be
updated
periodically
to
reflect
additions
and
changes
to
the
program.
3.4.1
Background
The
operating
life
of
sections
of
the
underground
facility
may
extend
to
approximately
fifty
years
from
the
date
of
excavation.
Over
time,
the
strains
associated
with
stress
conditions
around
the
excavation
result
in
degradation
of
the
surrounding
rock.
Safety
concerns
associated
with
deterioration
of
the
roof
necessitate
monitoring,
maintenance,
and
ground
control
mechanisms
to
ensure
safe
working
conditions.
Roof
support
systems
are
currently
in
place
throughout
the
facility;
however,
because
of
creep
closure,
they
may
undergo
severe
stress,
have
a
limited
service
life,
and
require
periodic
replacement.
Many
options
ar6
currently
available
for
ground
control
in
the
mining
industry.
Technologies
used
in
potash
and
salt
mines
are
the
most
applicable
to
WlPP
because
of
the
similar
behavior
of
the
rock.
A
comprehensive
testing
and
evaluation
program
has
been
used
to
determine
which
ground
support
components
and/
or
systems
are
most
applicable
to
specific
project
requirements.
This
program
consists
of
many
aspects
that
include
continuous
visual
inspections
of
the
underground
opening,
extensive
geomechanical
monitoring,
numerical
modeling,
analysis
of
rockbolt
failures,
implementation
of
ground
control
procedures,
and
comprehensive
in
situ
and
laboratory
testing,
and
evaluation
of
ground
support
components
and
systems.
13
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
The
excavations
vary
in
geometry,
geology,
age,
and
operational
use.
These
differences
affect
the
selection
of
ground
control
measures,
but
the
ability
of
the
salt
to
creep
or
flow
with
time
has
the
greatest
impact
on
selection
of
support
systems.
Salt
creep
exerts
strong
forces,
both
vertical
and
horizontal,
on
any
control
mechanism.
During
the
time
that
the
underground
has
been
active,
a
variety
of
ground
control
issues
have
been
encountered
ranging
from
minor
spalling
to
roof
falls.
3.4.2
Purpose
The
Ground
Control
Program
provides
the
strategies
for
development
and
selection
of
the
most
applicable
and
efficient
means
of
maintaining
and
monitoring
the
ground
conditions
of
the
WIPP
underground
to
ensure
safe
and
operational
conditions.
The
selection
of
ground
control
fixtures
is
in
accordance
with
30
CFR
u
57,
Subpart
B,
"Ground
Control."
3.4.3
Scope
The
program
is
continually
evolving.
Current
associated
activities
include:
Addressing
ground
control
concerns
and
design
and
implementation
of
ground
support
systems
on
a
case
by
case
basis
installing
and
monitoring
of
small
scale
and
full
scale
in
situ
support
systems
for
evaluation
Identifying
and/
or
developing
new
ground
control
technologies
that
have
application
to
WIPP
conditions
Documenting
and
evaluating
ground
support
system
component
failure
Evaluating
the
effects
of
new
mining
and
mine
design
changes
on
the
effectiveness
of
installed
ground
support
systems,
proposed
installations,
and
the
stability
of
the
excavation
3.4.4
Methods
Thorough
evaluations
of
the
ground
conditions
and
support
system
performance
throughout
the
facility
will
be
performed
annually.
Some
areas
may
be
evaluated
more
frequently
as
conditions
warrant,
These
evaluations
will
provide
information
necessary
to
address
the
near
term
ground
control
needs
and
for
long
term
ground
control
planning.
Three
basic
options
are
available
to
address
unstable
ground
conditions:
(I)
support
14
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
the
ground,
(2)
remove
the
ground,
or
(3)
discontinue
access.
The
first
two
options
are
engineering
alternatives
while
the
third
option
is
an
administrative
decision.
The
ground
control
design
criteria
are
based
on
long
term
objectives,
experience,
performance
of
existing
systems,
laboratory
and
in
situ
tests
of
selected
ground
control
components
and/
or
systems,
numerical
analysis,
and
site
specific
geotechnical
data.
These
criteria
may
be
modified
to
accommodate
technological
advances,
geologic
conditions,
or
operational
requirements.
Routine
Activities
Ground
support
systems
will
be
installed
in
accordance
with
approved
written
instructions.
Monitoring
of
the
geotechnical
instruments
that
monitor
the
performance
of
the
support
systems
will
be
performed
routinely
and
carried
out
according
to
approved
WlPP
procedures.
Other
Activities
of
the
Ground
Control
Program
Activities
which
are
in
development,
or
which
are
not
expected
to
be
performed
routinely,
will
be
performed
in
accordance
with
industry
standards
or
individual
program
plans
that
supplement
this
program
plan.
4.0QUALITY
ASSURANCE
The
WlPP
Geotechnical
Engineering
programs
are
governed
by
the
WID
Quality
Assurance
Program
Description.
Steps
to
ensure
quality
will
be
incorporated,
as
needed,
in
the
technical
procedures
used
for
geotechnical
engineering
activities.
The
Geotechnical
Engineering
manger,
or
assigned
designee,
is
responsible
for
developing
and
maintaining
this
program
plan
and
associated
procedures.
4.1
Desian
Control
Items
and
processes
will
be
designed
using
sound
engineering/
scientific
principles
and
appropriate
standards.
Design
work,
including
changes,
will
incorporate
appropriate
requirements
such
as
general
design
criteria
and
design
basis.
Design
interfaces
will
be
identified
and
controlled.
The
adequacy
of
products
will
be
verified
by
individuals
or
groups
other
than
those
who
performed
the
work.
Verification
work
will
be
completed
before
approval
and
implementation
of
the
design.
4.2
Procurement
Procurement
will
be
carried
out
in
accordance
with
the
appropriate
policies
and
procedures.
Technical
requirements
and
services
will
be
developed
and
specified
in
procurement
documents.
If
deemed
necessary,
these
documents
will
require
suppliers
to
have
an
adequate
quality
assurance
program
to
ensure
that
required
characteristics
are
attained.
15
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
4.3
Instructions.
Procedures
and
Drawinas
Quality
affecting
activities
performed
by,
or
on
behalf
of,
the
geotechnical
engineering
programs
will
be
performed
in
accordance
with
written
plans
or
approved
procedures.
WlPP
general
procedures
will
be
used
for
procurement,
document
control,
and
quality
assurance.
Technical
procedures
will
be
developed
for
routine
quality
affecting
functions.
The
procedures
will
include
in
process
and
final
quality
controls
and
documentation
require
ments.
The
procedures
will
be
as
detailed
as
required
and
include,
when
applicable,
quantitative
or
qualitative
acceptance
criteria
to
determine
that
activities
have
been
satisfactorily
accomplished.
Procedures
will
be
developed
in
accordance
with
existing
WlPP
procedures.
4.4
Document
Control
Documents
that
prescribe
processes,
specify
requirements,
or
establish
design
will
be
prepared,
approved,
issued,
and
controlled.
Controls
will
ensure
that
the
latest
approved
versions
of
procedures
are
used
in
performing
geotechnical
functions,
and
that
obsolete
materials
are
removed
from
work
areas.
The
Geotechnical
Engineering
manager
will
identify
the
individuals
responsible
for
the
preparation,
review,
and
approval
of
geotechnical
engineering
controlled
documents.
4.5
Control
of
Purchased
Material,
Eauioment.
and
Services
Measures
will
be
taken,
in
accordance
with
current
WlPP
procurement
policies
and
procedures,
to
ensure
that
procured
items
and
services
conform
to
specified
requirements.
These
measures
will
generally
include
one
or
more
of
the
following:
Evaluation
of
the
supplierk
capability
to
provide
items
or
services,
in
accordance
with
requirements,
including
the
previous
record
in
providing
similar
products
or
services
satisfactorily
Evaluation
of
objective
evidence
of
conformance,
such
as
supplier
submittals
Examination
and
testing
of
items
or
services
upon
delivery
If
it
is
determined
that
additional
measures
are
required
to
ensure
quality
in
a
specific
procurement,
additional
steps
may
be
included
in
procurement
documents
and
implemented
by
Geotechnical
Engineering
personnel
and/
or
the
Quality
and
Regulatory
Assurance
Department.
These
additional
assurances
may
include
source
inspection
and
audits
,or
surveillance
at
the
suppliers!
facilities.
16
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
4.6
Identification
and
Control
of
Items
Measures
will
be
used
to
ensure
that
only
correct
and
accepted
items
are
used
at
WIPP.
All
items
that
potentially
affect
the
quality
of
the
geotechnical
engineering
programs
will
be
identified
and
controlled
to
ensure
traceability
and
prevent
the
use
of
incorrect
or
defective
items.
4.7
Test
Control
Testing
or
experimentaI/
monitoring
activities
will
be
in
accordance
with
written
plans
or
procedures
that
contain
the
following
provisions,
as
applicable:
Purpose,
scope
and/
or
definition
Prerequisites
such
as
calibrated
instrumentation
and
supporting
data;
adequate
test
equipment
and
instrumentation,
including
accuracy
requirements;
completeness
of
item
to
be
tested;
suitable
and
controlled
environmental
conditions;
and
provisions
for
data
collection
and
storage
Instructions
for
performing
the
test
Any
mandatory
inspection
and/
or
hold
points
to
be
witnessed
by
WID
or
other
designated
representatives
Acceptance
and
rejection
criteria
Methods
of
documenting
or
recording
test
data
Requirements
for
qualified
personnel
Evaluation
of
test
results
by
authorized
personnel
Test
or
experirnental/
monitoring
procedures
prepared
by
other
project
participants
(e.
g.,
Sandia
National
Laboratories)
used
as
WID
procurement
documents
will
be
reviewed
to
ensure
that
the
documents
are
complete
and
the
tests
described
by
the
documents
are
adequate
to
determine
that
the
involved
equipment,
systems,
or
structures
are
operationally
acceptable.
4.8
Software
Reauirements
Computer
program
procurement,
design,
and
testing
activities
that
effect
quality
refated
activities
performed
by
WID
or
its
suppliers
will
be
accomplished
in
accordance
with
approved
procedures
(WP
16
1,
WlPP
Computer
Protection
Plan).
17
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
Test
requirements
and
acceptance
criteria
will
be
specified,
documented,
and
reviewed
and
will
be
based
upon
applicable
software
requirement,
design,
or
other
pertinent
technical
documents.
Required
tests,
including
verification,
hardware
integration,
and
in
use
tests,
will
be
controlled.
Testing
of
software
will,
at
a
minimum,
verify
the
capability
of
the
computer
program
to
produce
valid
results
for
test
problems
encompassing
the
range
of
permitted
usage
defined
by
the
program
documentation.
Testing
will
also
be
designed
to
identify
and
eliminate
any
serious
defect
that
could,
for
example,
cause
a
crash.
Depending
on
the
complexity
of
the
computer
program
being
tested,
requirements
may
range
from
a
single
test
of
the
completed
computer
program
to
a
series
of
tests
performed
at
various
stages
of
computer
program
development
to
verify
correct
translation
between
stages
and
proper
working
of
individual
modules.
This
will
be
followed
by
an
overall
computer
program
test.
Any
software
to
be
developed
on
site
(by
WID
personnel
or
others)
(i.
e.,
noncommercial
software)
will
follow
the
requirements
of
NQA
2.7,
and
shalI
include,
at
a
minimum,
a
requirements
document,
a
design
document,
a
validation
and
verification
plan,
a
software
quality
assurance
plan,
a
testing
plan
and
procedures,
a
configuration
management
plan,
and
appropriate
user
manuals.
These
will
be
reviewed
and
approved
by
appropriate
WID
personnel.
Regardless
of
the
number
of
stages
of
testing
performed,
verification
testing
and
validation
will
be
of
sufficient
scope
and
depth
to
establish
that
software
functional
test
requirements
are
satisfied
and
that
the
software
produces
a
valid
result
for
its
intended
function.
4.9
Control
of
Monitorina
and
Data
Collection
EauiDment
Monitoring
and
data
collection
equipment
will
be
controlled
and
calibrated
in
accordance
with
applicable
WlPP
controlled
procedures.
Results
of
calibrations,
maintenance,
and
repair
will
be
documented.
Calibration
records
will
identify
the
reference
standard
and
the
relationship
to
national
standards
or
nationally
accepted
measurement
systems.
Calibration
reports
and
operability
test
data
will
be
maintained
by
Geotechnicat
Engineering.
Any
out
of
tolerance
condition
will
be
evaluated
for
potential
impact
on
the
validity
of
data.
Impact
evaluation
and
corrective
actions
will
be
initiated
per
specific
Geotechnical
Engineering
instructions.
18
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
4.10
Handlina.
Storaae.
and
Shiminq
Handling,
storage,
and
shipping
of
items
will
be
coordinated
in
accordance
with
established
procedures
or
other
specific
documents.
Geotechnical
Engineering
is
responsible
for
storing,
handling,
and
shipping
rock
core
and
other
geologic
samples.
4.1
I
Control
of
Nonconformina
Conditionslltems
Conditions
adverse
to
quality
will
be
documented
and
classified
in
regard
to
their
significance.
Corrective
action
will
be
taken
accordingly.
Equipment
that
does
not
conform
to
specified
requirements
will
be
controlled
to
prevent
its
use.
Faulty
items
will
be
tagged
and
segregated.
Repaired
equipment
will
be
subject
to
the
original
acceptance
inspections
and
tests
prior
to
use.
4.12
Corrective
Actions
Conditions
adverse
to
acceptable
quality
will
be
documented
and
reported
in
accordance
with
corrective
action
procedures
and
corrected
as
soon
as
practical.
Immediate
action
will
be
taken
to
control
work,
and
its
results,
performed
under
conditions
adverse
to
acceptable
quality
in
order
to
prevent
degradation
in
quality.
The
Geotechnical
Engineering
manager,
or
designee,
will
investigate
any
deficiencies
in
activities
in
accordance
with
approved
procedures.
4.13
Records
Manauernent
Identification,
preparation,
collection,
storage,
maintenance,
disposition,
and
permanent
storage
of
records
will
be
in
accordance
with
approved
WlPP
procedures.
Generation
of
records
will
accurately
reflect
completed
work
and
facility
conditions
and
will
comply
with
statutory
or
contractual
requirements.
The
Geotechnical
Engineering
Records
and
Inventory
and
Disposition
Schedule
describes
the
classification
and
disposition
for
all
records
generated
by
the
group.
While
in
their
custody,
the
records
will
be
protected
from
loss
and
damage
in
accordance
with
approved
WlPP
procedures
and
they
will
coordinate
with
Project
Records
Services
(PRS)
for
transfer
of
quality
records
to
PRS.
They
are
also
responsible
for
the
Core
Library
in
the
Core
Storage
Building
where
records
will
be
maintained
of
all
Core
Library
activities,
including
additions,
removal
of
any
material,
any
tests
performed
on
the
core,
a
record
of
people
who
examine
the
core
on
site,
and
any
other
alterations
made
to
the
core.
4.14
Audits
and
IndeDendent
Assessments
Planned
periodic
assessments
will
be
conducted
to
measure
management
and
item
19
WlPP
Geotechnical
Engineering
Program
Plan
WP
07
01,
Rev.
2
quality
and
process
effectiveness,
and
to
promote
improvement.
The
organization
performing
independent
assessments
will
have
sufficient
authority
and
freedom
to
carry
out
its
responsibilities.
Persons
conducting
assessments
will
be
technically
qualified
and
knowledgeable
of
the
items
and
processes
to
be
assessed.
4.15
Data
Reduction
and
Verification
Computer
programs,
commercial
data
processing
applications,
and
manual
calculations
that
collect
or
manipulate/
reduce
data
will
be
verified.
Verification
must
be
performed
before
the
presentation
of
final
results
or
their
use
in
subsequent
activities.
If
it
becomes
necessary
to
present
or
use
unchecked
results,
transmittals
and
subsequent
calculations
will
be
marked
"preliminary"
until
such
time
that
the
results
are
verified
and
determined
to
be
correct.
,
5.0
REFERENCES
Title
30
CFR
57,
Subpart
B,
"Ground
Control"
Title
40
CFR
1
194,
Section
42,
"Monitoring"
WP
13
1,
Quality
Assurance
Program
Description
WP
16
1,
WlPP
Computer
Protection
Plan
20
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1
.ow
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DOEITWIPP
98
3
118
Geotechnical
Analysis
Report
for
July
1996
June
1997
September
1998
Y
Y
Waste
Isolation
Pilot
Plant
mE3
WP
I
I
I
I
I
I
I
I
i
1
1
i
i
i
1
1
i
Table
of
Contents
List
of
Tables
;
.............
iv
List
of
Figures
v
1.0
Introdmion
.....................
:
................................................................................................
1
1
1.1
Location
and
Description
........................................................................................
1
1
1.3
Development
Status
................................................................................................
14
1.4
Purpose
and
Scope
of
Geomechanical
Monitoring
Program
..................................
1
6
1.4.1
Instrumentation
...........................................................................................
1
6
1.4.2
Data
Acquisition
..........................................................................................
1
6
1.4.3
Data
Evaluation
...........................................................................................
1
8
1.4.4.
Data
Errors
..................................................................................................
1
9
2.0
Geology
2
1
2.1
Regional
Stratigraphy
..............................................................................................
2.1
2.1.1
Castile
Formation
..........................................................................................
2
1
2.1.2
Salado
Formation
..........................................................................................
2
3
2.1.3
Rustler
Formation
..........................................................................................
2
3
2.1.4
Dewey
Lake
Redbeds
....................................................................................
2.3
2.1.5
Dockum
Group
..............................................................................................
2
4
2.1.6
Gatuiia
Formation.
Mescalero
Caliche.
and
Surficial
Sediments
..................
2
4
Underground
Facility
Stratigraphy
.........................................................................
2
5
2.2.
I
Disposal
Horizon
Stratigraphy
......................................................................
2
5
Performance
of
Shafts
and
Keys
......................................................................................
3
1
3.1
Salt
Handling
Shaft
.................................................................................................
3
1
3.1
.
1
Shaft
Performance
.......................................................................................
3
1
3.1.2
Instrumentation
...........................................................................................
3
1
3.2
Waste
Shaft
.............................................................................................................
3
5
3.2.1
Shaft
Performance
.......................................................................................
3
5
3.3
Exhaust
Shaft
..........................................................................................................
3
9
3.3.1
Shaft
Performance
.....................................................................................
3
11
3.3.2
Instrumentation
.........................................................................................
3
11
Air
Intake
Shaft
.....................................................................................................
3
11
....................................................................................................................
.................................................................................................................................
1.2
Mission
....................................................................................................................
1
4
..
............................................................................................................................
2.2
2.2.2
Experimental
Area
Stratigraphy
....................................................................
2
7
3.0
3.2.2
Instrumentation
...........................................................................................
3
5
3.4
i
4.0
5
.
0
6.0
7.0
8.0
9.0
10.0
3.4.1
Shaft
Performance
.....................................................................................
3
15
3.4.2
Instrumentation
.........................................................................................
3
15
Performance
of
Shaft
Stations
..........................................................................................
4
1
4.1
Salt
Handiing
Shaft
Station
.....................................................................................
4
1
4
.
I
.
1
Modifications
to
Excavation
.......................................................................
4
1
4.1.2
Instrumentation
...........................................................................................
4
1
Waste
Shaft
Station
.................................................................................................
4
5
4.2.1
Modifications
to
Excavation
.......................................................................
4
5
4.2.2
Instrumentatiop
...........................................................................................
4
7
Performance
of
Access
Drifts
...........................................................................................
5
1
5.1
Modificationshlaintenance
.....................................................................................
5
1
5.2
Instrumentation
.......................................................................................................
5
1
5.2.
I
Borehole
Extensometers
..............................................................................
5
1
5.2.2
Convergence
Points
.....................................................................................
5
4
5.3
Excavation
Performance
.........................................................................................
5
4
5.4
Analysis
of
Convergence
Data
................................................................................
5
4
Performance
of
Northern
Experimental
Area
..................................................................
6
1
6.1
ModificationsNaintenance
.....................................................................................
6
1
6.2
Instrumentation
.......................................................................................................
6
1
6.2.
I
Borehole
Extensometers
..............................................................................
6
1
6.2.2
Convergence
Points
.....................................................................................
6
1
6.2.3
Wire
Convergence
Meters
..........................................................
......._.....
....
6
3
6.3
Excavation
Performance
.........................................................................................
6
3
6.4
Performance
of
Waste
Disposal
Area
............................................................................
~7
~
7.1
Modifications
to
Excavations
.............................................................................
....
7
1
7.2
Instrumentation
.......................................................................................................
7
2
7.3
Excavation
Performance
.........................................................................................
7
2
7.4
Analysis
of
Convergence
Data
................................................................................
7
5
4.2
Analysis
of
Convergence
Data
................................................................
...............
6
3
Geosciences
Program
.......................................................................................................
8
1
8.1
Borehole
Inspections
...............................................................................................
8
1
Geologic
Core
Lo_
gging
...........................................................................................
8
4
8.2
8.3
Summary
.............................................................................
...................................
........
9
1
References
and
Bibliography
........................................................................................
10
1
10.1
Cited
References
...................................................................................................
10
1
Geologic
and
Fracture
Mapping
of
Excavation
Surfaces
.......................
e._.
............
8
3
..
10.2
Selected
Bibliography
...
...
.
.
.
.
...
.
Q
..
.
.
..
.
.
.
.
.
.
.
..
.
.
.
.
.
.
.
.
.
...
.
.
.
.
.
.
.
.
.
..
.
.
.
.
.
.
.
.
,
.
..
.
.
.
.
.
.
..
.
.
....
.
.
.
.
..
.
...
.
.
10
3
Appendices:
Appendix
A
Corrected
Tables
of
Separation
and
Offset
in
Observation
Boreholes
for
the
1995
1996
Reporting
Period
...
111
I
.
0
Introduction
This
Geotechnical
Analysis
Report
(GAR)
interprets
and
presents
the
geotechnical
data
from
the
underground
excavations
at
the
Waste
Isolation
Pilot
Plant
(WIPP).
The
data,
used
to
characterize
conditions,
assess
design
assumptions,
and
clarify
and
evaluate
the
performance
of
the
underground
excavations
during
operations,
are
obtained
as
part
of
a
regular
monitoring
program.
GARS
have
been
available
to
the
public
since
1983.
During
the
Site
and
Preliminary
Design
Validation
(SPDV)
Program,
the
architectlengineer
for
the
project
produced
these
reports
on
a
quarterly
basis
to
document
the
geomechanical
performance
during
and
immediateiy
after
construction
of
the
underground
facility.
Since
the
completion
of
the
construction
phase
of
the
project
in
1987,
the
reports
have
been
prepared
annually
by
the
management
and
operating
contractor
for
the
facility.
This
report
describes
the
performance
and
conditions
of
selected
areas
from
July
1
,
1996,
to
June
30,
1997.
This
report
is
formatted
into
nine
chapters.
The
remainder
of
Chapter
1.0
provides
background
information
on
the
WIPP
site,
its
mission,
and
the
purpose
and
scope
of
the
geomechanical
monitoring
program.
Chapter
2.0
describes
the
local
and
regional
geology
of
the
WIPP
site.
Chapters
3.0
and
4.0
describe
the
geomechanical
instrumentation
located
in
the
facility
shafts
and
shaft
stations
and
the
results
of
the
monitoring
and
interpretation
of
this
instrumentation.
Chapters
5.0,6.0,
and
7.0
present
the
results
of
geomechanical
instrumentation
monitoring
in
the
three
main
portions
of
the
WIPP
underground
facility;
the
Northern
Experimental
Area,
the
access
drifts,
and
the
Waste
Disposal
Area.
Chapter
8.0
discusses
the
activities
included
in
the
Geosciences
Program,
which
includes
geologic
core
mapping,
fracture
mapping,
and
borehole
observations.
The
final
chapter.
Chapter
9.0.
summarizes
the
results
of
the
geomechanical
instrumentation
monitoring
and
compares
the
current
excavation
performance
to
the
system
design
requirements.
1.1
Location
and
Description
The
WIPP
is
located
in
southeastern
New
Mexico,
42
kilometers
(km)
(26
miles)
east
of
Carlsbad
(Figure
1
1).
The
surface
facilities
were
built
on
the
flat
to
gently
rolling
hiIls
that
are
characteristic
of
the
Los
Medaiios
area.
The
underground
facility
is
being
excavated
approximately
655
meters
(m)
(2,150
feet
[ft])
beneath
the
surface,
in
the
Salado
Formation.
Figure
1
2
shows
a
plan
view
of
the
underground
facility
at
the
WIPP,
site
as
i
t
is
currently.
1
1
I'
2
Figure
1
1
General
Location
of
the
WIPP
Facility
.
1
2
Portion
o
i
the
Facility
Deactivated
in
September
1996
Not
to
Scale
Figure
1
2
Schematic
of
Current
Underground
Facility
1
3
1:
I
1
1
I
1
I
1
1
I
'
I
I
I
I
i
!
9.0
Summary
At
the
beginning
of
the
WTPP
project,
criteria
were
developed
that
address
the
requirements
for
the
design
of
the
WPP
(DOE,
1984).
These
criteria,
in
the
form
of
design
requirements,
covered
all
aspects
of
the
mined
facility
and
its
operation
as
a
pilot
plant
for
the
demonstration
of
technical
and
operational
methods
for
permanent
disposal
of
CH
and
RH
TRU
waste.
As
the
WIPP
developed
and
the
focus
moved
toward
the
permanent
disposal
of
TRU
waste,
these
design
requirements
were
reassessed
and
replaced
in
1994
by
a
new
set
of
requirements
called
system
design
descriptions
(SDD).
Table
9
1
shows
the
comparison
of
these
SDDs
with
conditions
actually
observed
in
the
underground
from
July
1996
to
June
1997.
Fracture
development
in
the
roof
is
primarily
caused
by
the
concentration
of
compressive
stresses
in
the
roof
beam
and
is
influenced
by
the
size
and
shape
of
the
excavation
and
the
stratigraphy
in
the
immediate
vicinity
of
the
opening.
Pillar
deformations
induce
lateral
compressive
stresses
into
the
immediate
roof
and
floor.
With
time
the
buildup
of
stress
causes
differential
movement
along
stratigraphic
boundaries.
This
differential
movement
is
identified
as
offsets
in
observation
boreholes
and
is
indicated
by
bending
deformation
in
failed
rockboits.
Large
strains
associated
with
lateral
movements
in
the
roof
can
induce
fracturing
in
the
roof,
which
is
frequently
seen
near
the
ribs.
This
scenario
of
roof
deterioration,
combining
a
buildup
of
compressive
stresses
over
time,
horizontal
offsetting,
and
large
strains
associated
with
lateral
movements,
is
substantiated
by
observations
of
similar
roof
deterioration
in
SPDV
Room
1.
SPDV
Room
2,
and
the
E140
drift
between
S
IO00
and
S
1950.
Major
modifications
to
the
underground
during
this
reporting
period
consisted
of
roof
beam
removal
in
the
E140
drift
in
the
area
of
S
1000
to
S1300.
The
decision
to
remove
the
beam
came
as
a
result
of
operational
scheduling
and
convenience
as
well
as
observations
of
roof
beam
deterioration.
Observations
included
high
expansion
rates
across
clay
G
found
from
extensometer
data,
visual
observation
of
fracturing
within
the
immediate
roof,
and
an
increasing
number
of
bolt
failures
occurring
in
the
area.
Although
the
roof
beam
could
have
been
maintained
through
roof
control
measures,
it
was
also
determined
that
operationally
it
was
an
appropriate
and
convenient
time
to
remove
the
roof
beam.
Data
from
convergence
point
arrays
located
in
the
E
140
drift
between
S
1000
and
S
1300.
which
were
installed
after
the
roof
beam
was
removed,
indicate
the
vertical
closure
rate
after
roof
beam
removal
is
constant
at
approximately
4
c
d
y
r
(
1.5
in/
yr).
Data
from
convergence
point
arrays
in
the
E140
drift
between
S
1300
and
S
1950
show
a
relatively
constant
vertical
closure
rate
since
the
removal
of
the
roof
9
1
Table
9
1
Comparison
of
Excavation
Performance
to
System
Design
Descriptions
System
Design
Description
SDD
UHOO.
Underground
Hoisting.
Section
2.1.2.6.3
Section
2.1.26.4
Section
2.
f.
2.8
hydrostatic
pressure..
.
."
piezometers
located
behind
the
shaft
keys
in
the
Waste
Shaft
and
the
Exhausr
Shaft
remains
below
design
levels.
Piezometers
located
in
the
Salt
Handling
Shaft
were
not
functioning
during
this
reporting
period.
Historic
data
indicate
water
pressures
in
the
Salt
Handling
Shaft
to
be
below
design
levels.
The
Salt
Handling
Shaft
liner
continues
to
resist
water
inflow
into
the
shaft.
Efforts
are
underway
to
determine
if
the
piezometers
in
the
Salt
structurally
sable.
Extensometers
located
in
the
Salt
Handling
Shaft
and
the
Exhaust
Shaft
were
not
functioning
during
this
reporting
period.
Historic
data
indicate
that
closure
of
a11
the
shafts
remains
within
design
"The
key
shall
be
designed
to
retain
the
rock
formation
and
will
be
provided
with
chemical
seal
rings
and
a
water
collection
ring
with
drains
to
prevent
water
from
flowing
down
the
unlined
shaft
from
the
lining
above."
The
small
amount
of
groundwater
inflow
into
the
shafts
is
effectively
controlled
through
grouting.
Seepage
into
the
Exhaust
Shaft
is
minimal
and
the
source
and
content
of
such
seepage
are
being
characterized
(Intera
1997.
IT,
1997).
I
I
I
I
!
!
j
I
!
i
I
I
i
I
i
i
I
1
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
Table
9
1
(Continued)
Comparison
of
Excavation
Performance
to
System
Design
Descriptions
System
Design
Description
Requirement
SDD
AUOO,
Undermound
Facilities
and
Eauipment,
Section
2.2.1.2.
Underground
Disposal
Facilities
`The
underground
waste
disposal
facilities
shall
be
designed
to
provide
space
and
adequate
access
for
the
underground
equipment
and
temporary
storage
space
to
support
underground
operations."
"The
underground
waste
disposal
facilities
shall
be
designed
to
provide
the
2.2*
1.2*
Underground
(Continued)
capability
of
reuieving
the
emplaced
CH
an&
RH
TRU
waste?
"Entries
and
sub
entries
to
the
`
underground
disposal
area
and
tht
experimental
areas
shall
be
provided
and
sized
for
personnel
safety,
adequate
air
flow,
and
space
for
equipment."
Section
2.2.1.3,
Underground
Shaft
Pillar
Facilities
;DD
EMOO.
Environmental
vfonitorinq.
Section
2.2.5.
I
"Geomechaoical
instrumentation
shall
be
provided
to
measure
the
cumulative
deformation
of
the
rock
mass
Comments
Geomechanical
instrument
data
and
visual
observations
indicate
that
the
current
design
provides
adequate
access
and
storage
space.
retrievability
i
s
no
longer
necessary.
Deformation
of
excavation
remains
within
the
required
limits.
The
northern
portion
of
the
underground
from
approximately
NSOO
was
deactivated
during
this
reporting
period
because
the
area
is
no
longer
needed
for
experimental
purposes.
This
area
is
no
longer
accessible.
Approximately
1.5
meters
(5
feet)
of
roof;
up
to
clay
G,
was
removed
in
the
E140drift
from
SI000
to
S1300.
Geotechnical
instrumentation
is
operated
and
maintained
to
meet
this
requirement.
Additional
georechnical
instruments
were
installed
in
various
parts
of
the
WIPP
underground
(including
the
E140
drift.
Room
7.
Panel
1
,
and
SPDV
Room
4)
during
this
reporting
period.
Geotechnical
experts
agree
that
the
monitoring
program
at
the
WIPP
has
been
proven
adequate.
specifically
with
regard
to
the
instrumentation
in
Room
1
.
Panel
1
(DOE.
199
I
b).
beam,
despite
the
fact
that
the
rate
in
some
areas
is
approximately
5
c
d
y
r
(2
idyr).
These
rates
and
visual
observations
indicate
a
more
stable
roof
beam
in
the
E140
drift
between
S
1000
and
S
1950.
In
order
to
monitor
the
response
of
the
new
roof
beam,
14
convergence
point
arrays
have
been
installed
in
the
E140
drift
between
S
1000
and
S
1950
since
the
roof
beam
was
removed.
The
in
situ
performance
of
the
excavations
generally
continues
to
satisfy
the
appropriate
design
criteria.
although
specific
areas
are
being
identified
where
deterioration
resulting
from
aging
9
3
Attachment
D.
2
Hydrological
Do
cum
en
ts
I
Effective
Date:
3/
12
WP
02
1
Revision
3
Groundwater
Surveillance
Program
Plan
Cognizant
Section:
Environmental
Monitorina
Approved
By:
Siqnature
on
file
D.
R.
KumD
Cognizant
Department:
ESH
Approved
By:
Signature
on
file
C.
F.
Wu
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
TABLE
OF
CONTENTS
1
1
.Q
INTRODUCTION
..............................................................................................
1
2.0
REFERENCES
.................................................................................................
1
3.0
RESPONSIBILITIES
.........................................................................................
3
GSP
QUALITY
ASSURANCE
PLAN
................................................................
4.0
3
4.1
Introduction..
4
4.1
.I
Department
of
Energy
(DOE)
Order
5400.1
..........................................
4
4.1.2
4
4.1.3
Resource
Conservation
and
Recovery
Act
(RCRA)
..............................
4
4.1.4
Final
Environmental
Impact
Statement
(FEIS)
Commitments
................
4
4.1.5
Future
Land
Use
Decisions
...................................................................
5
GSP
Quality
Assurance
Requirements
........................................................
5
4.2.2
Quality
Assurance
Program..
.................................................................
5
4.2.3
Design
Control
.......................................................................................
5
4.2.4
Procurement
Document
Control
............................................................
5
4.2.5
Instructions,
Procedures,
and
Drawings
................................................
6
4.2.6
Document
Control
..................................................................................
6
4.2.7
Control
of
Purchased
Material,
Equipment
and
Services
......................
6
4.2.8
Identification
and
Control
of
Items
.........................................................
7
4.2.9
Control
of
Processes
.............................................................................
7
4.2.10
Inspection/
SurveilJance..
...............................................................
7
4.2.11
Test
Control
...................................................................................
8
4.2.12
Control
of
Monitoring
and
Data
Collection
Equipment
..................
8
4.2.13
Handling,
Storage,
and
Shipping
..................................................
8
4.2.14
Inspection
and
Acceptance
Testing
..............................................
a
4.2,15
Control
of
Nonconforming
Conditions
...........................................
9
4.2.16
Corrective
Action
...........................................................................
9
4.2.17
Quality
Assurance
Records
...........................................................
9
4.2.18
Assessments
.................................................................................
.....................................................................................................
DOEEH
01
73T
.........................................................................
;
............
4.2
IO
GSP
WATER
QUALITY
SAMPLING
PLAN
....................................................
10
5.1
Scope
......................................................................................
d
IO
5.1
.I
General
.................................................................................................
7
4
5.2
Surveillance
Well
Construction
..................................................................
13
5.3
Sampling
Proqram
Description
...................................................................
13
5.3.1
Serial
Sampling
....................................................................................
13
5.3.2
Final
Samples
......................................................................................
14
5.4
Groundwater
Pumpinq
and
Sampling
Svstems
..........................................
16
5.5
Pressure
Monitorinq
Svstems
........
..:.
........................................................
16
5.6
Sample
Analvsis
.........................................................................................
5.0
...................
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
.....................................................................................
17
18
19
19
21
5.6.1
Serial
Samples
5.6.2
Rnal
Samples
......................................................................................
................
5.7
5.8
Sample
Preservation,
Trackinq,
Packaging
and
Transportation
Qualitv
Assurance,
Records
Management
and
Document
Control
............
5.9
Calibration
Requirements
...........................................................................
6.0
6.1
6.2
6.3
6.4
6.5
6.6
6.7
............................................................
WATER
LEVEL
MONlTOR"
PLAN
21
Scope
21
Records
and
Document
Control
.................................................................
.........................................................................................................
................................................................................................
21
htroduction
....................................................................................................
22
Obiective
24
Field
Methods
24
Repodinq
....................................................................................................
25
..........................................................................
25
c
a1
i
brati
on
Requirements.
.............................................................................................
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
1
.o
INTRODUCTION
This
is
the
controlling
document
for
the
Waste
Isolation
Pilot
Plant
(WIPP)
Groundwater
Surveillance
Program
(GSP).
The
GSP
is
administered
as
part
of
the
WlPP
Environmental
Monitoring
Program
by
the
Environmental
Monitoring
(EM)
Section
of
the
Environment,
Safety
and
Health
(ES&
H)
Department.
2.0
REFERENCES
DOE
Order
5400.1
,
General
Environmental
Protection
Program
DOEIEH
01
73T,
Environmental
Regulatory
Guide
for
Radiological
Effluent
Monitoring
and
Environmental
Surveillance
Groundwater
Protection
Management
Program
Plan
WP
02
3,
Environmental
Procedures
Manual
WP
IO
AD.
WlPP
Maintenance
Administrative
Procedures
Manual
WP
12
1
,
Waste
Isolation
Pilot
Plant
Safety
Manual
WP
12
1
07,
Hazard
Communication
Program
WP
13
1,
WID
Quality
Assurance
Program
Description
WP
15
6,
Purchasing
Policies
and
Procedures
Manual
WP
15
PR,
Records
Management
Plan
3.0
RESPONSIBILITIES
The
overall
organizational
structure
of
the
Westinghouse
WID
is
described
in
Part
I
,
Section
1
of
the
Quality
Assurance
Program
Description
(QAPD).
The
GSP
is
the
responsibility
of
the
ES&
H
Department.
The
GSP
is
conducted
by
the
EM
Section
of
this
department.
The
EM
manager
assumes
responsibility
for
the
overall
design
and
implementation
of
the
GSP
including
the
following
areas:
0
Development
and
approval
of
specific
procedures
for
€he
conduct
of
all
GSP
activities.
1
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
0
0
Establishment
of
minimum
qualification
criteria
and
training
requirements
for
all
program
personnel.
Review
and
approval
of
programmatic
reports.
0
Oversight
of
appropriate
levels
of
cooperation
and
consultation
between
the
EM
Section
and
the
state
of
New
Mexico
regarding
environmental
monitoring.
1
Preparation
of
the
QA
section
of
the
GSP
Plan.
The
EM
manager
and
staff
are
responsible
for
achieving
and
maintaining
quality
in
the
GSP.
Job
descriptions
will
be
maintained
for
the
EM
manager,
professional,
technical,
and
administrative
staff
positions.
All
GSP
data
shall
be
reviewed
and
approved
by
the
EM
manager,
or
designee,
prior
to
release.
The
EM
manager
appoints
a
GSP
Team
Leader
(TL),
assigning
the
following
responsibilities
to
the
TL:
0
Direct
GSP
per
written
approved
procedures.
I]
Initiate
review
of
programmatic
plans
and
procedures.
0
Review
and
evaluate
sample
data.
0
Prepare
and
review
programmatic
reports.
0
Assure
that
appropriate
samples
are
collected
and
analyzed.
I]
Assure
that
adequate
technical
support
is
provided
to
the
Quality
and
Regulatory
Assurance
(Q&
RA)
Department,
when
required
during
audits
of
vendor
facilities.
The
EM
manager
designates
one
or
more
scientists,
engineers,
or
technicians
who
will
be
responsible
for
the
following
items:
Collection
and
subsequent
distribution
of
samples.
Preparation
and
maintenance
of
appropriate
data
sheets
and
sample
tracking
documentation.
Monitoring
of
equipment
operability
status.
Reporting
of
equipment
malfunctions.
Reporting
of
nonconformance
to
the
TL
or
EM
manager.
2
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
0
Overseeing
of
quality
control
checks
of
data.
0
Conducting
field
activities
in
accordance
with
written
procedures.
The
Q&
RA
manager
provides
independent
oversight
of
the
GSP,
via
the
assigned
cognizant
Q&
RA
engineer,
to
verify
that
quality
objectives
are
defined
and
achieved.
The
Q&
RA
manager
ensures
objective,
independent
assessments
of
GSP
quality
performance.
The
Q&
J#
manager
has
been
delegated
authority
and
given
organizational
freedom
by
the
WID
General
Manager
to
access
work
areas,
identify
quality
problems,
initiate
or
recommend
corrective
actions,
verify
implementation
of
corrective
actions,
and
ensure
that
work
is
controlled
or
stopped
until
adequate
disposition
of
an
unsatisfactory
condition
has
been
implemented.
The
EM
manager
assures
that
basic
qualifications
for
GSP
personnel
are
carried
out
in
accordance
with
Section
2
of
the
QAPD.
The
EM
manager
assures
that
position
descriptions
for
assigned
GSP
personnel
are
adequately
prepared.
Each
position
description
will
include
position
purpose,
principal
responsibilities,
nature
of
work,
and
scope.
The
EM
manager
andlor
TL
assures
that
training
is
performed
on
an
individual
basis
to
maintain
an
acceptable
level
of
proficiency
by
all
new
or
temporary
GSP
staff
and
by
all
permanent
GSP
staff.
New
GSP
employees
are
required
to
review
pertinent
program
documentation,
become
familiar
with
applicable
procedures,
and
complete
appropriate
qualifications
prior
to
undertaking
any
unsupervised
GSP
task,
To
become
qualified
to
perform
a
specific
task
or
series
of
tasks,
an
employee
must
demonstrate
subject
knowledge
and
practical
skills
and
become
certified
in
performing
the
task(
s)
by
a
board
certified
subject
matter
expert
(SME).
Employees
who
have
not
completed
the
appropriate
qualification
card
will
not
be
allowed
to
conduct
unsupervised
GSP
activities.
The
EM
manager,
TL,
or
task
SME
may
determine
the
need
for
retraining
of
GSP
personnel.
Retraining
may
be
noted
by
Q&
RA
during
any
sur%
eillance
or
audit
or
during
a
periodic
review
initiated
by
the
EM
manager,
TL,
or
SME.
The
EM
manager
assures
that
documents
detailing
all
staff
training
are
current
and
properly
filed.
Copies
of
training
records
shall
be
on
file
in
the
WID
Technical
Training
Sect
ion.
3
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
4.0
GSP
QUALITY
ASSURANCE
PLAN
4.1
Introduction
This
section
is
the
quality
assurance
(QA)
plan
for
the
WIPP
GSP.
The
objective
of
this
QA
plan
is
to
establish
the
specific
QA
requirements
associated
with
the
GSP.
The
GSP
currently
consists
of
two
activities:
the
Water
Quality
Sampling
Program
(WQSP)
and
the
Water
Level
Monitoring
Program
(WLMP).
Technical
implementation
of
each
specific
activity
is
controlled
by
an
individual
program
plan
and
unique
operating
procedures.
The
GSP
provides
a
mechanism
for
addressing
the
following:
4.1.1
Department
of
Energy
(DOE)
Order
5400.1
Chapter
3
of
the
DOE
Order
5400.1,
General
Environmental
Protection
Program,
states
that
I
'
...
all
Department
of
Energy
(DOE)
sites
will
conduct
a
groundwater
protection
management
program."
The
order
requires
each
ui)
E
site
to
provide
for
the
design
and
implementation
of
a
groundwater
monitoring
effort
that
supports
resource
management
and
complies
with
applicable
environmental
laws
and
regulations.
4.1.2
DOE/
EH
0173T
DOE/
EH
01
73T,
Environmental
Regulatory
Guide
for
Radiological
Effluent
Monitoring
and
Environmental
Surveillance,
states
that:
It
is
the
policy
of
DOE
to
conduct
effluent
monitoring
and
environmental
surveillance
programs
that
are
adequate
to
determine
whether
the
public
and
the
environment
are
adequately
protected
during
DOE
operations
and
whether
operations
are
in
compliance
with
DOE
and
other
applicable
Federal,
State,
and
local
radiation
standards
and
requirements.
It
is
also
DOE
policy
that
Departmental
monitoring
and
surveillance
programs
be
capable
of
detecting
and
quantifying
unplanned
releases
and
meet
high
standards
of
quality
and
credibility.
It
is
DOE'S
objective
that
all
DOE
operations
properly
and
accurately
measure
radionuclides
in
their
effluent
and
in
ambient
environmental
media.
4.1.3
Resource
Conservation
and
Recovery
Act
(RCRA)
By
virtue
of
a
Groundwater
Monitoring
Waiver,
prepared
under
40
CFR
265,
the
WlPP
Project
is
not
required
to
monitor
groundwater
to
comply
with
the
U.
S.
Environmental
Protection
Agency
(EPA)
RCRA.
The
WlPP
GSP
provides
a
basis
for
future
compliance
to
the
RCRA,
as
well
as
any
other
groundwater
protection
related
regulations,
should
the
need
arise.
4
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
4.1.4
Final
Environmental
Impact
Statement
(FEIS)
Commitments
Section
5.2.2
of
the
FEIS
states
that
"...
long
term
groundwater
sampling
and
water
level
monitoring
will
be
conducted
as
part
of
the
WlPP
Environmental
Monitoring
Program."
4.1.5
Future
Land
Use
Decisions
Data
collected
from
the
program
will
aid
in
making
future
groundwater
land
use
decisions
(Le.,
designing
long
term
and
passive
institutional
controls
for
the
site).
This
QA
plan
is
driven
by,
and
is
supplemental
to,
both
the
WID
QAPD,
WP
13
1,
and
implementing
WlPP
Q&
RA
procedures.
4.2
GSP
Qualitv
Assurance
Requirements
The
following
specific
Q&
RA
requirements
are
unique
to
the
GSP.
4.2.2
Quality
Assurance
Program
This
plan
is
governed
by
the
following
documents:
WP
13
1,
WID
Quality
Assurance
Program
Description;
and
WP
02
3,
Environmental
Procedures
Manual.
Steps
to
ensure
quality
are
incorporated,
as
needed,
in
the
technical
procedures
used
for
groundwater
surveillance
activities.
The
EM
manager
or
assigned
designee
is
responsible
for
developing
and
maintaining
this
QA
plan
and
groundwater
surveillance
procedures.
In
accordance
with
the
WID
QAPD,
Part
I,
Section
1,
groundwater
surveillance
data
activities
are
classified
as
Quality
Code
11.
4.2.3
Design
Control
The
design
control
requirements
used
by
Westinghouse
at
the
WID
are
described
in
Part
11,
Section
6
of
the
QAPD.
The
GSP
will
adhere
to
all
applicable
portions
of
these
requirements
when
performing
design
activities.
4.2.4
Procurement
Document
Control
Procurement
is
carried
out
in
accordance
with
WID
procurement
policies
and
procedures,
as
outlined
in
Part
I
I
,
Section
7
of
the
QAPD,
and
WP
15
6,
Purchasing
Policies
and
Procedures
Manual.
Both
documents
require
specification
of
a
quality
code
and
design
class
and
concurrence
by
the
Q&
F!
A
Department
with
procurement
documents,
Technical
requirements
for
procured
items
and
services
are
developed
and
specified
in
procurement
documents.
the
required
characteristics,
procurement
adequate
QA
program.
If
deemed
necessary
to
ensure
attainment
of
documents
may
require
suppliers
to
have
an
5
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
4.2.5
Instructions,
Procedures,
and
Drawings
Provisions
and
responsibilities
for
the
preparation
and
use
of
instructions
and
procedures
at
the
WIPP
are
outlined
in
Part
II,
Section
4
of
the
QAPD.
Quality
affecting
activities
performed
by
or
on
behalf
of
groundwater
surveillance
are
required
to
be
performed
in
accordance
with
documented
and
approved
procedures.
Technical
procedures
have
been
developed
for
each
quality
affecting
function
performed
for
groundwater
surveillance.
The
technical
procedures
unique
to
the
GSP
are
contained
in
the
procedures
sectien
of
this
manual.
The
procedures
are
as
detailed
as
required
and
include,
when
applicable,
quantitative
or
qualitative
acceptance
criteria
to
determine
that
activities
have
been
satisfactorily
accomplished.
Procedure
requirements
are
in
accordance
with
Section
4
of
WP
13
1.
Procedures
will
be
prepared
in
accordance
with
applicable
technical
writer's
guides.
4.2.6
Document
Control
Requirements
for
the
control
of
documents
are
outlined
in
Part
I
i
,
Section
4
of
the
WID
QAPD.
Controls
ensure
that
the
latest
approved
versions
of
procedures
are
used
in
performing
groundwater
surveillance
functions
and
that
obsolete
materials
are
removed
from
work
areas.
4.2.7
Control
of
Purchased
Material,
Equipment
and
Services
WlPP
policy
requirements
and
associated
responsibilities
for
the
control
of
purchased
material,
equipment,
and
services
are
outlined
in
Part
II,
Section
7
of
the
QAPD.
In
accordance
with
current
WlPP
procurement
policies
and
procedures,
measures
will
be
taken
to
ensure
that
procured
items
and
services
conform
to
specified
requirements.
These
measures
will
include
one
or
more
of
the
following:
I]
An
evaluation
of
the
supplier's
capability
to
provide
items
or
services
in
accordance
with
the
requirements,
including
the
history
of
providing
similar
products
or
services
satisfactorily.
[I
An
evaluation
of
objective
evidence
of
conformance,
such
as
supplier
submittal
(i.
e.,
QA
plan).
[I
An
examination
and
testing
of
items
or
services
upon
delivery.
If
it
is
determined
that
additional
measures
are
required
to
ensure
quality
in
a
specific
procurement,
additional
steps
may
be
provided
in
procurement
documents
and
implemented
by
groundwater
surveillance
staff
andlor
the
Q&
RA
Department.
These
additional
assurances
may
include
source
inspection
and
audits
or
surveillance
at
the
6
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
supplier's
facilities.
4.2.8
Identification
and
Control
of
Items
Measures
to
ensure
that
only
correct
and
accepted
items
are
used
at
the
WlPP
are
outlined
in
Part
11,
Section
8
of
the
QAPD.
All
items
that
potentially
affect
the
quality
of
the
GSP
are
uniquely
identified
and
controlled
to
ensure
that
only
accepted
items
are
used.
Equipment
is
administered
in
accordance
with
WP
IO
AD,
WlPP
Maintenance
Administrative
Procedures
Manual.
Calibration
reports
test
data
are
maintained
by
the
EM
Department.
Any
"out
of
tolerance"
condition
is
evaluated
for
potential
impact
on
the
validity
of
data.
Impact
evaluation
and
corrective
actions
are
initiated
per
specific
GSP
instructions.
4.2.9
Control
of
Processes
All
process
control
requirements
of
the
QAPD
are
met
by
the
GSP.
4.2.1
0
JnspectionlSurveillance
Inspection
and
surveillance
activities
are
conducted
as
outlined
in
Part
It,
Section
10
of
the
QAPD.
The
Q&
RA
Department
is
responsible
for
performing
the
applicable
inspections
and
surveillance
on
the
scope
of
work.
Performance
checks
are
performed
by
groundwater
surveillance
personnel
as
specified
by
the
appropriate
procedures,
and
by
WID
m6trology
laboratory
personnel.
Performance
checks
for
the
GSP
are
designed
to
determine
the
acceptability
of
purchased
items
and
to
assess
degradation
that
occurs
during
use.
4.2.1
1
Test
Control
Part
I
I
,
Section
8
of
the
WID
QAPD
outlines
the
requirements
and
responsibilities
of
the
WID
for
the
control
of
tests.
Tests
to
be
performed
for
the
GSP
fall
into
two
general
categories:
tests
of
items
upon
receipt
and
in
service,
and
operability
checks
of
equipment.
All
tests
are
performed
in
accordance
with
documented
and
approved'
plans
and/
or
procedures.
Testing
or
experirnental/
monitoring
plans
or
procedures
contain
the
following
provisions
as
applicable:
0
Scope
and/
or
definition
or
scope.
El
Prerequisites
such
as
calibrated
instrumentation
and
supporting
data;
adequate
test
equipment
and
instrumentation,
including
accuracy
requirements;
completeness
of
item
to
be
tested;
suitable
and
controlled
7
WP
02
1
Rev.
3
GROUNDWATER
SURVEiLLANCE
PROGRAM
PLAN
environmental
conditions;
and
provisions
for
data
collection
and
storage.
Instructions
for
performing
the
test.
Mandatory
inspection
andlor
hold
points
to
be
witnessed
by
the
WID
or
other
designated
representatives.
Acceptance
and
rejection
criteria.
Methods
of
documenting
or
recording
test
data.
Requirements
for
qualified
personnel.
Evaluation
of
test
results
by
authorized
personnel.
Control
of
Monitoring
and
Data
Collection
Equipment
Monitoring
and
Data
Collection
(M&
BC)
equipment
is
controlled
and
calibrated
according
WP
1
0
AD,
WIPP
Maintenance
Administrative
Procedures
Manual,
to
ensure
continued
accuracy
of
groundwater
surveillance
data.
Results
of
calibrations,
maintenance,
and
repair
are
documented.
Calibration
records
identify
the
reference
standard
and
the
relationship
to
national
standards
or
nationally
accepted
measurement
systems.
Records
are
maintained
to
track
uses
of
M&
DC
equipment.
If
M&
DC
equipment
is
found
to
be
out
of
tolerance,
the
equipment
is
tagged
and
its
use
ceased
until
corrections
are
made.
An
evaluation
shall
be
approved
by
the
EM
manager
and
corrective
measures
will
be
taken,
as
needed.
4.2.1
3
Handling,
Storage,
and
Shipping
Handling,
storage,
packaging,
and
shipping
of
groundwater
samples
are
controlled
in
accordance
with
WP
10
AD,
WlPP
Maintenance
Administrative
Procedures
Manual.
Proper
documentation
is
prepared
and
maintained
for
each
sample
to
minimize
damage,
loss,
deterioration,
and
extraneous
exposures.
4.2.14
Inspection
and
Acceptance
Testing
Measures
used
by
the
WID
to
ensure
that
required
inspections
and
tests
performed
are
outlined
in
Part
II,
Section
8
of
the
WID
QAPD.
Controls
are
implemented
in
accordance
with
documented
procedures
to
ensure
that
items
are
not
used
pnor
to
passing
required
inspections
and
tests.
The
status
is
identified
on
the
items
or
on
documents
traceable
to
the
items.
Items
that
have
not
been
accepted
are
identified
as
such
and
stored
separately
from
accepted
items.
The
operating
status
of
equipment
is
identified
on
the
equipment
or
on
the
equipment
list.
Faulty
equipment
is
tagged
and,
if
practicable,
physically
segregated
from
the
work
area.
8
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
4.2.15
Control
of
Nonconforming
Conditions
Part
I
I
,
Section
8
of
the
WID
QAPD
describes
the
system
used
at
the
WlPP
for
ensuring
that
appropriate
measures
are
established
to
control
nonconforming
conditions.
Nonconforming
conditions
connected
to
the
GSP
are
identified
in
and
controlled
by
documented
procedures.
Equipment
that
does
not
conform
to
specified
requirements
is
controlled
to
prevent
use.
The
disposition
of
defective
items
is
documented
on
records
traceable
to
the
affected
items.
Prior
to
final
disposition,
faulty
items
are
tagged
and
segregated.
Repaired
equipment
is
subject
to
the
original
acceptance
inspections
and
tests
prior
to
use.
4.2.16
Corrective
Action
Requirements
for
the
development
and
implementation
of
a
system
to
determine,
document,
and
initiate
appropriate
corrective
actions
after
encountering
conditions
adverse
to
quality
at
the
WlPP
are
outlined
in
Part
I
,
Section
3
of
the
QAPD.
Conditions
adverse
to
acceptable
quality
are
documented
and
reported
in
accordance
with
corrective
action
procedures
and
corrected
as
soon
as
practical.
Immediate
action
will
be
taken
to
control
work
performed
under
conditions
adverse
to
acceptable
quality,
and
its
results,
to
prevent
degradation
in
quality.
The
EM
manager
or
designee
investigates
any
deficiencies
in
groundwater
surveillance
activities
to
determine
if
there
is
an
underlying
root
cause.
All
such
actions
are
documented
and
reported
to
the
Q&
RA
Department.
4.2.17
Quality
Assurance
Records
Part
I,
Section
4
of
the
QAPD
outlines
the
policy
used
at
the
WIPP
regarding
ientification,
preparation,
collection,
storage,
maintenance,
disposition,
and
permanent
storage
of
QA
records.
The
EM
manager
or
designee
is
responsible
for
the
preparation
and
distribution
of
records
in
accordance
with
appropriate
DOE
Orders,
policies,
and
directives.
Records
to
be
generated
in
the
GSP
are
specified
by
procedure.
QA
records
are
identified.
This
is
the
basis
for
the
labeling
of
records
as
"QA"
on
the
EM
Records
Inventory
and
Disposition
Schedule
(RIDS).
QA
records
document
the
results
of
the
GSP
implementing
procedures
and
are
sufficient
io
demonstrate
that
all
quality
related
aspects
are
valid.
The
records
will
be
identifiable,
legible,
and
retrievable
in
accordance
with
WP
15
PR,
WID
Records
Management
Plan,
and
QA
record
procedures.
While
in
the
custody
of
the
GSP
group,
the
records
shall
be
stored
in
a
UL
fisted,
one
hour
fire
resistant
cabinet.
The
EM
manager
shall
coordinate
with
WlPP
Project
Records
Services
(PRS)
for
both
periodic
and
perpetual
transfer
of
records
to
PRS.
9
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
4.2.1
8
Assessments
Provisions
and
responsibilities
for
assessments
are
outlined
in
Part
i
l
l
,
Sections
9
and
'1
0,
of
the
QAPD.
Periodic,
independent
assessments
of
the
GSP
shall
be
scheduled,
planned,
and
performed
to
verify
that
work
is
performed
in
accordance
with
specified
requirements.
The
Independent
Assessment
Section
has
the
responsibility
and
oversight
authority
for
appraising
GSP
activities
for
compliance
with
applicable
environmental
statutes.
Assessment
teams
will
not
include
members
of
the
GSP
staff.
Assessments
are
performed
in
accordance
with
applicable
assessment
procedures.
5.0
GSP
WATER
QUALITY
SAMPLING
PLAN
5.1
S
c
m
e
This
section
of
the
WlPP
GSP
Plan
serves
as
the
controlling
document
for
the
WQSP
The
WQSP
is
a
subprogram
of
the
GSP.
The
WQSP
was
initiated
in
January
1985.
The
objective
of
the
program
is
to
collect
representative
and
reproducible
groundwater
samples
from
water
bearing
zones
in
the
area
of
the
WlPP
site.
The
purpose
of
the
program
is
to
provide
defensible
data
for
meeting
the
requirements
of
site
characterization,
performance
assessment,
regulatory
compliance,
and
permitting.
A
program
plan
that
defined
the
basic
structure
and
operational
activities
of
the
program
was
initially
developed
by
Colton
and
Morse
(1985).
The
program
plan
was
replaced
in
1987
by
WP
07
2,
Waste
Isolation
Pilot
Plant
Water
Quality
Sampling
Manual.
In
1991
the
WQSP
manual
was
replaced
by
WP
02
1,
Waste
Isolation
Pilot
Plant
Groundwater
Monitoring
Program
Plan
and
Procedures
Manual
~
5.1
.I
General
From
1984
to
1990,
the
WQSP
was
designed
to
characterize
the
physical
and
chemical
characteristics
of
representative
groundwater
samples
occurring
within
and
immediately
surrounding
the
WlPP
site.
Various
wells
were
serially
sampled,
three
times
each,
to
determine
the
representative
character
of
the
groundwater
present
at
each
location.
Data
collected
were
supplied
to
the
ES&
H
Department
and
used
to
develop
a
baseline
of
water
quality
data
as
part
of
the
Radiological
Baseline
Program.
A
nonradiological
database
was
developed
to
support
the
background
water
quality
characterization
report.
Data
were
also
supplied
to
and
used
by
Sandia
National
Laboratories
(SNL)
for
site
characterization
and
performance
assessment.
By
the
close
of
1990,
the
groundwater
of
interest
had
been
characterized,
and
the
objective
of
the
program
shifted
from
characterization
to
surveillance.
On
October
1,
1988,
the
ES&
H
Department
assumed
responsibility
for
the
WQSP.
Water
quality
sampling
activities
were
coordinated
with
the
Environmental
Monitoring
10
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
Program.
Collection
of
groundwater
quality
data
continues
to
assist
the
DOE
in
meeting
performance
assessment,
regulatory
compliance,
and
permitting
requirements.
The
data
also
provide:
0
Radiological
and
nonradiological
water
quality
input
to
the
WlPP
Environmental
Monitoring
Program.
I]
A
means
to
comply
with
future
groundwater
inventory
and
monitoring
regulations.
0
Input
for
making
land
use
decisions
(i.
e,,
designing
long
term
active
and
passive
institutional
controls
for
the
site).
Groundwater
exists
both
above
and
below
the
WIPP
repository,
but
no
hydrologic
continuity
exists
between
the
repository
and
the
groundwater.
Groundwater
below
the
repository
occurring
in
the
sandstones
of
the
Delaware
Mountain
Group
(Powers,
et
al.,
1978)
is
isolated
by
bedded
salt
deposits
in
the
lower
part
of
the
Salado
Formation
and
in
the
underlying
Castile
Formation.
Groundwater
below
the
repository
is
not
being
monitored
as
part
of
this
program.
Groundwater
above
the
repository
is
being
monitored.
Groundwater
exists
in
both
the
Dewey
Lake
Formation
and
the
Rustler
Formation.
Zones
monitored
for
background
characterization
within
the
Rustler
are
the
Culebra
and
the
Magenta
members.
These
zones
appear
to
be
dolomite
units
isolated
from
one
another
by
impermeable
units.
With
the
exception
of
excavated
shafts
at
WIPP,
these
zones
are
isolated
from
the
repository
excavations
by
bedded
salt
deposits
in
the
upper
two
thirds
of
the
Salado
Formation.
Postbackground
surveillance
is
focused
on
the
Culebra
because
it
is
the
primary
flow
path
within
the
Rustler
formation.
Databases
are
maintained
for
the
Magenta
so
that
if
the
need
arises
surveillance
of
the
Magenta
can
be
resumed.
The
Culebra
is
areally
persistent,
but
quantity
and
quality
of
water
va;
y
considerably
from
place
to
place.
The
dolomite
is
vuggy,
fractured,
and
commonly
associated
with
anhydride
(Lambert
and
Mercer,
1977).
The
Culebra
has
a
low
hydraulic
conductivity.
It
is
a
fractured
unit
that
is
best
modeled
as
a
dual
porosity
media.
Water
yields
are
small
and
saline
(Powers
et
al.,
1978).
The
Magenta
is
finely
crystalline
and
dense.
Like
the
Culebra,
the
Magenta
has
a
low
hydraulic
conductivity
through
fractures
and
contains
limited
amounts
of
poor
quality
water
(Powers
et
al.,
1978).
The
Dewey
Lake
Redbeds
consist
of
orange
red
silt
stone,
mud
stone,
and
some
11
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
sandstone.
The
Dewey
Lake
Redbeds
do
not
form
an
aquifer,
but
some
permeable
sand
lenses
are
present
and
those
yield
limited
quantities
of
fresh
water
to
a
few
private
wells
in
the
area
around
the
WIPP
site
(Powers
et
al.,
1978).
One
such
sand
lens
has
been
identified
within
the
WlPP
boundary
and
is
scheduled
for
surveillance
as
part
of
the
WQSP.
5.2
Surveillance
Well
Construction
Many
of
the
WIPP
surveillance
wells
were
drilled
and
completed
prior
to
1980.
As
the
WIPP
Project
progressed,
additional
monitoring
wells
were
completed
in
the
vicinity
of
the
site.
Drilling
of
the
bulk
of
WlPP
surveillance
wells
began
in
1976
and
continued
into
1988.
In
general,
all
of
these
wells
were
drilled
as
part
of
the
geologic
site
characterization
and
resource
evaluation
programs.
Most
WlPP
surveillance
wells
were
drilled
and
completed
using
oil
field
techniques.
Surveillance
wells
at
the
site
have
been
completed,
generally,
using
two
types
of
installations.
One
installation
requires
drilling
the
well
to
some
depth
below
the
base
of
the
Culebra
and
then
casing
the
well
to
the
bottom
of
the
hole.
The
interval
of
the
Culebra
or
Magenta
is
then
perforated
to
allow
access
to
the
formation
for
testing
or
sampling
purposes.
The
second
type
of
installation
consists
of
drilling
the
hole
to
a
depth
just
above
the
top
of
the
Culebra,
installing
well
casing
to
the
bottom
of
the
drilled
hole,
and
coring
or
drilling
through
the
Culebra
interval,
leaving
the
Culebra
interval
open
to
the
formation.
These
types
of
well
completions
presented
problems
in
collecting
undisturbed
and
representative
samples
from
the
water
bearing
units.
The
open
hole
completions
have,
in
some
cases,
resulted
in
sediments
below
the
CuIebra
being
exposed
in
the
sampling
interval.
In
some
cases,
these
sediments
are
rich
in
halite
or
other
evaporite
minerals,
causing
the
water
chemistry
in
the
well
bore
and
the
water
bearing
unit
surrounding
the
well
to
be
altered.
Often,
during
drilling
and
completion
of
surveillance
wells,
fluids
containing
fresh
water,
saturated
brine,
and
drilling
fluids
containing
petroleum
products
have
been
introduced
into
the
well
bore.
In
some
cases,
these
fluids
were
left
standing
in
the
well
bore
for
extended
periods
of
time,
resulting
in
contamination
of
the
surrounding
formation
(Crawley
1988).
Standard
oil
field
steel
well
casings
have
been
used
during
completion
of
the
WlPP
surveillance
wells.
This
type
of
casing
is
easily
corroded
by
the
brackish
to
brine
water
found
in
the
WlPP
area.
Based
on
serial
sampling
results,
it
appears
that
the
products
of
well
casing
corrosion
migrate
from
the
well
bore
into
the
formation,
resulting
in
a
halo
or
plume
of
groundwater
with
altered
chemistry
surrounding
the
surveillance
wells.
Obtaining
a
representative
sample
has
required
that
the
surveillance
wells
be
pumped
for
long
periods
of
time
to
remove
the
contamination.
Well
drilling
and
completion
techniques
such
as
those
described
above
are
usually
not
used
for
installation
of
monitoring
wells
employed
in
RCRA
or
sther
groundwater
12
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
sampling
programs,
due
to
the
likelihood
of
aquifer
contamination.
These
practices
required
that
the
WQSP
use
extensive
groundwater
pumping
in
order
to
obtain
uncontaminated
water
samples.
The
difficulty
in
obtaining
representative
groundwater
samples,
due
to
the
design
of
the
wells
used
by
the
WQSP,
necessitated
the
use
of
a
serial
sampling
technique.
Serial
sampling
and
the
associated
equipment
are
discussed
later
in
this
section.
Seven
observation
wells
were
completed
after
the
baseline
was
established
using
EPA
recommended
drilling
methods
and
casing
materials
that
have
the
potentiar
to
meet
RCRA
monitoring
standards.
Six
of
the
wells
were
completed
in
the
Culebra;
one
well
in
the
Dewey
Lake
formation.
Two
years
of
sampling
are
scheduled
prior
to
the
anticipated
receipt
of
waste.
The
data
gathered
from
these
wells
will
be
compared
to
the
existing
database
and
the
existing
background
data
will
be
appended
as
appropriate.
The
configuration
of
the
seven
new
observation
wells
may
well
preclude
the
necessity
to
perform
serial
sampling.
However,
sampling
of
a
portion
of
the
older
surveillance
wells
may
be
necessary
in
years
to
come.
Therefore,
a
discussion
of
serial
sampling
techniques
is
included
in
this
document.
5.3
Samdina
Proaram
Descrbtion
The
WQSP
has
employed
two
types
of
sampling
procedures
at
the
WIPP:
serial
sampling
and
final
sampling.
5.3.1
Serial
Sampling
Serial
sampling
is
the
collection
of
sequential
samples
for
the
purpose
of
determining
when
the
water
chemistry
stabilizes
or
reaches
a
steady
state.
Ideally,
when
the
water
chemistry
stabilizes,
it
is
assumed
that
the
chemistry
is
representative
of
the
native
formation
fluid,
and
a
final
sample
is
collected.
However,
in
reality,
serial
sampling
leads
to
the
collection
of
water
samples
with
reproducible
chemistries
which
may
or
may
not
be
representative
of
the
undisturbed
groundwater.
The
water
samples
may
still
be
impacted
by
well
construction
practices
and
effects
from
the
installation
of
downhole
pumping
and
sampling
equipment.
During
the
background
characterization
phase
of
the
WQSP
serial
sample,
field
parameters
were
monitored
on
a
daily
basis.
After
completion
of
the
background
characterization
phase,
monitoring
of
serial
sample
parameters
was
modified
by
pumping
each
well
for
48
hours
prior
to
the
start
of
serial
sampling
then
comparing
the
serial
sampling
analysis
results
to
the
average
last
day
serial
sample
results
for
previous
sampling
rounds.
A
95
percent
confidence
interval
was
established
for
com
pa
riso
n
standards.
13
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
The
field
analytical
parameters
found
to
be
the
most
useful
in
identifying
a
steady
state
condition
of
the
water
chemistry
include
chloride,
divalent
cations
(hardness),
and
alkalinity,
which
are
analyzed
by
classic
wet
chemistry
bench
methods
(titration).
Totai
iron
has
also
been
found
to
be
a
useful
indicator
and
is
analyzed
using
spectrophotometric
methods.
Other
serial
sampling
parameters
analyzed
in
the
field
include
measurement
of
pH,
Eh,
temperature,
specific
conductance,
and
specific
gravity.
Procedures
for
collection
and
analysis
of
serial
samples
are
processed,
approved,
and
maintained
by
the
site
documentation
process.
5.3.2
Final
Samples
Final
groundwater
samples
are
collected
once
evidence
from
serial
sampling
indicates
that
the
pumped
groundwater
has
reached
a
chemical
steady
state.
Final
samples
are
forwarded
to
a
contract
analytical
laboratory
for
analysis.
Final
samples
are
collected
in
the
appropriate
type
of
container
for
the
specific
analysis
to
be
performed,
For
each
parameter
analyzed,
a
sufficient
volume
of
sample
is
collected
to
satisfy
the
volume
requirements
of
the
analytical
laboratory.
This
includes
an
additional
volume
of
sample
water
necessary
for
maintaining
quality
control
standards.
All
final
samples
are
treated,
handled,
and
preserved
as
required
for
the
specific
type
of
analysis
to
be
performed.
Details
about
sample
collection,
preservation,
and
volumes
required
for
individual
types
of
analyses
are
found
in
the
applicable
procedures
generated,
approved,
and
maintained
by
the
site
documentation
process.
Splits
of
the
final
sample
are
provided
to
oversight
agencies
and
WIPP
stakeholders
as
requested
by
the
DOE.
A
split
of
the
sample
is
also
placed
in
storage
within
the
ES&
H
Environmental
Sample
storage
area
and
held
until
final
reports
from
the
contract
analytical
laboratory
have
been
evaluated
and
approved.
When
the
final
laboratory
report
has
been
approved
the
samples
are
removed
from
storage
and
destroyed.
Detailed
protocols,
in
the
form
of
procedures,
assure
that
samples
are
collected
in
a
consistent
and
repeatable
fashion.
Procedures
applicabie
to
water
quality
sampling
are
generated,
approved,
and
maintained
by
the
site
documentation
process.
The
serial
sampling
process
will
probably
not
be
needed
with
the
wells
completed
specifically
for
water
quality
sampling.
However,
during
the
first
two
years
of
sampling,
the
wells
will
be
serially
sampled
using
an
abbreviated
method.
It
is
anticipated
that
changes
in
the
water
chemistry
from
stagnated
to
representative
will
occur
within
the
first
24
hours
of
the
purging
process.
Whereas,
this
change
usually
occurred
over
a
seven
day
period
with
the
old
wells.
During
the
first
two
or
three
years
of
sampling,
these
wells
will
be
serially
sampled
with
the
first
sample
being
analyzed
as
soon
as
possible
after
the
pump
is
turned
on
and
daily
there
after
for
a
period
of
four
days
or
until
the
field
parameters
(chloride,
divalent
14
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
cations,
alkalinity
and
iron)
stabilize.
Eh,
pH,
and
conductance
will
be
monitored
continuously
by
using
a
flow
cell
with
ion
specific
electrodes
and
a
real
time
readout.
After
two
years
of
sampling
data
have
been
accumulated,
a
decision
will
be
made
to
determine
if
the
serial
sampling
process
can
be
eliminated.
If
serial
sampling
is
removed
from
the
water
quality
sampling
well
protocol,
the
decision
to
collect
samples
will
be
based
on
the
number
of
well
bore
volumes
purged
and
the
results
of
continuous
monitoring
of
temperature
Eh,
pH,
and
conductance.
5.4
Groundwater
PumDina
and
SarnDlina
Svstems
The
water
bearing
units
at
the
WlPP
are
highly
variable
in
their
ability
to
yield
water
to
surveillance
wells.
The
Culebra,
the
most
transmissive
hydrologic
unit
in
the
WlPP
area,
exhibits
transmissivities
that
range
many
orders
of
magnitude
across
the
site
area
and
has
been
the
primary
focus
of
the
GSP.
The
Magenta
has
a
lower
transmissivity
and
yields
very
small
quantities
of
water
to
wells.
Because
the
water
yielding
characteristics
of
the
hydrologic
units
at
the
WlPP
are
variable,
different
types
of
pumping
equipment
are
used
during
water
quality
sampling
activities.
The
groundwater
pumping
and
sampling
systems
used
to
collect
a
groundwater
sample
are
designed
to
provide
continuous
and
adequate
production
of
water
so
that
a
representative
groundwater
sample
can
be
obtained.
The
wells
used
for
water
quality
sampling
vary
in
yield,
depth,
and
pumping
lift.
These
factors
affect
the
duration
of
pumping
as
well
as
the
equipment
required
at
each
well.
Based
upon
expected
yields,
the
wells
monitored
at
WlPP
can
be
divided
into
three
categories
according
to
flow
rate:
(1
)
high
flow
rate
of
10
to
25
gallons
per
minute
(gpm);
(2)
medium
flow
rate
or
1
to
10
gpm;
and
(3)
low
flow
rate
of
less
than
1
gpm.
The
high
and
medium
flow
rate
wells
may
use
a
submersible
pump
packer
assembly.
The
low
volume
wells
may
require
a
gas
driven
piston
pump
packer
assembly.
A
discussion
of
the
different
pump
packer
equipment
is
provided
below.
The
type
of
pumping
and
sampling
system
to
be
used
in
a
wet1
depends
primarily
on
the
aquifer
characteristics
and
well
construction.
For
example,
if
well
construction
is
such
that
it
yields
contamination
to
the
aquifer
(i.
e.,
metal
casing)
a
packer
is
normally
recommended
to
minimize
purging
time,
If
the
aquifer
yields
adequate
water
to
the
well
to
be
classified
a
high
or
medium
production
well,
a
submersible
electric
pump
may
be
used.
However,
if
the
well
is
completed
with
the
water
bearing
unit
uncased,
a
gas
piston
pump
may
be
needed
to
minimize
stress
to
the
formation
walls
to
prevent
collapse
of
the
formation.
Wells
that
are
completed
to
water
quality
standards
are
cased
and
screened
through
the
production
interval
with
materials
that
do
not
yield
contamination
to
the
aquifer
or
allow
the
production
interval
to
collapse
under
stress.
An
electric,
submersible
pump
installation
without
the
use
of
a
packer
is
an
acceptable
installation
in
this
instance.
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
The
largest
amount
of
discharge
from
the
submersible
pump
takes
place
from
a
discharge
pipe.
In
addition
to
this
main
discharge
pipe
a
dedicated
nylon
sample
line,
running
parallel
to
the
discharge
pipe,
is
also
used.
Flow
through
the
pipe
is
regulated
on
the
surface
by
a
flow
control
valve
andlor
variable
speed
drive
controller.
Cumulative
flow
is
measured
using
a
totalizing
flow
meter.
Flow
from
the
discharge
pipe
is
routed
to
a
discharge
tank
for
disposal.
The
dedicated
nylon
sampling
line
is
used
to
collect
the
water
sample
that
will
undergo
analysis.
By
using
a
dedicated
nylon
sample
line,
the
water
is
not
contaminated
by
the
metal
discharge
pipe.
The
sample
line
branches
from
the
main
discharge
pipe
a
few
inches
above
the
pump.
Flow
from
the
sample
line
is
routed
into
the
sample
collection
area.
Flow
through
the
sample
collection
line
is
regulated
by
a
flow
control
valve.
The
sample
line
is
insulated
at
the
surface
to
minimize
temperature
fluctuations.
A
gas
driven
pump
and
sampling
system
can
be
used
on
any
volume
well.
When
used,
the
pump
intake
is
set
at
a
predetermined
depth
near
or
in
the
production
zone.
The
pumping
rate
is
adjusted
to
maintain
the
water
level
in
the
well
above
the
pump
intake.
The
flow
rate
for
gas
driven
pumps
is
controlled
by
regulating
the
air
pressure
on
the
pump
intake
or
by
a
flow
control
valve.
Water
is
continuously
discharged
into
a
water
storage
tank.
Detailed
protocol
for
assembling,
installing,
and
controlling
pumping
and
sampling
systems
is
found
in
the
procedures
generated,
approved,
and
maintained
by
the
site
documentation
process
5.5
Pressure
Monitorina
Svstems
Regardless
of
which
pump
is
used
when
sampling
a
well
that
was
drilled
for
the
geologic
site
characterization
and
resource
evaluation
program,
a
packer
is
used
to
isolate
the
pump
intake
from
contaminated
well
bore
fluid
that
exists
in
the
well
above
the
sampling
zone.
If
the
packer
seal
is
not
good,
contaminated
water
from
above
the
packer
can
leak
into
the
formation
water
being
sampled
and
bias
analytical
results.
If
the
packer
has
a
good
seal
the
pressure
above
the
inflated
packer
should
remain
con
st
ant.
Pressure
above
the
packer
is
monitored
using
transducers
and/
or
bubblers
to
verify
that
the
seal
on
the
packer
is
good.
Pressure
below
the
packer
is
monitored
to
ensure
that
water
levels
do
not
fall
below
the
pump
intake.
Periodic
checks
of
the
pressures
are
conducted
during
field
sampling
to
verify
packer
seal
integrity.
These
field
checks
are
recorded
on
Field
Activity
Log
Forms.
Wells
drilled
to
water
quality
specifications
do
not
require
the
installation
of
a
packer
because
sample
biases
due
to
well
construction
deficiencies
are
not
present.
However,
pressures
will
be
monitored
in
the
formation
to
maintain
water
level
above
the
pump
intake.
Procedures
governing
the
installation
and
use
of
pressure
monitoring
devices
are
generated,
approved,
and
maintained
by
the
site
documentation
process.
16
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
5.6
Sample
Analvsis
The
mobile
field
laboratory
provides
a
work
place
for
conducting
field
sampling
and
analyses.
The
laboratory
is
positioned
near
the
wellhead,
is
climate
controlled,
and
contains
the
necessary
equipment,
reagents,
glassware,
and
deionized
water
for
conducting
the
various
analyses.
Two
types
of
water
samples
are
collected:
serial
samples
and
final
samples.
Serial
samples
are
taken
at
regular
intervals
and
analyzed
in
the
mobile
laboratory
for
various
physical
and
chemical
parameters
(called
field
parameters).
The
serial
sample
data
are
used
to
determine
the
chemical
steady
state
conditions
of
the
groundwater,
as
a
direct
function
of
the
volume
of
the
water
being
pumped
from
the
well.
Interpretation
of
the
serial
sampling
data
enables
the
TL
to
make
a
determination
of
when
steady
state
conditions
are
attained
in
the
pumped
groundwater.
Final
samples
are
collected
when
the
serially
sampled
field
parameters
have
achieved
a
steady
state.
If
one
or
more
of
the
field
parameters
do
not
stabilize,
and
there
is
reason
to
believe
it
will
not,
the
TL
may
choose
to
collect
the
final
sample
regardless
of
this
instability
in
the
field
parameter(
s).
The
objective
of
the
serial
sampling
effort
is
to
obtain
representative
water
samples
in
a
reproducible
manner.
By
definition,
a
representative
groundwater
sample
is
a
sample
of
undisturbed
groundwater.
A
groundwater
sample
is
considered
to
be
representative
of
the
undisturbed
groundwater
only
if
it
is
chemically
identical
to
the
undisturbed
groundwater
(i,
e.,
completely
unaltered
by
the
effects
of
drilling,
postdrilling
processes
and
reactions,
and
sampling
procedures).
Obtaining
a
representative
groundwater
sample
is
a
theoretical
ideal.
For
example,
the
redox
potential
of
the
aquifer
groundwater,
Eh,
is
likely
to
change
as
a
result
of
pressure
decreases
(gas
loss)
and
contamination
by
atmospheric
oxygen
that
occurs
during
the
sampling
process.
The
ratios
between
the
different
oxidation
states
of
a
multivariant
element
may
change,
and
the
total
concentration
of
that
element
may
also
change
during
sampling
due
to
precipitation.
To
determine
how
close
the
pumped
groundwater
is
to
being
representative,
a
comparison
is
made
by
monitoring
the
same
selected
field
parameters
whiz5
were
used
to
initially
define
the
background
characteristics
of
the
water.
When
these
parameters
appear
stable,
then
the
determination
is
made
that
the
water
sample
is
representative.
Stability
is
usually
defined
as
*
5
percent
of
the
average
of
preceding
parameter
measurements
made
on
the
final
day
of
sampling
for
previous
rounds.
When
stability
has
been
determined,
a
final
sample
is
collected.
The
final
sample
is
considered
to
be
as
representative
a
sample
of
the
undisturbed
groundwater
as
can
possibly
be
obtained
considering
the
analytical
and
technical
means
at
hand.
17
WP
02
1
Rev.
3
G
RO
U
N
DWATER
SU
RVEl
LLAN
CE
PROGRAM
PLAN
5.6.1
Serial
Samples
Serial
samples
are
collected
and
analyzed
in
the
mobile
laboratory
to
detect
and
monitor
the
chemical
variation
of
the
groundwater
as
a
function
of
the
volume
of
water
pumped.
The
purpose
of
implementing
this
rigorous
serial
sampling
and
analysis
program
is
to
ascertain
when
the
pumped
groundwater
has
reached
a
chemical
steady
state.
Once
serial
sampling
begins,
the
frequency
at
which
serial
samples
are
collected
and
analyzed
is
left
to
the
discretion
of
the
TL.
The
serial
sampling
frequency
is
based
upon
the
site
specific
conditions
existing
at
each
well,
but
usually
is
performed
a
minimum
of
three
times
during
a
sampling
round.
The
three
field
parameters
of
temperature,
Eh,
and
pH
are
determined
by
either
an
"in
line"
technique,
using
a
self
contained
flow
cell,
or
an
"off
line"
technique,
in
which
the
samples
are
collected
from
a
nylon
sample
line
at
atmospheric
pressure.
The
iron,
divalent
cation,
chloride,
alkalinity,
specific
conductance,
and
specific
gravity
samples
are
collected
from
the
nylon
sample
line
at
atmospheric
pressure.
New
polyethylene
containers
are
used
to
collect
the
serial
samples
from
the
nylon
sample
line.
Serial
sampling
water
collected
for
solute
and
specific
conductance
determinations
is
filtered
through
a
0.45
pm
filter
membrane
using
a
stainless
steel,
in
line
filter
holder.
Filtered
water
is
used
to
rinse
the
sample
bottle
prior
to
serial
sample
collection.
Unfiltered
groundwater
is
used
when
determining
temperature,
pH,
Eh,
and
specific
gravity.
Sample
bottles
are
properly
identified
and
labeled.
The
filtered
sample
collected
for
solute
analyses
is
immediately
analyzed
for
iron
and
alkalinity,
as
these
two
solution
parameters
are
extremely
sensitive
to
changes
in
the
ambient
water
sample
pressure
and
temperature.
The
sample
aliquot
needed
for
the
other
chemical
parameter
analyses
may
be
taken
from
a
second
filtered
sample
bottle.
Temperature,
pH,
and
Eh,
when
not
measured
in
a
flow
cell,
are
measured
at
the
approximate
time
of
serial
sample
collection;
these
samples
are
collected
from
the
unfiltered
sample
line.
Experience
gained
from
the
serial
sampling
of
wells
has
shown
that
samples
to
be
analyzed
for
chloride
and
divalent
cations
can
be
stored
for
one
week
prior
to
analysis
with
confidence
that
the
analytical
results
will
not
be
altered.
Upon
completion
of
the
collection
of
the
final
sample
suite,
the
serial
sample
bottles
accrued
throughout
the
duration
of
the
pumping
of
the
well
are
discarded.
No
serial
sample
bottles
will
be
reused
for
sampling
purposes
of
any
sort.
However,
serial
samples
may
be
archived
for
a
period
of
time
depending
upon
the
need.
Procedures
for
sample
collection
and
analysis
are
generated,
approved,
and
maintained
by
the
site
documentation
process.
5.6.2
Final
Samples
18
WP
02
1
Rev.
3
G
RO
U
N
DWATER
S
U
RVEl
LLANC
E
PROGRAM
PLAN
The
final
sample
is
collected
once
the
pumped
groundwater
has
achieved
a
chemically
steady
state.
A
serial
sample
is
also
collected
and
analyzed
for
each
day
of
final
sampling.
Sample
preservation,
handling,
and
transportation
methods
are
designed
to
maintain
the
integrity
and
representativeness
of
the
final
samples.
Prior
to
collecting
the
final
samples,
the
collection
team
must
consider
the
analyses
to
be
performed
so
that
proper
shipping
or
storage
containers
can
be
assembled.
Final
samples
are
sent
to
contract
laboratories
and
analyzed
for
general
chemistry,
radionuclides,
metals,
and
selected
volatile
organic
compounds
that
are
specific
to
the
waste
anticipated
to
arrive
at
WIPP.
Gases
and
redox
couples
were
analyzed
during
the
baseline
study,
but
these
data
are
not
needed
for
environmental
monitoring
and
are
no
longer
obtained
on
a
routine
basis.
Water
samples
are
collected
at
atmospheric
pressure
using
either
the
filtered
or
unfiltered
nylon
sampling
lines
branching
from
the
main
sample
line.
The
samples
are
collected
in
new
and
unused
glass
and
plastic
containers.
Before
the
final
sample
is
taken,
all
plastic
and
glass
containers
are
rinsed
with
the
pumped
groundwater,
either
filtered
or
unfiltered,
dependent
upon
analysis
protocol.
When
the
rinsing
procedure
is
completed,
the
final
sample
is
collected.
5.7
Sample
Preservation,
Trackina.
Packaaina
and
Transoortation
Many
of
the
chemical
constituents
that
are
measured
are
not
chemically
stable
and
need
to
be
preserved.
Samples
requiring
acidification
are
treated
with
either
high
purity
hydrochloric
acid,
nitric
acid,
or
sulfuric
acid
(ULTREX
or
equivalent),
depending
upon
the
standard
method
of
treatment
required
for
the
particular
parameter
suite.
The
procedure
used
by
the
contract
laboratory
to
which
the
samples
are
being
sent
prescribes
the
type
and
amount
of
preservative
which
should
be
used.
This
information
is
recorded
on
the
Final
Sample
Checklist
for
use
by
field
personnel
when
final
samples
are
being
collected.
The
sample
tracking
system
at
WlPP
uses
uniquely
numbered
Chain
of
Custody
Forms
and
Request
for
Analysis
Forms.
The
primary
consideration
for
storage
or
transportation
is
that
samples
must
be
analyzed
within
the
prescribed
holding
times
for
the
parameters
of
interest.
Procedures
for
sample
tracking
and
preservation
are
generated,
approved,
and
maintained
by
the
site
documentation
process.
The
prescribed
transport
temperature
for
the
organic
samples
is
four
degrees
Celsius.
This
temperature
must
be
maintained
until
the
sample
reaches
the
contracted
laboratory.
Insulated
shipping
containers
packaged
with
reusable
blue
ice
are
used
to
keep
the
19
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
samples
cool
during
transport
to
the
contract
laboratory.
Hold
times
for
specific
analytical
parameters
require
samples
to
be
shipped
by
express
air
freight.
The
coolers
are
packaged
to
meet
Department
of
Transportation
and
International
Air
Transportation
Association
commercial
carrier
regulations.
5.8
Qualitv
Assurance.
Records
Manaaernent
and
Document
Control
All
aspects
of
quality
assurance,
records
management,
and
control
of
documents
generated
as
a
result
of
WQSP
are
governed
by
the
QAPD;
WP
15
PR,
Records
Management
Plan;
and
implementing
procedures
generated,
approved,
and
maintained
by
the
site
documentation
process.
A
chemistry
laboratory
notebook
is
maintained
in
the
mobile
laboratory
to
record
the
overall
conditions
at
the
well,
the
analytical
difficulties
or
problems
experienced,
and
any
information
which
may
be
pertinent
to
future
interpretation
and
scientific
use
of
the
field
data.
The
original
notebook
is
kept
in
the
field
laboratory.
A
copy
of
the
notes
made
for
each
sampling
round
is
kept
in
a
fire
resistant
file
cabinet.
All
field
data
collected
are
organized
into
a
data
book.
The
typical
field
data
book
contains
the
following:
A
copy
of
all
of
the
notes
entered
into
the
laboratory
notebook
concerning
the
sampling
round.
A
copy
of
all
chain
of
custody
forms
and
request
for
analysis
forms
used
to
distribute
the
final
samples.
A
copy
of
the
completed
final
sample
checklist.
A
copy
of
all
standardization
forms.
A
hard
copy
printout
of
all
computer
data
entries.
A
copy
of
all
of
the
Serial
Sampling
Report
Forms
submitted
for
the
sampling
round.
A
copy
of
all
worksheets
used
to
prepare
the
data
for
entry
into
the
computer.
A
written
summary
report
containing
a
description
of
the
well
completion
data,
a
brief
summary
of
serial
sampling
results,
and
general
observations.
A
copy
of
all
Field
Sketch
Plan
Forms.
A
copy
of
all
Field
Activity
Log
Forms.
20
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
0
A
computer
printout
of
all
data
logger
information,
if
a
data
logger
was
used.
0
Validated
Check
Print
copies
of
all
data
sheets.
A
contract
laboratory
data
book
is
made
for
each
contract
laboratory
used
to
analyze
samples
from
a
particular
well.
The
contract
laboratory
data
book
contains
at
a
minimum:
0
A
copy
of
the
contract
laboratory
analytical
report.
a
A
copy
of
the
computer
data
generated.
Data
collected
as
a
result
of
WQSP
activities
are
summarized
and
reported
on
an
annual
basis
in
the
Site
Environmental
Report.
Raw
data
are
stored
in
fireproof
cabinets
in
the
EM
Section
for
a
period
of
two
years
and
then
turned
over
to
PRS
for
storage
in
accordance
with
the
RIDS.
5.9
Calibration
Requirements
The
equipment
used
to
collect
data
for
the
WQSP
is
to
be
calibrated
in
accordance
with
WP
1
0
AD,
WIPP
Maintenance
Administrative
Procedures
Manual.
The
metrology
laboratory
is
responsible
for
calibrating
needed
equipment
on
schedule,
in
accordance
with
written
procedures.
The
EM
Section
is
responsible
for
maintaining
current
calibration
records
for
each
piece
of
equipment.
6.0
WATER
LEVEL
MONITORING
PLAN
6.1
Scoee
This
section
of
the
WlPP
GSP
serves
as
the
controlling
document
for
the
WLMP.
The
WLMP
is
a
subprogram
of
the
GSP.
The
quality
assurance
activities
of
the
WLMP
are
in
strict
accordance
with
the
QAPD
and
the
quality
assurance
implementing
procedures
specific
to
environmental
monitoring
are
found
in
WP
02
3,
Environmental
Monitoring
Procedures
Manual.
Water
level
monitoring
will
continue
through
the
postoperational
phase
of
the
WIPP.
This
plan
addresses
the
activities
of
the
WLMP
during
the
preoperational
and
operational
phases
of
the
WIPP.
Postoperational
activity
plans
will
be
formulated
at
a
later
date
and
will
address
the
objectives
of
water
level
monitoring
as
required
at
the
time
of
decommissioning.
.
6.2
Introduction
This
program
will
continue
the
collection
and
documentation
of
water
level
data
initiated
by
the
U.
S.
Geological
Survey
(Richey,
1987)
and
SNL
(Stensrud
et
al.,
1988)
as
part
21
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
of
the
WlPP
Site
Characterization
Program.
As
currently
planned,
water
level
measurements
will
be
conducted
using
hydrologic
test
wells
that
were
constructed
for
the
site
characterization
and
WQSP.
These
test
wells
are
distributed
geographically
both
within
and
surrounding
the
WlPP
site.
The
frequency
of
measurement
is
subjectively
defined
by
the
need
to
record
the
dynamic
nature
of
the
potentiometric
surface
through
time.
On
October
1,
1988,
the
ES&
H
Department
assumed
responsibility
for
Groundwater
Level
Monitoring
Activities.
At
that
time
a
WLMP
plan
was
still
being
developed.
In
June
of
1989,
an
initial
plan
was
finalized
entitled
WP
07
2,
WIPP
Water
Level
Monitoring
Program
Plan,
IT
Corp.
(June
1989).
WP
07
2
was
subsequently
replaced
in
1990
by
WP
02
1
,
Groundwater
Monitoring
Program
Plan
and
Procedures
Manual.
Collection
of
groundwater
level
data
assists
the
DOE
in
meeting
performance
assessment,
regulatory
compliance,
and
permitting
requirements.
These
data
also
provide:
U
0
0
U
0
0
6.3
Data
collection
as
required
by
the
Environmental
Monitoring
Plan.
A
means
to
fulfill
commitments
made
in
the
FEIS.
A
means
to
comply
with
future
groundwater
inventory
and
monitoring
regulations.
Input
for
making
land
use
decisions,
(i.
e.,
designing
long
term
active
and
passive
institutional
controls
for
the
site).
Assistance
in
understanding
any
changes
to
readings
from
the
water
pressure
transducers
installed
in
each
of
the
shafts
to
monitor
water
conditions
behind
the
liners.
An
understanding
of
whether
or
not
the
horizontal
and
vertical
gradients
of
flow
are
changing
over
time.
0
biective
The
objective
of
the
WLMP
is
to
extend
the
documented
record
of
water
level
fluctuations
in
the
Culebra
and
Magenta
members
of
the
Rustler
Formation
in
the
vicinity
of
the
WlPP
facility.
Water
level
data
will
also
be
collected
from
wells
completed
in
other
water
bearing
zones
overlying
and
underlying
the
WlPP
repository
horizon
when
access
to
those
zones
is
possible.
This
includes,
but
is
not
limited
to,
the
Bell
Canyon
Formation,
the
Forty
Niner
member
of
the
Rustler,
the
contact
zone
between
the
Rustler
and
Salado
Formations,
and
the
Dewey
Lake
Red
Beds,
when
access
to
these
zones
is
possible.
22
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
The
scope
of
the
program
is
subject
to
change
depending
upon
the
following:
a
Data
trends
0
Performance
assessment
program
needs
0
Environmental
Monitoring
Program
needs
0
Regulatory
compliance
needs
Water
level
measurements
will
be
taken
monthly
in
at
least
one
accessible
completed
interval
at
each
available
well
pad.
At
well
pads
with
two
or
more
wells
completed
in
the
same
interval,
quarterly
measurements
will
be
taken
in
the
redundant
wells.
Water
level
monitoring
will
continue
through
the
life
of
the
WlPP
Project.
It
may
be
deemed
necessary
to
temporarily
increase
the
frequency
of
monitoring
to
effectively
document
naturally
occurring
or
artificial
perturbations
that
may
be
imposed
on
the
hydrologic
systems
at
any
point
in
time.
This
will
be
conducted
in
selected
key
wells
by
increasing
the
frequency
of
the
manual
water
level
measurements
or
by
monitoring
water
pressures
with
the
aid
of
electronic
pressure
transducers
and
remote
data
logging
systems.
One
of
the
postulated
contaminate
pathways
to
the
biosphere
in
the
event
of
a
release
is
believed
to
be
in
the
water
bearing
zones
of
the
Rustler
Formation,
more
specifically,
the
Magenta
and
Culebra
members.
The
Culebra
is
believed
to
be
the
more
conductive
of
the
two
(Mercer,
1983)
and
has
received
the
most
attention
in
site
characterization
studies.
Other
water
bearing
zones
in
the
vicinity
of
the
WlPP
site,
in
which
a
limited
number
of
hydrologic
test
wells
have
been
completed,
include
the
Dewey
Lake
Red
Beds,
the
RustlerlSalado
Contact,
the
Forty
Niner
Member
of
the
Rustler,
and
the
Bell
Canyon
Formation.
All
of
the
above
listed
zones
will
be
monitored
as
part
of
this
program
plan,
subject
to
availability.
Water
level
fluctuations
of
confined
water
bearing
units
may
result
from
a
variety
of
hydrologic
phenomena
(Freeze
and
Cherry,
1979)
and
(Davis
and
DeWeist,
1966).
These
include:
1
Changes
in
groundwater
storage
(ems.,
groundwater
recharge)
0
Changes
in
atmospheric
pressure
0
Deformation
of
the
water
bearing
zone
(e.
g.,
earthquakes
and
earth
tides)
0
Disturbances
within
or
adjacent
to
a
well
(e.
g.,
groundwater
pumping
and
shaft
construction)
23
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
Interpretation
of
water
level
measurements
and
corresponding
fluctuations
over
time
is
complicated
at
the
WlPP
by
spatial
variation
in
fluid
density
both
vertically
in
well
bores
and
areally
from
well
to
well.
To
monitor
the
hydraulic
gradients
of
the
hydrologic
flow
systems
at
the
WlPP
accurately,
actual
water
level
measurements
and
the
densities
of
the
fluids
in
the
well
bores
must
be
known.
When
both
of
these
parameters
are
known,
equivalent
freshwater
heads
can
be
calculated.
The
concept
of
freshwater
head
is
discussed
in
Lusczynski
(1
961)
where
the
following
definition
is
provided:
Fresh
water
head
at
a
given
point
in
groundwater
of
variable
density
is
defined
as
the
water
level
in
a
well
filled
with
fresh
water
from
that
point
to
a
level
high
enough
to
balance
the
existing
pressure
at
that
point.
Fresh
water
heads
.
define
hydraulic
gradients
along
a
horizontal.
A
discussion
explaining
the
calculation
of
freshwater
heads
from
midformation
depth
at
WlPP
can
be
found
in
Haug,
et
ai.
(1987).
A
Pressure
Density
Survey
Program
(PDSP)
has
been
conducted
to
determine
the
actual
variation
in
density
gradients
existing
in
the
test
wells.
The
PDSP
measured
the
actual
midformation
pressures
of
the
Culebra.
Data
from
this
program
have
identified
those
wells
in
which
some
adjustment
to
measured
water
level
values
must
be
accounted
for
in
order
to
calculate
the
measured
water
levels
accurately
in
terms
of
equivalent
freshwater
heads.
6.4
Field
Methods
Po
obtain
an
accurate
groundwater
level
measurement,
a
calibrated
water
level
measuring
device
is
lowered
into
a
test
well
and
the
depth
to
water
is
recorded
from
a
known
reference
point.
When
using
an
electrical
conductance
probe,
the
depth
to
water
can
be
determined
by
reading
the
appropriate
measurement
markings
on
the
embossed
measuring
tape
when
the
alarm
is
activated
at
the
surface.
Specific
procedures
regarding
the
specific
activities
governing
the
Water
Level
Monitoring
Program
are
generated,
approved,
and
maintained
by
the
site
documentation
process.
6.5
Records
and
Document
Control
All
incoming
data
will
be
processed
in
a
timely
manner
to
assure
data
integrity.
The
data
management
process
for
water
level
measurements
begins
with
completion
of
the
field
data
sheets.
Date,
time,
tape
measurement,
equipment
identification
number,
calibration
due
date,
initial
of
the
field
personnel,
and
equipmenffcomments
are
recorded
on
the
field
data
sheets.
If,
for
some
unexpected
reason,
a
measurement
is
not
possible
(Le.,
a
test
is
under
way
that
blocks
entry
to
the
well
bore),
then
a
notation
as
to
why
the
measurement
was
not
taken
is
recorded
in
the
comment
column.
Personnel
also
use
the
comment
column
to
report
any
security
observations
(Le.,
well
lock
missing).
24
WP
02
1
Rev.
3
GROUNDWATER
SURVEILLANCE
PROGRAM
PLAN
Data
recorded
on
the
field
data
sheets
and
submitted
by
field
personnel
are
subject
to
guidelines
outlined
in
WP
02
3,
Environmental
Procedures
Manual.
The
data
are
entered
onto
a
computerized
worksheet.
The
worksheet
calculates
water
level
in
both
feet
and
meters
relative
to
the
top
of
casing
and
also
relative
to
mean
sea
level.
A
check
print
is
made
of
the
worksheet
printout.
The
check
print
is
used
to
verify
that
data
taken
in
the
field
is
properly
reported
on
the
database
printout.
A
minimum
of
I
O
percent
of
the
spreadsheet
calculations
are
randomly
verified
on
the
check
print
to
ensure
that
calculations
are
being
performed
correctly.
If
errors
are
found,
the
worksheet
is
corrected.
The
data
contained
on
the
computerized
worksheet
are
translated
into
a
database
file.
A
printout
is
made
of
the
database
file.
The
data
each
month
are
then
compiled
into
report
format
and
transmitted
to
the
appropriate
agencies
as
requested
by
the
DOE.
A
computerized
database
file
is
maintained
for
all
groundwater
level
data.
Monthfy
and
quarterly
data
are
appended
into
a
yearly
file.
Upon
verification
that
the
yearly
database
is
free
of
errors,
it
is
appended
into
the
project
database
file.
A
printed
copy
of
the
project
database
is
maintained
in
the
ES&
H
EM
fire
resistant
storage
area
current
through
December
of
the
preceding
year.
6.6
ReDortinq
Data
collected
from
this
program
are
reported
in
the
Annual
Site
Environmental
Report
(ASER).
The
ASER
includes
all
applicable
information
that
may
affect
the
comparison
of
water
level
data
through
time.
This
information
will
include
but
is
not
limited
to:
1
Well
configuration
changes
that
may
have
occurred
from
the
time
of
the
last
measurement
(i.
e.,
plug
installation
and
removal,
packer
removal
and
reinstallation,
or
both;
and
the
type
and
quantity
of
fluids
that
may
have
been
introduced
into
the
test
wells).
0
Any
pumping
activities
that
may
have
taken
place
since
publication
of
the
last
annual
report
(i.
e.,
water
quality
sampling,
hydraulic
testing,
and
shaft
installation
or
grouting
activities).
6.7
Calibration
Requirements
The
equipment
used
in
taking
groundwater
level
measurements
is
to
be
calibrated
in
accordance
with
WP
10
AD,
WlPP
Maintenance
Administrative
Procedures
Manual.
The
WID
metrology
laboratory
is
responsible
for
calibrating
needed
equipment
on
schedule,
in
accordance
with
written
procedures.
The
EM
Section
is
responsible
for
maintaining
current
calibration
records
for
each
piece
of
equipment.
25
WATER
LEVEL
MEASUREMENTS
FOR
THE
MONTH
OF
MARCH
1999
COMMENTS
AND
OBSERVATIONS
1.
All
measurements
were
referenced
to
top
of
casing
and
adjusted
to
mean
sea
level.
2.
Measurements
were
made
with
water
levef
probe
E0112
and
PE0122.
The
calibration
recall
date
on
this
instrument
is
01/
15/
99.
3.
Well
number
0
268,
packer
pressure
was
observed
to
be
200
psi.
4.
Well
number
Wipp
12,
checked
for
H2S;
result
was
negative.
5.
Well
numbers
H
05,
H
06,
H
07,
H
08,
and
H
09,
have
had
tall
grass
and
debris
removed
as
well
mesquite
trimmed
back
to
insure
safety
around
well
heads.
Page
1
0
R
1
G
I
N
A
L'
Report
Quarterty
Waterlevel
Measurements
For
MARCH
1999
WELL
ZONE
CASING
DATE
TIME
DEPTH
ADJUST
ADJUSTED
ADJUSTED
WATER
ELEVATION
NUMBER
ELEVATION
TO
TO
DEPTH
DEPTH
LEVEL
IN
it
amsl
WATER
TOC
TOC
METERS
ELEVATION
ME7ERS
AEC
7
AEC
8
C
2505
C
2506
C
2507
CB
1
0
268
DOE
1
DOE
2
ERDA
9
H
01
(PIP)
H
01
(ANNULUS)
H
O2bl
H
02b2
H
02~
H
03bl
H
03b2
H
03b3
H
03dI49
(PIP)
H
03dlDL
(PVC)
H
04b
H
04~
H
02a
H
05a
H
05b
H
0%
H
06a
H
06b
H
06C
H
07bl
H
07b2
H
08a
H
09a
H
O&
H
09b
H
0%
H
1
Oa
H
lob
H
I
Ibl
H
1
1
b2
H
I
1
b3
H
llb4
H
12
H
14
H
15
H
16
(PVC)
H
16
(PIP)
H
17
H
I
8
H
I
9b0
H
19b2
H
19b3
H
19b4
H
19b5
H
I
9b6
H
19b7
P
14
CUL
BIC
SR
SR
SR
CUL
CUL
CUL
CUL
CUL
CUL
MAG
CUL
MAG
CUL
CUL
MAG
CUL
CUL
49ER
DL
CUL
MAG
CUL
CUL
MAG
CUL
CUL
MAG
CUL
CUL
MAG
R
U
SISAL
CUL
CUL
CUL
MAG
CUL
CUL
CUL
CUL
CUL
CUL
CUL
CUL
DL
ULM
CUL
CUL
CUL
CUI
CUL
CUL
CUL
'
CUL
CUL
CUL
3657
25
3537.10
3413.05
34
12.87
3410.01
3328.38
3466.04
3419.09
3410.10
3399.53
3399.53
3378.09
3378.46
3378.31
3378.41
3390.64
3390.03
3390
01
3390.01
3333.35
3334.04
3506.24
3506.04
3506.04
3348.1
1
3348.25
3348.52
316417
3
164.40
3432.99
3432.90
3406.68
340686
3407.30
3689.47
341
1.62
3411.64
3412.42
3427.19
3347.11
3481
63
3406
77
3406.77
3385.31
3414.21
3418.38
3419.01
3419.09
3419.03
3418.63
3419.07
3418.99
3361.06
3280.70
3388.67
3688.67
3410.89
03110199
07:
OO
03/
08/
99
11
:43
03/
10/
99
1153
03/
10/
99
1156
03110199
12101
03/
09/
99
13:
14
03/
09/
99
1539
03/
10/
99
11:
23
03/
10199
08:
lO
03/
10/
99
09:
14
03l10199
09124
03110199
09:
29
03/
10/
99
09140
03/
10/
99
0957
03/
10/
99
09:
46
03/
10/
99
0951
03/
16/
99
12:
21
03/
16/
99
12~
24
03/
16/
99
12131
03/
16/
99
12145
03/
16/
99
12:
38
03110199
10:
21
0311
0199
10129
03110199
0750
03/
10/
99
07134
03110199
07:
43
03/
10/
99
08:
33
0311
0199
08143
03/
10/
99
08:
38
03/
09/
99
06:
15
03/
09/
99
06:
1
1
03/
09/
99
07:
18
03/
09/
99
07:
26
03/
09/
99
08:
03
03/
09/
99
07:
49
03/
09/
99
07%
03/
09/
99
0850
03/
09/
99
09:
OO
03/
09/
99
10145
03/
09/
99
I
I
:04
03/
09/
99
11:
14
03/
09/
99
10:
28
03/
09/
99
09:
49
03/
10/
99
10:
08
0311
0199
1
1
:36
03/
10/
99
12:
16
0311
0199
12:
20
0309l99
12:
45
03/
09/
99
13%
03/
09/
99
13:
48
03109199
14~
16
03/
09/
99
14:
02
03/
09/
99
13%
03/
09/
99
14110
03/
09/
99
13142
03108199
14107
03/
09/
99
Page
1
619.44
537.58
44.89
44.21
45.66
360.27
275.45
491.63
360.67
404.49
375.86
170.13
344.00
237.33
342.70
342.98
240.12
393.20
391.62
305.86
319.84
333.33
475.60
349.45
296.94
297.24
284.81
167.32
167.76
405.59
453.54
415.50
416.15
416.10
528.81
695.25
432.19
432.23
433.05
427.88
457.39
338.56
520.75
108.63
366.94
425.55
354.98
430.72
432.00
432.24
431.49
431.68
432.08
432.28
316.31
190.82
478.1
I
0.98
0.00
0.00
0.00
0.00
0.00
0.75
0.00
0.00
0.65
0.67
0.67
0.00
0.00
0.00
0.00
0.00
0.00
0.00
2.22
2.22
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.54
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
3.70
3.89
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
618.46
44.89
44.21
45.66
360.27
274.70
491
63
360.67
403.84
375.19
169.46
344.00
237.33
342.70
342.98
240.1
2
393.20
391.62
303.64
317.62
333.33
190.82
475.60
478.1
1
349.45
296.94
297.24
284.81
167.32
167.76
405.59
453.54
415.50
415.61
416.10
528.81
695.25
432.19
432.23
433.05
427.88
457.39
338.56
520.75
104.93
363.05
425.55
354.96
430.72
432.00
432.24
431.49
537.58
431.68
432.08
432.28
316.31
ia8.51
163.85
13.68
13.48
13.92
109.81
83.73
149.85
109.93
123.09
114.36
51.65
104.85
72.34
104.45
104.54
73.19
119.85
119.37
92.55
96.81
101.60
58.16
144.96
145.73
106.51
90.51
90.60
51.00
51.13
123.62
138.24
126.64
126.68
126.83
?61.18
211.91
131.73
131.74
131.99
130.42
139.41
103.19
158.72
31.98
110.66
129.71
108.19
131.67
131.75
131.52
131.58
131.70
131.76
96.41
86.81
131.28
3038.79
2999
52
3368.16
3368.66
3364.35
2968.1
1
3006.00
2974.41
3058.42
3006.26
3024.34
3230.07
3034.09
3141.13
3035.61
3035.43
3150.52
2996.83
2997.05
3086.37
3072.39
3000.02
3143.22
3030.64
3027.93
3156.59
3051.17
3051.01
3063.71
2996.85
2996.64
3027.40
2979.36
2991.18
2991.25
2991.20
3159.86
2994.22
2979.43
2979.41
2979.37
2983.01
2969.80
3008.55
2960.88
3301.84
3043.72
2959.76
3059.25
2987.66
2987.01
2986.85
2987.54
2986.95
2986.99
2986.71
51344.75
f
i
7
ORIGINAL
926.22
914.25
1026.62
1025.77
1025.45
904.68
916.23
906
60
932.21
916.31
921.82
984.53
924.79
957.42
925.25
925.20
960
.:
913
3
913
50
940.73
936.46
914.41
958.05
923.74
922.91
9c
9%.
,J
929.95
933.82
913.44
913.38
922.75
908.11
911.71
411.73
911.72
963.13
412.64
908.13
908.12
908.17
909.22
917
01
1W.
40
927.73
902.
f
3
432.46
910.64
970.44
910.39
410.60
910.42
910.35
9
1
D
"4
905.20
902.48
410.43
I
Report
Quarterly
WELL
NUMBER
Waterlevel
Measurements
For
MARCH
1999
ZONE
CASING
DATE
TIME
DEPTH
ADJUST
ADJUSTED
ADJUSTED
WATER
ELEVATION
ELEVATION
TO
LEVEL
IN
TO
DEPTH
DEPTH
ft
amsl
WATER
TOC
TOC
METERS
ELEVATION
METERS
P
IS
P
I
7
WIPP
I2
WIPP
13
WIPP
18
WIPP
I9
WIPP
21
WIPP
22
WIPP
25
(PIP)
WIPP
25
(ANNULUS)
WIPP
26
p
18
WIPP
27
(PIP)
WIPP
28
(PIP)
WIPP
29
WIPP
30
(PIP)
WQSP
I
WQSP
2
WQSP
3
WQSP
4
WQSP
5
w
a
s
p
4
WQSP
6a
CUL
cu
L
CUL
CUL
CUL
CUL
CUL
CUL
CUL
CUL
MAG
CUL
CUL
RUSlSAL
CUL
cu
L
CUL
CUL
CUL
CUL
CUL
CUL
DL
3311.38
3337.24
3478.42
3472.06
3405.71
34
58.76
3435.14
3418.96
3428.12
3214.39
3214.39
3153.20
3349.21
3429.05
3419.20
3463.90
3433.00
3384
40
3363
80
3364.70
3178
98
2978.26
3480.30
03/
09/
99
03/
09/
99
03/
09/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
08/
99
03/
10/
99
0311
0199
03/
10/
99
031
10199
0310a199
o~
oa199
15:
19
13:
OO
1O:
ll
13:
15
12:
12
1313
13:
OO
12:
30
1250
09:
15
09:
21
14:
30
06:
OO
08:
15
14:
58
08:
51
1349
11:
ll
13:
26
11:
Il
11:
02
1051
10:
55
Page
2
298.49
355.35
321.49
440
32
347.73
426.01
396.62
404.78
399.86
156.34
133.09
99'00
300.18
11.42
364.41
366.26
466.70
447.99
350.50
165.86
156.68
404.18
383.75
0
00
054
0
00
064
0
00
0
00
0
00
0
00
0
42
0
00
0
00
0
42
0
42
0
00
0
21
0
21
0
21
0
21
0
21
0
21
0
18
o
68
2
oa
298.49
354.81
320.81
440.32
347.09
426.04
396.62
404.78
399.86
155.92
156.68
133.09
299.76
11.42
362.33
366.05
403.97
466.49
383.54
350.29
165.68
98.58
447.78
40.98
108.15
134.21
105.79
129.85
123.38
121.88
47.52
47.76
40.57
30.05
91.37
3.48
110.44
111.57
123.13
142.19
136.48
116.90
106.77
50.50
97.78
120.89
3012
89
918
33
2982
43
909
04
3157
61
962
44
3031
74
924
07
3058
62
932
27
3032.75
924
38
3038
52
926
14
3014
18
918
72
3028
26
923
01
3058
47
932
22
3057
71
931
99
3020
l?
920
53
3080
4
0
938
91
3049
45
929
47
2966
BJ
90429
3066
72
934
74
3053
15
930
60
3059
93
932
67
301
3
8f
91861
2985
22
909
90
3000
86
914
68
3013
51
918
52
319902
975
06
ORIGINAL
WATERLEVEL
ELEVATION
UPDATE
MARCH
1999
WELL
ZONE
CASING
DATE
TIME
DEPTH
ADJUST
ADJUSTEC
ADJUSTED
WATER
~L
N
A
T
i
O
h
l
NUMBER
ELEVATION
TO
TO
DEPTH
DEPTH
LEVEL
IN
k
amsl
WATER
TOC
TOC
METERS
ELEVATION
METERS
AEC
7
AEC
7
AEC
7
AEC
7
AEC.
7
AEC
7
AEC.
7
AEC
7
AEC.
7
AEC
7
AEC
7
AEC
7
==
E==.===
=======
s========
E=======
=E=====
==
3657
25
0415'98
06
12
61904
0
9
8
3657
25
0513'98
06
00
61889
0
9
8
3657
25
07/
15/
98
10
52
61901
098
3657
25
08/
12/
98
06
23
61922
0
9
8
3657
25
09/
10,98
11
58
61924
098
3657
25
10114198
06
14
619
13
0
9
8
3657
25
1111
1/
98
09
30
61954
0
9
8
365725
12107'98
11
06
61932
0
9
8
3657
25
01/
13/
99
06
18
61952
0
9
8
365725
OUOBi99
1226
61949
098
365725
03/
10/
99
0700
61944
0
9
8
3657
25
06/
11/
98
0605
618
94
098
.
.
51806
18838
517
91
188
34
517.96
10035
618.03
108.38
518.24
188.44
518.15
18841
610.34
188.47
518.54
188.53
618.51
100
52
618.46
188.51
618.26
188.45
518.56
188.54
._____
._
3039
19
3039
34
3039.29
3039
22
3039.01
3038
99
3039.10
3038.91
3038.71
3038.73
3038
69
3038.74
a
926
35
926
3
9
926
35
926
29
926
2%
926
32
926
t9
926.26
926
20
926.21
926.22
926
3a
AEC
7.
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09110196
11y1
11/
11
12/
07
38
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l
K
6
9
O
y
W
:
DATE
PAGE
1
OF
80
WATERLEVEL
EtEVATION
UPDATE
MARCH
1999
WELL
ZONE
CASING
DATE
TIME
OEPTH
ADJUST
AOJUSTEC
ADJUSTED
WATER
ZLEVATION
NUMBER
ELEVATION
TO
TO
DEPTH
DEPTH
LEVEL
IN
f~
amsl
WATER
TOC
TOC
METERS
ELEVATION
METERS
AEC
8
AEC
8
AEC
8
AEC
8
AECd
AEC
8
AEC
8
AEC
8
AEC
8
AEC
8
AEC
8
AEC
8
BIC
BIC
BIC
B/
C
B/
C
BIC
BIC
BIC
BIC
BIC
BIC
81C
3537
10
3537
10
3537.10
3537.10
3537.10
3537.10
3537
10
3537.10
3537
10
3537.10
3537.10
2537.10
0411
5198
031
3/
98
0611
1/
98
07115198
0811
2/
98
09110198
10114i98
11/
09/
98
12107198
01113/
99
02/
08/
99
03/
08/
99
07
15
549
94
06.43
548
95
07
00
547.91
11:
18
546.66
07:
16
545.62
12:
21
544.54
07.02
543.27
11:
36
542.28
11:
36
540.74
06.52
539
70
12.02
538.61
11:
43
537
58
0
00
0
00
0
00
0
00
0
00
0
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0
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0
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0.00
0.00
0
00
0
00
549
94
548
95
547
91
546
66
545
62
544
54
543.27
540.74
539.70
538
61
537
58
542
2a
167
62
167
32
167
00
166
62
166
30
165
98
165.59
165
29
164.82
164
50
164.17
163.85
2987
15
2988.75
2989
19
2990.44
2991
40
2992
56
2993
03
2994
82
2996.36
2997.40
2998
49
2999.52
910
44
910
79
911.11
911.49
911
80
912.!
3
912
52
912.82
913.29
913.61
913.94
974.25
AEC
8.
BELL
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25
Groundwarer
level
Measurements
for
March
1999
i
______________~
______________
&ELL
NO
AEC
7
AEC
3
0;
c
3537
10
C
2505
SR
3413
05
C
2506
SR
3412.87
C
2507
SR
D
268
CUL
DOE
1
CUL
3466.04
DOE
2
CUL
3419
09
ERDA
9
H
a
l
(PIP)
H42a
CUL
3378
09
HU2bl
H02b2
CUL
H42c
CUL
3378.41
H43bl
H43b2
CUL
3390.03
H03d/
49
(PIP)
49ER
3390.01
H43d/
DL
{PVC)
/
DL
HU4b
CUL
Hd4c
HdSa
CUL
Hd5b
CUL
3506
04
H45c
Hd6a
CUL
3348.11
H46b
CUL
H46c
MAG
334852
H47bl
CUL
H47b2
3164.40
H48a
H48c
H49a
CUL
3406
68
H49b
CUL
H09c
CUL
3407
30
H
loa
H
lob
CUL
H
11
b
l
CUL
H
1
1
b2
CUL
3411
64
H
11
b3
CUL
H
l
l
M
CUL
3410
89
H
12
CUL
H
14
CUL
H
15
CUL
C6
1
CUL
3328
39
/
H
Ol
(ANNULUS)
/
H
03b3
,
CUL
H
16
(PVC)
/
DL
H
16
(PIP)/
ULM
34m.
77
H
17
CUL
335.31
H
18
CUC
3059
25/
H
19b0
CUL
H
19b2
CUL
2987.011
H
19b3
CUL
H
19M
CUL
H
19b5
CUL
H
19b6
CUL
H
19b7
CUL
3418.99
P
14
CUL
3361
06
P
15
CUL
P
17
CUL
P
18
CUL
WIPP
12
CUL
WIPP
13
CUL
905.7
1
WIPP
18
CUL
WIPP
19
CUL
WIPP
21
CUL
WIPP
22
WIPP
25
(PIP)
3058.47
.
.
MSL
M
926
22.
914
25,
'
1026
62/
1026
77/
1025
4
5
/
904
6
8
/
916
23/
906
60/
957
42/
925
2
5
/
925
20/
960
28/
940
7
3
/
4
5
8
0
4
922
9
d
930
oo/
929
9
5
/
936
jd
914
4
4
923
74f
962
1w
933
82/
913
d
913
38/
922
7
4
908
11/
911
71/
911
73
911
72'
908
1
2
/
908
11/
909
2
2
1
905
9170l/
902
4a/
1006
d
932
4&/
410
44
910
39/
910
60
910
6
4
1
910
4
2
/
909
0
4
1
962
44/
924
07/
918
72
923
O
J
432
2
2
1
WIPP
25
(ANNULUS)
/'
WiPP
26
WIPP
27
(PIP)
/
WiPP
29
"PP
30
(PIP)
`wasp
i
wasp
2
wasp
3
wasp4
wOSP
6a
ViQSP
5
`rVQSP
6
h4AG
CUL
CUL
RUS
SAL
CUL
cuc
CUL
CUL
CUL
CUL
CUC
cui
DL
3211.39
3153
20
3249
21
2978
26
3
2
9
05
3419.20
3463.90
3590
30
w
3
00
3384.40
3363
80
3364
70
3178
98
03/
08/
99`
13.49/
03/
08/
96
11.1
1/
0
3
0
6
1
9
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d
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11.11/
03/
10/
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03m99
10.55/
03i10196
11
0
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156.68/
1
3
3
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9
I
1
42/
266
26/
34
18/
4
6
6
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9
364
4
J
350.50
1
6
5
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0
o
d
0
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0
4
2
5
5
2
0
8
1
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4
2
1
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2
1
1
0
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O
.t
l
/
0.18/
1
5
6
.6
4
299.7
447.7
165.68
3080
40
3024.45
/
3054
93
/
2986.84/
3066.72
/
3053.
TS
f
3013
81
/
301331/
3199.02/
CHECKPRINT
AEC
I
AEC
7
AEC
T
AEG?
AEC
7
AEGt
AEC
T
AEC
7
AEC
7
AECI
AEC
7
nEG7
CUL
CUL
CUL
CUL
CUL
CUL
CUL
CUL
CUL
CUL
CUL
CUL
3657
25
3657
25
3657.25
3657.25
3657
25
3657
25
3657
25
3657
25
3657
25
3657.25
3657.25
3657
25
04/
15198
031
398
0611
1/
90
07115198
08112l98
09l10198
10114198
1
Ill
1198
lrn7198
Oll1359
02/
08/
99
Q3110/
99
06.12
06.00
06.05
1052
06~
23
11.58
06'14
0930
11.06
06:
10
r2:
zs
07
W
619
04
6:
8.89
618.94
619.01
619.22
619.24
619.13
619
54
619.32
619.52
619.49
619.44
0.98
0
98
0
98
0.98
0.98
0
98
0
98
0
98
0
98
0.98
0.98
0.98
618
06
617
91
61
7.96
618
03
618
24
618
26
618
15
618
56
618.34
618.54
618.51
61846
188.38
3039.19
18834
303934
188.35
3039.29
188
30
303922
188.44
3039.01
18845
303899
188
41
3039.10
18854
3038.69
18847
30Jg.
91
188.53
3038.7l
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.
3x230
PAGE
2
OF
80
Waste
Isolation
Pilot
Plant
Annual
Site
Environmental
Report
Calendar
Year
1997
DOEIWIPP
98
2225
Issue
Date:
September
29,
1998
1997
Annual
Site
Environmental
Report
DOElWlPP
98
2225
TABLE
OF
CONTENTS
LIST
OF
TABLES
iii
)
..........................................................
LIST
OF
FIGURES
.........................................................
iv
ACRONYMSAND
ABBREVIATIONS
...........................................
xi
3
W
CHAPTER
1
EXECUTIVE
SUMMARY
........................................
1
1
1.1
Compliance
Summary
..........................................
1
2
1.1.1
National
Environmental
Policy
Act
Annual
Mitigation
Report
.......
1
2
1.1.2
Superfund
Amendments
and
Reauthorization
Act
Title
I
l
l
Emergency
and
Hazardous
Chemical
Inventory
................
1
2
1
.
1.3
New
Mexico
Air
Quality
...................................
1
2
1
.
1.4
Environmental
Compliance
Assessments
.....................
4
3
1.1.5
IS0
14001
Environmental
Management
Systems
...............
13
1
.
1.6
Voluntary
Release
Assessment
Program
at
Selected
Solid
Waste
Management
Units
at
WlPP
................................
1
3
1.1.7
Federal
Acquisition,
Recycling,
and
Waste
Prevention
...........
1
3
Environmental
Monitoring
Program
Information
.......................
1
4
1.2.
I
Environmental
Monitoring
Plan
.............................
14
Environmental
Radiological
Program
Information
.....................
1
4
1.3.1
Airborne
Particulate
Sampling
..............................
1
5
1.3.2
Soil
Sampling
...........................................
1
5
1.3.3
Groundwater
...........................................
?a
1.3.4
Surface
Water
and
Sediment
Sampling
.......................
1
6
1.3.5
Biotic
Sampling
.........................................
1
7
Nonradiological
Environmental
Monitoring
Information
.................
$
7
1.4.1
Land
Management
.......................................
1
8
1.4.2
Meteorology
............................................
1
8
1.4.3
Wildlife
Population
Monitoring
..............................
1
8
1.4.4
Reclamation
of
Disturbed
Lands
............................
?
9
1.5
QualityAsscnrance
............................................
1
10
1.2
1.3
1.4
CHAPTER2
INTRODUCTION
..............................................
2
1
Description
of
the
WlPP
Project
...................................
2
1
WlPP
Property
Areas
.....................................
2
2
Demographics
Within
the
Affected
Environment
................
2
3
2.1
2.1.1
2.1.2
CHAPTER
3
COMPLIANCE
SUMMARY
......................................
3
1
3.1
Compliance
Overview
..........................................
3
1
Statutes
and
Regulations
Applicable
to
WlPP
........................
3
1
3.3
Compliance
Status
.............................................
3
2
Liability
Act
.............................................
3
2
3.3.2
Federal
Acquisition.
Recycling.
and
Pollution
Prevention
.........
3
3
Resource
Conservation
and
Recovery
Act
.....................
3
3
National
Environmental
Policy
Act
...........................
3
5
3.3.5
Clean
Air
Act
...........................................
3
6
3.3.6
Clean
Water
Act
....................................
..
.
3
8
Safe
Drinking
Water
Act
...................................
3
9
National
Historic
Preservation
Act
..........................
3
10
3.3.9
Hazardous
Materials
Transportation
Act
.....................
3
72
3.3.10
Packaging
and
Transportation
of
Radioactive
Materials
.........
3
13
3.2
3.3.1
Comprehensive
Environmental
Response.
Compensation.
and
3.3.3
3.3.4
3.3.7
3.3.8
1997
Annual
Site
Environmental
Report
DOEMliPP
98
2225
3.4
Other
Significant
Accomplishments
and
Ongoing
Compliance
Activities
...
3
14
3.4.1
Environmental
Compliance
Assessment
Program
..............
3
14
3.4.2
Site
Environmental
Management
Program
....................
3
15
3.4.3
IS0
14000
Standards
for
Environmental
Management
.........
3
15
3.4.4
Pollution
Prevention
Committee
............................
3
16
3.4.5
Environmental
Training
..................................
3
17
CHAPTER
4
ENVIRONMENTAL
PROGRAM
INFORMATION
......................
4
1
4.1
Environmental
Monitoring
Plan
...................................
4
1
4.2
Baseline
Data
................................................
4
1
4.3
Land
Management
Programs
....................................
4
2
4.3.1
Land
Management
and
Environmental
Compliance
..............
4
3
4.3.2
Wildlife
Population
Monitoring
..............................
4
3
4.3.3
Reclamation
of
Disturbed
Lands
............................
4
6
4.3.4
Oil
and
Gas
Surveillance
..................................
4
7
CHAPTER
5
5.1
5.2
5.3
5.4
5.5
5.6
5.7
5.8
ENVIRONMENTAL
RADIOLOGICAL
ASSESSMENT
..................
5
1
Airborne
Gross
AlphalBeta
......................................
5
1
Airborne
Particulate
...........................................
5
18
SoilSamples
................................................
5
32
Surface
Water
...............................................
5
43
Groundwater
...............................................
5
56
Sediments
..................................................
5
56
Biota
......................................................
5
68
Trend
Analyses
..............................................
5
77
CHAPTER
6
ENVIRONMENTAL
NONRADIOCOGICAL
PROGRAM
INFORMATION
....
6
1
6.1
Principal
Functions
of
Nonradiological
Sampling
......................
6
1
6.2
Meteorology
..................................................
6
1
6.2.1
Climatic
Data
...........................................
6
1
6.2.2
Wind
Direction
and
Wind
Speed
............................
6
2
Volatile
Organic
Compounds
Monitoring
............................
6
2
6.4
Seismic
Activity
...............................................
6
7
6.5
Liquid
Effluent
Monitoring
.......................................
6
7
6.3
CHAPTER
7
GROUNDWATER
PROTECTION
.................................
7
1
CHAPTER
8
QUALITY
ASSURANCE
......................................
..
.
8
1
8.1
Sample
Collection
Methodologies
..............
..................
8
1
Revision
of
Procedures
.........................................
8
2
8.3
interlaboratory
Comparisons
.....................................
8
2
Analytical
Laboratory
Quality
Assurance
and
Quality
Control
............
8
7
8.5
Data
Handling
................................................
8
7
8.6
Records
Management
...........................................
8
7
CHAPTER9
REFERENCES
...............................................
9
1
8.2
8.4
APPENDIX
A
.
LOCATION
CODES
...........................................
A
1
APPENDIX
B
.
CONCENTRATIONS
OF
ALPHA
AND
BETA
ACTIVITIES
IN
AIR
PARTICULATE
..............................................
B
1
a
ii
1997
Annual
Site
Environmental
Report
DOWJPP
98
2225
CHAPTER
7
GROUNDWATER
PROTECTION
Current
groundwater
monitoring
activities
at
WIPP
are
outlined
in
the
Groundwater
Monitoring
Program
Plan
and
Procedure
Manual
(WP
02
1,
Revision
3).
The
plan
is
a
QA
document
that
contains
program
plans
for
each
of
the
activities
performed
by
ground
water
monitoring
personnel.
In
addition,
WP
02
1
provides
detailed
pr
dures
for
performing
specific
activities
such
as
pumping
system
installations,
fiqfjfparameter
analyses
and
documentation,
and
QA
records
manage
ment.
Groundwater
monitoring
activities
are
also
defined
in
the
EMP.
The
objective
of
the
groundwater
monitoring
program
is
to
determine
the
physical
and
chemical
characteristics
of
groundwater;
maintain
surveillance
of
groundwater
levels
surrounding
the
WiPP
facility,
both
before
and
throughout
the
operational
lifetime
of
the
facility;
and
futfili
the
requirements
of
the
RCRA
Part
B
permit
application
and
DOE
Order
5400.1.
Background
water
quality
data
were
collected
from
1985
through
the
1990
sampling
period
to
futfill
the
requirements
of
DOE
Order
5400.
A
as
reported
in
DOENVIPP
92
013,
"Background
Water
Quality
Characterization
Report
for
the
Waste
Isolation
Pilot
Plant"
In
the
latter
part
of
1994
seven
new
wells
were
drilled
(Figures
7.5
through
7.11)
in
anticipation
of
the
RCRA
permitting
process.
Background
data
were
collected
from
these
wells
from
1995
through
1997
and
reported
in
DOUWIPP
98
2285,
Waste
isolation
Pilot
Plant
RCRA
Background
Groundwater
Quality
Baseline
Report."
This
background
data
will
be
compared
to
water
quality
data
collected
throughout
the
opera
tional
life
of
the
facility.
Preoperational
data
gathered
in
the
interim
period
will
be
used
to
strengthen
the
background
data,
to
evaluate
the
need
to
make
adjustments
to
comparison
criteria,
and
to
determine
future
regulatory
needs
and
land
use
decisions.
The
data
obtained
by
the
WQSP
in
1997
supported
two
major
programs
at
WIPP:
(1)
the
Groundwater
Monitoring
Program.
in
compliance
with
40
CFR
Q
264
and
(2)
perfQrmance
assessment
in
compliance
with
4f&
FR
§
'IS%
Each
of
these
programs
requiresa'
unique
set
of
analyses
and
data.
Particular
sample
needs
are
defined
by
each
pr
m.
In
addition
to
the
characterization
of
grounhater,
the
WQSP
supported
radio
nuclide
monitoring
for
the
WID
Environmental
Analysis
and
Compliance
Section.
Results
of
radionuclide
sampling
are
discussed
in
Chapter
5.
Representatives
from
the
EEG
were
on
hand
at
selected
sampling
events
to
collect
samples
for
independent
evaluation.
The
WIPP
site
lies
within
the
Pews
Valley
section
of
the
Southern
Great
Plains
physiographic
province
(Powers
et
at.,
1978).
Geologic
and
lithologic
descn'ptions
of
the
area
surrounding
the
site
can
be
found
in
documents
such
as
the
EMP,
the
Groundwater
Protection
Management
Program
Plan
(DOENVIPP
96
2162),
and
USGS
83
4016
(Mercer,
1983).
'Industries
in
the
vicinity
that
could
potentially
contribute
to
the
pollution
of
the
groundwater
are
potash
mining,
oil
and
gas
explorationlproduction,
and
agriculture.
The
Culebra
is
the
most
significant
water
bearing
unit
within
the
vicinity
of
WIPP.
No
known
hydrologic
connection
exists
between
the
repository
horizon
and
the
Culebra.
Surveillance
of
hydrological
characteristics
in
the
Culebra
provides
data
that
can
be
used
to
detect
changes
in
water
characterization.
It
also
provides
additional
data
for
use
in
hydra
logic
models
designed
to
predict
long
term
performance
of
the
repository.
Groundwater
surface
elevation
data
is
gathered
from
77
well
bores;
five
of
which
are
equipped
with
production
inflated
packers
to
allow
groundwater
level
surveillance
of
more
than
one
producing
zone
through
the
same
well
bore
(Figure
7.2).
Groundwater
quality
data
were
gathered
from
six
wells
completed
in
the
Culebra
member
o
f
the
Rustler
formation
and
one
well
completed
in
the
Dewey
Lake
formation
(Figure
7.1).
The
1997
Annual
Site
Environmental
Report
DOEMliPP
98
2225
water
quality
sampling
process
has
been
developed
using
logistics
from
groundwater
wells
originally
constwcted
for
characterization,
not
intended
for
groundwater
monitoring
activities.
Seven
wells
were
drilled
in
the
latter
part
of
1994
constructed
for
the
explicit
purpose
of
gathering
water
quality
data.
Thesgwells
are
constructed
with
fiberglass
casing
and
screens
that
will
not
bias
sample
collection.
Similar
sampling
protocols
to
those
used
in
the
past
for
wells
drilled
for
resource
evaluation
and
site
geologic
characterization
were
used
through
CY
1997.
More
effiaent
sampling
methods
are
being
evaluated
and
should
be
phased
in
during
CY
1998.
Sampling
episodes
are
referred
to
as
a
"sampling
round."
Each
sampling
round
con
sists
of
the
collection
of
two
types
of
samples:
(1)
serial
samples
and
(2)
final
samples.
Serial
samples
are
taken
periodically
while
the
well
is
being
purged.
Key
physical
and
chemical
parameters
(known
as
field
parameters)
are
analyzed
and
compared
with
past
serial
sampling
data,
when
available,
until
a
chemical
steady
state
has
been
reached.
A
chemical
steady
state
is
defined
as
f
5
percent
of
the
average
of
the
three
to
five
preceding
para
meter
measurements
made
on
the
final
day
of
serial
sampling
from
preceding
sampling
rounds.
Stabilition
of
these
field
parameters
is
a
function
of
purging
and
is
used
as
an
indi
cator
to
determine
if
the
groundwater
is
representative
of
the
zona,
bdng
sampled.
A
%a1
sample
is
collected
when
it
has
been
determined
that
the
pumped
groundwater
has
achieved
a
representative
state.
The
sample
is
then
sent
off
site
to
a
contract
laboratory
for
analysis.
Groundwater
monitoring
activities
during
CY
1997
included
Groundwater
Quality
Sampling
and
Groundwater
Level
Surveillance.
Groundwater
Qualitv
SamDling
Sampling
for
groundwater
quality
was
performed
semiannually
at
seven
well
sites
during
CY
1997
(Figure
7.1).
The
wells
were
7
2
serially
sampled
as
soon
as
possible
after
the
pump
was
turned
on
to
better
observe
early
chemical
reactions
to
pumping.
Field
analysis
for
Eh,
pH,
specific
gravity,
specific
conduc
tance,
alkalinity,
chloride,
divalent
cations,
and
total
iron
were
performed
on
a
periodic
basis
during
the
serial
sampling.
These
field
para
meters
were
used
as
indicators,
during
the
purging
process
to
better
determine
when
the
fonation
water
being
pumped
had
reached
a
representative
state.
Normally
this
process
&
quired
four
to
seven
days
to
complete.
Following
the
field
analysis
of
the
final
serial
sample,
samples
were
cokcted
and
shipped
to
an
independent,
contracted,
laboratory
for
analysis.
Parameters
of
art.
alysis
by
the
contracted
laboratory
include
the
groundwater
monitoring
list
in
Appendix
IX
of
40
CFR
Q
264
and
those
indicator
parameters
wmrnon
to
the
Culebra
member
of
the
Rustler
as
listed
in
Table
7.1.
WlPP
has
not
received
waste;
thekfore
no
hazardous
constituent
has
been
introduced
to
the
environment
as
a
result
of
WIPP
opera
tions.
Data
collected
provide
background
information.
The
total
gallons
of
water
removed
from
the
Culebra
as
a
resutt
of
groundwater
surveillance
activity
was
approximately
44,318
gallons
throughout
the
year.
During
the
same
period
10,962
gallons
of
water
were
removed
from
the
Dewey
lake
formation.
Water
quality
of
the
Culebra
sampled
near
WlPP
is
naturally
poor
and
is
not
suitable
for
human
consumption
or
for
agricultural
purposes.
The
groundwater
of
the
Culebra
is
considered
to
be
class
Ill
waters
by
€PA
guidelines.
The
water
contains
naturally
high
concentrations
of
total
dissolved
solids
and
mineral
constituents
primarily
of
chloride,
calcium,
magnesium,
sodium
and
potassium
(Mercer,
1983).
The
high
total
of
dissolved
solids
concentration
has
historically
posed
problems
for
laboratories
performing
analysis
because
the
water
interferes
with
the
normal
operation
of
standard
laboratory
equip
ment
such
as
Atomic
Absorption
or
Inductively
Coupled
Plasma,
causing
estimated
quantitation
limits
to
be
inconsistent.
1997
Annual
Site
Environmental
Report
DOEMIIPP
98
2225
Water
quality
measurements
performed
in
the
Dewey
Lake
fotmation
indicate
that
the
waters
are
considerably
fresher.
Samples
collected
from
the
Dewey
Lake
formation
are
suitable
for
livestock
consumption
having
TDS
values
below
10,000
mg/
L.
These
waters
are
classi
fied
as
Class
II
waters
according
to
€PA
Guidance.
Saturation
of
the
Dewey
Lake
Formation
in
the
area
of
WlPP
is
discontinuous
and
no
hydrologic
connection
has
been
established
that
would
indicate
that
WIPP
activities
would
have
an
Impact
on
the
Dewey
Lake.
Sampling
during
calendar
year
1997
marked
the
end
of
data
collection
for
baseline
purposes
for
the
RCRA
permitting
process.
A
detailed
baseline
report
entitled
'Waste
Isolation
Pilot
Plant
RCRA
Background
Groundwater
Quality
Report"
was
issued
just
prior
to
the
Issuance
of
the
1997
ASER.
To
summarize;
this
report
contains
calculated
background
concentrations
for
groundwater
quality
parameters
from
seven
monitoring
wells
that
are
located
within
the
boundaries
of
the
WlPP
site.
From
1995
to
1997,
the
GMP
collected
groundwater
samples
from
the
Culebra
and
Dewey
Lake
water
bearing
zones
in
the
area
of
the
WIPP
site.
The
GMP
has
sampled
7
WlPP
monitoring
wells
five
separate
times.
Groundwater
was
sampled
during
the
GMP
from
the
Culebra
Dolomite
Member
of
the
Rustler
Formation
and
the
Dewey
Lake.
The
GMP
focused
primarily
on
the
characteriation
of
Culebra
Dolomite
groundwater,
since
the
Culebra
is
the
first
continuous
water
bearing
zone
above
the
waste
repository
horizon
and
is
the
most
transmissive
hydrologic
unit
in
the
WlPP
area.
Because
Culebra
groundwater
chemistry
is
extremely
variable
across
the
WIPP
site,
areawide
background
values
for
groundwater
constituents
could
not
be
established.
Instead,
background
groundwater
quality
was
defined
for
each
individual
well.
A
minimum
of
four
separate
rounds
of
data
from
a
well
was
required
to
establish
the
background
ground
water
quality
at
that
well.
Preliminary
analysis
categorized
GMP
data
into
three
groups
based
on
the
frequency
of
detection
and
the
proximity
of
detections
to
MDLs.
The
three
groups
are
as
follows:
Major
Cations
and
Anions.
Constituents
that
collectively
make
up
greater
than
99
percent
of
the
dissolved
solids.
These
constituents
are
generatly
detected
at
concentrations
that
are
well
above
the
MOL.
Minor
Cations,
Trace
Metals,
Anions,
and
Indicator
Parameters.
Constituents
with
concentrations
that
are
generally
less
than
10
mglL
in
groundwater.
A
substantial
amount
of
the
data
are
below
the
MDL,
and
those
detected
concentrations
are
generally
close
to
the
MDL.
Organic
Compounds.
Include
VOCs,
SVOCs,
pesticides,
and
PCBs
(all
of
the
parameters
induded
in
40
CFR
5
264,
Appendix
IX).
Very
few
detections
of
these
compounds
were
observed
in
GMP
data.
Given
the
three
data
groups
defined
above,
background
concentrations
were
determined
and
reported
in
the
following
manner:
A
95th
UTL
or
95th
percentile
confidence
interval
based
on
the
distribution
type
was
computed
for
every
major
constituent
from
each
well.
Thus,
the
expected
background
concentration
for
a
major
constituent
at
a
given
well
is
represented
by
a
95
percent
confidence
intewal.
The
95th
UTL
for
most
minor
constituents
could
not
be
calculated
due
to
the
large
number
of
NDs;
thus,
the
background
concentration
range
for
a
minor
constituent
at
a
given
well
is
represented
by
the
observed
95th
percentile
concentration
range
based
on
MDLs
for
that
parameter
at
that
well.
Prior
to
the
determination
of
background
concentration
values,
the
GMP
data
were
evaluated
for
trends.
Trend
analysis
was
necessary
to
determine
if
any
concentrations
7
3
1997
Annual
Site
Environmental
Report
DOEMllPP
98
2225
were
changing
with
time
due
to
natural
(or
non
WlPP
related)
causes.
The
procedure
used
to
determine
background
water
quality
is
depen
dent
on,
or
somewhat
controlled
by,
the
natura
of
the
concentration/
time
relationship.
In
general,
temporal
trends
in
concentrations
were
not
found
in
#$
e
GMP
data,
and
the
procedure
used
to
establish
background
water
quality
reflected
this
finding.
I
Additional
sampling
rounds
at
each
GMP
well
may
provide
more
insight
into
potentiat
trends
in
water
quality.
The
GMP
data
were
also
evaluated
for
potential
outliers.
Potential
outliers
were
evaiuated
through
visual
examination
only.
If
a
value
appeared
to
be
an
outlier
by
visual
examination,
an
additional
observation
was
performed
to
estimate
if
that
value
was
within
G
O
percent
of
its
nearest
neighbor
or
if
it
was
due
to
routine
analytical
uncertainty.
Only
four
values
were
actually
excluded
from
the
major
and
minor
constituent
data
set
prior
to
the
establishment
of
background
concentration
summary
statistics
and
box
and
whisker
plots
{Figures
7.12
through
7.72).
The
following
are
the
specific
findings
and
conclusions
of
the
baseline
study:
Some
constituents
at
several
wells,
including
WQSP
1,
WQSP
2,
WQSP
3,
WQSP
5,
WQ8P
6,
and
WQSP
GA
show
potential
concentration
trends
However,
in
almost
every
case
the
trend
is
within
the
range
of
expected
analytical
uncertainty,
or
the
trend
is
not
supported
by
charge
balance
considerations
or
by
similar
trends
in
other
constituents,
such
as
TDS.
9
Wells
WQSP
4,
WQSP
5,
and
WQSP
6
exhibit
concentrations
of
several
para
meters
that
decrease
significantly
from
the
first
to
the
second
or
later
sampling
rounds.
This
may
indicate
that
the
first
sample
is
not
representative,
possibly
due
to
incomplete
well
development
and
that
the
wells
are
"cleaning
up"
from
the
initial
well
installation
process.
Background
groundwater
quality
was
successfully
defined
for
seven
wells.
Back
ground
concentrations
for
major
and
minor
cations,
anions,
and
indicator
parameters
were
e@
blished
for
Culebra
Dolomite
and
Dewey
Lake
groundwater.
Although
the
background
concentrations
of
many
minor
constituents
are
uncertain,
the
baseline
report
documents
the
"expected"
values
for
these
constituents,
if
similar
analytical
tech
niques
are
used
in
future
sampling
efforts.
Hazardous
organic
compounds
are
not
present
in
groundwater
in
the
vicinity
of
the
WlPP
site.
Detections
of
these
compounds
are
very
infrequent,
and
the
majority
of
detected
compounds
are
typical
laboratory
contaminants
as
defined
by
the
EPA.
Some
of
the
occurrences
may
also
be
related
to
well
installation
or
sampling
practices.
Specific
details
on
statistical
methods
and
formulas
used
to
reach
these
conclusions
can
be
found
in
DOEMllPP
98
2285,
"Waste
Isolation
Pilot
Plant
RCRA
Background
Groundwater
Quality
Base
line
Report."
Groundwater
Level
Surveillance
In
October
1988,
WlPP
was
tasked
with
conducting
a
groundwater
level
surveillance
program.
Seventy
seven
well
bores
are
used
to
perform
surveillance
of
seven
water
bearing
zones
in
the
WlPP
area.
The
two
zones
of
primary
interest
are
the
Culebra
and
Magenta
members
of
the
Rustler
formation.
Fifty
nine
measurements
are
taken
in
the
Culebra;
and
ten,
in
the
Magenta.
Three
measurements
each
are
taken
in
the
Dewey
Lake
and
Santa
Rosa
formations.
Two
measurements
are
taken
in
the
Rustler/
Salado
contact.
One
measurement
each
is
taken
in
Bell
Canyon,
Forty
niner,
and
an
unnamed
lower
member.
Locatiort&
of
groundwater
level
surveillance
sites
arszictured
in
Figure
7.2.
Five
well
bores
are
configured
to
allow
monitor
ing
of
more
than
one
formation.
These
are
H
01
CulebralMagenta,
H
03d
Dewey
Lake/
Forty
niner,
H
16
Dewey
Lakehnnamed
lower
7
4
1997
Annual
Site
Environmental
Report
DOElWtPP
98
2225
member,
WIPP
25
CulebralMagenta,
and
WIPP
27
CulebralMagenta.
Groundwater
surface
elevations
in
the
vicinity
of
WlPP
may
be
influenced
by
site
activities
such
as
pumping
tests
for
site
characterization,
water
quality
sampling,
or
shaft
sealing.
Other
influences
on
groundwater
surface
elevations
may
be
caused
by
natural
groundwater
level
fluctuations
and
industrial
influences
from
agriculture,
mining,
and
resource
exploration.
Groundwater
elevation
measurements
in
the
Culebra
indicate
that
the
generalized
directional
flow
of
groundwater
is
north
to
south
in
the
vicinity
of
WIPP
(Figure
7.3).
Regional
groundwater
levels
taken
'
in
43
Culebra
observation
wells
with
more
than
four
data
points
for
the
year
show
increases
in
water
levels
occurred
in
26
wells
and
17
wells
showed
a
decrease
in
water
levels
over
the
period
of
January
1997
through
December
1997.
During
this
period
23
wells
had
net
water
level
increases
or
decreases
of
less
than
one
foot
Total
fluctuation
of
more
than
one
foot
in
groundwater
levels
occurred
in
33
of
the
wells.
Nine
wells
with
fluctuations
of
more
than
one
foot
(WQSP
1
through
WQSP
6,
H
19b0,
H
18,
and
H
14)
may
have
been
influenced
by
groundwater
quality
sampling
activities.
Four
wells
(ERDA
[United
States
Energy
Research
and
Development
Administration]
9,
WIPP
18,
WIPP
19,
WIPP
21,
and
WIPP
22)
may
have
been
influenced
by
site
activities.
Water
level
increases
originating
to
the
south
of
the
site
in
the
H
9
area
and
extending
up
gradient
toward
the
site
are
currently
unexplained.
Studies
are
currently
being
conducted
to
try
and
explain
the
anomalies.
Groundwater
flow
directions
in'
the
Magenta
appear
to
be
generally
from
an
east
to
west
direction
across
the
WIPP
site
(Figure
7.4).
Regional
groundwater
level
measurements
taken
in
the
Magenta
dolomite
indicate
that
water
levels
are
increasing
in
wells
located
near
the
center
of
the
site,
while
water
levels
near
or
outside
the
WlPP
boundary
appear
to
be
relatively
stable.
One
well
H
01
has
had
anomalus
water
level
increases
and
appears
to
be
influencing
the
wells
in
the
immediate
vicinity
(H
2bl
and
H
3bl).
The
cause
is
as
yet
undetermined.
7
5
1997
Annual
Site
Environmental
Report
DOEMllPP
98
2225
'
A
N
Figure
7.1
Water
Quality
Sampling
Program
Sample
Wells
1997
7
6
Attachment
D.
3
Waste
Activity
Documents
Reviewed
c
.
Effective
Date:
o
m
5197
WP
05
WA.
02
Revision
0
WIPP
Waste
Information
System
Program
Cognizant
Section:
Waste
Operations
Approved
By:
Cognizant
Department:
Operations
Approved
By:
Jeff
Cotton
Signature
on
file
C.
E.
Conway
Signature
on
file
WlPP
Waste
information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
TABLE
OF
CONTENTS
ACRONYMS
AND
ABBREVIATIONS
.............................................................................
iii
1
.O
lNTRODUCTlON
....................................................................................................
1
2.0
SCOPE
...................................................................................................................
1
3.0
RESPONSIBILITIES
...............................................................................................
2
3.1
Waste
Operations
..........................................................................................
2
Resource
Conservation
and
Recoverv
Act
Permittinq
...................................
4
Qualitv
and
Rewlatorv
Assurance
................................................................
4
Proiect
Record
Services
.................................................................................
4
h
lformation
Svstems
Development
................................................................
4
3.6
Technical
Traininq
.........................................................................................
5
TRU
waste
Proqrams
....................................................................................
5
Department
of
Enercrv/
Car~
sbad
Area
Office..
................................................
5
3.2
3.3
3.4
3.5
3.7
3.8
4.0
ACCESS
......................................................................................................
5
4.1
User
Access
...................................................................................................
6
5.0
W
l
S
COMPONENT?
...........................................................................................
6
5.1
Administration
................................................................................................
7
5.1
.1
Administrative
Tables
..........................................................................
7
5.1
2
User
Administration
.............................................................................
7
5.1.3
Data
~~~i
n
i
s
t
r
a
t
i
o
n
.............................................................................
7
5.1
4
Security
................................................................................................
7
5.2
Characterization
Module
................................................................................
8
5.3
Certification
Module
.......................................................................................
8
5.4
Shippino
Module
............................................................................................
9
5.5
hventorV
Module
...........................................................................................
9
6.0
US"
THE
9
6.1
Electronic
Data
Entrv
Characterization
Module
...........................................
9
6.2
Database
Use
in
APProvinQ
the
WSPF
............................................
10
6.3
Manual
Data
Entrv
Characterization
Module
.............................................
11
6.4
Review
and
Approval
of
Characterization
Data
Entries
...............................
11
6.5
Electronic
Data
Entw
Certification
Module
................................................
11
6.6
Manual
Data
Entrv
Certification
Module
....................................................
12
6.7
Review
and
Approval
of
Certification
Data
Entries
......................................
12
6.8
Electronic
Data
Entw
ShiPPinq
Module
.....................................................
12
6.9
Manual
Data
EntrV
ShiPPina
Module
.........................................................
13
6.10
Review
and
Approval
of
Shippina
Data
Entries
...........................................
13
6.1
1
Shipment
Receipt
Data
................................................................................
13
6.12
Barcode
Data
Check
of
Shipment
Received
Containers
...........................
13
6.13
Shipment
Approval
.......................................................................................
14
6.14
Recordins
Overpack
Information
.................................................................
14
.................................................................................................
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
6.1
5
Barcode
Data
Entry
Location
of
DrumlAssemblies
....................................
15
6.1
6
Container
Disposal
Data
..............................................................................
15
7.0
SETTING
UP
OTHER
SITES
TO
USE
THE
WWlS
..............................................
15
8.0
EXCEPTIONS
AND
UNRESOLVED
SAFETY
QUESTION
DETERMINATIONS..
16
9.0
DATA
CHANGE
CONTROL
17
..................................................................................
10.0
W
l
S
PROGRAM
REPORTS
17
17
I
O
.
1
Printing
Standardized
Reports
.....................................................................
38
10.2
Shipment
Summaw
Report
~
.........................................................................
10.3
Nuclide
Report
18
18
10.4
Waste
Emplacement
Report
........................................................................
10.5
Headspace
Gas
Concentration
Report
........................................................
18
19
10.6
Requlatow
Reporting:
Biennial
Reporting
Input
Report
..............................
..............................................................................
.............................................................................................
11
.O
W
l
S
PROGRAM
RECORDS
19
19
11
.I
Backup
and
Archivins
Requirements
...........................................................
.............................................................................
12.0
SITE
DERIVED
WASTE
29
........................................................................................
13.0
TRAINING
FOR
THE
WWlS
PROGRAM
20
.............................................................
14.0
REFERENCES
20
......................................................................................................
Attachment
1
WWlS
Access
Request
Form
22
................................................................
23
Attachment
2
WWlS
User
Access
Authorization
Levels
.............................................
24
Attachment
3
WWlS
Access
Notification
Form
...........................................................
Attachment
4
Shipping
Review
of
Cellulose,
Plastics
and
Rubber
.............................
25
iii
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
ACRONYMS
AND
ABBREVlATlONS
CAO
Carlsbad
Area
Office
CFR
Code
of
Federal
Regulations
DOE
Department
of
Energy
EPA
Environmental
Protection
Agency
ID
Identification
ISD
Information
Systems
Development
NMED
New
Mexico
Environment
Department
NRC
Nuclear
Regulatory
Commission
Q&
RA
Quality
and
Regulatory
Assurance
RCRA
SWB
Standard
Waste
Box
TRAMPAC
TRU
Transuranic
TRUPACT
ti
voc
Volatile
Organic
Compound
WAC
Waste
Acceptance
Criteria
WID
Waste
Isolation
Division
WlPP
Waste
Isolation
Pilot
Plant
WSPF
Waste
Stream
Profile
Form
W
l
S
WIPP
Waste
Information
System
Resource
Conservation
and
Recovery
Act
TRUPACT
II
Authorized
Methods
for
Payload
Control
Transuranic
Package
Transporter
Model
II
iv
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
1.0
INTRODUCTION
This
Waste
Isolation
Pilot
Plant
(WIPP)
Waste
Information
System
(WWIS)
Program
describes
and
details
the
methods
to
be
used
to
implement
the
WWlS
database
activities.
The
WWlS
is
specified
and
required
by
the
Compliance
Certification
Application
for
the
Waste
Isolation
Pilot
Plant
(DOEKAO
1996
21
84,
Title
40,
Code
of
Federal
Regulations
[CFR],
Section
191
);
the
Transuranic
Waste
Characterization
Quality
Assurance
Program
Plan
(CAO
94
1
01
0);
the
WIPP
Resource
Conservation
and
Recovery
Act
(RCRA)
Part
B
Permit
Application,
Chapter
C,
Waste
Analysis
Plan
(DOEMIPP
91
005);
and
the
Waste
Acceptance
Criteria
for
the
WlPP
(DO
ENVl
PP
069).
2.0
SCOPE
This
WWlS
Program
addresses
the
entire
range
of
activities
performed
by
the
WWIS.
Data
received
by
the
WIPP
for
waste
acceptance
purposes
is
used
to
determine
compliance
with
t
h
e
RCRA
Part
B
Permit
Application
and
40
CFR
0194
requirements.
Since
no
physical
analysis
of
waste
will
take
place
at
WIPP,
the
data
management,
review,
and
approval
processes
are
critical
to
ensure
WIPP's
regulatory
compliance.
The
W
l
S
is
an
on
line
database
system
used
to:
Record
waste
container
characterization
and
certification
data
supplied
by
the
transuranic
(TRU)
waste
generators,
as
required
by
the
WIPP
Waste
Acceptance
Criteria
(WAC),
to
gain
acceptance
for
disposal
at
WlPP
Print
a
Summary
Report
that
provides
a
listing
of
waste
container
characterization
data
for
use
in
review
of
Waste
Stream
Profile
Forms
(WSPF)
associated
with
the
container
characterization
data
Provide
computerized
hold
and
approval
points
for
the
WlPP
data
administrator
regarding
WlPP
acceptance
of
container
characterization
and
certification
data
Communicate
the
approval/
rejection
status
of
characterization
and
certification
data
to
the
generatorkhipper
Record
proposed
shipment
configuration
details
from
the
generatorkhipper
for
containers
that
have
received
WIPP
approval
of
characterization
data
Provide
a
hold
and
approval
point
for
the
WlPP
data
administrator
to
approve
or
reject
the
proposed
shipment
1
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
Communicate
the
approvaI/
rejection
status
of
proposed
shipments
to
the
g
eneratorlsh
i
p
per
Provide
a
Shipment
Report
for
WlPP
personnel
to
verify
the
"as
received"
shipment
against
the
information
listed
on
the
manifest
accompanying
the
shipment,
and
to
verify
that
containers
received
are
those
approved
by
WlPP
for
shipment
Record
the
disposal
location
of
the
containers
when
they
are
placed
in
the
underground
disposal
area
Record
(automatically)
any
changes
made
to
WWIS
data,
record
changes,
and
provide
a
Change
Log
Report
to
identify
changes
that
have
been
made
Provide
required
reports,
which
are
entered
into
the
facility
operating
record
and
kept
as
a
quality
record
for
the
lifetime
of
the
facility
The
above
functions
require
the
interaction
of
several
groups
within
Waste
Operations,
and
with
generatodshipper
sites
and
others,
such
as
internal
and
external
review/
oversight
groups.
his
program
defines
the
responsibilities
and
activities
for
each
group
of
WWlS
users
at
WIPP.
3.0
RESPONSIBILITIES
3.1
Waste
Operations
The
Waste
Operations
Section
is
the
organization
with
cognizance
over
the
waste
acceptance
and
emplacement
process
at
WIPP.
The
review
and
approval
of
waste
data
is
coordinated
by
Waste
Operations
and
all
records
generated
by
the
review
and
approval
process
are
controlled
by
Waste
Operations
until
transferred
to
Project
Records
Services.
The
WWlS
data
administrator
is
responsible
for
establishing
access
authorization
to
the
WWlS
for
generatodshipper
sites;
approving
user
characterization
data,
certification
data,
proposed
shipping
data,
and
maintenance
of
Administrative
Reference
Tables
used
in
WWlS
operation;
deleting
generator
data
records
when
requested
by
the
generator
(the
WWIS
Change
Log
Records
record
deletions
archived
as
a
part
of
the
overall
database
process);
and
assisting
users
with
problems
associated
with
the
application.
2
WIPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
The
data
administrator
is
also
responsible
for
the
following
activities
regarding
WWIS
operation:
D
D
*
I
D
Determine
the
need
for
access,
assign
user
identifications
and
enter
them
into
the
W
l
S
Determine
acceptability
of
waste
container
data
submitted
by
the
generator
in
the
WWlS
Characterization
Module
for
WSPF
approval
Designate
approved
WSPF
numbers
in
the
WWlS
Administration
Tables
Determine
acceptability
of
waste
container
data
submitted
by
the
generator
in
the
WWlS
Certification
Module
Enter
needed
data
into
€he
Reference
Data
Tables
of
the
WWlS
Process
WSPF(
s)
to
the
requirements
of
the
Waste
Stream
Profile
Form
Review
and
Approval
Program
(WP
05
WA.
03)
Produce
reports
from
the
WWlS
Enter
approved
changes
to
the
W
I
S
data
Assist
generators
with
data
entry
problems
Serve
as
the
contact
point
at
WlPP
for
the
generator
sites
regarding
data
transmittal
and
submittal
Hazardous
Waste
Operations
is
responsible
for:
Initially
receiving
the
TRUPACT
II
shipment
Signing
the
manifest
Reviewing
WWlS
data
to
determine
if
it
agrees
with
information
on
the
Shipment
Manifest
Notifying
the
Waste
Handling
engineer
of
the
manifest
review
results
Resolving
manifest
discrepancies
by
working
with
the
WWlS
data
administrator
and
the
generatodshipper
3
WlPP
Waste
information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
The
Waste
Handling
engineer
is
responsible
for
two
primary
entry
inputs
to
the
WWIS:
Recording
acceptance
of
the
shipment
in
the
WWlS
after
verifying
that
the
correct
containers
were
received,
based
on
shipment
information
in
the
WWIS
and
Shipment
Manifest
information
Recording
off
loaded
container
information
and
container
disposal
locations
'
3.2
Resource
Conservation
and
Recovery
Act
Permittinq
The
RCRA
Permitting
Section
reviews
each
WSPF
and
the
associated
Characterization
Data
Summary
Report,
then
completes
a
checklist
to
document
that
review
per
WP
05
WA.
03.
A
specific
focus
of
this
review
is
to
ensure
that
the
requirements
of
the
WlPP
Waste
Analysis
Plan
are
properly
implemented.
RCRA
Permitting
also
performs
periodic
reviews
(on
a
selected
or
"as
necessary"
basis)
of
generator
waste
container
characterization
data
entered
into
the
WWIS.
Cognizant
R
C
W
Permitting
personnel
have
access
to
the
WWIS
database
for
use
in
review
of
administrative
information,
waste
characterization
data,
certification
data,
decay
analysis,
change
log,
inventory,
and
regulatory
reporting.
3.3
Qualitv
and
Recrulatorv
Assurance
Quality
and
Regulatory
Assurance
(Q&
RA)
participates
in
the
review
and
approval
activities
for
the
WSPF
to
verify
that
the
submittal
is
complete
and
properly
signed.
On
a
selective
basis,
Q&
RA
will
review
waste
container
data
submitted
to
WIPP
through
the
WWlS
by
the
generatorkhipper
sites
to
determine
if
the
generator
data
entered
into
the
WWIS
is
complete.
3.4
Proiect
Record
Services
Project
Record
Services
is
responsible
for
t
h
e
retention
of
records
generated
by
the
WlPP
waste
acceptance
process.
Some
of
the
records
generated
by
this
process
will
be
retained
at
the
facility
as
a
part
of
the
operational
record
until
closure
of
the
facility.
Other
records
will
be
sent
to
records
storage.
Criteria
to
define
the
record
retention
times
are
listed
in
the
approved
Records
Inventory
and
Disposition
Schedule
and
the
implementing
procedures
for
each
document.
4
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
3.5
Information
Svstems
DeveloDment
Information
Systems
Development
(ISD)
is
the
support
organization
for
the
VWVIS.
ISD
is
responsible
for
keeping
the
WWlS
functional
and
facilitating
electronic
communications
between
WlPP
and
the
generator
sites.
ISD
also
provides
a
secure
area
for
the
WWlS
server;
performs
nightly,
quarterly,
and
annual
backups
of
system
records;
and
maintains
network
communications.
3.6
Technical
Traininq
The
Human
Resources
Technical
Training
Section
is
responsible
for
controlling
and
maintaining
the
W
I
S
Qualification
Card.
The
qualification
cards
are
used
as
part
of
the
WlPP
qualification
program
and
will
be
maintained,
controlled,
and
retained
per
the
implementing
procedures.
The
Waste
Operations
data
administrator
(the
Subject
Matter
Expert)
will
aid
Technical
Training
personnel
in
the
development
of
the
WWlS
Qualification
Card.
3.7
TRU
Waste
Proarams
The
Engineering
TRU
Waste
Programs
Section
provides
the
cognizant
engineer
(configuration
manager)
for
the
WWlS
Program.
The
cognizant
engineer
is
responsible
for
providing
design
and
configuration
management
for
the
WWlS
database
and
represents
the
primary
source
of
engineering
interface
for
the
WWIS.
Configuration
management
is
addressed
in
approved
Waste
Isolation
Division
(WID)
management
procedures.
3.8
Department
of
EnerclvlCarlsbad
Area
Office
The
Carlsbad
Area
Office
manager
is
responsible
for
granting,
or
suspending,
a
site's
authority
to
certify
TRU
waste
to
the
WAC
(certification
authority)
and
to
use
the
TRUPACT
II
and
Remote
Handled
TRU
72€
3
Cask
(transportation
authority)
based
upon
an
assessment
of
their
documented
TRU
waste
program
and
its
implementation.
After
approving
the
required
generatorkhipper
plans,
the
CAO,
together
with
the
managing
and
operating
contractor,
will
perform
certification
audits
of
the
generator/
shipper
sites
to
assess
the
implementation
of,
and
compliance
with,
the
approved
plans.
Based
upon
acceptable
results
of
the
certification
audit,
the
CAO
will
grant
TRU
waste
certification
authority
and
transportation
authority
to
the
site.
The
CAO
is
also
responsible
for
review
and
approvalldenial
of
generatorlshipper
site
requests
for
exceptions
(variances)
to
the
WlPP
operations
and
safety
requirements.
The
CAO
cannot
approve
exceptions
to
requirements
that
are
confrored
by
others,
such
as
the
Nuclear
Regulatory
Commission
WRC),
for
transportation
or
the
Environmental
Protection
Agency
(EPA)
and
ine
New
Mexico
Environment
Department
(NMED)
for
the
RCRA
component
of
TRU
mixed
waste,
without
first
obtaining
changes
to
the
controlling
permits.
5
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
4.0
WWlS
ACCESS
The
hardware
for
the
W
l
S
system
is
located
in
a
controlled
access
area
within
the
WlPP
facility.
Computer
access
to
the
W
l
S
database
is
controlled
by
means
of
user
identifications
and
passwords
assigned
to
users
having
a
need
to
use
the
waste
information
system.
A
user
must
obtain
authorization
from
the
WlPP
data
administrator
before
being
allowed
to
log
onto
the
electronic
system.
Prior
to
granting
user
access,
the
data
administrator
will
instruct
potential
users
in
the
proper
use
of
the
WWIS.
When
the
authorization
is
granted,
read/
write
access
restrictions
are
also
imposed
on
the
user
to
ensure
that
the
integrity
of
the
data
within
the
database
is
maintained.
4.1
User
Access
The
WWlS
data
administrator
receives
requests
for
system
access
from
users
on
the
WWIS
Access
Request
Form
(Attachment
I).
Generatorkhipper
sites
must
be
certified
by
the
CAOWIPP
prior
to
entering
waste
data
into
the
W
l
S
for
review
by
the
WIPP.
The
data
administrator
reviews
the
WWlS
Access
Request
Form
and
approves
or
disapproves
the
requested
authorization
reason
for
access
(designated
in
Attachment
2),
signs
the
WWlS
Access
Request
Fom,
and
forwards
the
request
to
the
Waste
Operations
manager
for
final
approval.
After
obtaining
the
approval
of
the
Waste
Operations
manager,
the
data
administrator
provides
instruction
to
the
requestor
on
the
proper
use
of
the
WWIS,
enters
the
access
type
onto
the
WWlS
Access
Request
Form,
and
makes
the
necessary
entries
into
the
WWIS
Administration
Reference
Tables
to
allow
the
user
access
to
the
WWIS.
Access
restrictions
are
imposed
as
defined
in
the
Software
Requirements
Specification
and
the
Software
Design
Description,
and
are
documented
on
the
approved
WWlS
Access
Request
Form.
The
data
administrator
will
advise
the
user
when
the
approved
access
to
the
WWlS
has
been
established
by
providing
the
user
with
a
copy
of
the
signed
WWlS
Access
Request
Form.
The
signed
W
l
S
Access
Request
Form
will
be
transmitted
to
the
user
as
an
attachment
to
the
W
l
S
Access
Notification
Form
(Attachment
3).
The
data
administrator
will
file
a
copy
of
the
WWlS
Access
Notification
Form
and
attached
W
I
S
Access
Request
Form
in
the
WWlS
project
files.
The
data
administrator
will
revoke
any
access
privileges
at
the
request
of
the
user
or
Waste
Operations
manager
by
accessing
the
Administrative
Reference
Tables
and
inserting
an
access
termination
date
equal
to
the
date
of
revocation.
6
WIPP
Waste
information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
5.0
WlS
COMPONENTS
The
W
I
S
database
is
a
complex,
multifaceted
database
system
designed
to
perform
functions
ranging
from
retaining
simple
data;
providing
a
platform
for
the
review/
approval
of
generator/
shipper
sites
waste
information;
tracking
of
waste
containers
by
categories;
combining
containers
into
packages
and
shipments;
and
to
verify
emplacement
location
of
the
containers
in
the
repository.
To
fulfill
the
variety
of
tasks
assigned
to
the
W
I
S
,
the
database
system
is
divided
into
several
modules.
These
modules,
other
components,
and
organizationallindividual
responsibilities
are
described
below.
5.1
Administration
5.1.1
Administrative
Tables
The
WWIS
has
an
extensive
library
of
Administration
Tables.
These
tables,
used
by
the
data
administrator,
contain
complexwide
requirements
specified
in
DOENVIPP
069
and
CAO
94
1010.
Also
included
in
the
tables
are
site
specific
information
listed
in
CAO
approved
generatorlshipper
site
Quality
Assurance
Project
Plans,
Certification
Plans,
TRUPACT
II
Authorized
Methods
for
Payload
Control
(TRAMPAC),
and
data
supplied
to
WlPP
regarding
individual
containers,
waste
streams,
and
shipping
informat
ion.
5.1.2
User
Administration
The
user
administration
function
is
the
responsibility
of
the
Waste
Operations
data
administrator.
The
data
administrator
is
responsible
for
maintaining
WWlS
data
pertaining
to
individual
users
of
the
system.
This
includes
updating
user
data
files
(information
about
the
users),
setting
up
access
for
new
users
to
the
application,
instructing
personnel
in
the
proper
use
of
the
W
I
S
,
assisting
users
with
problems
associated
with
the
application,
defining
the
extent
of
use
of
the
system
for
each
user,
and
deleting
users
from
the
application.
5.1.3
Data
Administration
The
data
administrator
is
responsible
for
determining
user
access
to
the
data,
administering
Reference
Tables
used
systemwide,
producing
reports
from
the
Reference
Tables,
and
logging
changes.
The
WWlS
is
capable
of
producing
several
standardized
and
specialized
reports
concerning
the
waste
data
supplied
by
the
generatorkhipper
site.
Internal
and
external
requests
for
these
reports
will
be
processed
by
the
data
administrator
on
the
basis
of
the
nature
of
the
request,
the
availability
of
resources
to
perform
the
request,
and
the
approval
of
Waste
Operations
management.
The
data
administrator
updates
tables
containing
limit
and
reference
data
and
provides
change
information
to
the
Change
Log.
7
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
5.1.4
Security
The
Waste
Operations
data
administrator
controls
access
to
the
databases
and
data
through
passwords,
and
controls
access
to
the
data
at
the
record
level.
AIf
data
transmitted
between
the
W
l
S
server
located
at
the
WlPP
and
the
WWlS
and
elsewhere
will
be
via
the
limited
access
Departmen1
of
Enerav
Business
Network
/DOE
BN).
Users
are
assigned
access
authorization
levels
as
listed
in
Attachment
2.
Users
are
only
allowed
to
view
data
pertaining
to
their
access
authorization
level
and/
or
site.
5.2
Characterization
Module
The
Characterization
Module
allows
the
generatodshipper
to
enter
specific
container
information
to
be
used
to
validate
the
characterization
activities
of
the
generator
site
for
the
data
summary
on
the
WSPF
submitted
for
WlPP
approval.
Approval
of
the
WSPF
will
be
required
before
waste
containers
associated
with
the
waste
stream
can
be
approved
and
accepted.
Required
information
fields
for
the
characterization
data
input
are
indicated
by
a
shaded
entry
box
on
the
interactive
input
screen
for
manual
input.
For
electronic
data
input,
data
information
is
defined
in
data
structure
tables
included
in
the
WWlS
User's
Guide.
After
the
data
passes
the
limit
and
edit
checks
and
is
reviewed
by
the
W
l
S
data
administrator,
it
is
considered
"acknowledged"
data.
An
entry
is
made
by
the
WlPP
data
administrator,
making
the
data
available
for
viewing
to
the
generator
only
through
the
Certification
Module
pull
down
screen.
The
generatodshipper
is
denied
any
further
write
access
to
the
information
fields
of
the
Characterization
Module
at
this
point.
This
module
has
provisions
to
generate
a
WWlS
Waste
Characterization
Data
Report,
which
contains
a
listing
of
the
characterization
data
for
the
containers
covered
by
a
WSPF.
A
copy
of
this
report
will
be
attached
to
the
WSPF
to
support
the
review
of
the
information.
Container
data
not
accepted
by
W
l
S
in
this
module
will
not
be
retained
by
the
WVVIS.
A
Bad
Data
Report
will
be
created
and
will
explain
the
reason(
s)
for
rejection.
Rejected
data
will
require
resubmittal
to
WlPP
prior
to
further
consideration.
5.3
Certification
Module
The
Certification
Module
allows
for
generator
transmittal
and
WlPP
data
administrator
verification
of
submitted
WAC
data.
All
modifications
to
the
data
will
be
tracked
in
a
Change
Log.
In
this
module,
the
data
administrator
will
accept
or
reject
certification
8
WIPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
data
and
provide
verification
reports.
After
acceptance
of
the
submitted
data,
the
WWlS
will
automatically
generate
an
Acceptance
Report.
If
the
submitted
Certification
Module
data
is
rejected,
the
data
administrator
will
generate
a
Rejection
Report
and
notify
the
generatorlshipper
site.
Required
information
fields
for
certification
data
input
are
indicated
by
a
shaded
entry
box
on
the
interactive
input
screen
for
manual
input.
For
electronic
data
input,
data
information
is
defined
in
data
tables
included
in
the
WWlS
User's
Guide.
After
the
data
passes
the
limit
and
edit
checks
and
a
review
by
the
W
l
S
data
administrator,
it
is
considered
"acknowledged"
data
and
an
entry
is
made
by
the
WIPP
data
administrator.
The
generatorkhipper
is
denied
any
further
write
access
to
the
information
fields
of
the
Certification
Module
at
this
point.
5.4
Shitminu
Module
The
Shipping
Module
allows
the
generatorlshipper
to
propose
a
shipment
configuration
for
WIPP
approval.
The
proposed
shipment
information
is
entered
into
the
WWlS
and
subjected
to
data
limit
checks
to
determine
if
the
shipping
requirements
of
the
TRAMPAC
and
WIPP
WAC
are
met
by
the
proposed
shipment.
After
passing
these
electronic
data
checks,
the
shipping
information
is
reviewed
by
WIPP
operating
personnel.
If
everything
is
in
order,
the
shipment
data
is
approved
and
the
generatorlshipper
may
proceed
with
the
shipment.
This
module
generates
the
Shipment
Summary
Report
used
by
Waste
Operations
to
verify
that
the
correct
containers
have
been
shipped.
5.5
lnventorv
Module
The
inventory
Data
Module
is
designed
for
WIPP
to
record
what
containers
have
been
received,
the
receipt
date,
and
the
disposal
locations
for
those
containers.
This
module
generates
the
Container
Emplacement
Report,
which
will
be
kept
as
part
of
the
facility
operating
record.
The
Inventory
Data
Module
also
generates
other
reports
concerning
the
disposed
waste
inventory,
including
reports
on
nuclides,
container
data,
headspace
gas,
and
biennial
information.
6.0
USING
THE
WWlS
Each
module
and
component
described
above
requires
input
from
several
users,
such
as
the
generatorkhipper,
data
administrator,
and
others.
From
these
modules
and
Administrative
Tables,
the
WWIS
has
the
capability
of
generating
various
reports
to
track
the
input
from
t
h
e
generator/
shipper
sites.
These
reports
are
listed
and
described
9
WIPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
in
WP
05
WA.
01,
WlPP
TRU
Waste
Data
Management
Plan.
The
methods
to
be
employed
in
the
completion
of
each
module
of
the
WWlS
database
are
described
and
defined
below.
6.1
Electronic
Data
Entry
Characterization
Module
Prior
to
review
of
generatorlshipper
characterization
data,
the
data
administrator
will
ensure
that
the
DOE/
CAO
has
granted
certification
and
transportation
authority
to
the
generatorjshipper
site
as
stated
in
Section
3.8.
Generatorskhippers
must
notify
the
WWlS
data
administrator
of
new
WSPF
numbers
prior
to
inputting
Characterization
Module
container
data
associated
with
that
profile
number.
After
notification
of
the
new
numbers,
the
data
administrator
will
enter
the
proposed
WSPF
numbers
in
the
WWlS
Administration
Reference
files,
but
will
leave
the
approval
date
blank
(indicating
that
the
WSPF
is
not
yet
approved).
No
generatorlshipper
site
waste
data
will
be
accepted
by
the
WWlS
database
until
the
data
administrator
has
updated
the
Administrative
Reference
Tables
to
include
the
WSPF
number.
Electronic
transfer
of
characterization
data
is
granted
to
sites
that
have
an
electronic
waste
information
system.
The
data
from
the
user
system
must
be
formatted
to
be
consistent
with
the
WWlS
data
structures
as
listed
in
the
WWlS
User's
Manual
(SP
WO
WlS
002).
Before
data
is
transmitted,
the
user
system
formatting
wit1
be
verified
to
ensure
integrity.
The
WWlS
data
administrator
will
transmit
the
system
format
and
assist
the
user
with
the
setup
of
the
data
structure.
The
WWlS
system
performs
edit
and
range
checks
on
the
characterization
data
and
identifies
all
errors
by
waste
container
identification
number.
After
electronic
transmittal
of
characterization
data
to
the
W
I
S
,
the
generators/
shippers
are
only
allowed
to
view
their
packages
and/
or
print
error
reports.
After
the
characterization
data
has
passed
alf
range
and
edit
checks
and
has
been
approved
by
the
Waste
Operations
data
administrator,
the
shipper
will
receive
a
message
to
that
effect.
6.2
WWlS
Database
Use
in
Amrovinu
the
WSPF
The
review
and
approval
of
WSPFs
are
governed
by
WlPP
approved
procedures.
After
receipt
of
the
WSPF
from
the
generator/
shipper
site,
Waste
Operations
routes
a
copy
of
each
WSPF
and
associated
WWlS
Characterization
Data
Summary
Reports
from
the
WWlS
to
RCRA
Permitting
and
Q&
RA.
The
Summary
Report
provides
reviewers
with
a
listing
of
waste
container
characterization
data
associated
with
the
WSPF.
These
organizations
review
the
form
against
requirements
of
the
WlPP
Waste
Analysis
Plan,
the
Quality
Assurance
Program
Plan,
and
the
WlPP
Quality
Assurance
Program
Description.
After
the
reviewers
have
completed
their
reviews,
a
meeting
may
be
called
by
Waste
Operations
if
any
profile
deficiencies
are
noted.
Waste
Operations
interfaces
with
the
10
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
generatodshipper
to
resolve
any
noted
deficiencies.
After
all
WlPP
reviewers
concur
that
the
WSPF
is
acceptable,
Waste
Operations
notifies
the
generatorlshipper
of
the
WSPF
approval.
The
WlPP
data
administrator
makes
an
approved
date
entry
into
the
WWlS
data
Reference
Tables,
causing
the
program
to
recognize
the
approved
profile
number.
This
entry
is
necessary
for
the
data
to
be
accepted
into
the
WWIS
Certification
Module.
When
the
WSPF
is
routed
for
review,
it
is
tracked
by
a
routing
slip
and
is
recorded
into
a
log
of
the
WSPFs
received
by
the
WlPP
in
accordance
with
WP
05
WA.
03.
A
critical
part
of
waste
stream
approval
is
the
WlPP
RCRA
Specific
Generator
Site
Waste
Screening
and
Acceptance
Audit
Program
Plan,
(WP
02
PC.
01).
After
the
initial
audit
and
approval,
annual
audits
are
performed
for
sites
shipping
waste
to
WIPP.
The
data
administrator
ensures
that
the
waste
generator
has
successfully
passed
the
scheduled
CAO
certification
and
WlPP
RCRA
specific
audits
and
resolved
any
significant
deficiencies
before
approving
a
WSPF
from
that
site.
6.3
Manual
Data
Entrv
Characterization
Module
Manual
characterization
data
entry
access
is
granted
to
generatodshipper
sites
that
have
limited
or
small
quantities
of
TRU
waste,
or
that
do
not
have
an
electronic
information
system
but
do
have
access
to
the
WWlS
database
capabilities.
Manual
data
entry
allows
a
generatorlshipper
site
without
an
electronic
waste
information
system
to
enter
waste
data
directly
into
the
various
blocks
of
the
characterization
data
entry
screens.
Although
the
manually
entered
data
process
is
much
slower
than
that
of
electronic
data
transfer,
the
entered
waste
data
receives
the
same
editllimit
checks
and
reviews
as
electronic
data
transfers.
Generatordshippers
must
notify
the
W
l
S
data
administrator
of
new
WSPF
numbers
prior
to
inputting
Certification
Module
container
data
associated
with
that
profile
number.
After
notification
of
the
new
WSPF
numbers,
the
data
administrator
will
enter
the
proposed
numbers
in
the
WWlS
Administration
Reference
fifes,
but
will
leave
the
approval
date
blank
(indicating
that
the
profile
is
not
yet
approved).
No
generatodshipper
site
waste
data
will
be
accepted
by
the
WWlS
database
until
the
data
admini
strator
has
updat
ed
the
Admin
ist
rat
iv
Refer
ence
Table
S.
e
11
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
6.4
Review
and
ADDroval
of
Characterization
Data
Entries
The
data
administrator
periodically
reviews
container
Characterization
Module
data
that
have
passed
the
WWlS
datallimit
checks.
The
review
requirements
are
at
the
discretion
of
the
data
administrator
but
are
primarily
performed
for
consistencv
with
the
Waste
Stream
Profile
Form.
After
review
of
the
data,
the
data
administrator
will
indicate
acceptance
or
rejection
of
each
container
characterization
record
on
the
acceptheject
screen
feature
in
the
WWIS.
If
the
record
is
rejected,
the
data
administrator
will
input
the
reason
for
the
rejection
into
the
WWlS
and
notify
the
generator/
shipper
of
the
reason
for
rejection.
6.5
Electronic
Data
Entrv
Certification
Module
The
electronic
transfer
of
certification
data
is
granted
to
sites
that
have
electronic
waste
information
system
capabilities.
To
use
the
WWlS
electronic
data
option,
the
data
from
the
user
system
must
be
formatted
to
be
consistent
with
the
WWlS
data
structures.
Before
data
are
transmitted,
the
user
system
formatting
will
be
verified
by
acceptance
testing
of
the
generatorishipper
electronic
data
system
to
ensure
integrity
and
compatibility
with
the
WlPP
WWlS
server.
The
WWlS
system
performs
edit
and
range
checks
on
the
data
and
identifies
errors
by
waste
container
identification
number.
After
electronic
transmittal
of
certification
data
to
the
WVVIS,
generators/
shippers
can
only
view
their
certification
packages
and/
or
print
error
reports.
After
the
data
have
passed
all
range
and
edit
checks
and
received
approval
from
the
Waste
Operations
data
administrator,
the
generator
will
receive
an
electronic
message
to
document
the
approval.
6.6
Manual
Data
Entrv
Certification
Module
Manual
certification
data
entry
access
is
granted
to
generator/
shipper
sites
which
have
limited
or
small
quantities
of
TRU
waste
or
which
do
not
have
an
electronic
information
system
but
do
have
WWIS
database
capabilities.
Manual
data
entry
allows
a
generator/
shipper
site
without
access
to
an
electronic
waste
information
system
to
enter
waste
data
directly
into
the
various
blocks
of
the
WWlS
Certification
Module
data
entry
screens.
Although
the
manually
entered
data
process
is
much
slower
than
that
of
electronic
data
transfer,
the
entered
waste
data
receives
the
same
edit/
limit
checks
and
reviews
as
electronic
data
transfers.
This
module
is
structured
to
accept
only
data
that
pertains
to
accepted
waste
stream
profiles.
This
allows
the
generatorkhipper
to
enter
waste
container
data
for
approval
of
the
individual
containers.
The
data
will
be
screened
by
the
WWlS
to
perform
limit
checks
for
each
data
entry.
Data
outside
the
range
limits
of
the
WAC
will
be
rejected
12
WIPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
by
the
database.
6.7
Review
and
Approval
of
Certification
Data
Entries
The
data
administrator
will
periodically
review
container
Certification
Module
data
that
have
passed
the
WWlS
datallimit
checks.
The
reviews
are
at
the
discretion
of
the
data
administrator
but
are
primarily
performed
for
consistencv
with
the
Waste
Stream
Profile
A
Form
After
review
of
the
data,
the
data
administrator
will
indicate
acceptance
or
rejection
of
each
container
characterization
record
on
the
accepffreject
screen
feature
in
the
WWIS.
If
the
record
is
rejected,
the
data
administrator
will
input
the
reason
of
the
rejection
into
the
WWIS.
The
W
I
S
automatically
notifies
the
generatorlshipper
site
of
the
rejection.
6.8
Electronic
Data
Entrv
ShbDina
Module
The
electronic
transfer
of
shipping
data
will
be
granted
to
sites
that
have
an
electronic
waste
information
system.
The
data
from
the
user
system
must
be
formatted
to
be
consistent
with
the
WWlS
data
structures.
Before
data
are
transmitted,
the
user
system
formatting
will
be
verified
by
acceptance
testing
of
the
generator
electronic
data
system
to
ensure
integrity
and
compatibility
with
the
WlPP
WWIS
server.
Edit
and
range
checks
are
performed
by
the
W
I
S
.
The
data
entered
are
descriptors
by
waste
container
or
dunnage
container
and
include
shipment,
packaging,
and
assembly
information.
6.9
Manual
Data
Entrv
ShipDina
Module
Manual
shipping
data
entry
access
is
granted
to
generatorkhipper
sites
which
have
limited
or
small
quantities
of
TRU
waste
or
which
do
not
have
access
to
an
electronic
information
system
but
do
have
WWlS
database
capabilities.
Manual
data
entry
allows
a
generatorkhipper
site
without
an
electronic
waste
information
system
to
enter
waste
data
directly
into
the
fields
of
the
WWlS
Shipping
Module
data
entry
screen.
Although
the
manually
entered
waste
data
process
is
much
slower
than
that
of
electronic
data
transfer,
the
entered
waste
data
receives
the
same
edifflimit
checks
and
reviews
as
electronic
data
transfers.
6.10
Review
and
ApDroval
of
ShiDDina
Data
Entries
After
the
generatorlshipper
site
has
entered
the
required
Shipping
Module
entries,
the
WlPP
data
administrator
will
review
the
data
to
ensure
that
it
is
complete
and
passes
the
WWlS
electronic
data
checks.
The
data
administrator
will
additionally
verify
and
document
on
Attachment
4,
ushipping
Review
of
Cellulose,
Plastics
and
Rubber
13
WlPP
Waste
information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
(CPR),
n
that
the
amount
of
the
material
parameters
contained
in
the
shipment
will
not
cause
the
WlPP
repository
inventory
of
cellulose,
plastics
and
rubber
to
exceed
the
limit
of
2x107
kgs.
After
these
checks
have
been
completed,
the
data
administrator
approves
the
generatorkhipper
site
shipping
data
entries
by
selecting
the
"accept"
field
on
the
WWlS
"ReviewlApprove
Shipment
Information"
screen.
This
approval
allows
the
generatorkhipper
site
to
proceed
with
preparing
the
proposed
shipment
for
transport
to
WIPP.
6.11
Shioment
ReceiDt
Data
Prior
to
bringing
a
TRUPACT
II
shipment
into
the
Waste
Handling
Building,
the
Waste
Handling
engineer
will
print
a
Shipment
Summary
Report
for
use
in
preparing
for
the
shipment
unloading.
This
report
is
used
by
the
Waste
Handling
engineer
and
Hazardous
Waste
Operations
to
provide
a
summary
of
parameters
important
to
waste
receipt
and
planning
considerations.
6.12
Barcode
Data
Check
of
Shioment
Received
Containers
The
following
information
will
normally
be
gathered
using
a
programmed
WWIS
interface
for
downloading
information
to
the
barcode
scanner,
but
the
information
can
be
manually
recorded
and
compared
to
the
information
in
the
Shipment
Summary
Report.
Data
input
to
the
WWlS
can
be
accomplished
by
keyboard
input
of
container
barcode
numbers
and
disposal/
storage
locations.
The
W
l
S
contains
screens
which
allow
manual
input
of
the
inventory
and
location
information
if
the
barcoding
equipment
is
not
available.
The
Waste
Handling
engineer
will
place
the
barcode
scanner
in
the
connect
cradle
and
downtoad
shipment
information
to
the
scanner.
The
Waste
Handling
technician
will
scan
a
container
barcode
from
each
assembly
after
it
is
removed
from
the
TRUPACT
II.
(The
WWlS
program
will
associate
the
barcoded
container
with
the
seven
pack
assembly
number
and
any
of
the
remaining
drums
of
the
assembly.)
The
programmed
scanner
will
indicate
if
the
scanned
container
is
listed
in
the
approved
shipment
information.
(After
matching
the
scanned
container
number
with
the
number
in
the
WWIS,
shipment
approval
may
proceed.)
If
the
scanner
identifies
the
container
number
as
incorrect,
the
container
will
be
scanned
again.
If
the
number
is
not
recognized
in
the
second
scanning,
the
Waste
Handling
engineer
will
be
notified.
The
Waste
Handling
engineer
will
notify
the
Waste
Operations
manager
and
Hazardous
Waste
Operations
that
the
shipment
container
number
does
not
agree
with
the
shipment
summary
information.
It
is
the
responsibility
of
Hazardous
Waste
Operations
to
resolve
any
manifest
discrepancies
by
working
with
the
W
l
S
data
14
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
administrator
and
the
generatorkhipper.
6.13
ShiDment
Approval
The
Waste
Handling
engiileer
will
notify
Hazardous
Waste
Operations
if
the
w
c
d
d
container(
s)
agree
with
the
WWlS
Shipment
Summary
and
obtain
their
recommendation
for
approval
or
disapproval
of
shipment,
based
on
agreement
with
manifest
*formation.
After
ysrifying
agreement
between
the
WWlS
Shipment
Summary
and
the
Hazardous
Was6
Manifest
from
Hazardous
Waste
Operations,
the
Waste
Handling
engineer
will
indicate
acceptance
of
the
shipment
by
selecting
the
shipment
"accept"
screen
festure
of
the
WWIS.
I
f
the
WWIS
Shipment
Summary
and
the
Hazardous
Waste
Manifest
are
not
in
agreement,
the
Waste
Handling
engineer
will
notify
the
Waste
Operations
manager
before
making
a
shipment
rejection
entry
into
the
WWlS
(this
is
expected
to
be
a
rare
event).
6.14
Recordina
Overpack
Information
If
Waste
Handling
Operations
finds
it
necessary
to
overpack
waste
containers
(Le.,
loading
corroded,
damaged,
or
contaminated
containers
into
a
larger
container),
the
Waste
Handling
engineer
will
access
the
WWlS
Overpacked
Container
input
screen
and
record
the
overpacked
container
(i.
e.,
drum
or
Standard
Waste
Box
[SWS])
configuration
information.
Disposal
location
information
will
be
recorded,
using
the
same
procedures
used
for
non
overpacked
containers.
6.15
Barcode
Data
Entrv
Location
of
DrumlAssemblies
The
Waste
Handling
engineer
can
establish
valid
storage
locations
(room
and
panel)
by
updating
the
pull
down
screen
in
the
Inventory
Module
of
the
WWlS
prior
to
disposal.
Waste
containers
may
not
be
taken
underground
for
disposal
until
the
Waste
Handling
engineer
has
accepted
the
shipment,
as
indicated
by
the
Shipment
Approval
in
the
WWIS.
_.
6.16
Container
DisRosal
Data
The
Waste
Handling
engineer
will
place
the
underground
barcode
scanner
in
the
connect
cradle
and
download
shipment
information
to
the
scanner.
The
Waste
Handling
technician
can
enter
the
disposal
location,
including
panel
and
room,
into
the
barcode
scanner
for
each
assembly.
15
WIPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
After
disposal
locations
for
assemblies
of
the
shipment
are
recorded
in
the
barcode
scanner,
the
Waste
Handling
engineer
will
upload
the
location
information
from
the
barcode
scanner
to
the
WWIS.
Data
errors
in
the
module
are
listed
in
the
"Bad
Location"
screen
of
the
WWIS.
After
uploading
the
location
information,
the
Waste
Handling
engineer
will
review
the
bad
location
screen
of
the
WWIS,
if
necessary,
and
correct
any
locations
that
were
found
to
be
incorrect.
The
data
administrator
will
print
a
Waste
Container
Emplacement
Report
weekly
to
document
updated
emplacements
performed
during
the
reporting
period.
This
report
is
added
by
the
data
administrator
to
the
WWlS
Operational
Log
and
retained
at
WlPP
for
the
operational
life
of
the
facility.
7.0
SETTING
UP
OTHER
SITES
TO
USE
THE
WWlS
The
Waste
Operations
data
administrator
provides
the
generatorlshipper
sites
with
several
levels
of
assistance
in
setting
up
generator/
shipper
sites
with
the
WWlS
database.
Services
provided
to
the
generatorlshipper
sites
include:
a
a
a
a
e
e
8.0
Providing
users'
computers
with
the
necessary
W
l
S
client
files
Making
appropriate
entries
in
the
WlPP
W
l
S
to
establish
identifications
for
the
designated
sites
and
users
Providing
data
structure
tables
for
sites
to
populate
with
site
waste
data
(for
electronic
data
entry)
Providing
WWlS
database
user
training
(on
the
job
training)
for
generatorlshipper
site
data
entry
personnel
Providing
the
generator/
shipper
sites
with
a
user's
manual
Providing
site
support
visits
by
the
data
administrator
and
programming
support
personnel
Providing
telephone
support
each
workday
during
work
hours
Providing
the
site
with
an
acceptance
test
to
qualify
the
site
system
in
the
transmittal
of
data
from
the
site
to
the
WlPP
WWlS
EXCEPTIONS
AND
UNRESOLVED
SAFETY
QUESTION
DETERMINATIONS
16
WIPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
Requests
for
exceptions
(variances)
to
the
WlPP
operations
and
safety
requirements
must
be
formally
submitted
to
the
CAO
for
approval.
The
CAO
cannot
approve
exceptions
(variances)
to
requirements
that
are
controlled
by
others,
such
as
the
NRC
for
transportation,
or
the
EPA
and
the
NMED
for
the
RCRA
component
of
TRU
mixed
waste,
without
first
obtaining
changes
to
the
controlling
permits.
An
exception
may
be
allowable
since
the
stated
limit
is
an
average
based
on
the
average
concentration
in
a
room
divided
by
the
number
of
containers
emplaced
in
the
room.
The
typical
drum
Volatile
Organic
Compound
(VOC)
concentration
will
be
well
below
the
established
maximum
average
concentration.
An
evaluation
can
be
performed
at
the
time
of
the
generatots
request
for
the
exception
to
ensure
that
the
addition
of
a
drum
with
a
VOC
concentration
greater
than
the
maximum
average
will
not
cause
the
concentration
in
the
room
to
exceed
the
maximum
average
limit.
Unreviewed
Safety
Question
Determinations
are
performed
by
WID
per
WP
12
ARlOOI.
Unreviewed
Safety
Question
Determinations
are
conducted
to
determine
the
impact
of
proposed
waste
data
that
is
outside
the
current
limits
of
the
WAC
and
compares
the
impact
to
the
margin
of
safety
in
the
WlPP
Safety
Analysis
Report.
The
data
administrator,
upon
written
notification
of
a
CAO
approved
Exception
Request
and
receipt
of
an
acceptance
of
the
proposed
change
by
Environment,
Safety,
and
Health,
will
update
the
WWlS
WAC
Exception
Table
with
the
WAC
exception
number,
package
identification,
and
the
new
limits
for
the
field
allowed
in
the
exception.
9.0
DATA
CHANGE
CONTROL
The
data
administrator
is
responsible
for
WWlS
data
management
and
change
control.
The
W
I
S
has
several
methods
of
identifying,
documenting,
and
controlling
the
changing
of
generator/
shipper
site
waste
data.
These
methods
include:
Rejecting
container
data
not
accepted
by
WWlS
in
the
Characterization
Module
or
Certification
Module
(a
Bad
Data
Report
will
be
created,
explaining
the
reason
for
reject
ion)
Resubmitting
rejected
data
will
require
correction
and
resubmittal
to
the
WlPP
prior
to
further
consideration
a
?hanging
the
approval
status
after
completion
of
each
review
and
approval
stage,
defining
which
module
can
be
used
to
gain
access
to
the
data
Deleting
a
record,
if
a
record
change
is
required
by
the
generatorkhipper
after
the
approval
process
has
begun
(the
WIPP
data
administrator
deletes
the
record
after
recording
the
reason
for
the
deletion
in
the
Change
Log
and
places
a
copy
of
the
deleted
record
in
the
database
Change
Log
for
future
reference)
17
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
.
Recording
(automatically)
any
changes
made
to
WWlS
data
records
and
providing
a
Change
Log
Report
to
identify
changes
that
have
been
made
(Change
Log
records
will
be
maintained
by
the
database
and
archived
when
the
database
archive
copies
are
made)
10.0
WWlS
PROGRAM
REPORTS
The
W
l
S
is
designed
to
produce
standardized
reports
for
various
uses.
The
WWIS
reports
are
listed
in
WP
05
WA.
01.
These
reports
will
satisfy
routine
needs,
but
specialized
reports
may
occasionally
be
required
of
the
W
l
S
data.
Provisions
are
available
for
performing
queries
to
provide
information
for
nonstandard
data
requests.
These
requests
will
be
processed
by
the
data
administrator
on
the
basis
of
the
nature
of
the
request,
the
availability
of
resources
to
perform
the
request,
and
the
approval
of
Waste
Operations
management.
10.1
Printina
Standardized
Reports
Access
to
WWlS
database
standardized
reports
is
controlled
by
the
access
authorizations
assigned
to
users.
The
WWlS
data
administrator
will
print
and
provide
copies
of
reports
for
WIPP
personnel
who
do
not
have
access
authorization
to
the
WWlS
information.
The
WWlS
data
administrator
will
print
and
issue
reports
to
organizations
outside
of
WIPP
only
with
the
express
written
direction
of
the
CAO
or
the
reports
may
be
sent
to
the
CAO
representative
for
distribution.
Such
written
requests
for
distribution
will
be
filed
by
the
data
administrator
for
future
reference,
10.2
Shipment
Summarv
ReDort
The
Shipment
Summary
Report
will
be
generated
at
the
request
of
the
Waste
Handling
engineer
after
all
of
the
shipment
information
has
been
received
by
the
WWlS
and
will
include
the
information
necessary
for
acceptance
at
the
WIPP.
This
information
will
include
shipment
number,
TRUPACT
I1
number,
assembly
number,
inner
containment
vessel
closure
date,
shipment
certification
date,
shipment
date,
weight,
surface
dose
rate,
identification
numbers
of
each
container
in
the
shipment,
total
activity
level,
nuclides
(by
TRUPACT
It),
and
the
Hazardous
Waste
Manifest
Number
(if
assigned)
to
the
shipments.
18
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
10.3
Nuelide
Report
The
Nuclide
Report
lists
the
radionuclides
contained
in
the
waste
disposed
at
WlPP
at
the
time
that
the
report
is
generated
and
includes
the
total
activity
of
individual
radionuclides
as
well
as
the
total
repository
activity.
The
report
is
organized
by
waste
type
(contact
handledhemote
handled),
using
selection
criteria
established
by
the
user,
such
as
nuclides
by
generator
during
a
specified
period,
or
all
actinides.
This
report
can
be
used
to
aid
in
EPA
reporting
and
assist
WIPP
personnel
in
organizing
data
requests
for
input
to
the
Decay
Module.
This
report
is
to
be
generated
by
WIPP
personnel
as
required.
10.4
Waste
Emdacement
ReDort
The
Waste
Emplacement
Report
is
generated
on
an
emplacement
period
basis
when
containers
have
been
emplaced
or
otherwise
dispositioned
and
the
data
has
been
input
to
the
WWIS
from
the
barcode
reader
interface.
The
data
is
to
be
collected
by
container
(for
S
WBs
or
Ten
Drum
Overpacks)
or
assembly
number
(for
seven
packs).
This
report
will
be
generated
weekly
and
will
be
added
to
the
Operational
Log
and
retained
at
WlPP
for
the
operational
life
of
the
facility.
10.5
Headspace
Gas
Concentration
Report
The
Headspace
Gas
Concentration
Report
contains
the
average
concentration
of
all
headspace
analytes
in
a
particular
storage
room.
The
selection
criteria
is
for
all
containers
in
a
room
as
defined
by
actual
emplacement
information.
This
report
is
generated
on
demand.
10.6
Reaulatorv
Reportina:
Biennial
ReDortina
lnwt
Report
The
Biennial
Reporting
Input
Report
will
be
generated
annually
and
is
arranged
by
waste
type
for
each
generator
contributing
waste
to
WlPP
in
the
previous
year.
This
report
summarizes
the
amount
(weight
and
volume)
of
the
waste
received
from
each
generator
and
collects
all
of
the
EPA
hazardous
codes
to
provide
cross
correlation
in
the
various
reporting
schemes.
The
EPA
identification
of
each
waste
generator
is
included
along
with
the
Item
Description
Code
(or
other
local
code),
the
waste
matrix
code,
TRUPACT
if
Content
Code,
and
the
WlPP
waste
stream
identification.
This
report
is
intended
to
provide
input
to
WID
personnel
responsible
for
generating
the
Biennial
Report.
11
.O
WWlS
PROGRAM
RECORDS
Project
Record
Services
is
responsible
for
the
retention
of
records
generated
by
the
WlPP
WWIS
database
program.
Some
of
the
records
generated
by
this
program
will
be
retained
at
the
facility
as
a
part
of
the
operational
record
until
closure
of
the
facility.
19
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
Other
records
will
be
sent
to
records
storage.
Criteria
to
define
record
retention
times
are
listed
in
the
approved
Records
Inventory
and
Disposition
Schedule
and
the
implementing
procedures
for
each
document.
11.1
Backup
and
Archivina
Reauirements
The
WWIS
data
administrator
will
ensure
that
required
nightly
backups
of
system
information
are
performed.
The
W
l
S
data
administrator
will
use
this
backup
information
to
reconfigure
the
system
in
the
abnormal
event
of
a
system
failure
and
loss
of
system
data.
Nightly
backups
will
be
sent
out
of
the
building
to
a
backup
server
to
provide
for
the
event
of
catastrophic
hardware
failure.
In
the
event
of
a
system
failure,
the
W
l
S
data
administrator
is
responsible
for
evaluating
the
failure
event
and
determining
the
write
access
users
that
should
be
notified
of
the
failure
since
data
entered
on
the
day
of
the
failure
may
have
been
lost.
The
WWlS
data
administrator
will
create
quarterly
and
annual
archive
copies
of
the
database
information
and
will
provide
the
archive
copies
of
the
WWlS
database
to
Waste
Operations
for
inclusion
in
the
operating
record,
which
will
be
retained
for
the
life
of
the
facility.
12.0
SITE
DERIVED
WASTE
Waste
data
for
site
derived
waste
will
be
input
into
the
WWlS
by
the
Waste
Handling
engineer.
This
activity
will
be
performed
per
the
requirements
of
the
procedure
entitled
Site
Derived
Mixed
Waste
Handling,
WP
05
WH1036.
13.0
TRAINING
FOR
THE
WWlS
PROGRAM
This
section
outlines
the
type
of
training
that
each
type
of
WWIS
user
must
have,
incfuding
a
qualification
card
for
the
data
administrator@).
The
WWIS
data
administrator
qualification
card
specifies
the
required
reading,
prerequisite
training,
knowledge
requirements,
and
practical
application
requirements
needed
to
ensure
proper
use
of
the
W
I
S
by
the
data
administrator.
The
WlPP
Technical
Training
Section
administers
the
qualification
card
program
and
controls
the
WWSS
Qualification
Cards.
The
basis
of
the
remaining
WWlS
training
will
be
on
the
job
training.
Waste
Operations
on
the
job
WWlS
training
will
include
for
the
Waste
Handling
technicians'
and
Waste
Handling
engineers'
hands
on
use
of
the
system
to
gain
the
practical
application
knowledge
needed
to
operate
the
system.
20
WIPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
The
Configuration
Manager
will
receive
instruction
on
the
proper
use
of
the
WWlS
from
the
data
administrator
(the
Subject
Matter
Expert).
Software
configuration
management
training
required
for
the
Configuration
Manager
is
described
in
the
WlPP
Training
Program
(WP
14
TR.
O1)
and
Engineering
procedures.
The
data
administrator
will
be
qualified
per
the
criteria
listed
in
WlPP
RCRA
Part
B
Permit
Application,
DOEANIPP
91
005,
Revision
6,
Appendix
H
2;
and
training
will
be
documented
on
a
WWlS
Operator
Qualification
Card.
Waste
Handling
personnel
will
be
required
by
their
training
program
to
be
qualified
to
operate
the
WWIS.
This
training
will
be
documented
on
the
Waste
Handling
Qualification
Cards.
Other
personnel
will
be
instructed
through
on
the
job
training
in
the
use
of
the
WWlS
by
the
data
administrator
prior
to
granting
of
an
access
code
to
the
W
l
S
database.
14.0
REFERENCES
CAO
94
1010,
Transuranic
Waste
Characterization
Quality
Assurance
Program
Plan
CAO
95
1108,
WIPP
Waste
Information
System
Software
Quality
Assurance
Plan
DOEICAO
1996
21
84,
40
CFR
191,
Compliance
Certification
Application
for
the
Waste
Isolation
Pilot
Plant
DOENIPP
069,
Waste
Acceptance
Criteria
for
the
Waste
Isolation
Pilot
Plant
DOElWlPP
91
005,
WlPP
RCRA
Part
B
Permit
Application,
Chapter
C,
Waste
Analysis
Plan
SP
WO
WWIS
002,
WWIS
User's
Manual
WP
05
WA.
01
,
WlPP
TRU
Waste
Data
Management
Plan
WP
05
WA.
03,
Waste
Stream
Profile
Form
Review
and
Approval
Program
Attachment
1
WIS
Access
Request
Form
Date:
Requestor:
Phone:
Company:
E
Mail
Address:
Fax:
Organization
or
Site
Requesting
Access
To
W
I
S
:
Address:
City/
State:
Zip:
Period
of
Access
Authorization
Requested:
End
Date:
or
indefinite
TYPE
OF
USER:
GeneratodShipper
21
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
Characterization
Data
Official
Certification
Official
Shipping
Official
Regulatory
Compliance
Official
WlPP
Operations
Remote
Site
Query
Only
(your
site
data
only)
WlPP
Query
Only
RCRA
Permitting
Section
Staff
Quality
Engineers
Data
Administrator
Database
Administrator
Computer
Protection
Program
Manager
System
Administrator
REASON
FOR
ACCESS:
Generatorbhipper
data
input
for
review
and
approval
WlPP
employee
assigned
WlPP
duties
Regulatory
Compliance
oversight
Quality
Assurance
oversight
External
analysis
Other:
Signature
of
Requestor:
Site
TRU
Steering
Committee
Member.
Data
Administrator
FOR
WlPP
APPROVAL
USE
ONLY
Date
Waste
Operations
Manager
Date
Assigned
User
ID:
Assigned
Site
IO:
Assigned
Password
ID:
Assigned
Database
ID:
Page
2
of
1
fn
Q)
>
Q)
J
L
Q)
fn
3
f
I
(Y
w
S
Q)
f
L
u
I
cr:
h
(u
m
u
c
b
E
>
e
9,
(u
WlPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
Attachment
3
WWIS
Access
Notification
Form
Date:
Phone:
Site:
Requestor:
Requestor
Organization:
Address:
WWlS
ACCESS:
Approved
Rejected
WIPPWID
Waste
Operations
Data
Administrator:
Date:
Signature
Attachment:
WWlS
Access
Request
Form
Page
1
of
I
24
WIPP
Waste
Information
System
Program
WP
05
WA.
02,
Rev.
0,
Chg.
2
Attachment
4
Shipping
Review
of
Cellulose,
Plastics
and
Rubber
Page
1
of
1
25
Selection
Criteria
Container
Number
57023
Site
Id
%
Wastestream
%
Data
Status
Code
%
Waste
Container
Data
Report
WlPP
Waste
Information
System
Waste
Isolation
Pilot
Plant
Paae2af5
Waste
Container
Information
Cntr
Num
:
57023
Site
Id
:
Data
Status
Code
:
LA
LOS
A
M
O
S
NATIONAL
LABORATORY
Shipment
Data
Approved
by
WlPP
Waste
Stream
Profile
:
LA
TA
55
43.01
Type
Code
:
2
SWB
WAC
Ex.
#
:
Cert
Date
:
03/
08/
1999
Cert
Site
:
WACRev#:
5
LA
LOS
ALAMOS
NATIONAL
LA
Generator
Site
:
IDC
Code
:
LA
LOS
ALAMOS
NATIONA
Matrix
Code
:
S5400
Trucon
Code
:
LA125A
Shipping
Category
:
111.1
C1
Pcb
Conc(
Ppm)
:
0
Decay
Heat
Uncert
(Watts)
:
Decay
Heat
(Watts)
:
.206
.0336
Closure
Date
:
05/
27/
1998
Vent
Date
:
0212411994
Filter
Install
Date
:
05/
27/
1998
Filter
Model
Number
:
NF013
Aspiration
Id
:
3
Gas
Gen
Rate
:
Gas
Hyd
Meth
Gen
Rate
:
Gas
Gen
Comp
Date
:
Packaging
Num
:
128
Shipment
Num
:
LAO0001
Assembly
Id
:
1288
Overpack
Cntr
Num
:
Overpack
Cntr
Type
:
Radionuclide
Description
Handling
Code
:
CH
Waste
Type
Code
:
TRU
Wst
Strrn
Bir
Id
:
T
004
Wst
S
t
n
Mwir
Id
:
0.00
TN
Alpha
Act
(Cii
:
TN
Alpha
Act
Uncert
(Ci)
:
Tru
Alpha
Act
Conc
(CYg)
:
TN
Alpha
Act
Conc
Uncert
(Cilg)
:
Pu239
Eq
Act
(PE
Ci)
:
Pu239
Fiss
Grn
Eq
(Fge)
:
Pu239
Fiss
Gm
Eq
Uncert
(Fge)
:
Layers
Of
Packaging
:
1
Fill
Factor
(%)
:
44
Liner
Type
:
Liner
Punctured
:
Gross
Weight
(Kg)
:
424.9
Gross
Weight
Uncert
(Kg)
:
Alpha
Surf
Cont
(dpm/
lOOcm2)
:
BG
Surf
Cont
(dpm/
100cmZ)
:
Bg
Dose
Rate
(rnrerdhr)
:
Neut
Dose
Rate
(rnrem/
hr)
:
Total
Dose
Rate
(mrem/
hr)
:
1.4
7
f
2
0
0
0
Cntr
Disposal
Date
:
Cntr
Status
Code
:
PRE
6.160E+
OO
2.010E+
00
4.468E
05
1
458E
05
5.61
*I
1
04
Nuclide
Information
Activity(
Ci)
Activity
Uncert(
Ci)
Mass(
G)
Mass
Uncert(
G)
pu
238
PU
240
PU
241
PU
242
PU
239
AM
24
1
NP
237
PLUTONIUM
238
PLUTONIUM
240
PLUTONIUM
241
PLUTONIUM
242
PLUTONIUM
239
AMERICIUM
241
NEPTUNIUM
237
6.15
.00183
.000003
.000007
.00434
.00421
.oooooo
1.005
.0076
.000001
.000002
.00113
.00284
.oooooo
.356
00794
001
12
00
1
68
.069
00121
.000602
.Ea
.0331
000212
000475
01
795
.00082
AM0158
Waste
Container
Data
Report
WlPP
Waste
Information
System
Waste
isolation
Pilot
Plant
Page
3
of
5
Waste
Container
Information
Cntr
Num
:
57023
Site
Id
:
Data
Status
Code
:
Type
Code
:
LA
LOS
ALAMOS
NATIONAL
LABORATORY
Shlpment
Data
Approved
by
WlPP
2
SWB
Waste
Stream
Profile
:
LA
TA
5543.01
Nuclide
information
Mass
Radionuclide
Description
Activity(
Ci)
Activity
Uncer&(
Ci)
Mass(
G)
Uncert(
G)
U
234
URANIUM
234
~~
.00047
.000133
.0744
.02095
Waste
Mat1
Parm
Radio
Assay
Method
Material
Parameters
Information
Description
Weight(
Kg)
RUBBER
4.39
IRON
BASE
METAL
ALLOYS
114.15
OTHER
M
ETAUALLOYS
.06
CELLULOSICS
1.55
PLASTICS
18.1
FRAM
PAN
Method
Id
RTRM
VISUAL
Assay
Methods
Information
Description
Assay
Date
Description
PC/
GAMMA
ISOTOPIC
RATIO
SYSTEM
PASSIVE/
ACTIVE
NEUTRON
COUNTER
Characterization
Methods
Information
MOBILE
RTR
@
LANL
VISUAL
CHARACTERIZATION
METHOD
Sample
Id
:
H
8FEB0413.
D
Layer
No
Sampled
:
0
Sample
information
041301.
l998
04/
30/
1998
Charz
Method
Date
o
i
11
311
998
0312711
990
Sample
Type
:
HGHM
Date
Sampled
:
02/
04/
1998
Sample
Amounts
Analyte
Method
Concentration
Date
Analyzed
Detection
Method
1333
74
0
HYDROGEN
74
82
8
METHANE
Sample
Id
:
V
8FEB0413.
D
Layer
No
Sampled
:
0
520.1
.02
Volume
02/
04/
1998
U
520.1
.02
Volume
02/
04/
1998
U
%
Yo
Sample
Type
:
HGVO
Date
Sampled
:
Q2/
04/
1998
Waste
Container
Data
Report
WlPP
Waste
Information
System
Waste
Isolation
Pilot
Plant
Page
4
of
5
~~
~~~
~
Waste
Container
Information
Cntr
Num
:
57023
Site
Id
:
Data
Status
Code
:
Type
Code
:
LA
LOS
ALAMOS
NATIONAL
LABORATORY
Shipment
Data
Approved
by
WlPP
2
SWB
Waste
Stream
Profile
:
LA
TA
5543.01
Sample
Id
:
V
8FEB0413.
D
Layer
No
Sampled
:
0
Sample
Information
Sample
Type
:
HGVO
Date
Sampled
:
02/
04/
1998
Sample
Amounts
Analyte
Method
100
41
4
ETHYL
BENZENE
107
06
2
1,2
DICHLOROETHANE
108
10
1
METHYL
ISOBUTYL
KETONE
108
67
8
1,3,5
TRIMETHYLBENZENE
108
88
3
TOLUENE
108
90
7
CHLOROBENZENE
10838311
06423
M,
P
XYLENE
110
82
7
CYCLOHEXANE
127
1
8
4
TETRACHLOROETHYLENE
156
59
2
CIS
1
,ZDICHLOROETHYLENE
56
23
5
CARBON
TETRACHLORIDE
60
29
7
ETHYL
ETHER
67
56
1
METHANOL
67
64
1
ACETONE
67
66
3
CHLOROFORM
71
36
3
BUTANOL
71
43
2
BENZENE
71
55
6
1,
l
,I
TRICHLOROETHANE
75
09
2
METHYLENE
CHLORIDE
75
25
2
BROMOFORM
75
34
3
1,
l
DICHLOROETHANE
75
35
4
1,
l
DICHLOROETHY
LENE
76
13
1
1,1,2
TRICHLORO
I
,2,2
TRIFLUOROETHANE
78
93
3
METHYL
ETHYL
KETONE
79
01
6
TRICHLOROETHYLENE
79
34
5
I
,I
,2,
ZTETRACHLOROETHANE
9547
6
O
XYLENE
95
63
6
1,2,4
TRIMETHYLBENZENE
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
430.1
Concentration
Date
Analyzed
Detection
Method
2.43
Ppm
2.42
Ppm
25.5
Ppm
3.71
Ppm
2.07
Ppm
2.3
Ppm
4.9
Ppm
2.39
Ppm
1.83
Ppm
2.31
Ppm
1.88
Ppm
2.66
Ppm
15.1
Ppm
20.5
Ppm
1.76
Ppm
21.8
Ppm
1.52
Ppm
2.01
Ppm
1.71
Ppm
2.65
Ppm
2.23
Ppm
.92
Ppm
1.91
Ppm
18.9
Ppm
1.72
Ppm
2.49
Ppm
2.54
Ppm
3.47
Ppm
Comment
Information
Comment
Type
Comments
.
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
04/
1998
02/
0411
998
ozo4/
199a
02/
0411
998
U
U
U
U
U
U
U
U
u
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
Waste
Container
Data
Report
WlPP
Waste
Information
System
Waste
Isolation
Pilot
Plant
Page
5
of
5
Waste
Container
Information
Cntr
Num
:
57023
Site
Id
:
Data
Status
Code
:
Type
Code
:
LA
LOS
ALAMOS
NATIONAL
LABORATORY
Shipment
Data
Approved
by
WlPP
2
SWB
Waste
Stream
Profile
:
LA
TA
5543.01
Comment
Information
Comment
Type
Comments
~
~
~
~
WASTE
CONTAINER
ORIGINAL
DRUM
REPACKAGED
INTO
MULTIPLE
DRUMS,
THEN
INDIVIDUAL
DAUGHTER
DRUMS
REPACKAGED
INTO
SWB
WITH
DRUM
LID
REMOVED
&
3
EMPTY
DRUMS
FILTER
DATE
AND
CLOSURE
DATE
ARE
FOR
SWB
CONTAINER,
VENT
DATE
IS
FOR
WASTE
VENTING
WHICH
IS
THE
DATE
ORIGINAL
DRUM
WAS
VENTED,
RTRM
ON
ORIGINAL
DRUM
BEFORE
REPACKAGING
DAUGHTER
DRUM
WAS
USED
FOR
RADIOASSAY
ORIGINAL
VENTED
&
FILTERED
DRUM
WAS
REPACKAGED
AFTER
HGAS
RADIONUCLIDES
49CFR173.433F
ISOTOPE
LIST
FOR
SHIPPING
PAPERS
&
LABELING:
PU
238
GENERAL
COMMENTS
ASSAY
METHODS
CHAR2
METHODS
Selection
Criteria
Site
id
:
Nuclide
:
Panel
Number
:
Room
Number
:
Handling
Code
:
Show
Uncertainty
:
TRU
Nuclides
Only
:
EPA
Tracked
Nuclides
Only:
%
%
%
%
%
YES
96
Y
WlPP
Waste
Information
System
Nuclide
Report
Waste
Isolation
Mot
Plant
Page
2
of
2
Panel
Number:
1
Room
Number:
1
Activity
Activity
Mass
Radionuclide
(Ci)
Uncert
(Ci)
Mass(
G)
Uncert(
G)
PU
239
PLUTONIUM
239
61
3
63.05
68
63.5
Totals:
613
63.05
68
63.5
Panel
Number:
1
Room
Number:
2
Activity
Activity
Mass
Radionuclide
.
(Ci)
Uncert
(Ci)
Mass(
G)
Uncert(
G)
AM
241
AMERICIUM
241
.017937191
7
.0012559
.005171
PU
238
PLUTONIUM
238
.047886207
7
.003351
002767
PU
239
PLUTONIUM
239
4.02001
3791
10
3.07141
19.22
PU
240
PLUTONIUM
240
.233645937
7
.01636
1.0151
PU
242
PLUTONIUM
242
Panel
Number:
1
.00002954
7
.000002068
007454
Totals:
4.319512666
38
3.092378968
20.250492
Room
Number:
8
Activity
Activity
Mass
Radionuclide
(Ci)
Uncert
(Ci)
Mass(
G)
Uncet
t(
G)
PU
239
PLUTONIUM
239
14
6.1
134
6.1
Totals:
14
6.1
134
6.1
Panel
Number:
1
Room
Number:
7
Activity
Activity
Mass
Radionuclide
(Ci)
Uncert
(Ci)
Mass(
G)
Uncert(
G)
U
238
URANIUM
238
.00000068
2
0
2
Panel
Number:
1
Totals:
.00000068
2
0
2
Room
Number:
7
Activity
Activity
Mass
Mass(
G)
Uncert(
G)
Radionuclide
(Ci)
Uncert
(Ci)
AM
241
AMERICIUM
241
1.487297834
35.33348
.402953
.124164
46.487302
032572
PU
238
*
PLUTONIUM
238
80.452481581
35.181366
PU
239
PLUTONIUM
239
PU
240
PLUTONIUM
240
128.099689442
38.7763
1805.07754
191
.I21
5.380749684
35.86457
15.3752
1
1.2917
PU
242
PLUTONIUM
242
.0004a9627
35.000065651
.064286713
.075494
~~
Totals:
215.420708168
180.155781651
1867.40728171
202.64493
Grand
Totals:
846.740221
514
289.305781651
2072.49966068
294.495422
Working
Copy
Delaware
Basin
Drilling
Surveillance
Plan
WP
02
PC.
02.
Rev.
0
CCA.
40
CFR
Part
191,
Compliance
Certification
Application
for
the
Waste
Isolation
Pilot
Plant.
DOEKAO
1996
2184.
October
1996,
United
States
Department
of
Energy,
Waste
isolation
Pilot
Plant,
Carlsbad
Area
Office,
Carlsbad,
New
Mexico.
6
Working
Copy
.
Delaware
Basin
Drilling
Surveillance
Plan
WP
02
PC.
02,
Rev.
0
FIGURE
1
SURVEILLANCE
AREAS
WITHIN
THE
DELAWARE
BASIN
I
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24,
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WASTE
ISOLATION
PILOT
PLANT
DELAWARE
BASIN
DRILLING
SURVEILLANCE
PROGRAM
ANNUAL
REPORT
997
throuph
SEPTEMBER
I
998
DBANNUALREPORT
Table
of
Contents
1.0
Delaware
Basin
Drilling
Surveillance
Program
2.0
Background
Appendix
DEL
Data
DEL.
5.1.3
Drilling
Fluids
DEL.
7
DEL.
7.1
Regulatory
Context
DEL.
7.2
Shallow
Drilling
Events
DEL.
7.2.1
Water
Wells
DEL.
7.2.2
Potash
Coreholes
DEL.
7.2.3
Sulhr
Coreholes
Inadvertent
and
Intermittent
Intrusion
by
Drilling
DEL.
7.3
Deep
Drilling
Events
DEL.
7.4
DEL.
7.5
DEL.
7.6
Borehole
Permeability
Assessment
Rate
of
Drilling
in
the
Basin
Pressurized
Brine
Encounters
Within
the
Delaware
Basin
3.0
Schedule
Delaware
Basin
Drilling
Surveillance
Program
4.0
1998
Updates
Delaware
Basin
Drilling
Surveillance
Program
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
Drilling
Fluids
Shallow
Drilling
Events
Deep
Drilling
Events
Rate
of
Drilling
in
the
Basin
New
Mexico
Well
Count
and
Intrusion
Rate
Pressurized
Brine
Encounters
Within
the
Delaware
Basin
Borehole
Permeability
Assessment
Borehole
Depths
and
Diameters
New
Drilling
Technology
5.0
Summary
1998
Delaware
Basin
Drilling
Surveillance
Program
1
3
3
4
4
4
4
5
5
5
5
9
13
14
14
14
14
14
15
16
.
17
17
17
17
17
6.0
Quality
Assurance
18
7.0
References
19
Figure
1
Figure
2
Figure
3
Figure
4
Figure
5
Figure
6
Table
DEL
3
Table
DEL
4
Table
DEL
5
Table
DEL
6
Table
DEL
7
List
of
Figures
WIPP
Site,
Delaware
Basin,
and
Surrounding
Area
20
Minimum
Oiiand
Gas
Well
Plugging
Requirements
in
the
Delaware
Basin
21
Standard
Oil
and
Gas
Well
Plugging
Practices
in
the
Potash
Resource
Area
of
the
Delaware
Basin
Typical
Well
Structure
and
General
Stratigraphy
Near
the
WIPP
Site
Stratigraphy
for
W
P
Site
and
Surrounding
Area
Delaware
Basin
Drilling
Surveillance
Program
Schedule
FY
98
and
FY
99
List
of
Tables
Boreholes
Within
the
Delaware
Basin
Number
of
Shallow
and
Deep
Boreholes
Within
the
Delaware
Basin,
by
Resource
or
Type
Number
of
Shallow
Boreholes
Per
Square
Kilometer
in
the
Delaware
Basin,
by
Resource
or
Type
Number
of
Deep
Boreholes
Per
Square
Kilometer
in
the
Delaware
Basin,
by
Resource
or
Type
Number
of
Boreholes
Per
Square
Kilometer
to
be
Used
in
Performance
22
23
24
25
6
7
8
8
Assessment
Calculations
9
1.0
DELA
WARE
BASIN
DRILLING
SURVEELANCE
PROGRAM
The
Delaware
Basin
Drilling
Surveillance
Program
(DBDSP)
is
designed
to
monitor
resource
extraction
activities
in
the
vicinity
of
the
Waste
Isolation
Pilot
Plant
(WIPP).
This
program
is
based
on
Environmental
Protection
Agency
(EPA)
requirements.
The
EPA
environmental
standards
for
the
management
and
disposal
of
Transuranic
(TRU)
radioactive
waste
are
codified
in
40
CFR
Part
191
(EPA
1993).
Subparts
B
and
C
of
the
standard
address
the
disposal
of
radioactive
waste:
The
standard
requires
the
Department
of
Energy
(DOE)
to
demonstrate
the
expected
performance
of
the
disposal
system
using
a
probabilistic
risk
assessment
or
performance
assessment
(PA).
This
PA
must
show
that
the
expected
repository
performance
will
not
release
radioactive
material
above
limits
set
by
the
EPAs
standard.
This
assessment
must
include
the
consideration
of
inadvertent
drilling
into
the
repository
at
some
hture
time.
The
EPA
provided
criteria
in
40
CFR
0
194.33
that
addressed
the
consideration
of
future
deep
and
shallow
drilling
in
PA.
These
criteria
lead
to
the
formulation
of
conceptual
models
that
incorporate
the
effects
of
these
activities.
These
conceptual
models
use
parameter
values
drawn
fiom
the
databases
in
Appendix
DEL
of
the
Compliance
Certification
Application
(CCA).
Appendix
DEL
databases
contain
resource
extraction
information
gathered
as
a
precursor
to
the
DBDSP.
Examples
of
information
of
interest
include
the
drilling
rate
of
deep
and
shallow
boreholes
and
data
relating
to
these
holes
such
as
diameter.
In
accordance
with
these
criteria
the
DOE
used
the
historical
rate
of
drilling
for
resources
in
the
Delaware
Basin
to
caiculate
a
fbture
drilling
rate.
In
particular,
in
calculating
the
frequency
of
future
deep
drilling,
40
CFR
9
194.33(
b)(
3)(
1)
(EPA
1996)
provided
the
following
guidance
to
the
DOE:
idenafy
deep
drilling
that
has
occurred
for
each
resource
in
the
Delaware
Basin
over
the
past
100
years
prior
to
the
time
at
which
a
compliance
application
is
prepared.
The
DOE
used
the
historical
record
of
deep
drilling
for
resources
below
2,150
feet
(656
meters)
that
has
occurred
over
the
past
100
years
in
the
Delaware
Basin.
2,150
feet
was
chosen
because
this
is
the
depth
to
the
repository
and
the
repository
is
not
directly
breached
by
boreholes
less
than
this
depth.
In
the
past
100
years,
deep
drilling
occurred
for
oil,
gas,
potash,
and
s
u
l
k
exploration.
These
drilling
events
were
used
in
calculating
the
rate
of
deep
drilling
within
the
controlled
area
(the
sixteen
section
Land
Withdrawal
Boundary
of
W
P
)
and
throughout
the
basin
in
the
future,
as
discussed
in
Appendix
DEL
of
the
CCA.
Historical
drilling
for
purposes
other
than
resource
exploration
and
recovery
(such
as
W
P
site
investigation)
were
excluded
from
the
calculation
in
accordance
with
guidance
provided
in
40
CFR
194.33.
In
calculating
the
fiequency
of
hture
shallow
drilling,
40
CFR
4
194.33(
b)(
4)(
1)
states
that
the
DOE
should:
idenufy
shallow
dnlling
that
has
occurred
for
each
resource
in
the
Delaware
Basin
over
the
past
IO0
years
prior
to
the
time
at
which
a
compliance
application
is
prepared.
1
Additional
criterion
for
calculation
of
fbture
shallow
drilling
rates
is
provided
in
40
CFR
6
194.3
3
(b)(
4)(
iii):
in
considering
the
hstorical
rate
of
all
shallow
drilling,
the
Department
may.
if
justified.
consider
only
the
hstorical
rate
of
shallow
dnliing
for
resources
of
similar
type
and
quality
to
those
in
the
controlled
area.
The
only
resources
present
at
shallow
depths
(less
than
2,150
feet
[655
meters]
below
the
surface)
within
the
controlled
area
are
water
and
potash.
Thus,
consistent
with
40
CFR
0
194.33(
b)(
4),
the
DOE
used
the
historical
record
of
shallow
drilling
associated
with
water
and
potash
extraction
in
the
Delaware
Basin
to
calculate
the
rate
of
shallow
drilling
within
the
controlled
area.
The
EPA
provides
fkrther
criteria
concerning
the
analysis
of
the
consequences
of
fUture
drilling
events
in
performance
assessments
in
40
CFR
tj
194.33(
c)(
EPA
1996).
Consistent
with
these
criteria,
the
following
parameters
regarding
drilling
were
considered
in
the
performance
assessment
as
documented
in
Appendix
DEL
of
the
CCA:
types
of
drilling
fluids
*
amounts
of
drilling
fluids
borehole
depths
borehole
diameters
borehole
plugs
fraction
of
such
boreholes
that
are
sealed
by
humans
0
natural
processes
that
will
degrade
plugs
*
instances
of
encountering
pressurized
brine
in
the
Castile
The
DOE
will
continue
to
provide
surveillance
of
the
drilling
activity
in
the
Delaware
Basin
in
accordance
with
the
criteria
established
in
40
CFR
194
during
the
operational
phase
and
win
continue
until
the
DOE
and
the
EPA
agree
that
no
hrther
benefit
can
be
gained
from
continued
surveillance.
The
results
of
this
surveillance
activity
will
be
used
in
performance
assessment
calculations
performed
in
support
of
recertification.
The
purpose
of
the
Delaware
Basin
Drilling
Surveillance
Plan
is
to
provide
for
active
surveillance
of
drilling
activities
within
the
Delaware
Basin
(Figure
l),
with
specific
emphasis
on
the
nine
township
area
that
includes
the
Waste
Isolation
Pilot
Plant
(WIPP)
Site
(Figure
1).
The
surveillance
of
drilling
activities
will
build
on
the
data
presented
in
Appendix
DEL
and
comply
with
the
activities
presented
in
Appendix
DMP
of
the
CCA,
which
were
used
to
develop
modeling
assumptions
for
PA.
The
collection
of
additional
information
on
drilling
patterns
and
practices
in
2
the
Delaware
Basin
will
be
used
to
define
whether
the
drilling
scenarios
in
the
application
continue
to
be
valid
at
each
recertification
or
documentation
of
continued
compliance
for
the
WIPP.
Surveillance
of
drilling
activities
within
the
Delaware
Basin
will
be
implemented
no
later
than
at
the
beginning
of
the
operational
phase.
This
activity
will
continue
after
closure
for
100
years
or
until
the
DOE
can
demonstrate
to
the
EPA
that
there
are
no
significant
concerns
to
be
addressed
by
further
surveillance
(Section
7.1.4,
DOE
1996b).
Beginning
no
later
than
the
initiation
of
the
operational
phase
and
continuing
through
post
closure,
drilling
activities
within
the
Delaware
Basin
will
be
tracked
using
commercially
available
databases.
Drilling
activities
as
related
to
hydrocarbon
resources,
potash
boreholes,
and
water
wells
that
occur
within
the
nine
township
area,
in
which
the
W
P
Site
is
centered,
will
be
more
rigorously
monitored
using
the
commercial
databases,
visual
surveillances,
and
the
drilling
records
maintained
by
both
state
and
federal
organizations.
2.0
BACKGROUND
APPENDIX
DEL
1996
DATA
The
information
and
tables
presented
in
this
section
are
from
Appendix
DEL
of
the
Compliance
Certification
Application
(DOE
1996a)
submitted
to
the
EPA
in
October
1996.
This
information
was
used
in
the
PA
that
supported
the
first
WIPP
certification
to
the
EPA
disposal
standard.
The
basis
of
the
DBDSP
is
to
provide
annual
accounting
on
the
specific
items
mentioned
in
this
section.
The
well
counts
listed
in
Tables
DEL
4,
DEL
5,
and
DEL
6
were
used
to
calculate
the
intrusion
rate
for
PA.
Table
DEL
7
shows
the
results
of
those
calculations.
Section
4.0
of
this
report
will
address
the
specific.
items
from
this
section
with
updated
counts
fiom
1996
and
new
calculations
as
necessary.
DEL.
S.
1.3
Drilling
fluids
are
an
integral
part
of
every
drilling
program.
Rotary
drilling
rigs
and
drill
bits
would
not
be
able
to
hnction
without
drilling
fluids,
or
mud
as
it
is
most
commonly
referred
to
in
the
oil
and
gas
industry.
The
drilling
fluids
are
circulated
continuously
through
the
drill
pipe,
down
hoie
to
the
bit
nozzles,
and
back
up
the
annulus
to
the
mud
tanks
or
pits
on
the
surface.
The
drilling
fluids
pumped
through
the
bit
nozzles
cause
the
bit
cutters
to
turn
which,
a'
4g
with
the
turning
of
the
drill
stem,
cuts
the
hole.
As
the
fluid
moves
out
through
the
drill
bit,
a
i
carries
the
cuttings
made
by
the
bit
to
the
surface.
Drilling
fluids
serve
several
other
functions
as
well.
They
lubricate
and
cool
the
bit,
assist
in
bringing
heavier
cuttings
to
the
surface,
aid
in
controlling
pressures
that
may
exist
in
formations
that
are
penetrated
by
the
bit,
and
serve
as
a
source
of
downhole
information.
There
are
a
variety
of
drilling
fluids
used
in
Delaware
Basin
drilling.
Most
rotary
drilling
operations
use
saturated
brine
(10
to
10.5
pounds
per
gallon)
as
a
drilling
fluid
until
reaching
the
Bell
Canyon
Formation,
where
intermediate
casing
is
set.
The
brine
has
most
often
been
3
manufactured
by
injecting
fresh
water
into
the
Salado
Formation
and
then
pumping
the
water
back
to
the
surface.
This
process
enables
drillers
to
have
a
constant
source
of
quality
brine
water.
Saturated
brine
is
used
heavily
in
drilling
because
the
intermediate
string
passes
through
the
Salado
Formation,
which
is
salt.
Fresh
water
will
cause
washout
of
the
salt.
Once
drilling
is
continued
in
harder
rock
formations,
such
as
the
Bell
Canyon
Formation,
materials
such
as
bentonite,
barite,
or
attapulgite
are
often
added
to
the
drilling
fluid.
All
of
these
materials
will
increase
viscosity
and
add
weight
to
the
drilling
fluid
column.
In
recent
years,
the
increased
capacities
of
circulating
systems
and
improvements
in
pumping
technology
have
resulted
in
greater
precision
in
controlling
mud
flow.
Present
day
drilling
fluids
have
been
formulated
using
complex
chemistry
to
combat
specific
downhole
problems.
These
additions
to
fluid
technology
allow
the
driller
to
vary
chemical
and
physical
properties
of
the
drilling
fluid
many
times
if
necessary
while
drilling
an
oil
or
gas
well.
DEL.
7
Inadvertent
and
Intermittent
Intrusion
by
Drilling
Information
pertinent
to
the
assessment
of
the
likelihood
of
inadvertent
intrusion
into
the
repository
is
presented
in
this
section.
DEL.
7.1
Regulatory
Context
The
EPA
criteria
for
certification
of
WIPP's
compliance
with
the
40
CFR
Part
191
disposal
regulations
state
that
performance
assessments
examine
deep
and
shallow
drilling
that
may
potentially
affect
the
disposal
system
during
the
10,000
year
regulatory
time
frame
(40
CFR
tj
194.33[
a]
and
tj
194.54[
b][
l]).
Deep
drilling
is
defined
by
the
criteria
as
drilling
events
that
reach
or
exceed
2,150
feet
(655
meters)
below
the
surface
while
shallow
drilling
means
drilling
events
that
do
not
reach
a
depth
of
2,150
feet
(655
meters)
(6
194.2).
The
total
rate
of
deep
drilling
must
be
calculated
as
the
sum
of
the
rates
of
deep
drilling
for
each
resource
in
the
Delaware
Basin
over
the
past
100
years.
The
total
rate
of
shallow
drilling
must
be
calculated
as
the
sum
of
the
rates
of
shallow
drilling
over
the
same
time
period
for
each
resource
in
the
Delaware
Basin
that
is
of
similar
type
and
quality
as
the
resources
in
the
W
P
controlled
area.
DEL.
7.2
Shallow
Drilling
Events
The
majority
of
shallow
holes
are
composed
of
water
wells,
potash
cbreholes,
and
sulkr
coreholes.
The
identification,
location,
and
depth
of
the
shallow
boreholes
in
the
Delaware
Basin
have
been
taken
from
existing
commercial
databases
and
maps.
The
data
gathered
on
shallow
boreholes
was
taken
directly
from
commercial
databases
and
BLM
records
as
described
below.
DEL.
7.2.1
w
r
W
e
h
Information
on
water
wells
in
the
Delaware
Basin
was
obtained
from
a
commercial
database
developed
by
Whitestar
Corporation
of
Englewood,
Colorado.
4
DEL.
7.2.2
Potashew
Information
on
potash
coreholes
in
the
Delaware
Basin
was
compiled
from
BLM
records.
DEL.
7.2.3
Mfu
r
Coreho
la
Sulfbr
corehole
information
was
obtained
from
a
commercial
database
developed
by
Whitestar
Corporation
of
Englewood,
Colorado,
and
the
Petroleum
Information
Corporation
of
Denver,
Colorado.
DEL.
7.3
Deep
Drilling
Events
Only
the
drilling
of
a
deep
well
could
result
in
inadvertent
human
intrusion
into
the
WIPP
repository.
The
only
known
wells
that
can
be
classified
as
deep
are
oil
and
gas
wells.
Information
on
the
identification,
location,
and
depth
of
the
deep
boreholes
in
the
Delaware
Basin
has
been
derived
from
existing
commercial
databases
and
maps.
The
data
gathered
on
the
deep
oil
and
gas
boreholes
are
available
from
several
commercial
sources.
To
assure
the
accuracy
of
these
commercial
databases
and
maps,
and
obtain
the
best
possible
count
of
deep
wells
in
the
basin,
these
commercial
sources
were
verified
against
one
another.
The
data
sources
selected
for
determining
the
number
of
oil
and
gas
wells
in
the
DeIaware
Basin
were
maps
obtained
fiom
the
Midland
Map
Company
(MMC)
and
a
database
obtained
fiom
the
Petroleum
Information
Corporation
(PI).
Both
the
MMC
and
PI
obtained
well
records
from
the
NMOCD
and
the
Railroad
Commission
of
Texas
OGD.
These
companies
have
a
reputation
for
data
reliability;
the
information
they
provide
is
regarded
as
a
standard
within
the
industry.
However,
these
companies
do
not
provide
any
warranty
on
the
accuracy
or
the
completeness
of
the
data.
It
is
not
considered
economically
feasible
to
validate
these
data.
The
process
of
validating
the
data
would
require
field
verification
of
wells
in
an
area
covering
approximately
8,910
square
miles
(23,077
square
kilometers)
as
well
as
a
comparison
of
NMOCD
and
BLM
records
with
the
private
records
of
the
various
oil
and
gas
companies.
While
it
was
not
considered
feasible
to
vaiidate
the
original
data,
it
was
considered
reasonable
to
determine
a
verifiable
deep
well
count.
By
comparing
the
two
selected
commercial
sources
of
data,
a
count
of
deep
wells
in
the
Delaware
Basin
has
been
prepared.
In
comparing
the
PI
database
to
the
MMC
maps,
some
wells
were
found
to
be
identified
either
in
the
database
or
on
the
maps,
but
not
in
both
sources.
The
well
count
presented
here
was
derived
using
aIl
wells
in
the
PI
database
plus
the
wells
identified
on
the
MMC
maps
that
were
not
in
the
PI
database.
DEL.
7.4
Rate
of
Drilling
in
the
Basin
The
number
of
boreholes
listed
in
the
PI
database
and
the
number
of
boreholes
shown
on
the
5
MMC
map
but
not
listed
in
the
PI
database
are
provided
in
Table
DEL
3.
In
addition,
the
number
of
shallow
and
deep
boreholes
created
in
the
Delaware
Basin
over
the
past
100
years
is
shown
by
type
of
borehole
in
Table
DEL
4.
En
the
case
of
water
wells,
the
available
data
do
not
include
the
depths
of
all
of
the
water
wells
shown
in
the
database.
To
amve
at
an
estimate
of
the
total
number
of
deep
and
shallow
water
weils,
the
ratio
of
known
deep
wells
(that
is,
those
2,150
feet
[656
meters]
or
greater)
versus
known
shallow
water
wells
was
calculated
and
applied
to
the
total
number
ofwater
wells
shown
in
the
database.
Table
DEL
3.
Boreholes
Within
the
Delaware
Basin,
1996
Boreholes
Shown
on
the
Midland
Map
But
Boreholes
Listed
Not
Listed
in
the
PI
Total
Number
of
Borehole
Type
in
the
PI
Database
Database
Boreholes
by
Type
Oil
Well
Gas
Well
OiUGas
Well
Abandoned
Wells
Dry
Hole
Jnjection
Well
Service
Well
Total
Hydrocarbon
Boreholes
Sulphur
Corehole
Potash
Corehole
Stratigraphic
and
Core
Test
Hole
'
Water
Well
Brine
Well
(Solution
Mining)
Total
Other
Boreholes
Hydrocarbon
Boreholes
5,728
37
1,569
2
11
0
167
1
3,453
56
72
2
147
0
.I50
98
Other
Resource,
Exploratory,
or
Test
Boreholes
5
84
0
925
0
1,271
'
0
2,311
1
0
0
5,092
0
5,765
1,571
14
168
3,509
74
147
11,248
584
925
1,271
'
2,3
11
1
5,092
Excluding
boreholes
dnlled
as
part
of
WIPP
site
characterization
programs
6
The
intrusion
rate
for
boreholes
drilled
per
square
kilometer
(0.39
square
mile)
over
10,000
years
has
been
calculated
using
the
borehole
counts
listed
in
Tables
DEL
4,
DEL
5,
and
DELQ.
The
calculated
rates
suggested
for
use
in
the
performance
assessment
are
shown
in
Table
DEL
7.
As
provided
by
40
CFR
3
194.33(
b)(
4)(
iii),
the
calculated
rate
for
shallow
boreholes
excludes
sulphur
holes
because
no
economically
extractable
sulphur
is
located
within
the
WIPP
land
withdrawal
area
(NMBMMR
1995).
In
addition,
consistent
with
EPA
guidance
in
the
ReJponse
to
Comments
Document
For
40
CFR
Pur?
194
(EPA
1996c)
(see
page
12
8,
last
paragraph),
both
shallow
and.
deep
holes
created
as
part
of
WIPP
site
characterization
efforts
have
been
excluded
from
the
count.
Based
on
the
data
provided
in
these
tables,
the
calculated
rates
are
21.821
shallow
holes
per
square
kilometer
(0.39
square
mile)
and
46.765
deep
holes
per
square
kilometer
(0.39
square
mile)
over
10,000
years.
Table
DEL4.
Number
of
Shallow
and
Deep
Boreholes
Within
the
Delaware
Basin,
by
Resource
or
Type,
1996
1
Borehole
Type
Shallow
Borehole
Deep
Borehole
'
Hydrocarbon
Borehole
608
Sulphur
Corehole
195
Potash
Corehole
906
Stratigraphic
and
Core
Test
Hole
1,215
Water
Well
2,3
11
Brine
Well
(Solution
Mining)
1
Total
Boreholes,
by
Depth
5,536
10,640
89
19
56
0
0
10,804
'
Equal
to
or
less
than
2,150
feet
(655
m).
Greater
than
2,150
feet
(655
m).
Excluding
boreholes
drilled
as
part
of
WIPP
site
characterization
programs.
7
Table
D
E
E
5
Number
of
Shallow
Boreholes
Per
Square
Kilometer
in
the
Delaware
Basin,
by
Resource
or
Type
',
1996
Borehole
Type
Deep
Boreholes
*
Boreholes
Per
Square
F(
m
Hydrocarbon
Borehole
10,640
46.056
Sulphur
Corehole
89
0.385
Potash
Corehole
19
0.082
Stratigraphic
and
Core
Test
Holes3
56
0.212
Brine
Well
(Solution
Mining)
0
0
Water
Well
0
0
Total
Deep
Boreholes
10,804
16.765
i
~
~
Borehole
Type
Shallow
Boreholes
*
Boreholes
Per
Square
Km
Hydrocarbon
Borehole
608
2.632
Sulphur
Corehole
495
2.113
Potash
Corehole
906
3.922
Stratigraphic
&
Core
Test
Holes
1,215
'
I
Water
Wells
2,311
5.259
10.003
Brine
Well
(Solution
Mining)
1
0.004
Total
Shallow
Boreholes
5,536
23.963
*
*
The
area
of
the
Delaware
Basin
is
23,102.1
square
kilometers
(14.356
square
miles).
The
number
of
holes
per
square
kilometer
is
calculated
as
follows:
(number
of
holes)
x
10.000
years
/
area
/
100
years.
Equal
to
or
less
than
2.150
feet
(655
m).
Excluding
boreholes
dnlled
as
part
of
WIPP
site
characterization
programs.
Table
DEL6.
Number
of
Deep
Boreholes
Per
Square
Kilometer
in
the
Delaware
Basin,
by
Resource
or
Type
*,
1996
8
Table
DEL
7.
Number
of
Boreholes
Per
Square
Kilometer
to
be
Used
in
Performance
Assessment
Calculations,
1996
Type
of
Borehole
Number
of
Boreholes
Boreholes
Per
Square
Km
Shallow
Borehole
5.041
'
21.821
Deep
Borehole
10,801
46.765
'
Excluding
sulphur
coreholes
and
boreholes
drilled
as
part
of
W
P
site
characterization
programs.
'
Excluding
boreholes
dnlled
as
part
of
WIPP
site
characterization
programs.
DEL.
7.5
Pressurized
Brine
Encounters
Within
the
Delaware
Basin
Some
of
the
human
intrusion
scenarios
evaluated
in
the
WIPP
performance
assessment
include
the
assumption
that
a
borehole
results
in
the
establishment
of
a
flow
path
between
the
repository
and
a
pressurized
brine
pocket
that
could
be
located
beneath
the
repository
in
the
Castile.
To
iden*
reasonable
assumptions
for
use
in
the
CCA
performance
assessment,
commercial
drillers
and
operators
with
experience
in
the
Delaware
Basin
were
surveyed
to
determine
the
frequency
of
occurrence
and
typical
depths
of
abnormally
pressurized
brine
zones
within
the
Delaware
Basin
(Personal
Communication
1996d;
Personal
Communication
1996e;
Personal
Communicatbn
1996c
Personal
Communication
19968).
For
the
purpose
of
this
investigation,
abnormalIy
pressurized
brine
zones
are
defined
as
those
that
exhibit
pressures
exceeding
the
hydrostatic
pressure
of
the
column
of
drilling
fluid
in
the
hole.
Consistent
with
this
definition,
any
brine
encounter
having
pressure
exceeding
hydrostatic
pressure
is
considered
abnormally
pressurized.
Flow
to
the
surface
driven
by
differential
pressures
just
above
hydrostatic
pressure,
however,
would
typically
not
be
noticed
by
a
driller,
and
is
expected
to
be
of
little
impact
to
performance
assessment.
When
asked
how
often
abnormally
pressurized
brine
zones
are
encountered,
each
of
the
drillers
surveyed
stated
that
it
was
an
uncommon
occurrence
in
the
Delaware
Basin,
and
that
they
believe
the
actual
frequency
to
be
less
than
five
percent.
This
estimate
captures
those
occurrences
where
the
differential
pressure
could
be
great
enough
to
drive
a
noticeable
quantity
of
drilling
fluid
to
the
surface.
The
drillers
reported
that
these
zones
are
most
frequently
encountered
in
the
Castile
Formation
in
the
Delaware
Basin.
The
Castile
Formation
within
the
Land
Withdrawal
Area
(LWA)
is
approximately
1,250
feet
(381
meters)
thick.
It
is
primarily
an
anhydrite
formation
and
has
been
found
to
have
isolated
areas
that
hold
quantities
of
brine.
Based
on
observed
Castile
porosity
(amount
of
space
in
the
formation
to
store
brine)
and
permeability
(ability
of
the
formation
to
conduct
fluids),
brine
present
in
the
unit
may
be
released
into
an
intersecting
uncased
wellbore.
This
brine
may
be
normally
or
abnormally
pressured.
9
Hydrostatic
pressure
at
any
depth
in
the
wellbore
is
calculated
using
the
formula:
Prn
=
MW
x
D
x
0.052
where
Pm=
pressure
(pounds
per
square
inch),
MW=
mud
weight
(pounds
per
gallon),
D=
depth
(feet),
and
and
0.052
is
a
conversion
factor
representing
mud
density.
For
example,
at
3,000
feet
(915
meters),
the
hydrostatic
pressure
is
calculated
at
1,560
pounds
per
square
inch
(1.08
x
lo7
Pa)
based
upon
the
use
of
a
10
pounds
per
gallon
saturated
brine
as
the
drilling
fluid.
In
this
example,
brine
flow
to
the
surface
would
be
possible
only
if
the
brine
source
is
pressurized
greater
than
1,560
pounds
per
square
inch.
Typically,
the
driller
would
become
aware
of
abnormally
pressurized
brine
zones
only
if
the
pressure
of
the
brine
encounter
is
sufficient
to
cause
a
noticeable
gain
of
fluid
in
the
mud
pit.
When
this
occurs
and
the
flow
is
not
great
enough
to
cause
immediate
concern,
drilling
will
typically
continue,
but
the
driller
will
calculate
the
rate
of
brine
flow.
This
is
accomplished
by
shutting
off
the
pumps
and
using
a
bucket
of
known
capacity
to
catch
the
fiee
flowing
brine
and
noting
the
time
that
it
takes
to
fill
the
bucket.
From
this
measurement,
the
driller
can
determine
the
rate
of
flow
in
barrels
per
minute.
If
the
flow
rate
is
not
so
great
as
to
cause
concern
ofover
filling
the
reserve
pit,
drilling
would
continue
until
the
hole
reaches
the
Bell
Canyon
Formation.
The
intermediate
casing
would
then
be
tun
and
cemented.
Once
in
place,
the
casing
string
would
isolate
the
over
pressurized
zone
and
prevent
fbrther
flow
to
the
surface.
A
very
heavy
brine
flow,
however,
such
as
one
that
could
potentially
fill
the
pit
within
one
to
two
hours,
would
not
be
allowed
to
continue.
Corrective
action
would
be
taken
in
the
form
of
killing
the
flow
of
brine.
This
is
accomplished
in
the
field
by
shutting
in
the
blowout
preventor
(BOP)
and
calculating
the
downhole
pressure.
Using
this
pressure,
the
driller
then
determines
the
quantity
of
barite
(the
mud
additive
most
often
used)
that
must
be
added
to
the
drilling
fluid
to
sufficiently
increase
the
hydrostatic
pressure
exerted
by
the
column,
so
that
the
differentiai
pressure
results
in
downward
flow
itom
the
drilling
fluid
column
into
the
formation.
When
brine
flow
to
the
surface
has
stopped,
drilling
continues
to
the
depth
originally
determined
in
the
well
plan.
Once
this
depth
is
reached,
intermediate
casing
is
run
and
cemented
in
place.
The
drillers
reported
that
measures
to
kill
pressure
driven
flow
to
the
surface
are
rarely
required.
They
are
generally
able
to
drill
through
the
Castile
Formation
while
brine
is
flowing
and
successfblly
set
the
intermediate
string
in
the
Bell
Canyon
Formatien
(the
typical
drilling
horizon).
Using
a
typical
drilling
scenario
based
on
a
pressurized
zone
at
a
depth
of
3,000
feet
(915
meters)
with
a
hydrostatic
pressure
of
1,560
pounds
per
square
inch
(1.08
x
lo7
Pa),
flow
rates
necessary
to
fill
the
pit
at
one
and
two
feet
per
hour
increments
have
beeh
calculated.
This
calculation
is
provided
below.
10
Assume:
A.
B.
C.
D.
E.
F.
G.
H.
I.
J.
K.
L.
M.
N.
Well
Depth,
A2
:
Mud
Pit
Volume:
Casing
Weight:
Casing
Inner
Diameter
Open
Hole
Inner
Diameter
Unit
Volume:
Unit
Volumetric
Flow
Rate:
Drilling
Fluid:
Density
(p):
Friction
Factor
(f):
Internal
Casing
Pipe
Area
(A):
Gravity
(8):
Velocity
(1
ft/
hr
Brine
Pit
Disp.):
Velocity
(2
ft/
hr
Brine
Pit
Disp.):
3,000
feet
125
feet
*
125
feet
*
6
feet
=
93.750
cubic
feet
=
701.298.701
gallons
32
pounds
per
foot
8.625
inches
11.5
inches
=
0.958
feet
15,625
cubic
feet
per
foot
of
vertical
height
4.34
cubic
feet
per
second
Case
1:
10.25
pounds
per
gallon
brine
Case
2:
barite
Case
1:
76.68
pounds
per
cubic
foot
Case
2:
263.3
pounds
per
cubic
foot
0.06
for
coated
casinglopen
hole
x
d2/
4
=
~(
0.958)~/
1=
0.721
square
feet
32.17
feet
per
square
second
V
=
QIA=
4.31*
1/
0.721
=
6.017
feet
per
second
V
=
QIA=
4.34*
2/
0.721
=
12.034
feet
per
second
Equation:
Derived
from
Gieck
(1987)
For
the
case
of
1
f
a
r
brine
pit
displacement:
AP
=
1,654.099
pounds
per
square
inch
(1.14046
x
lo7
Pa)
gauge
For
the
case
of
2
fthr
brine
pit
displacement:
AP
=
1,823.784
pounds
per
square
inch
(1.25745
x
IO'
Pa)
gauge
The
calculation
shows
that
a
one
foot
per
hour
pit
level
increase
would
be
possible
only
if
encountering
bottom
hole
pressures
of
at
least
1,654
pounds
per
square
inch
gauge.
A
two
foot
per
hour
increase
in
the
pit
level
would
require
a
pressure
of
1,824
pounds
per
square
inch
(1
25745
x
lo7
Pa)
gauge.
Those
surveyed
indicated
that
pressures
of
this
magnitude
are
seldom
experienced
in
the
Delaware
Basin,
and
that
both
one
and
two
foot
per
hour
pit
IeveI
rises
would
be
noticed
by
the
driller.
The
low
rate
of
occurrence
of
abnormally
pressured
brine
zones
in
the
Delaware
Basin
(or
WIPP
vicinity)
has
been
fbrther
supported
by
information
documented
in
the
drilling
records.
Using
databases
assembled
by
PI
and
MMC,
which
provide
well
name,
operator,
location,
total
depths,
casing
sizes,
and
dates
of
drilling
and
completion,
the
DOE
has
developed
a
list
of
all
oil
and
gas
wells
that
have
been
drilled
within
the
New
Mexico
portion
of
the
Delaware
Basin.
Wells
on
this
list
are
located
in
the
southern
portions
of
Eddy
and
Lea
Counties,
which
are
the
only
New
11
Mexico
counties
within
the
Delaware
Basin.
The
well
files
at
the
OCD
offices
in
Artesia
and
Hobbs,
New
Mexico,
(the
NMOCD
maintains
the
records
of
wells
drilled
on
both
state
and
federal
leases
in
Eddy
and
Lea
Counties)
were
idso
reviewed.
The
files
record
activities
entered
by
the
drillers
Erom
initiation
of
drilling
to
completion
of
a
particular
well.
Drillers
note
in
these
reports
any
unusual
occurrences
such
as
abnormally
pressured
brine.
Incidents
of
this
type
are
reported
in
the
form
of
daily
reports.
Although
there
is
no
requirement
that
they
do
so,
drillers
may
include
pressurized
brine
encounters
in
their
daily
reports,
even
if
there
has
been
no
effect
on
drilling
activities.
The
Texas
portion
of
the
Delaware
Basin
was
not
evaluated.
The
rationale
for
not
including
the
Texas
portion
is
that
wells
nearer
the
WIPP
land
withdrawal
area
are
of
greatest
interest
in
determining
the
presence
of
brine
within
the
Castile.
Of
a
total
of
3,406
well
files
reviewed,
28
were
found
to
have
notations
by
the
driller
indicating
the
encounter
of
pressurized
brine.
Another
factor
influencing
performance
assessment
analysis
is
the
time
that
flow
fiom
a
pressurized
zone
to
the
surface
would
continue
prior
to
the
installation
of
the
intermediate
casing
string.
As
stated
previously,
the
intermediate
casing
is
typically
run
when
the
Bell
Canyon
Formation
is
reached,
which
is
approximately
4,000
feet
(1,220
meters)
in
depth
near
the
WIPP
site.
At
this
time,
the
drill
string
is
removed
from
the
hole
and
intermediate
casing
is
run
and
cemented
fiom
4,000
feet
(1,220
meters)
to
the
surface.
Mer
cementing
is
completed,
the
driller
is
required
by
regulation
to
wait
24
hours
for
the
cement
to
set
before
drilling
resumes.
Drilling
time
from
the
repository
depth
at
2,150
feet
(656
meters)
through
the
remaining
portion
of
the
Salado
and
all
of
the
Castile
(an
additional
1,250
feet;
381
meters)
is
calculated
to
be
54
hours.
This
number
is
based
on
drilling
rates
of
50
to
60
feet
(1
5
to
1
8
meters)
per
hour
from
the
base
of
the
surface
casing
at
800
feet
(244
meters),
to
the
top
of
the
Castile
at
2,750
feet
(838
meters)
(New
Mexico
Junior
College
1995).
The
drilling
rate
is
expected
to
slow
to
30
to40
feet
(9
to
12
meters)
per
hour
through
the
Castile
(New
Mexico
Junior
College
1995).
Once
the
Bell
Canyon
has
been
entered,
an
additional
14
hours
are
typically
required
to
remove
the
drill
string
from
the
hole
and
run
and
cement
the
3,200
feet
(976
meters)
of
casing.
In
the
majority
of
drilling
operations,
the
driller
will
be
able
to
safely
drill
ahead,
reach
the
Bell
Canyon,
and
complete
the
intermediate
casing,
without
having
to
resort
to
killing
the
pressure.
However,
if
pressures
encountered
are
great
enough
that
the
driller
is
forced
to
engage
the
BOP
and
add
weight
to
the
drilling
fluid,
the
maximum
time
that
flow
to
the
surface
would
occur
is
one
to
two
hours.
Therefore,
two
hours
represents
a
reasonable
lower
bound
duration
and
is
derived
from
high
pressure
situations
where
the
BOP
would
be
used
to
stop
the
flow
to
the
surface
and
control
the
pressure
by
adding
weight
to
the
drilling
fluids.
12
DEL.
7.6
Borehole
Permeability
Assessment
Human
intrusion
scenarios
evaluated
in
the
WIPP
performance
assessment
assume
that
one
or
more
boreholes
intercept
the
repository
and
that
the
boreholes
are
subsequently
plugged.
To
support
the
evaluation
of
the
potential
consequences
of
scenarios
of
this
type,
the
DOE
has
assessed
the
permeabilities
that
may
be
expected
in
plugged
boreholes
in
the
Delaware
Basin.
The
permeability
of
the
borehole
plugs
is
important
because
this
is
a
measure
of
the
quantity
of
contaminated
fluids
that
could
hypothetically
flow
through
the
borehole
plug.
Results
of
this
work
are
reported
in
Inadvertent
Intrusion
Borehole
Permeability,
included
as
Attachment
7.
The
DOE
report
summarizes
plugging
practices
in
the
Delaware
Basin
and
identifies
three
plugging
configurations
typically
used
in
the
basin:
a
single
continuous
plug
through
the
evaporite
sequence,
*
a
two
plug
configuration
that
contains
one
plug
in
the
Bell
Canyon
Formation
(below
the
depth
of
potential
brine
reservoirs)
plus
one
plug
in
the
Rustier
Formation
(between
the
Culebra
aquifer
and
the
repository),
and
a
three
plug
configuration
that
contains
the
two
plugs
described
for
the
two
plug
configuration,
plus
an
additional
plug
in
the
Salado
Formation.
Conclusions
presented
in
the
DOE
report
for
each
of
these
configurations
include
the
following.
m
In
the
case
of
the
single
continuous
plug,
the
permeability
of
the
plug
is
expected
to
remain
at
5
x
square
meters
for
the
entire
10,000
year
period
of
interest.
*
For
the
two
plug
configuration,
the
permeability
between
the
repository
and
the
surface
is
expected
to
be
5
x
lo
''
square
meters
for
a
period
of
200
years
and
lo"
square
meters
to
1
O
I4
square
meters
after
that.
The
plug
between
the
Castile
and
the
repository
is
expected
to
have
a
very
high
permeability
for
200
years
and
values
of
lo"
to
square
meters
up
to
1,200
years,
and
to
1
O
I5
square
meters
after
that.
With
the
three
plug
configuration,
the
permeability
between
the
intermediate
plug
and
the
surface
is
expected
to
be
5
x
meters
after
that.
The
intermediate
plug
is
expected
to
have
a
permeability
of
5
x
IO"
square
meters
for
a
median
time
of
5,000
years,
and
the
borehole
between
the
Castile
and
the
repository
is
expected
to
have
values
ranging
from
lo"
to
years
more,
and
square
meters
for
200
years
and
lo
''
to
square
square
meters
fur
1,000
to
IO
''
square
meters
after
that.
Under
all
scenarios
considered
in
the
report,
the
permeability
of
the
borehole
plug
systems
never
exceed
that
of
silty
sand
(lo"
to
lo
''
square
meters).
13
3.0
SCHEDULE
DELAWARE
BASIN
DRILLING
SURVEILLANCE
PROGRAM
The
implementation
of
the
Delaware
Basin
Drilling
Surveillance
Program
was
October
1
,
1997
at
the
start
of
the
fiscal
year
(FY98).
Appendix
DEL
was
formalized
and
finalized
in
March,
1996
for
submittal
in
the
Compliance
Certification
Application
(CCA).
From
March,
1996
untiI
October,
1997
no
surveillance
was
performed
in
the
Delaware
Basin
on
drilling
activities.
The
original
data
presented
a
history
of
when
the
wells
were
drilled
and
what
their
status
was
when
they
were
drilled..
The
focus
now
is
not
only
when
a
well
was
drilled
but
what
its
current
status
is.
To
fill
in
the
blank
spaces
an
aggressive
schedule
(see
Figure
6
)
was
developed
to
bring
the
program
up
to
date.
4.0
1998
UPDATES
DELAWARE
BASIN
DRILLING
SURVEILLANCE
PROGRAM
The
information
provided
in
this
section
are
the
results
of
the
ongoing
Delaware
Basin
Drilling
Surveillance
Program.
One
of
the
purposes
of
the
program
is
to
report
any
deviations
from
the
material
that
was
provided
in
Appendix
DEL
of
the
CCA.
4.1
Drilling
Fluids
Since
Appendix
DEL
of
the
CCA
was
finalized
no
changes
have
occurred
in
the
drilling
practices
in
the
Delaware
Basin.
This
was
accomplished
by
a
review
of
the
records
of
all
new
wells
drilled
in
the
New
Mexico
portion
of
the
Delaware
Basin
since
1995.
A
change
in
drilling
practices
would
necessitate
a
change
in
the
application
of
drilling
fluids.
The
mud
programs
(or
drilling
fluid
programs)
have
remained
basically
the
same
as
what
was
reported
in
Appendix
DEL.
4.2
Shallow
Driliing
Events
Commercial
sources
and
visits
to
the
OCD,
BLM,
and
State
Engineer's
offices
are
used
to
identify
new
wells.
A
look
at
the
well
fife
will
identifi
whether
it
is
a
shallow
event
or
not.
Any
new
well
drilled
to
a
depth
of
less
than
2,150
feet
will
classify
the
well
as
shallow.
This
applies
only
to
wells
that
are
located
within
the
Delaware
Basin.
Most
shallow
events
are
fiom
water
and
mineral
exploration
in
the
immediate
area
although
no
new
mineral
exploration
has
been
identified
in
the
last
two
years.
4.3
Deep
Drilling
Events
In
the
Delaware
Basin
deep
drilling
events
are
usually
associated
with
oil
and
gas
drilling.
Commercial
sources
and
visits
to
the
OCD
offices
are
used
to
identify
these
events.
If
the
total
depth
reached
is
greater
than
2,150
feet
it
is
classified
as
a
deep
drilling
event.
14
4.4
Rate
of
Drilling
in
the
Basin
1998
The
following
information
is
derived
from
the
databases
maintained
by
the
Delaware
Basin
Drilling
Surveillance
Program.
It
depicts
both
shallow
and
deep
drilling
events.
This
information
also
adds
to
the
numbers
presented
in
the
tables
presented
in
Appendix
DEL.
The
supplied
data
is
current
through
8/
1/
98.
In
Appendix
DEL
certain
well
types
were
shown
but
not
used
in
the
calculations
for
intrusion
rates
(WTPP
boreholes).
This
does
not
occur
in
the
updated
material.
One
reason
for
this
is
that
deleting
certain
holes
fiom
the
calculations
does
not
make
much
difference
due
to
the
number
of
holes,
thus,
all
holes
will
be
used
in
the
count.
HYDROCARBON
HOLES
Dry
Hole
Oil
Well
Gas
Well
OiYGas
Well
Drilling
or
Waiting
on
Paperwork
Injection
Well
Salt
Water
Disposal
Well
Service
Well
Junked
&
Abandoned
Hole
Plugged
Oil
Well
Plugged
Gas
Well
Plugged
Oil
&
Gas
Well
Plugged
Injection
Well
Plugged
Salt
Water
Disposal
Well
Sulfur
Boreholes
Potash
Boreholes
W
P
Boreholes
Stratigraphic
Test
Holes
Water
Wells
Salt
Wells
Core
Holes
2,425
3,707
782
126
15
3
02
1
105
1
1
1
518
164
56
0
o_
8,312
OTHER
RESOURCE
HOLES
584
0
0
1,222
1,706
8
45
3,565
1,006
1,775
584
4
46
9
37
17
41
157
76
0
8
4
3,764
0
1,005
198
2
590
4
2
1,801
TOTAL
3,43
I
5,582
1,336
130
61
311
38
I22
152
675
240
56
8
4
12,076
TOTAL
584
198
1,224
2,296
12
47
5,366
1,005
15
Total
Resource
Holes
in
the
Delaware
Basin
11,877
5,565
17,442
ADDITIONAL
INFORMA
TION
l!
Yuumx
TOITAL
Hydrocarbon
holes
>
2,150'
deep
Hydrocarbon
holes
<
2,150'
deep
S
u
b
boreholes
>
2,150'
deep
Potash
boreholes
>
2,150'
deep
WIPP
boreholes
>
2,150'
deep
Stratigraphic
test
holes
>
2,150'
deep
Water
wells
>2,150'
deep
Salt
wells
>
2,150'
deep
Core
holes
>
2,150'
deep
1
1,442
634
89
19
10
56
0
0
0
Total
of
all
resource
holes
>
2,150'
deep
Total
of
all
resource
holes
in
the
Delaware
Basin
11,675
5.767
17,442
Total
of
all
resource
holes
<
2,150'
deep
LWTRUSION
RATE
The
intrusion
rate
is
calculated
as
follows:
(number
of
holes)
X
10,000
years
/
area
(23,102
square
kilometers)
/
102
years.
The
original
calculation
was
for
100
years
but
that
was
through
1996.
Each
year
that
passes
will
show
another
year
at
the
end
of
the
formula.
Doing
the
calculation
this
way
yields
the
average
and
also
keeps
a
running
account
of
the
total
number
of
wells
in
the
Delaware
Basin.
This
is
a
more
conservative
method
than
the
one
shown
beIow.
Another
way
to
calculate
the
intrusion
rate
is
to
maintain
the
100
year
standard.
This
would
mean
dropping
all
the
wells
drilled
in
the
first
year.
At
the
current
rate
of
drilling
the
number
of
welIs
would
actually
decrease
over
time
as
the
boom
years
of
oil
drilling
are
long
gone.
This
would
eventually
lower
the
intrusion
rate.
At
any
one
time
only
the
number
of
wells
driIled
during
the
100
year
span
would
be
accounted
for.
This
method
would
not
give
a
true
accounting
of
what
is
happening
in
the
Delaware
Basin
over
the
entire
period
of
interest.
1998
Intrusion
Rate
Shallow
holes
=
24.47
boreholes.
per
square
kilometer
Deep
holes
=
49.55
boreholes
per
square
kilometer
4.5
New
Mexico
Well
Count
and
Intrusion
Rate
For
added
interest
the
counts
and
intrusion
rates
were
re
calculated
using
only
the
wells
in
the
16
New
Mexico
portion
of
the
Delaware
Basin.
The
intrusion
rate
worked
out
to
be
70
holes
per
square
kilometer
utilizing
all
of
the
known
deep
holes.
4.6
Pressurized
Brine
Encounters
Within
the
Delaware
Basin
28
wells
were
originally
identified
as
encountering
pressurized
brine
in
the
Castile.
AI1
new
weirs
identified
since
the
formulation
of
Appendix
DEL
have
been
researched
for
encounters
of
brine.
None
were
found
to
have
encountered
pressurized
brine.
4.7
Borehole
Permeability
Assessment
The
plugging
practices
and
requirements
as
identified
in
Appendix
DEL
are
stil1
the
same
as
currently
being
conducted
in
the
Delaware
Basin
(see
Figures
2
and
3).
Therefore,
the
calculations
presented
in
the
Appendix
DEL
assessment
have
not
changed.
4.8
Borehole
Depths
and
Diameters
The
typical
borehole
depths
(related
to
the
oil
bearing
strata)
and
the
diameter
of
the
portion
of
the
drilled
hole
have
not
changed
from
those
which
were
reported
in
Appendix
DEL.
Borehole
depths
are
variable
across
the
Delaware
Basin
due
to
the
different
depths
at
which
oil
and
gas
are
located.
Hole
sizes
vary
from
well
to
well
but
several
stand
out
as
being
the
most
commonly
used
by
the
local
operators
(see
Figures
4
and
5
).
4.9
New
Drilling
Technology
Breakthrough
developments
in
autodriller
and
mud
system
technologies
have
been
incorporated
into
a
series
of
drilling
rigs
that
not
only
provide
drillers
and
operators
with
the
tools
and
means
to
drill
wells
faster
and
safer,
but
may
ultimately
alter
drilling
work
processes
and
procedures.
Utilizing
this
concept
reduced
drilling
times
by
37%,
required
no
mud
pits
resulting
in
faster
cleanup
times,
allowed
for
a
smaller
footprint
which
saved
operator
location
construction
costs,
and
enabled
rigging
up
on
small
environmentally
sensitive
locations.
Already
one
well
has
been
drilled
in
this
area
utilizing
this
technology.
5.0
SUMMARY
1998
DELAWARE
BASIN
DRILLING
SURVEILLANCE
PROGRAM
The
Delaware
Basin
Drilling
Surveillance
Program
continues
to
monitor
the
drilling
of
oil
and
gas
wells
within
the
Delaware
Basin.
This
information
is
added
to
the
existing
databases
as
necessary.
Another
ongoing
process
is
the
determination
of
the
current
status
of
each
well
within
the
nine
townships.
Any
changes
require
updating
the
existing
databases.
Numerous
changes
do
occur,
such
as
operator
changes,
oil
to
injection,
gas
to
plugged,
etc.
Since
the
finalization
of
Appendix
DEL
in
the
spring
of
1996
there
have
been
two
very
productive
years
in
oil
and
gas
drilling
within
17
the
Delaware
Basin,
specifically
the
area
immediately
south
of
the
site.
Since
January,
1998
the
price
of
crude
oil
has
dropped
$3.00
per
barrel
of
oil
causing
the
drilling
rate
for
oil
in
this
area
to
become
almost
non
existent.
Well
status
verification
for
the
New
Mexico
portion
of
the
Delaware
Basin
is
95%
complete.
3,773
known
hydrocarbon
wells
exist
in
this
area.
This
total
includes
all
of
the
wells
drilled
in
this
area
since
the
finalization
of
Appendix
DEL.
This
year
the
Texas
portion
of
the
Delaware
Basin
is
scheduled
to
undergo
the
same
process
as
was
accomplished
in
the
New
Mexico
portion
of
the
Delaware
Basin
the
last
year.
Due
to
current
oil
prices,
this
program
does
not
expect
many
new
wells
to
be
drilled
in
this
area
over
the
next
year.
Since
many
wells
will
change
from
oil
and
gas
to
salt
water
disposal,
injection,
or
plugged
and
abandoned
status
over
time,
verification
of
well
status
is
needed
to
accurately
monitor
these
resource
extraction
activities.
6.0
QUALITY
ASSURANCE
Activity
will
be
conducted
in
accordance
with
the
appropriate
portions
of
Section
2.1.
of
the
CAO
Quality
Assurance
Program
Document
(CAO
QAPD).
Specifically,
procedures
will
be
followed
(and
prepared
as
needed)
to
assure
the
accurate
recording
of
information
and
data
taken
from
outside
sources,
and
the
verification
of
any
calculations
performed
to
develop
modeling
parameters
from
field
data.
When
possible
and
practical,
field
verification
will
be
conducted.
Field
verification
shall
be
mandatory
w
i
t
h
one
mile
of
the
WIPP
site
boundary.
Field
data
wiII
be
recorded
in
permanent
notebooks
in
accordance
with
CAO
QAPD
*
18
7.0
REFERENCES
(Section
7.1.4,
DOE
1996b)
Chapter
7,
Section
7.1.4,
Effectiveness
of
the
Active
Institutional
Controls
Program,
of
the
Compliance
Certification
Application,
DOEKAO
1996
2
184,
October
1996.
Appendix
DEL
Appendix
DMP
Oil
&
Gas
Journal,
96:
50,
12/
14/
1998
Autodriller,
cylindrical
mud
tanks,
generate
breakthrough
developments
in
drilling
technologies
CAO
QAPD
19
Figure
1
Wipp
Site,
Delaware
Basin,
and
Surrounding
Area
20
AN3BRPTf
5,000
6,000
7.000
9,000
B.
250
.Ip
Fasing
Cemerring
:or
8.625"
3.3.
.I
I
..
4
:so'
Cerrenr
?lug
8.625"
0.9.
interrneaiote
Casing
i
NOT
TO
SCALE
:
Casing
Cementing
for
5.50"
O.
D.
Production
Casing
50'
Cemenr
?tug
%st
Iron
Elridge
Plug
I
SRAPiiiC
LEGEND
5.50"
O.
D.
2roduction
Cosing
.
..'
.
.
.'
.
,.,#
C3ncrete
..
..
.
,
.
,
3:
eel
Casing
Czs:
l
r
m
Figure
2
Minimum
Oil
and
Gas
Well
Plugging
Requirements
in
the
Delaware
Basin
21
2,000
3.000
4,000
5,000
6.000
7.000
8.000
8.250
GRAPHIC
LEGEND
5.50"
0.
D.
Production
Casing
Figure
3
in
the
Potash
Resource
Area
of
tie
&laware
Basin
Standard
Oil
and
Gas
Well
Plu
gin
Practices
5
I
+2325'
W
4
Ln
<
0
L
6075'
_.
.
~'
:;
..
?
'_.
.I
..
_.
.
....
...
..
...
..
..
,I
,.
..
..
572
....
......
..:
.
?
.........
...
..........
y
,
..
..
....
....
..
..
'
..
.
.
1
:
.
I
..
..
._
.....
...
:
..
"
..
..
,
..
S
L;
R
FAC
E
CASING
SiZE
C
>t
t
'ABLE
AT
i3WER
LEFT)
I
r
...
..
..
...
.....
*OLE
SIZE
(SEE
TABLE
AT
LOWER
LEFT)
i
'
..
.....
;
..
\2
7/
0"
TUBINt
lfl
PERFORATIONS
>
CMT
RETAINEF?
\IOT
73
SCALE
Figure
4
Typical
Well
Structure
and
General
Stratigraphy
Near
the
WlPP
Site
23
I
I
f
i
I
3000
FT.
i
1
2ASTILE
I
/
4000
FT.
11000
Fr.
12000
Fr.
13000
FT.
14000
FT.
1
BELL
CANYON
I
I
I
1
BRUSHY
CANYON
I
I
I
30NE
SPRINGS
I
I
I
15000
FT.
16000
F
l
.
'7000
FT.
19000
FT.
OURCE:
GEOLOGICAL
C++
ARACTERIZA:
ION
QEFJORT
NOT
ro
SCALE
~
Fgure
5
Stratigraphy
for
WIPP
Site
and
Surrounding
Area
24
..
Attachment
D.
5
Effective
Date:
Cognizant
Section:
Mine
Engineerinq
Approved
By:
Cognizant
Department:
Engineering
Approved
By:
WIPP
Underground
B
Surface
Surveying
Program
WP
09
ES,
O
l,
Rev.
1
Table
of
Contents
ii
ACRONYMS
AND
ABBREVIATIONS
..............................................................................
....................................................................................................
I
1
.O
INTRODUCTION
1
2
1.1
Background
.......................................................................................................
1.2
WlPP
Surveying
Historv
and
Accuracy
Reauirements
.....................................
5
2.0
ADMiNlSPRATlON
.................................................................................................
5
2.1
Organization
.....................................................................................................
5
2.2
Responsibilities
................................................................................................
5
2.3
Training
and
Qualifications
...............................................................................
5
3.0
TECHNICAL
PROGRAM
DESCRIPTION
...............................................................
6
g
Prowam
.....................................................................
7
3.1
3.2
Surface
Surveyinq
Program
.............................................................................
8
3.3
Subsidence
Monitoring
Program
......................................................................
11
4.0
QUALITY
ASSURANCE
........................................................................................
12
4.1
Survey
Equipment
Control
..............................................................................
12
4.2
Procurement
...................................................................................................
12
4.3
Instructions,
Procedures,
and
Drawings
.........................................................
12
4.4
Document
Control
...........................................................................................
13
4.5
Control
of
Purchased
Material,
Equipment/
Services
......................................
13
4.6
identification
and
Control
of
Items
..................................................................
13
4.7
Software
Requirements
..................................................................................
14
4.9
Control
of
Nonconforming
Conditionslltems
...................................................
14
4.10
Corrective
Action
......................................................................................
14
4.1
1
Records
Management
15
4.1
2
Audits
and
Independent
Assessment
.......................................................
15
4.13
Data
Reduction
and
Verification
..............................................................
15
5.0
IMPLEMENTATION
MATRIX
................................................................................
15
5.1
WID
Mine
Engineerinq
...................................................................................
15
6.
Q
REFERENCES
......................................................................................................
..............................................................................
I
round
&
Surface
Surveying
Program
CCA
Compliance
Certification
Application
DOE
Department
of
Energy
FGCS
Federal
Geodetic
Control
Subcommittee
GPS
GIobal
Positioning
Survey
K
kilometer
.
mm
millimeter
NAD
27
NGS
National
Geodetic
Survey
QA
Quality
Assurance
QAPD
Quality
Assurance
Program
Description
PRS
Project
Records
Service
SDD
System
Design
Description
TRU
Trans
u
ran
ic
WID
Waste
Isolation
Division
LVl
PP
North
American
Datum
of
1927
Waste
Isolation
Pilot
Plant
WlPP
Underground
&
Surface
Surveying
Program
WP
09
ES.
81,
Rev.
1
1.0
1NTRODUGTION
This
document
defines
the
Surveying
Program
and
responsibilities
currently
being
carried
out
by
the
Waste
Isolation
Division
(WID)
Mine
Engineering
Surveying
Section.
The
Surveying
Section's
program
plans
and
functions
are
designed
to
provide
location
and
alignment
information
necessary
to
establish
precise
horizontal
and
vertical
control
for
all
aspects
of
underground
and
surface
configuration.
Surveying
activities
currently
consist
of,
but
are
not
limited
to,
the
following:
a
Underground
site
configuration,
controi,
and
update
a
Surface
site
configuration,
control,
and
update
a
Operations
and
engineering
support
8
Geotechnical
ground
control
support
Surface
subsidence
monitoring
These
acfivities
are
implemented
and
controlled
by
this
document,
Federal
Geodetic
Control
Subcommittee
(FGCS)
standards,
and
#eWP
A
3
1
WlPP
Quality
Assurance
Program
Description
(QAPD).
1.1
The
Surveying
Program
provides
surveying
services
and
information
to
any
section
or
group
within
the
W1D
Engineering
Department
for
planning,
engineering
andlor
documentation
purposes.
The
Surveying
Program
also
provides
basic
information
to
other
WID
sections
and
departments
so
that
the
safe
disposal
of
transuranic
(TRU)
and
mixed
waste
can
be
demonstrated
both
in
the
short
term
(during
the
operational
life
of
the
faciiity)
and
in
the
long
term
(following
decommissioning),
while
satisfying
all
regulations
governing
permanent
isolation
of
the
waste.
The
program
provides
construction
surveying
for
WID
engineering,
planning,
and
documentation
purposes,
but
does
not
include
construction
surveying
for
contractors.
Drivers
for
this
program
include
the
Compliance
Certification
Application,
the
Occupational
Safety
and
Health
Act,
the
Mine
Safety.
and
Health
Act,
and
Waste
isolation
Pilot
Plant
(WIPP)
System
Design
Descriptions
(SDDs).
The
program
also
helps
ensure
the
facility
operates
safely
and
that
the
data
are
available
to
make
decisions
for
managing
and
performing
engineering
and
operational
activities.
Each
surveying
activity
is
controlled
by
this
Surveying
Program
that
describes
the
general
scope
of
the
survey,
its
methodology,
and
quality
assurance
(QA)
requirements.
1
To
satisfy
the
listed
regulatory
drivers,
certain
activities
and
functions
are
required
of
the
Mine
Engineering
Surveying
Section.
These
commitments
are
listed
as
follows:
J
Perform
an
annual
subsidence
monitoring
survey
Publish
an
annual
report
of
subsidence
survey
data,
including
a
comparison
with
prior
years
data
0
Maintain,
replace,
and
expand
the
subsidence
monument
network,
as
required
Maintain
state
of
the
art
leveling
equipment
and
capability
I
.2
0
Surveying
was
one
of
the
first
activities
to
take
place
at
the
WlPP
site.
Coordinates
for
the
site
were
brought
in
from
the
National
Geodetic
Survey
(NGS)
monument
ORustlerO.
New
Mexico
State
Plane
Coordinates
North
American
Datum
of
1927
(NAD
27)
are
used
at
the
WlPP
for
control.
In
general
practice
at
the
WIPP,
these
coordinates
are
truncated
for
use
as
the
site
coordinate
system.
To
arrive
at
the
site
coordinates,
490,000
feet
was
dropped
from
the
Northing
and
660,000
feet
was
dropped
from
the
Easting
of
the
New
Mexico
State
Plane
Coordinates
NAD
27.
The
base
point
for
t
h
e
WlPP
site
was
the
section
corner
common
to
Sections
20,
21
,
28,
and
29
in
T.
22
S.,
R.
31
E.
During
1986,
a
surveying
contractor
was
retained
to
resurvey
the
site
to
bring
in
coordinates
and
transfer
them
underground.
Surveys
were
run
from
the
NGS
monuments
UBerryfl
and
I]
5rininstool,
fl
using
NAD
27
values.
Because
the
originai
base
point
had
been
lost,
a
new
base
point
(PT
30)
was
chosen
and
new
plant
coordinates
were
calculated
for
all
existing
points.
It
is
important
to
remember
that
plant
coordinates
are
on
a
rectangular
grid
while
State
Plane
Coordinates
take
into
account
that
the
earth
is
a
spheroid.
It
is
not
possible
to
make
a
direct
comparison
of
the
two
systems
for
more
than
one
point
at
a
time.
In
1993,
a
resurvey
of
the
underground
was
conducted.
Horizontal
locations
were
traversed,
and
the
true
bearings
were
checked
using
a
gyro
compass.
Additionally,
a
level
survey
was
conducted
through
20
benchmarks
located
throughout
the
underground.
Because
of
salt
creep,
the
horizontal
location
points
are
placed
in
the
roof
on
the
center
line
of
the
drifts
and
vertical
benchmarks
are
placed
in
the
drift
walls
at
approximately
mid
height
of
the
drift.
..
.
The
vertical
surveying
monitoring
commitments
in
the
Gempkscc:
Cs+&
ez&
w
Ap@
s&
m+
CCAfdivides
the
monitoring
into
three
phases:
developmental,
operational,
and
post
closure.
During
the
initial
developmental
phase,
31
4
kilometers
of
First
Order,
Class
I
survey
was
performed
by
the
NGS
in
1977.
The
NGS
network
was
resurveyed
in
1981
and
the
relative
movement
between
Carlsbad
and
the
WlPP
site
was
measured
to
be
about
2
centimeters.
The
relative
motion
across
the
network
..
2
WIPP
Underground
8a
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
1
was
down
to
the
east
and
up
to
the
west.
The
1981
NGS
survey
also
established
new
survey
lines
that
connected
the
previous
First
Order
benchmarks
through
Carlsbad
to
Second
Order
survey
lines
through
Eunice
and
Hobbs
Turing
this
survey,
benchmarks
were
placed
over
the
Nash
Draw
from
the
north
end
tu
ihe
Remuda
Basin,
over
potash
mines,
the
WlPP
site,
and
the
San
Simon
Sink.
Independent
of
the
NGS
work,
but
using
the
established
First
Order,
Class
1
NGS
benchmarks,
an
additional
52
benchmarks
were
installed
by
surveying
companies
working
under
contract
to
WIPP.
The
benchmarks
were
installed
in
a
grid
on
approximately
1,000
foot
centers.
This
grid
covers
the
WlPP
planned
repository
and
extends
about
1,000
feet
beyond
the
edge
of
the
planned
?xtent
of
the
waste
panels.
Second
Order,
Class
I
t
FGCS
specifications
were
used
for
these
benchmarks.
This
work
was
completed
in
1986.
A
Global
Positioning
Survey
(GPS)
was
conducted
in
1994
by
the
WlPP
Site
Survey
Section
in
conjunction
with
a
contractor.
The
GPS
was
used
to
check
horizontal
control
and
independently
verify
the
Second
Order,
Class
I
I
subsidence
survey
conducted
in
1994.
In
1996,
the
WlPP
Site
Survey
Section,
in
conjunction
with
a
contractor,
performed
a
First
Order,
CIass
I
level
survey
from
the
Berry
Monument,
20
miles
east
of
the
WlPP
site.
The
survey
went
over
the
52
existing
subsidence
monuments
at
the
site
and
back
to
the
Berry
Monument.
At
the
start
of
the
closure
phase,
it
is
anticipated
that
a
review
of
all
past
subsidence
surveys
and
the
adequacy
of
the
existing
subsidence
stations
will
be
conducted.
New
subsidence
stations,
if
needed,
will
be
installed
to
FGCS
standards.
A
survey
that
achieves
First
Order,
Class
I
accuracy
may
then
be
conducted.
Information
from
this
survey
will
be
combined
with
published
information
from
all
previous
work
to
form
a
baseline
database
for
subsidence
information
in
accordance
with
the
CCA.
The
CCA
states
that
this
post
closure
survey
is
to
be
repeated
in
three
years.
Thence,
it
is
to
be
repeated
every
ten
years
for
the
next
100
years,
or
until
the
Department
of
Energy
(DOE)
determines
that
further
surveys
are
not
required.
The
U.
S.
Department
of
Commerce
is
responsible
for
establishing
and
maintaining
basic
control
networks
for
the
nation.
The
Department
of
Commerce
carries
this
out
through
the
NGS
which
establishes
surveys,
then
adjusts
and
publishes
the
results
on
horizontal
and
vertical
geodetic
control
networks.
As
part
of
the
control
program,
the
FGCS
prepares
classification
and
standards
for
geodetic
control
surveys.
The
following
tables
outline
general
requirements
for
horizontal
and
vertical
control.
3
WIPP
Underground
&
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
l
4
WlPP
Underground
&
Surface
Surveying
Program
WP
09
ES.
04,
Rev.
1
Horizontal
surveys
at
the
WlPP
are
conducted
to
FGCS
accuracy
standards
for
Second
Order,
Class
I
I
surveys.
The
Second
Order,
Class
11
level
of
accuracy
is
the
standard
recommended
for
the
type
of
surveying
performed
at
the
WlPP
by
the
FGCS.
It
was
also
established
as
such
by
the
original
design
basis
documents
and
is
carried
through
into
t
h
e
AUOO
SDD.
First
Order,
Class
I
results
are
routinely
obtained
by
the
WIPP
Site
Surveying
Section.
Subsidence
surveys
are
carried
out
in
the
same
manner
as
vertical
surveys.
In
subsidence
measurements,
the
error
is
determined
by
both
the
equipment
used
and
the
distances
between
the
stations.
As
defined
by
the
FGCS
a
First
Order,
Class
I
level
survey
has
a
maximum
loop
error
of
4mm
JK
where
K
is
the
length
of
survey
loop
in
Kilometers.
A
Second
Order,
Class
II
level
survey
has
a
maximum
loop
error
of
8mm
JK
or
two
times
the
error
of
a
First
Order
survey.
Technoiogical
advances
in
electronic
digital
levels
allow
the
user
to
obtain
numerical
results
that
far
exceed
the
minimum
Second
Order,
Class
II
standard.
2.0
ADM
1
N
l
STRATI
ON
2.1
Oraanization
The
organizational
structure
of
the
WID
is
described
in
]
5
WiPF
Underground
&
Surface
Surveying
Program
WP09
ES.
01,
Rev.
1
WP
13
1.
The
Mine
Engineering
Site
Surveying
Section
reports
to
the
Mine
Engineering
Manager.
The
underground
and
surface
Surveying
Program
is
within
the
cognizance
of
the
AUOO
System.
2.2
The
Mine
Engineering
Site
Surveying
Section
cognizant
engineer
and
staff
are
responsible
for
achieving
and
maintaining
quality
in
the
Mine
Engineering
Site
Surveying
S
ect
io
n.
2.3
Personnel
who
perform
specific
tasks
associated
with
surveying,
surveying
data
collection,
survey
data
reduction,
and
Quality
Control
measures
are
trained
and
qualified
in
the
application
of
the
specific
requirements
to
complete
their
tasks.
Minimum
training
for
Engineering
personnel
is
identified
in
the
WP
09.
Engineering
Conduct
of
Operations.
3.0
TECHNICAL
PROGRAM
DESCRIPTION
The
VJIPP
Underground
and
Surface
Surveying
Program
is
divided
into
three
parts:
underground,
surface,
and
subsidence
monitoring.
Underground
and
surface
surveying
covers
all
surveying
performed
underground
and
on
the
surface
to
provide
location,
alignment
and
elevation
information
for
all
departments
concerned
with
surface
operations
and
TRU
waste
handling.
Control
points
are
maintained
upon
which
the
location,
alignments,
and
elevations
are
based.
This
information
is
also
used
for
updating
existing
drawings
and
surface
maps.
Subsidence
monitoring
provides
for
leveling
and
horizontal
control
of
all
the
subsidence
monuments
within
the
16
square
miles
of
the
surface
properties
(WIPP
Land
Withdrawal
Area).
These
surveys
are
either
conducted
by
the
WlPP
Surveying
Section
personnel,
or
by
qualified
contractorhendor
personnel
under
the
direct
supervision
of
the
WlPP
Mine
Engineering
Surveying
Section.
Finally,
this
plan
gives
the
Mine
Engineering
Surveying
Section
the
flexibility
to
provide
qualified
surveys
and
survey
information
to
any
other
internal
WID
section,
provided
the
request
is
approved
by
the
Mine
Engineering
manager.
3.1
Underaround
Survevincl
Proaram
The
purpose
of
the
Underground
Surveying
Program
is
to
maintain
accurate
location
information
of
the
underground
structures
and
to
provide
alignment
for
new
excavations.
The
Underground
Surveying
Program
ensures
continuing
confirmation
of
underground
configuration
through
surveys.
These
surveys
generate
data
that
are
used
in
underground
planning,
underground
extensions
and
TRU
and
mixed
waste
emplacement.
Information
from
the
surveys
is
used
to
document
the
existing
extent,
6
WIPP
Underground
&
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
1
size,
and
location
of
the
entries
crosscuts,
panels,
and
rooms
of
the
underground.
Activities
associated
with
this
program
include
control
surveys,
level
surveys,
alignment
point
installation,
grade
point
installation,
laser
alignment,
and
as
found
surveys.
Other
surveying
activities
are
performed
as
needed.
Underground
surveying
is
the
only
way
to
provide
information
for
the
construction
and
precise
location
of
underground
structures.
Because
of
the
safety
constraints
inherent
in
handling
and
emplacement
of
TRU
and
mixed
waste
in
the
WIPP
underground,
state
of
the
art
surveying
equipment
and
methods
are
used.
The
Underground
Surveying
Program
provides
information
basic
to
the
design,
construction,
and
operation
of
the
repository.
3.1.
q
Methodology
Routine
underground
surveys
are
carried
out
in
accordance
with
common
industry
practice,
and
in
accordance
with
standards
specified
by
the
FGCS.
Other
surveys
which
are
in
development,
or
are
not
routine
are
performed
in
accordance
with
common
industry
practice,
or
individual
program
plans.
a.
Routine
Survevs
Horizontal
Control
Surveys
Horizontal
Control
Surveys
are
made
as
the
repository
is
excavated
to
provide
accurate
location
of
existing
and
planned
openings.
Vertical
Control
Surveys
Vertical
Control
Surveys
are
made
as
the
repository
is
excavated
to
provide
precise
elevation
and
vertical
control
of
existing
and
planned
openings.
Alignment
Surveys
Alignment
Surveys
are
performed
as
required
to
provide
alignment
and
grade
points
for
mining
operations
as
excavation
of
the
repository
proceeds.
Alignment
Surveys
include
the
setting
of
laser
alignment
instruments
to
coincide
with
the
horizontal
control
grade
points.
Mapping
Surveys
Mapping
Surveys
provide
information
of
the
existing
location,
size,
and
shape
of
the
underground
structures.
Location
Surveys
Location
Surveys.
provide
precise
location
information
on
geotechnical
instruments
and
stationary
underground
structures.
b.
Other
Underqround
Surveying
Activities
Other
underground
surveying
activities
are
performed
as
required.
An
example
of
other
surveying
activities
might
include
a
shaft
piunbing
survey.
7
WIPP
Underground
&
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
1
C.
All
survey
data
are
collected
electronically,
downloaded,
and
processed
using
approved
software
programs.
Distribution
of
information
is
accomplished
by
electronic
files.
A
hard
copy
is
provided
to
a
customer
as
required.
Storage
of
survey
information
js
maintained
on
the
Survey
Section's
computers,
and
a
back
up
file
resides
on
the
WIPP
Intranet.
A
hard
copy
of
the
information
is
also
maintained
in
the
Survey
Section
files.
3.2
The
purpose
of
the
Surface
Surveying
Program
is
to
maintain
accurate
location
information
of
surface
structures
and
to
provide
location
and
topographical
information
for
planning
and
construction
of
new
surface
structures.
The
Surface
Surveying
Program
ensures
continuing
confirmation
of
site
configuration
through
surface
surveys.
These
surveys
generate
data
that
is
used
in
site
planning
and
new
surface
projects.
Information
from
the
surveys
is
used
to
document
the
existing
extent,
size,
and
location
of
the
site
facilities
as
they
exist.
Activities
associated
with
this
program
include
control
surveys,
level
surveys,
and
existing
condition
surveys.
Other
surveying
activities
are
performed
on
an
"as
needed"
basis.
Surface
surveying
is
the
only
way
to
provide
information
of
the
construction
and
precise
location
of
facility
structures.
Because
of
the
safety
constraints
inherent
in
handling
of
TRU
and
mixed
waste
at
the
WIPP,
state
of
the
art
surveying
equipment
and
methods
are
obtained
and
used.
The
Surface
Surveying
Program
provides
information
basic
to
the
design,
construction,
and
operation
of
the
surface
facilities.
3.2.1
Meth
odo
I
og
y
Surveys
performed
on
a
routine
basis
are
carried
out
in
accordance
with
common
industry
practice,
and
in
accordance
with
standards
specified
by
the
FGCS.
Other
surveys
which
are
in
development,
or
are
not
routine
are
performed
in
accordance
with
common
industry
practice,
or
individual
program
plans.
a.
Routine
Surveys
Horizontal
Control
Surveys
Horizontal
Control
Surveys
are
made
as
needed
for
horizontal
control.
Vertical
Control
Surveys
Vertical
Control
Surveys
are
made
as
needed
for
vertical
control
,
Topographic
Surveys
Topographic
Surveys
are
performed
as
required
to
provide
8
WIPP
Underground
8
Surface
Surveying
Program
WP
09
ES.
61,
Rev.
1
planning
and
construction
information
for
surface
projects.
Mapping
Surveys
Mapping
Surveys
provide
information
of
the
existing
location,
size,
and
shape
of
existing
surface
facilities.
b.
Other
Surface
Surveying
Activities
Other
surface
surveying
activities
will
be
performed
as
required.
An
exampie
of
other
surveying
activities
might
include
a
GPS
Survey.
C.
Data
Processing,
Distribution,
and
Storage
All
survey
data
are
collected
electronicaily,
downloaded,
and
processed
using
approved
programs.
Distribution
of
information
is
accomplished
by
electronic
files.
A
hard
copy
is
also
provided
to
a
customer,
if
needed.
Storage
of
survey
information
is
maintained
on
the
Survey
Section's
computers
and
a
backup
file
resides
on
the
WlPP
Intranet.
A
hard
copy
of
the
information
is
also
maintained
in
the
Survey
Section's
files.
,
3.3
@
Subsidence
is
defined
as
the
tertical
movement
of
the
land
surface
anywhere
within
a
defined
subs
i
den
ce
bas
i
n
.
S
peci
f
i
ca
I
I
y
,
subs
i
den
ce
monitoring
comprises
the
p
re
ci
se
measurement
of
the
relative
vertical
movement
of
the
land
surface
which
can
be
in
the
form
of
uplift
(upwards
movement)
or
subsidence
(downwards
movement)
relative
to
an
assumed
fixed
reference
point.
The
fixed
reference
point
is
assumed
to
be
fixed
since
it
is
placed
outside
the
subsidence
basin.
However,
it
is
also
subject
to
some
of
the
same
factors
and
processes
that
affect
and
cause
surface
movement.
Thus,
it
may
also
be
in
motion.
The
techniques
used
to
monitor
subsidence
measure
the
vertical
height
difference
between
an
array
of
markers
on
the
surface
and
is
typically
performed
with
a
leveling
survey.
Under
normal
conditions,
one
reference
benchmark
(ideally,
one
outside
the
potential
subsidence
basin)
is
utilized
as
the
standard
and
the
relative
movement
of
other
stations
or
benchmarks
are
compared
to
it
in
order
to
detect
vertical
differential
movement
over
a
period
of
time.
Subsidence
can
be
caused
by
a
number
of
factors.
Potential
examples
could
include
mining,
hydrocarbon
(petroleum)
exploration
and
production,
petroleum
production
related
water
injection
and
disposal,
water
well
drilling
and
completion,
geoiogical
deformation,
and
dissolution.
Nash
Draw
is
a
major
subsidence
feature
near
the
WIPP,
caused
by
the
dissolution
of
evaporites
in
the
upper
Salado
and
lower
Rustler
formations.
Near
the
WIPP,
localized
mine
induced
subsidence
is
associated
with
areas
where
pillars
were
removed
during
second
pass
extraction
in
potash
mines.
Subsidence
monitoring
of
the
surface
area
over
the
underground
excavations
is
a
consequence
of
several
government
and
WID
requirements.
The
WlPP
SDD
AUOO
9
WlPB
Underground
8n
Surface
Surveying
Program
WP
09
ES.
04,
Rev.
1
2.2.1
.e
states,
"The
design
of
the
mine
will
result
in
no
more
than
one
inch
surface
subsidence
within
500
feet
of
the
waste
shaft."
This
is
one
of
the
original
design
parameters
to
assure
protection
of
the
WlPP
surface
structures.
The
size
of
the
underground
shaft
pillar
area
and
the
layout
of
the
WlPP
mine
plan
is
based
on
this
parameter
among
others.
Calculations
to
assure
this
low
level
of
subsidence
around
the
waste
shaft
were
made
by
the
WlPP
architectslengineers.
The
AUOO
SDD
document
is
the
driver
for
the
annual
subsidence
survey
around
the
WlPP
shaft
and
is
conducted
according
to
the
specifications
of
a
Second
Order,
Class
I
I
Survey
as
stated
by
the
FGCS.
This
classification
allows
for
a
maximum
of
about
215
inch
vertical
error
per
mile
of
survey.
Thus,
the
maximum
survey
error
is
small
enough
that
it
will
not
mask
any
subsidence
that
might
occur
within
500
feet
of
the
Waste
Shaft.
The
Subsidence
Monitoring
Program
monitors
vertical
ground
movement
over
the
underground
openings
at
WIPP.
Monitoring
stations
were
installed
on
the
surface
over
the
completed
and
planned
underground
excavations
in
a
grid
with
spacing
of
approximately
1,000
feet.
Precise
level
surveys
are
conducted
annually
to
determifie
any
surface
movement
of
the
subsidence
stations.
Subsidence
monitoring
was
selected
by
the
DOE
as
a
basic
long
term
monitoring
tool.
The
initial
subsidence
survey
is
considered
as
the
baseline
condition.
Because
subsidence
monitoring
is
performed
annually,
it
is
also
useful
as
an
active
institutional
control
(short
term)
tool.
Subsidence
monitoring
is
non
intrusive
by
nature
and
can
be
related
to
numerical
assessments.
Subsidence
monitoring
can
detect
substantial
and
detrimental,
or
slight
and
insignificant
deviations
from
expected
repository
performance
by
comparing
current
subsidence
values
to
previous
loop
surveys.
Subsidence
monitoring
can
be
implemented
independent
of
site
utilities,
providing
useful
data
for
a
reasonable
cost
over
a
relatively
long
time
period,
and
requires
minimum
maintenance
to
sustain
a
high
quality
performance
level.
Subsidence
monitoring
provides
information
on
vertical
surface
movement
in
mining
areas
due
to
creep
closure
of
underground
openings.
This
closure
results
in
a
subsidence
basin
on
the
surface
the
extent
of
which
depends
on
the
underground
extraction.
Establishing
permanent
stations
over
the
underground
openings
and
perjodically
traversing
through
these
stations
with
precise
level
surveys
can
determine
the
subsidence
profile,
provided
these
surveys
are
continued
far
enough
into
the
future
to
allow
the
subsidence
to
reach
the
surface.
The
Backfill
Engineering
Analysis
Report,
(WEC
1994),
evaluates
the
potential
for,
and
predicts
subsidence
caused
by,
the
mining
of
the
WIPP's
shafts,
drifts,
and
waste
disposal
rooms.
These
calculations
account
for
a
range
of
emplaced
waste
volumes,
waste
densities,
and
backfill
types.
Subsidence
was
also
calculated
for
conditions
where
no
backfill
would
be
used.
10
WPP
Underground
&
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
'l
This
study
predicts
the
maximum
subsidence
expected,
and
was
performed
to
specifically
estimate
subsidence
for
long
term
repository
performance
monitoring
and,
as
such,
do
not
account
for
other
factors
that
may
influence
subsidence
such
as
local
petroleum
expioration
and
production,
and
potash
mining.
The
Surveying
Subsidence
Program
provides
the
capability
to
assess
the
responses
of
the
surface
and
underground
facility
due
to
surface
subsidence.
3.3.1
Methodology
The
activities
associated
with
the
Subsidence
Program
are
designed
to:
Provide
time
related
spatial
information
on
surface
subsidence
within
an
area
of
500
feet
of
the
waste
shaft
during
the
operational
phase
of
the
repository
0
Provide
time
related
spatial
information
on
surface
subsidence
over
the
influence
area
of
the
underground
openings
with
which
subsidence
predictions
can
be
compared
e
Maintain
a
database
of
subsidence
data
e
Provide
an
annual
written
report
during
the
operational
phase
The
process
by
which
subsidence
information
is
obtained
may
change
with
changing
technology.
Nothing
in
this
plan
will
limit
the
adoption
of
new
technology
provided
the
performance
of
subsidence
surveys
follow
the
specifications
described
in
the
FGCS
specifications
and
procedures
for
subsidence
leveling
surveys.
The
following
are
activities
of
the
Subsidence
Program:
Subsidence
Station
Maintenance
Subsidence
stations
are
maintained
as
needed.
Restoration,
replacement,
and
installation
of
new
stations
will
be
petformed
according
to
FGCS
specifications
and
procedures
for
Second
Order,
Class
II
Surveys.
Testinq
When
in
use,
daily
tests
are
performed
on
all
equipment
used
to
ensure
proper
operation
and
calibration.
Subsidence
Surveys
Subsidence
surveys
are
performed
annually
until
closure.
After
closure,
in
accordance
with
t
h
e
CCA,
subsidence
surveys
will
be
performed
on
the
first
and
third
year,
then
at
ten
year
intervals
for
the
next
100
years,
or
as
long
as
DOE
deems
necessary.
Report
and
Database.
A
report
is
generated
each
year
that
details
the
current
subsidence
survey
and
summarizes
previous
year's
values.
Survey
information
will
be
11
WWP
Underground
8
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
2
maintained
in
electronic
files
in
two
locations.
Backup
electronic
files
of
the
information
are
maintained
on
the
WIPP
Intranet.
4.8
QUAhlfY
ASSU
The
WIPP
Surveying
Engineering
Programs
are
governed
by
W
w
#lssufm
into
the
technicat
processes
used
for
Surveying
Engineering
activities,
as
needed.
The
Mine
Engineering
manager,
or
assigned
designee,
is
responsible
for
developing
and
maintaining
this
program.
Surveying
and
subsidence
surveying
at
the
WlPP
performed
by
qualified
contractor/
vendor
personnel
are
under
the
direct
supervision
of
the
WlPP
Mine
Engineering
Site
Survey
Section.
Vendor
personnel
who
perform
surveying
related
work
must
meet
the
following
minimum
standards:
.
Steps
to
ensure
quality
wi2
be
incorporated
0
Five
years
experience
in
field
surveying
Demonstrated
proficiency
in
the
use
of
various
precision
leveling
equipment
specified
for
the
monitoring
prsgram(
s)
a
Demonstrated
proficiency
in
the
use
of
various
related
surveying
software
specified
for
the
monitoring
prograrn(
s)
Demonstrated
proficiency
in
the
use
of
various
GPS
related
equipment
and
software
4.1
Survev
Equimnent
Control
Survey
equipment
processes
use
sound
surveying/
scientific
principles
and
appropriate
standards.
The
WIPP's
QA
program
and
WID
Engineering
require
that
tests
be
performed
on
all
equipment
when
in
use
to
ensure
proper
operation
and
calibration.
Surveying
equipment
are
controlled
and
calibrated
in
accordance
with
WlPP
procedures.
Results
of
calibrations,
maintenance,
and
repair
will
be
documented.
Calibration
records
will
identify
the
reference
standard
and
the
relationship
to
national
and
international
standards
or
nationally
accepted
measurement
systems.
Calibration
reports
and
operability
tests
are
maintained
by
the
WlPP
Metrology
Lab,
W
W
P
10
AD.
01
WlPP
Metrology
Program
requires,
at
a
minimum
of
every
two
years
or
in
accordance
with
manufacturerus
recommendations,
all
equipment
be
given
complete
maintenance
and
calibration
checks
by
approved
vendor(
s)
or
a
qualified
laboratory
to
ensure
the
equipment
is
properly
calibrated
and/
or
in
proper
working
condition.
For
subsidence
measurement
equipment,
maintenance
and
calibration
are
performed
by
approved
vendors
in
accordance
with
national
standards.
Equipment
is
maintained
and
calibrated
by
vendors
on
the
WIPP
QA
approved
Qualified
Supplier's
12
WlPP
Underground
&
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
1
List.
The
W1PP
QA
will
process
and
ensure
the
adequacy
of
routine
maintenance
performed
by
the
vendor.
4.2
Procurement
Procurement
of
equipment
is
carried
out
in
accordance
with
the
appropriate
poiicies
and
procedures
for
Design
Class
I
1
1B
equipment.
Technical
requiren
rents
and
services
will
be
developed
and
specified
in
procurement
documents.
If
deemed
necessary,
these
documents
will
require
suppliers
to
have
an
adequate
QA
program
to
ensure
that
required
character
ist
i
cs
are
attained
.
4.3
Qual
jty
affecting
activities
performed
by,
or
on
behalf
of,
the
Surveying
Programs
are
performed
in
accordance
with
FGCS
standards,
WIPP
approved
work
instructions,
andor
WIPP
approved
written
plans.
4.4
Document
Control
The
Mine
Engineering
manager
identifies
the
individuals
responsible
for
the
preparation,
review,
and
approval
of
Surveying
Engineering
controlled
documents.
Documents
generated
as
a
result
of
the
subsidence
surveys
are
reviewed
by
cognizant
technical
EngiT
ieering
perso'nnel
to
ensure
their
adequacy
and
accuracy.
Controlled
documents
are
reviewed
in
accordance
with
DOE
and
DOE/
WIPP
QuaMy
AsswaxeQ&
Review
procedures.
4.5
Control
of
Purchased
Material,
EauiDmentlServices
Measures
are
taken,
in
accordance
with
current
WlPP
procurement
policies
and
procedures,
to
ensure
that
procured
items
and
services
conform
to
specified
requirements.
These
measures
will
generally
include
one
or
more
of
the
following:
Evaluation
of
the
supplier's
capability
to
provide
items
or
services,
in
accordance
with
requirements,
including
the
previous
record
in
providing
similar
products
or
services
satisfactorily
e
Evaluation
of
objective
evidence
of
conformance,
such
as
supplier
submittals
e
Examination
and
testing
of
items
or
services
upon
delivery
I
f
it
is
determined
that
additional
measures
are
required
to
ensure
quality
in
a
specific
procurement,
additional
steps
may
be
provided
for
procurement
documents
and
implemented
by
Surveying
Engineering
personnel
and/
or
the
Quality
and
Regulatory
Assurance
Department.
These
additionai
assurances
may
include
source
inspection
13
WIPP
Underground
86
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
1
and
audits
or
surveillances
at
the
supplier's
facilities.
Measures
are
used
to
ensure
that
only
correct
and
accepted
items
are
used
at
the
WIPP.
All
items
that
potentially
affect
the
quatity
of
the
Surveying
Engineering
Programs
will
be
identified
and
controlled
to
ensure
traceability
and
prevent
the
use
of
incorrect
or
defective
items.
4.7
Computer
program
testing
activities
that
affect
quality
related
activities
performed
by
the
WID
or
their
suppliers
are
accomplished
in
accordance
with
approved
procedures
as
specified
by
the
W
W
P
13
1,
Test
requirements
and
acceptance
criteria
will
be
specified,
documented,
and
reviewed
and
will
be
based
upon
applicable
design
or
other
pertinent
technical
documents.
Required
tests,
including
verification,
hardware
integration,
and
in
use
tests,
will
be
controlled.
Testing
of
software
will
verify
the
capability
of
the
computer
program
to
produce
valid
results
for
test
probiems
encompassing
the
range
of
permitted
use
defined
by
the
program
d
o
w
men
ta
t
ion.
Depending
upon
the
complexity
of
the
computer
program
being
tested,
requirements
may
range
from
a
single
test
of
the
completed
computer
program
to
a
series
of
tests
performed
at
various
stages
of
computer
program
development
to
verify
correct
translation
between
stages
and
proper
working
of
individual
modules.
This
is
followed
by
an
overall
computer
program
test.
Regardless
of
the
number
of
stages
of
testing
performed,
verification
testing
and
validation
will
be
of
sufficient
scope
and
depth
to
establish
that
test
requirements
are
satisfied
and
that
the
software
produces
a
valid
result
for
its
intended
function.
4.8
Handling,
storage,
and
shipping
of
surveying
equipment
will
be
coordinated
in
accordance
with
the
manufacturer's
recommendations.
4.9
Control
of
Nonconforminq
Conditionslitems
Conditions
adverse
to
quality
will
be
documented
and
classified
with
regard
to
their
significance.
Gorrective
actions
will
be
taken
accordingly.
14
WIPP
Underground
&
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
1
Equipment
that
does
not
conform
to
specified
requirements
will
be
controlled
to
prevent
its
use.
Faulty
items
will
be
tagged
and
segregated.
Repaired
equipment
will
be
subject
to
the
original
acceptance
inspections
and
tests
prior
to
use.
4.10
Conditions
adverse
to
acceptable
quality
will
be
documented
and
reported
in
accordance
with
corrective
action
procedures
and
corrected
as
soon
as
practical.
Immediate
action
will
be
taken
to
control
work,
and
its
results,
performed
under
conditions
adverse
to
acceptable
quality
in
order
to
prevent
degradation
in
quality.
The
Mine
Engineering
manager,
or
designee,
will
investigate
any
deficiencies
in
activities.
4.11
Records
Manaqernent
Identification,
preparation,
collection,
storage,
maintenance,
disposition,
and
permanent
storage
of
records
will
be
in
accordance
with
approved
WlPP
procedures.
Generation
of
records
will
accurately
reflect
completed
work
and
facility
conditions
while
complying
with
statutory
or
contractual
requirements.
Records
will
be
transferred
and
protected
from
loss
and
damage
in
accordance
with
w
e
s
m
W
P
15
PR,
WlPP
Records
Management
Program.
.c
4.12
Audits
and
lndemndent
Assessment
Planned
and
periodic
assessments
will
be
conducted
to
measure
management
item
quality
and
process
effectiveness,
and
to
promote
improvement.
The
organization
performing
independent
assessments
will
have
sufficient
authority
to
carry
out
its
responsibilities.
Persons
conducting
technical
assessments
will
be
technically
qualified
and
knowledgeable
of
the
items
and
processes
to
be
assessed.
4.13
Data
Reduction
and
Verification
Computer
programs,
commercial
data
processing
applications,
and
manual
calculations
that
collect
or
maniputateheduce
data
will
be
verified.
Verification
must
be
performed
before
the
presentation
of
final
results
of
their
use
in
subsequent
activities,
WlJ!
becomes
necessary
to
present
or
use
unchecked
results,
transmittals,
and
subsequent
calculations
will
be
marked
"DRAFT"
until
such
time
that
the
results
are
verified
and
determined
to
be
correct.
5.0
IMPLEMENTATION
MATRIX
5.1
WID
Mine
Enaineerinq
15
WIPP
Underground
8
Surface
Surveying
Program
WP
09
ES.
01,
Rev.
1
WID
Mine
Engineering
will
be
the
cognizant
technical
organization
with
regard
to
the
implementation
of
the
WIPP
Underground
and
Surface
Surveying
Program,
including
Subsidence
Monitoring.
As
such,
WID
Mine
Engineering
is
responsible
for
the
perform
a
nce
,
rn
e
t
hod0
I
og
y
,
ca
1
cu
I
at
i
o
n
s
,
and
other
associated
activities
i
nvo
I
vi
n
g
the
collection,
interpretation,
and
presentation
of
required
data
necessary
to
implement
the
program
at
the
WIPP.
For
surface
surveys
outside
the
protected
area,
Mine
Engineering
personnel
will
ensure
compliance
with
the
National
Environmental
Policy
Act
(NEPA),
if/
as
applicable,
prior
to
initiating
survey
activities.
WID
Mine
Engineering
is
also
responsible
for
the
Annual
Subsidence
Monitoring
Survey
Report
as
well
as
all
other
necessary
documentation.
The
Annual
Subsidence
Monitoring
Survey
Report
will
be
published
within
each
calendar
year
as
a
DOE
document.
6.0
REFER
Backfill
Engineering
Analysis
Report,
IT
Corporation,
(1
994)
WP
13
1
,
Quality
Assurance
Program
Description
Compliance
Certification
Application
Classification,
Standards
of
Accuracy,
and
General
Specifications
of
Geodetic
Control
Surveys,
Federal
Geodetic
Control
Committee
(now
Federal
Geodetic
Control
Subcommittee),
[I
9751
1980,
Reprint
16
W
I
October
1998
Waste
Isolation
Pilot
Plant
Table
of
Contents
......................................................................................................
1
.
Introduction
1
2
.
Equipment
........................................................................................................
1
3
.
Office
Processing
.............................................................................................
1
4
.
Methodology
.....................................................................................................
1
5.
t
Accuracy
Summary
by
Loop
.......................................................................
5
6
.
Adjusted
Level
Loops
.......................................................................................
8
7
.
Adjusted
Elevations
(1
998)
..............................................................................
9
5
.
General
Summary
of
Results
...........................................................................
4
.
..............................................................................
8
Comparison
of
Elevations
10
List
of
Tables
Table
1
.
Description
of
1998
Leveling
Loops
......................................................
4
Table
3.
Detailed
Loop
Measurements
...............................................................
6
Table
2.
Summary
of
Distance
and
Accuracy
for
1998
Leveling
Loops
..............
4
Table
4
.
Adjusted
Elevations
by
Loop
.................................................................
8
Table
5
.
1998
Adjusted
Elevations
......................................................................
9
List
of
Figures
Figure
1
.
Individual
Loops.
Total
Loop.
and
Underground
Excavations
..............
3
I
List
of
Acronyms
DOE
Department
of
Energy
DOY
Day
of
year
FGCS
Federal
Geodetic
Control
Subcommittee
M&
IE
Measurement
and
Test
Equipment
NGS
National
Geodetic
Survey
WID
Waste
Isolation
Division
WlPP
Waste
Isolation
Pilot
Plant
References
Classification,
Standards
of
Accuracy,
and
General
Specifications
of
Geodetic
Control
Surveys,
Federal
Geodetic
Control
Committee
(now
Federal
Geodetic
Control
Subcommittee),
I19751
1980,
Reprint.
Interim
FGCS
Specifications
and
Procedures
to
Incorporate
Electronic
Digital
/
Bar
Code
Leveling
Systems,
Federal
Geodetic
Control
Subcommittee,
ver.
4.0,
dated
July
15,1994.
WlPP
Subsidence
Monument
Leveling
Surveys
1986
7997,
DOE
I
WlPP
98
2293,
June
1998.
ii
DQEWIPP
99
2293
I
.
Introduction
Sections
2
through
7
of
this
report
define
the
result
of
the
1998
leveling
survey
through
the
subsidence
monuments
at
the
WIPP
site.
Approximately
18
miles
of
leveling
was
completed
through
ten
vertical
control
loops.
The
1998
survey
includes
the
determination
of
elevation
on
each
of
the
52
existing
subsidence
monuments
and
the
WlPP
baseline
survey,
and
14
of
the
National
Geodetic
Survey's
(NGS)
vertical
control
points.
Digital
leveling
techniques
were
utilized
to
achieve
better
than
Second
Order
Class
I
I
loop
closures
as
outlined
by
the
Federal
Geodetic
Control
Subcommittee
(FGCS).
The
field
observations
were
completed
during
September
and
October
of
1998
by
personnel
from
the
Waste
Isolation
Division
(WID)
Surveying
Group,
Mine
Engineering
Section,
Engineerirrg
Department.
Finally,
Section
8
contains
Table
6,
which
summarizes
the
elevations
for
all
surveys
from
1986
through
1998,
inclusive.
A
detailed
listing
of
the
1986
through
1997
surveys
is
contained
in
the
report,
WPP
Subsidence
Monument
beveling
Surveys
1986
1997,
DOWIPP
98
2293.
2.
Equipment
The
observations
were
taker!
with
the
WILD
NA3003
Electronic
Digital
Level
(WIPP
M&
TE
ID#
0999)
manufactured
by
Leica,
and
bar
coded
leveling
staffs.
The
calibration
for
the
NA3003
is
valid
from
May
20,
1998,
through
May
20,
2000.
The
data
were
recorded
electronically
on
the
Leica
GRMI
0
REC
Module,
which
is
built
into
the
instrument.
In
addition
to
the
electronic
record,
a
written
field
log
was
maintained
to
record
information
that
is
not
stored
in
the
electronic
record.
3.
Office
Processing
Each
day
the
data
were
downloaded
from
the
GRMIO
REC
Module
to
the
survey
group
computer.
The
original
raw
data
files
were
maintained
intact,
and
further
processing
was
performed
on
a
copy
of
the
original
raw
data
file.
Listing
of
the
data,
and
the
adjustment
of
the
loops,
was
completed
with
the
DIGILEV
software
(version
10.94d)
from
Leica
Canada.
The
results,
as
summarized
below,
were
extracted
from
the
output
of
the
DiGlLEV
software.
4.
Methodology
The
weather
conditions
during
the
observations
of
the
1998
survey
were
generally
mild
with
moderate
temperatures
and
light
to
moderate
breezes.
The
elevations
for
the
1998
survey
are
computed
from
the
adjusted
obsa,
dafions
based
on
the
elevation
of
the
subsidence
monument,
S
37
(3,423.874
feet).
S
37
is
the
monument
that
is
furthest
from
the
influence
of
the
underground
1
DOWIPP
99
2
excavations,
and
has
been
held
fixed
for
all
of
the
subsidence
leveling
surveys
since
1993.
The
monument,
Pf
30,
has
been
physically
disturbed
and
was
removed
from
the
1998
survey.
For
visual
reference,
Figure
1
shows
a
graphic
display
of
the
individual
loops,
the
total
survey,
and
the
relationship
to
the
underground
excavations.
2
Q
419*..
..
s
37
e.,
'
0
.
_,
........
Loop
2
.
.
s51
._
..
_
..........
,
.....
..
.
.
:'s38
Legend
=
Survey
Pmnt
0
=Shaft
x
418
e
w
m
.
s43;
!O
...
.__..
.
.............
..*...
>..
S%
'PTJO
3
,
0
PT
31
.y
PT
21
S
27
Figure
1.
Individual
Loops,
Total
Survey
and
Underground
Excavations
3
5.
General
Summary
of
Resuits
(260)
September
21,1998
(264)
September
22,
1998
Table
1
below
describes
the
ten
leveling
loops
that
were
measured
to
obtain
the
elevations
of
the
subsidence
monuments.
The
table
contains
the
start
date
of
the
observations,
a
loop
number,
and
the
points
that
are
contained
within
the
loop.
Table
1.
Description
of
1998
Leveling
Loops
W418,
V
418,
S
41,
U
418,
Y
418,
A
419,
C
419
4
U
418,
S
18,
S
17,5
43,5
20,
S
42,
5
40,
S
21,
S
39,
S
19,
S
41,
U
418
U
418,
T
418,
K
349,
S
46,
S
418.
K
349,
T
418.
5
(265)
I
U
418
(266)
October
16,
1998
(289)
September
24,
1998
(267)
October
15,
1998
T
418,
S
16,
S
44,
T
418
K
349,
5
24,
S
23,
S
22,
PT
31,
PT
30,
S
09,
S
45,
S
10,
PT
32,
K
349
K
349,
S
52,
S
24,
S
25,
S
26,
S
49,
S
48,
S
13,
PT
33,
$12,
K
349
S
418,
S
34,
S
33,
S
32,
S
27,
PT
21,
S
22,
S
28.
7
8
9
Table
2
summarizes
the
results
of
the
leveling
loops
in
terms
of
vertical
closure
and
accuracy.
The
requirement
for
Second
Order
Class
11
loop
closure
accuracy
was
achieved
in
all
cases.
(288)
September
29,1998
(272)
Table
2.
Summa9
of
Distance
and
Accuracy
for
1998
Leveling
Loops
S
29,
S
46,
S
418
5
418,
S
34,
S
35,
S
36,
S
50,
5
31,
S
47,
S
30,
5418
10
Loop
Cumulative
Vertical
Accuracy
Allowable
Distance
(ft)
Closure
(ft.)
Accuracy
4
5.1
Accuracy
Surnrnav
by
Loop
Table
3
shows
a
detailed
summary
of
the
observations
in
the
leveling
loops
for
the
1998
survey.
The
information
in
the
table
for
each
loop
includes:
Between
each
benchmark
in
the
loop:
The
distance
leveled
between
benchmarks
along
the
loop.
0
The
number
of
instrument
setups
between
each
of
the
benchmarks.
The
difference
in
elevation
from
each
benchmark
to
the
next.
For
each
loop
as
a
whole:
The
accuracy
of
leveling.
The
accuracy
of
the
leveling
is
given
in
terms
of
feet
times
the
square
root
of
the
length
of
the
loop
in
miles.
The
actual
accuracy
of
leveling
is
computed
in
the
DlGlLEV
software,
and
is
based
on
the
actual
vertical
closure
of
the
loop.
The
maximum
allowable
accuracy
is
based
on
the
allowable
accuracy
of
a
loop
as
stated
in
the
FGCS
interim
specification
for
digital
leveling.
The
FGCS
specification
for
Second
Order
Class
II
loop
closure
permits
a
maximum
of
8mmdKm
(8mm
times
the
square
root
of
the
length
of
the
loop
in
Km).
This
converts
to
0.033ft.
dmile
(0.033
feet
times
the
square
root
of
the
length
Gf
t
h
e
loop
in
miles)
when
stated
in
feet.
All
values
indicated
in
this
summary
are
expressed
in
feet.
Inspection
of
the
following
tables
shows
that
in
every
case
the
actual
accuracy
is
well
below
the
maximum
allowable
accuracy
for
each
loop,
The
column
in
each
table
that
is
labeled
"Difference"
is
the
vertical
difference
from
one
point
to
the
next.
It
is
important
to
note
that
the
vertical
difference
figures
have
been
rounded,
and
a
slight
difference
may
exist
in
the
vertical
closure
figure
from
the
algebraic
sum
of
the
column.
The
cumulative,
or
total,
distance
of
each
loop.
The
vertical
closure
of
the
loop.
Allowable
accuracy
for
each
loop.
5
DOEMIPP
99
2
Table
3.
Detailed
loop
Measurements
kcuracv
of
Leveling:
0.002
I
s
418
I
K
349
I
2,087
I
14
I
2.457
12.745
9.364
4.003
0.002
1,187
D
419
S
51
2.744
S
51
S
38
3.61
1
24
0.632
A.
.
A
~
5
38
1
11334
I
10
:umulative
Distance:
9,533
DHfeF3,
nCi
7.297
0.81
5
8.273
7.249
3.687
1.81C
3.730
4.359
6.81
5
1
1.170
0.088
Setups
6
2
6
8
10
8
6
4
6
10
14
lertical
Closure:
iccuracy
of
beveling:
illowable
Accumcv:
0
.m
S
ol
s
03
180
595
0.044
s
53
1.238
0.000
I
s
4
3
1
E
1
s
45
m
IO
1,195
PT
1
0
S
14
1.193
S
14
S
15
1,000
S
15
T
418
444
Loop
3
Distance
1,418
955
532
41
5
1,225
596
579
61
1
404
244
2,395
2,164
2,371
13,910
A
41
9
setups
10
6
4
4
8
4
4
4
4
2
20
16
16
4.895
1
FX
I
1
595
0.561
1,176
5.800
T
418
1,749
4.010
Cumulative
Distance:
10,164
9.1
15
Vertical
Closure:
6.694
Accuracy
of
Leveling:
A419
Y
347
Y
347
2
41
8
2
418
Y
418
Y
418
X
418
X
418
,W
418
V
418
s
41
U
418
Y
418
Y
418
A41
9
w
418
w
i
a
s
41
u
41
a
0.130E
0.00:
0.04E
table
Accuracy:
_.
.
1
1y
Loop
7
Distance
915
To
S
24
S
23
s
22
PT
31
PT
30
S
09
s
45
s
10
PT
32
K
349
Distanec:
2.09f
8.142
2.677
7.71
E
1.231
0.14s
0.
m
0.00:
17.083
S
24
0.002
PT
31
1,026
1,065
1,430
1,022
169
1.011
1.010
685
988
9,321
Cumulative
Distance:
Vertical
Closure:
Accuracy
of
Leveling:
Distance
setups
4
8
6
6
6
4
10
14
6
2
a
From
W
1
8
51
8
S
I
7
s
4
3
s
2
0
5
42
SA0
s
2
1
5
3
9
s
19
To
s
fa
S
I
7
S
43
5
2
0
s42
S
40
s
2
1
s
39
s
19
S
41
1,112
706
696
598
1,332
1,132
1,836
757
245
9,739
ala
10.533
6.1
02
6.191
7.505
3.810
1
1.983
4.752
4.622
5
41
U418
Cumulative
Distance:
Vertical
Closure:
0.007
0.005
I
Accuracy
of
Leveling:
Table
3
continued
on
next
page..
(.
6
DOENYIPP
99
2293
Table
3.
Detailed
Loop
Measurements
(continued)
S
24
S
25
S
26
s
49
S
48
S
13
PT
33
s
12
K
349
Iistance:
Vertical
Closure:
To
S
34
s
33
5
32
S
27
PT
21
s
22
S28
S
29
S
46
S
418
1,079
1,032
1,024
94
1
1,013
1,007
527
547
904
8,326
Setups
1
Difference
2
i
3.376
5.469
5.823
11.981
12.716
0.678
10.924
2.473
Accuracy
of
Leveling:
0.004
Allowable
Accuracy:
0.041
LOOP
3
From
Distance
S
418
1,086
S
34
s
33
S
32
5
27
PT
21
s
2
2
S
28
S
29
_._
.
S
46
1,025
1,066
1,303
83
1,438
1,592
983
699
1,016
10.291
0.005
Cumulative
distance:
K
c
l
o
s
u
r
e
:
Setups
8
8
8
10
1
10
11
7
5
7
Difference
9.648
1
3.039
5.575
13.796
3.361
3.864
5.587
6.722
0.184
1.840
0.002
0.002
=pc
Loop
10
3istance
I
Setup
1
Difference
F
1.132
I
8
I
9.647
s
47
S
30
5
30
S
418
hmulative
Distance:
dertical
Closure:
4ccuracy
of
Leveling:
4llowable
Accuracy:
1,059
8.450
1,015
9.024
1,517
16.301
966
~
';
1
1
3.589
745
3.069
608
4
5.179
795
2.282
7,837
0.008
0.007
0.@
40
7
I
6.
Adjusted
Level
Loops
Table
4
is
a
summary
of
the
adjusted
elevations
for
the
ten
loops
measured
in
1998.
This
has
been
extracted
from
the
output
of
the
DlGlLEV
software.
Table
4.
Adjusted
Elewations
by
L
O
Q
~
,_,
a
I
;>
3:
1
3404.172
3416.916
U
418
3426.279
1
(2
419
I
3437.648
1
3395.887
3387.744
1
S
35
I
3400.516
8
DOEIWIPP
39
2293
7.
Adjusted
Elevations
(1
998)
Table
5
shows
the
adjusted
elevations
for
the
subsidence
monuments
and
the
NGS
points
contained
within
the
1998
survey.
These
elevations
are
normalized
to
the
monument,
S
37.
All
elevations
are
shown
in
feet,
and
are
within
the
WiPP
local
system.
Table
5.
1998
Adjusted
Elevations
9
I
8.
Comparison
of
Elevations
Table
6
compares
the
elevations
from
all
of
the
subsidence
leveling
surveys
from
I986
through
1998.
Table
6.
Comparison
of
Etevations
19864998
Note:
(1)
The
subsidence
monument,
S
02
was
relocated
in
1989.
(2)
The
subsidence
monument,
S
02,
no
longer
exists
after
the
1992
survey.
(3)
The
subsidence
monument,
S
I
1,
no
longer
exists
after
the
1992
survey.
Table
6
continued
on
next
page
...
10
DOENVlPP
99
2293
Table
6.
Comparison
of
Elevations
1986
1998
(continued)
Note:
(4)
The
subsidence
monument,
5
54,
no
longer
exists
after
the
1992
suwey.
(5)
The
monument,
PT
30,
has
been
physically
disturbed
and
was
removed
from
the
1998
survey.
Table
6
continued
on
next
page
...
11
I
?
12
Attachment
D.
6
Other
Reviewed
Table
7
7.
Preclosure
and
Postclosure
Monitored
Parameters
Preclosure
X
/
x
l
x
i
Monitored
Parameter
Culebra
groundwater
composition
Culebra
change
in
groundwater
flow
I
.
___
~
4
L
Probability
of
encountering
a
Castile
brine
reservoir
v"
/
Qilling
rate
4
d
bbsidence
measurements
x
i
i
A
X
F
a
t
e
activity
...
.
..
.
.
i
Creep
closure
and
stresses
Li
Extent
of
deformation
4
x
Initiation
of
brittle
deformation
4
x
i
t
i
t
j
X
Displacement
of
deformation
features
!I/
X
i
EEMENTATION
OF'
WIPP
LONG
TERM
MONITORING
PROGRAMS
J
~~~~~~~
n~~
Monitoring
The
program
that
monitors
this
data
is
implemented
by
WP
09
ES.
01,
Revision
0,
WPP
Underground
&
Suflace
Su
rveying
Program,
that
was
effective
January
23,
1998.
Subsidence
measurements
are
taken
at
monitoring
stations
installed
on
the
surfslce
above
the
completed
and
planned
WlPP
underground
excavations.
Since
1992
regular
subsidence
measurements
hwe
been
taken
and
they
will
continue
to
be
conducted
annually.
4
The
program
that
monitors
this
data
is
implemented
by
WP
05
WAOZ,
Revision
0,
WPP
Wmte
r
~~~~t
i
o
~
System
Program,
that
was
effective
on
April
15,
1997.
Since
DOE
has
not
begun
disposal
of
waste
yet,
no
actud
data
representing
waste
disposed
of
at
WIPP
has
been
entered
into
the
computerized
waste
information
system.
However,
=data
have
been
put
into
the
system
and
reports
have
been
run
to
vernfy
the
system
is
functional.
Information
will
be
entered
into
the
data
system
by
the
generator
sites
as
they
ship
waste
to
W
P
for
disposal.
ile
Brine
Reservoir
The
program
that
monitors
this
data
is
implemented
by
WP
02
PC.
02,
Revision
0,
Delwm&
'
Basin
Drilrilzg
Suweillmce
Plan,
that
was
effective
on
March
27,
1998.
Information
is
gathered
as
records
are
filed
with
the
appropriate
agency
and
data
is
gathered
from
these
records
and
put
into
a
database.
The
database
includes
records
of
drilling
activity
(including
borehole
depth,
diameter,
and
type),
well
conversion
activities,
occurrences
of
pressurized
brine
in
the
Castile
formation,
injection
well
operation,
plugging
and
abandonment
(including
descriptions
of
plugging
configurations),
and
identity
of
well
ownership.
Information
gathering
activities
began
in
late
1995.
Culebra
Ground
Water
Composition
and
Culebra
Ground
Water
Flow
The
program
that
monitors
this
data
is
implemented
by
WP
02
1,
Revision
3
,
Groundwater'
that
was
effective
on
March
12,
1996.
Sa
groundwater
composition
and
nd
water
flow.
The
current
su
1996,
however,
an
early
program
dates
back
to
1985.
Creep
Closure
and
Stresses,
Extent
of
Deformation,
Initiation
of
Brittle
Deformation.
and
Disulacement
of
Deformation
Features
The
program
that
monitors
this
data
is
implemented
by
WP
07
01,
Revision
2,
WPP
Geotechnical
Engineering
v'
Program
Plan,
that
was
effective
on
March
16,
1998.
Data
is
collected
by
a
network
of
instruments
including
tape
and
borehole
extensometers,
convergence
meters,
rockboit
load
cells,
pressure
cells,
crack
meters,
strain
gauges,
and
piezometers.
Data
is
logged
either
remotely
by
data
loggers,
or
manually.
The
measurement
program
began
in
1983
and
is
conducted
at
least
quarterly.
A
comprehensive
report
containing
the
results
of
the
data
analysis
is
published
annually.
Attachment
D.
4
Drilling
Related
Documents
Reviewed
I
Working
Copy
Effective
Date:
3/
27/
97'
WP
02
PC.
02
Revision
0
Cognizant
Section:
Long
Term
Reauiatory
Compliance
Approved
By:
Sianature
on
File
R.
J.
Leonard
Cognizant
Department:
Environment.
Safety.
and
Wealth
Approved
By:
sin
Driliing
Surveillance
Plan
WP
02
PC.
02.
Rev
.
0
TABLE
OF
CONTENTS
ACRONYMS
.........................................................
ii
1.0
INTRODUCTION
.................................................
9
2.0
PURPOSE
......................................................
2
3.0
IMPLEMENTATION
...............................................
3
4.0
ACTIVITIES
.....................................................
3
4.1
Texas
Portion
of
t
h
e
Delaware
Basin
..............................
3
4.2
New
Mexico
Portion
of
the
Delaware
Basin
..........................
3
4.3
Nine
Township
Area
Information
..................................
4
4.4
General
Database
Maintenance
..................................
5
5.0
REPORTS
.......
....................
.........................
5
6.0
QUALITYASSURANCE
............................................
5
REFERENCES
.......................................................
5
FlGBiRE
1
SURVEILLANCE
AREAS
WITHIN
THE
DELAWARE
8ASIN
.........
7
I
'Warking
Copy
Delaware
Basin
Drilling
Surveillance
Pian
WP
02
PC.
02,
Rev.
0
BLM
CAO
CCA
CFR
DOE
EPA
OCD
QAPD
WiPP
Bureau
of
Land
Management
Carlsbad
Area
Office
Compliance
Certification
Application
Code
of
Federal
Regulations
U.
S.
Department
of
Energy
Environmental
Protection
Agency
State
of
New
Mexico
Oil
Conservation
Division
Quality
Assurance
Program
Description
Waste
Isolation
Pilot
Plant
ii
Working
Copy
Delaware
Basin
Drilling
Surveillance
Pian
WP
02
PC.
02,
Rev.
0
1
.O
INTRODUCTION
The
Environmental
Protection
Agency
(EPA)
environmental
standards
for
the
management
and
disposal
of
transuranic
radioactive
waste
are
codified
in
Title
40,
Code
of
Federal
Regulations
(CFR),
Part
191
(EPA
1993).
Subparts
€3
and
C
of
the
standard
address
the
disposal
of
radioactive
waste.
The
standard
requires
that
the
Department
of
Energy
(DOE)
demonstrate
through
the
use
of
a
probabilistic
risk
assessment
that
the
disposal
system
will
function
to
contain
radioactivity
below
specified
release
limits
considering
the
effects
of
reasonably
expected
human
initiated
and
natural
processes
and
events.
This
includes
the
consideration
of
inadvertent
drilling
into
the
repository
at
some
future
time.
The
EPA
provided
criteria
in
40
CFR
§
194.33
that
addressed
the
consideration
of
future
deep
and
shallow
drilling
in
performance
assessments.
These
criteria
lead
to
the
formulation
of
conceptual
models
that
incorporate
the
effects
of
these
activities.
These
conceptual
models
use
parameter
values
drawn
from
the
databases
in
Appendix
DEL
of
the
Compliance
Certification
Application
(CCA).
In
accordance
with
these
criteria,
the
DQE
used
the
historical
rate
of
drilling
for
resources
in
the
Delaware
Basin
to
calculate
a
future
drilling
rate.
In
particular,
in
calculating
the
frequency
of
future
deep
drilling,
40
CFR
§
194.33(
b)(
3)(
I)(
EPA
1996)
provided
the
following
guidance
to
the
DOE:
Identify
deep
drilling
that
has
occurred
for
each
resource
in
the
Delaware
Basin
over
the
past
100
years
prior
to
the
time
at
which
a
compliance
application
is
prepared.
The
DOE
used
the
historical
record
of
deep
drilling
for
resources
below
2,150
feet
(656
meters)
that
has
occurred
over
the
past
700
years
in
the
Delaware
Basin.
In
the
past
100
years,
deep
drilling
for
oil,
gas,
potash,
and
sulfur
exploration
has
occurred.
All
of
these
drilling
events
were
used
in
calculating
the
rate
of
deep
drilling
within
the
controlled
area
(the
16
section
Land
Withdrawal
Boundary)
and
throughout
the
basin
in
the
future,
as
discussed
in
Appendix
DEL
of
the
CCA.
Historical
drilling
for
purposes
other
than
resource
exploration
and
recovery
(such
as
WlPP
site
investigatio?)
were
excluded
from
the
calculation
in
accordance
with
guidance
provided
in
40
CFR
3
194.33.
In
calculating
the
frequency
of
future
shallow
drilling,
40
CFR
§
194.33(
b)(
4f(
I)
states
that
the
DOE
should:
Identify
shallow
drilling
that
has
occurred
for
each
resource
in
the
Delaware
Basin
over
the
past
100
years
prior
to
the
time
at
which
a
compliance
application
is
prepared.
1
I
Working
Copy
Delaware
Basin
Drilling
Suweillance
Plan
WP
02
PC.
02,
Rev.
0
An
additional
criterion
with
respect
to
the
calculation
of
Future
shallow
drilling
rates
is
provided
in
40
CFR
194.33(
b)(
4)(
iii):
In
considering
the
historical
rate
of
all
shallow
drilling,
the
Department
may,
if
justified,
consider
only
the
historical
rate
of
shallow
drilling
for
resources
of
similar
type
and
quality
to
those
in
the
controlled
area.
The
only
resources
present
at
shallow
depths
(less
than
2,150
feet
1655
meters)
below
the
surface)
within
the
controlled
area
are
water
and
potash.
Thus,
consistent
with
40
CFR
§
194.33(
b)(
4),
the
DOE
used
the
historical
record
of
shallow
drilling
associated
with
water
and
potash
extraction
in
the
Delaware
Basin
in
calculating
the
rate
of
shallow
drilling
within
the
controlled
area.
The
EPA
provides
further
criteria
concerning
the
analysis
of
the
consequence
of
future
drilling
events
in
performance
assessments
in
40
CFR
5
194.33(
c)(
EPA
1996).
Consistent
with
these
criteria,
the
following
parameters
regarding
drilfing
were
also
included
in
the
performance
assessment
as
documented
in
Appendix
DEL
of
the
CCA:
Types
of
drilling
fluids
Amounts
of
drilling
fluids
Borehole
depths
Borehole
diameters
E3orehole
plugs
Fraction
of
such
boreholes
that
are
sealed
by
humans
Natural
processes
that
will
degrade
plugs
Instances
of
encountering
pressurized
brine
in
the
Castile
Formation
The
DOE
will
continue
to
provide
surveillance
of
the
drilling
activity
in
the
Delaware
Basin
in
accordance
with
the
criteria
established
in
40
CFR
5
194
during
the
operational
phase
and
will
continue
until
the
DOE
and
EPA
agree
that
no
further
benefit
can
be
gained
from
continued
surveillance.
The
results
of
this
surveillance
activity
will
be
used
in
performance
assessment
calculations
performed
in
support
of
recertification.
2.0
PURPOS
The
purpose
of
the
Delaware
Basin
Drilling
Surveillance
Plan
is
to
provide
for
active
surveillance
of
drilling
activities
within
the
Delaware
Basin
(see
Figure
I),
with
specific
emphasis
on
the
nine
township
area
that
includes
the
Waste
Isolation
Pilot
Plant
(WIPP)
site
(Figure
I).
The
surveillance
of
drilling
activities
will
build
on
the
data
presented
in
Appendix
DEL
and
comply
with
the
activities
presented
in
Appendix
DMP
of
the
CCA,
which
were
used
to
develop
modeling
assumptions
for
performance
assessment.
The
collection
of
additional
information
on
drilling
patterns
and
practices
in
the
Delaware
Basin
will
be
used
to
define
whether
the
drilling
scenarios
in
the
application
continue
to
b
e
valid
ai
,ach
five
year
recertification
time
for
the
WIPP.
2
working
copy
Delaware
Basin
Drilling
Surveillance
Plan
WP
02
PC.
02,
Rev.
0
Surveillance
of
drilling
activities
within
the
Delaware
Basin
will
be
implemented
no
later
than
the
beginning
of
the
operational
phase.
This
activity
will
continue
until
100
years
after
closure
or
until
the
DOE
can
demons'.
.de
to
the
EPA
that
there
are
no
significant
concerns
to
be
addressed
by
further
surveillance,
as
discussed
in
Chapter
7,
Section
7.1.4,
Effectiveness
of
the
Active
Institutional
Controls
Program,
of
the
CCA,
DOE/
CAO
1996
2184,
October
1996.
Beginning
no
later
than
the
initiation
of
the
operational
phase
and
continuing
through
post
closure,
driliing
activities
within
the
Delaware
Basin
will
be
tracked
using
commercially
available
databases.
Drilling
activities
related
to
hydrocarbon
resources,
potash
boreholes,
and
water
welts
that
occur
within
the
nine
township
area,
will
be
more
rigorously
monitored
using
the
commercial
databases
and
the
drilling
records
maintained
by
both
state
and
federal
organ
iza
t
io
n
s
.
4.
Q
ACTIVITIES
4.1
Texas
Portion
of
the
Delaware
Basin
Data
on
drilling
activities
as
related
to
hydrocarbon
resources,
sulfur
boreholes,
and
water
wells
that
occur
within
the
Texas
portion
of
the
Delaware
Basin
will
be
speeificalIy
collected
and
recorded
by
Long
Term
Regulatory
Compliance
on
a
monthly
basis.
The
data
will
be
collected
from
commercial
databases
and
will
be
verified
from
state
and
federal
records
as
necessary.
This
data
(to
the
extent
it
is
not
proprietary)
will
be
added
to
the
existing
visual
database
established
for
the
CCA.
The
specific
activities
in
the
Texas
area
(see
Figure
1)
that
will
be
tracked
on
a
monthly
basis
are
as
follows:
New
drilling
activities
(deep
and
shallow)
Abandonment
activities
(when
plugged)
Type
of
well
(oil,
gas,
sulfur,
water,
etc.)
4.2
New
Mexico
Portion
of
the
Delaware
Basin
Data
on
drilling
activities
related
to
hydrocarbon
resources,
sulfur
boreholes,
and
water
wells
that
occur
within
the
New
Mexico
portion
of
the
Delaware
Basin
will
be
specifically
collected
and
recorded
by
Long
Term
Regulatory
Compliance
on
a
monthly
basis.
The
data
will
be
collected
from
commercial
databases
and
will
be
verified
from
state
and
federal
records.
This
data
(to
the
extent
it
is
not
proprietary)
will
be
added
to
the
existing
visual
database
and
a
database
of
New
Mexico
wells
established
for
the
CCA.
3
Woiking
Copy
Delaware
Basin
Drilling
Surveillance
Plan
WP
02
PC.
02,
Rev.
0
The
specific
activities
in
the
New
Mexico
area
(see
Figure
1)
that
will
be
tracked
on
a
monthly
basis
are
as
follows:
New
drilling
activities
(deep
and
shallow)
Abandonment
activities
(when
and
how
plugged)
Type
of
weli
(oil,
gas,
sulfur,
water,
etc.)
Occurrences
of
pressurized
brine
within
the
Castile
Formation
Injection
well
operation
(disposal
and
secondary
recovery)
Solution
well
mining
(salt
and
potash)
*
*
0
0
*
4.3
Nine
Township"
Area
Information
Data
on
drilling
activities
related
to
hydrocarbon
resources,
potash
boreholes,
and
water
wells
that
occur
within
the
Delaware
Basin
portion
of
the
nine
township
area
(see
Figure)
will
be
specifically
collected
and
recorded
by
bong
Term
Regulatory
Compliance
on
a
monthly
basis.
The
data
will
be
collected
from
commercial
databases
and
from
state
and
federal
records.
This
data
(to
the
extent
it
is
not
proprietary)
will
be
added
to
the
existing
visual
and
New
Mexico
wells
databases
established
for
the
CCA.
The
specific
activities
in
the
nine
township
area
that
will
be
tracked
on
a
monthly
basis
are
as
follows:
New
drilling
activities
(of
any
kind,
both
deep
and
shallow)
e
Abandonment
activities
(when
and
how
plugged)
*
Type
of
well
(oil,
gas,
sulfur,
water,
ete.)
*
Occurrences
of
pressurized
brine
within
the
Castile
Formation
Injection
well
operation
(disposal
and
secondary
recovery)
Solution
well
mining
(salt
and
potash)
Maintenance
of
databases
for
incidences
of
non
compliance
with
Bureau
of
Land
Management
(BLM)
and
State
of
New
Mexico
Oil
Conservation
Division
(OC)
rules
as
information
is
recw
ied
in
the
files
maintained
by
the
BLMIOCD
e
Identification
of
ownership
(through
BLMIOCD
records
monitoring)
of
all
state
and
federal
minerals
and
hydrocarbon
leases
within
the
area
4
Working
Copy
Delaware
Basin
Drilling
Surveillance
Plan
WP
02
PC.
02,
Rev.
0
4.4
General
Database
Maintenance
Long
Term
Regulatory
Compliance
will
maintain
and
update,
on
a
monthly
basis,
the
databases
of
the
Delaware
Basin
established
for
the
CCA,
in
an
electronic
format.
The
visual
database
(an
electronic
map
of
the
defined
area)
will
reflect
the
current
status
of
ail
known
wells
in
the
Delaware
Basin.
Maps
of
the
Delaware
Basin
wiil
be
published
as
needed
from
this
visual
database.
The
New
Mexico
well
database
will
be
in
a
database
format
that
will
contain
the
same
information
as
the
visual
database
and
will
include
much
more
detailed
information
on
the
wells
in
the
New
Mexico
portion
of
the
Delaware
Basin.
5.0
REPORTS
Data
will
be
reviewed
annually
to
ensure
there
are
no
substantial
and
detrimental
deviations
from
the
assumptions
used
in
the
perfdrrnance
assessment
documented
in
the
CCA.
An
annual
report
will
then
be
prepared
and
included
with
other
environmental
data
and
will
be
provided
to
the
DOE
and
made
available
to
the
EPA.
Every
five
years,
information
will
be
summarized
for
input
into
the
recertification
process
as
defined
in
40
CFR
5
194.15
(EPA
1996).
6.0
QUALITY
ASSURANCE
Activities
will
be
conducted
in
accordance
with
the
appropriate
sections
of
WP
13
1,
WID
QAPD.
Specifically,
an
outside
source
(the
Waste
Isolation
Division
Quaiity
and
Regulatory
Assurance
Department)
will
randomly
select
a
minimum
of
20
wells
from
a
map
of
the
Delaware
Basin.
They
will
verify
that
the
information
contained
in
the
two
databases;
the
visual
and
New
Mexico
wek,
matches
the
information
prorided
from
the
commercial
databases
and
records
$rom
the
state
and
federal
agencies.
When
possible
and
practical,
field
verification
will
be
conducted
only
within
the
nine
township
area
and
only
to
the
extent
to
verify
the
actual
condition
of
the
well.
Field
verification
recorded
in
permanent
notebooks
will
be
done
in
accordance
with
WP
13
1,
WID
QAPD.
REFERENCES
EPA,
1993.
40
CFR
§
Part
191:
Environmental
Standards
for
the
Management
and
Disposal
of
Spent
Nuclear
Fuel,
High
Level
and
transuranic
Radioactive
Wastes;
Final
Rule.
Federal
Register,
Vol.
58,
No.
242,
p.
66398.
December
20,
1993.
Office
of
Radiation
and
Air,
Washington,
D.
C.
€PA,
1996.
40
CFR
Pa&
194:
CritePia
for
the
Certifi
Waste
Isolation
Pilot
Plant's
Compliance
with
the
40
CFR
Part
191
Disposal
Regulations;
Final
Rule.
Federal
Register,
Vol.
61
,
pp.
5224
5245,
February
9,
1996.
Office
of
Radiation
and
Indoor
Air,
Washington,
D.
C.
&
M
c
a
t
i
o
n
of
the
5
| epa | 2024-06-07T20:31:39.645707 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0012-0189/content.txt"
} |
EPA-HQ-OAR-2001-0014-0135 | Supporting & Related Material | "2002-03-28T05:00:00" | null | epa | 2024-06-07T20:31:39.713056 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0135/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0136 | Supporting & Related Material | "2002-03-28T05:00:00" | null | epa | 2024-06-07T20:31:39.713815 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0136/content.txt"
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|
EPA-HQ-OAR-2001-0014-0137 | Supporting & Related Material | "2002-03-28T05:00:00" | null | epa | 2024-06-07T20:31:39.714450 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0137/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0138 | Supporting & Related Material | "2002-04-05T05:00:00" | null | epa | 2024-06-07T20:31:39.715263 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0138/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0139 | Supporting & Related Material | "2002-04-12T04:00:00" | null | epa | 2024-06-07T20:31:39.716171 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0139/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0140 | Supporting & Related Material | "2002-04-12T04:00:00" | null | epa | 2024-06-07T20:31:39.716827 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0140/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0141 | Supporting & Related Material | "2002-04-24T04:00:00" | null | epa | 2024-06-07T20:31:39.717512 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0141/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0142 | Supporting & Related Material | "2002-04-24T04:00:00" | null | epa | 2024-06-07T20:31:39.718219 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0142/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0143 | Supporting & Related Material | "2002-04-19T04:00:00" | null | epa | 2024-06-07T20:31:39.718995 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0143/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0144 | Supporting & Related Material | "2002-04-19T04:00:00" | null | epa | 2024-06-07T20:31:39.719722 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0144/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0145 | Supporting & Related Material | "2002-04-19T04:00:00" | null | epa | 2024-06-07T20:31:39.720404 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0145/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0146 | Supporting & Related Material | "2002-04-19T04:00:00" | null | epa | 2024-06-07T20:31:39.721045 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0146/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0147 | Supporting & Related Material | "2002-05-01T04:00:00" | null | epa | 2024-06-07T20:31:39.721748 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0147/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0148 | Supporting & Related Material | "2002-05-01T04:00:00" | null | epa | 2024-06-07T20:31:39.722337 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0148/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0149 | Supporting & Related Material | "2002-04-29T04:00:00" | null | epa | 2024-06-07T20:31:39.722941 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0149/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0150 | Supporting & Related Material | "2002-05-07T04:00:00" | null | epa | 2024-06-07T20:31:39.723593 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0150/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0151 | Supporting & Related Material | "2002-04-19T04:00:00" | null | epa | 2024-06-07T20:31:39.724238 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0151/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0152 | Supporting & Related Material | "2002-04-12T04:00:00" | null | epa | 2024-06-07T20:31:39.724895 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0152/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0153 | Supporting & Related Material | "2002-05-21T04:00:00" | null | epa | 2024-06-07T20:31:39.725633 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0153/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0154 | Supporting & Related Material | "2002-05-30T04:00:00" | null | epa | 2024-06-07T20:31:39.726276 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0154/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0155 | Supporting & Related Material | "2002-05-30T04:00:00" | null | epa | 2024-06-07T20:31:39.727068 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0155/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0156 | Supporting & Related Material | "2002-06-24T04:00:00" | null | epa | 2024-06-07T20:31:39.727734 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0156/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0157 | Supporting & Related Material | "2002-07-17T04:00:00" | null | epa | 2024-06-07T20:31:39.728361 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0157/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0158 | Supporting & Related Material | "2002-03-28T05:00:00" | null | epa | 2024-06-07T20:31:39.729127 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0158/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0159 | Supporting & Related Material | "2002-03-28T05:00:00" | null | epa | 2024-06-07T20:31:39.729960 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0159/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0160 | Supporting & Related Material | "2002-03-28T05:00:00" | null | epa | 2024-06-07T20:31:39.730651 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0160/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0161 | Supporting & Related Material | "2002-03-28T05:00:00" | null | epa | 2024-06-07T20:31:39.731330 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0161/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0162 | Supporting & Related Material | "2002-04-12T04:00:00" | null | epa | 2024-06-07T20:31:39.731959 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0162/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0163 | Supporting & Related Material | "2002-04-12T04:00:00" | null | epa | 2024-06-07T20:31:39.732751 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0163/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0164 | Supporting & Related Material | "2002-04-24T04:00:00" | null | epa | 2024-06-07T20:31:39.733699 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0164/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0165 | Supporting & Related Material | "2002-04-24T04:00:00" | null | epa | 2024-06-07T20:31:39.734457 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0165/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0166 | Supporting & Related Material | "2002-04-19T04:00:00" | null | epa | 2024-06-07T20:31:39.735215 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0166/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0167 | Supporting & Related Material | "2002-04-19T04:00:00" | null | epa | 2024-06-07T20:31:39.735926 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0167/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0168 | Supporting & Related Material | "2002-04-19T04:00:00" | null | epa | 2024-06-07T20:31:39.736730 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0168/content.txt"
} |