[Federal Register: September 12, 2007 (Volume 72, Number 176)]
[Proposed Rules]
[Page 52205-52261]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr12se07-23]
[[Page 52205]]
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Part II
Environmental Protection Agency
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40 CFR Parts 51, 52, 70, and 71
Operating Permit Programs and Prevention of Significant Deterioration
(PSD) and Nonattainment New Source Review (NSR); Flexible Air
Permitting Rule; Proposed Rule
[[Page 52206]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 52, 70, and 71
[EPA-HQ-OAR-2004-0087, FRL-8462-9]
RIN 2060-AM45
Operating Permit Programs and Prevention of Significant
Deterioration (PSD) and Nonattainment New Source Review (NSR); Flexible
Air Permitting Rule
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: We are proposing to revise the regulations governing State and
Federal operating permit programs required by title V of the Clean Air
Act (CAA or the Act) and the New Source Review (NSR) programs required
by parts C and D of title I of the Act. These proposed actions are
based, in large part, on the lessons learned through EPA's pilot
experience in which EPA worked closely with States and certain sources
subject to title V permitting requirements to develop flexible air
permitting approaches that provide greater operational flexibility and,
at the same time, ensure environmental protection and compliance with
applicable laws.
In pilot permits, increased flexibility is primarily achieved
through advance approvals under NSR and alternative operating scenarios
(AOSs). The proposed revisions clarify how this can often be done in
the existing regulatory framework of the operating permit programs. The
proposed revisions also add major NSR requirements for Green Groups,
which allow future changes to occur within a group of emissions
activities, provided that they are ducted to a common air pollution
control device which is determined to meet ``best available control
technology'' (BACT) or ``lowest achievable emission rate'' (LAER), as
applicable and that they are determined to comply with all relevant
ambient requirements.
DATES: Comments. Written comments must be received on or before
November 13, 2007. Under the Paperwork Reduction Act, comments on the
information collection provisions must be received by OMB on or before
October 12, 2007.
Public Hearing. If anyone contacts EPA requesting to speak at a
public hearing by October 2, 2007, we will hold a public hearing
approximately 30 days after publication in the Federal Register.
Additional information about the hearing would be published in a
subsequent Federal Register notice.
ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2004-0087, by one of the following methods:
http://www.regulations.gov: Follow the on-line
instructions for submitting comments.
E-mail: a-and-r-Docket@epa.gov.
Fax: (202) 566-9744.
Mail: Environmental Protection Agency, EPA Docket Center
(EPA/DC), Air and Radiation Docket, Mail Code 2822T, 1200 Pennsylvania
Avenue, NW., Washington, DC 20460. Please include two copies. In
addition, please mail a copy of your comments on the information
collection provisions to the Office of Management and Budget (OMB),
Attn: Desk Officer for EPA, 725 17th St., NW., Washington, DC 20503.
Hand Delivery: EPA Docket Center, (Air Docket), U.S.
Environmental Protection Agency, Room 3334, 1301 Constitution Ave.,
NW., Washington, DC. Such deliveries are only accepted during the
Docket's normal hours of operation, and special arrangements should be
made for deliveries of boxed information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2004-0087. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
http://www.regulations.gov, including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through http://www.regulations.gov or e-mail.
The http://www.regulations.gov Web site is an ``anonymous access'' system,
which means EPA will not know your identity or contact information
unless you provide it in the body of your comment. If you send an e-
mail comment directly to EPA without going through http://www.regulations.gov,
your e-mail address will be automatically captured and included as part
of the comment that is placed in the public docket and made available
on the Internet. If you submit an electronic comment, EPA recommends
that you include your name and other contact information in the body of
your comment and with any disk or CD-ROM you submit. If EPA cannot read
your comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment. Electronic
files should avoid the use of special characters, any form of
encryption, and be free of any defects or viruses. For additional
instructions on submitting comments, go to I C & D of the SUPPLEMENTARY
INFORMATION section of this document.
Docket: All documents in the docket are listed in the index at
http://www.regulations.gov. Although listed in the index, some information is
not publicly available, i.e., CBI or other information whose disclosure
is restricted by statute. Certain other material, such as copyrighted
material, is not placed on the Internet and will be publicly available
only in hard copy form. Publicly available docket materials are
available either electronically in http://www.regulations.gov or in hard copy
at the EPA Docket Center (Air Docket), EPA West, Room 3334, 1301
Constitution Ave., NW., Washington, DC. The Public Reading Room is open
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal
holidays. The telephone number for the Public Reading Room is (202)
566-1744, and the telephone number for the Air Docket is (202) 566-
1742.
FOR FURTHER INFORMATION CONTACT: For issues concerning advance
approvals and AOSs, contact Michael Trutna, Air Quality Policy Division
(C504-01), U.S. Environmental Protection Agency, Research Triangle
Park, NC 27711; telephone (919) 541-5345, fax number (919) 541-4028; or
electronic mail at trutna.mike@epa.gov.
For issues concerning ARMs and EPA's pilot permits, contact David
Beck, Office of Policy, Economics, and Innovation, Innovative Pilots
Division (C304-05), U.S. Environmental Protection Agency, Research
Triangle Park, NC 27711; telephone (919) 541-5421, fax number (919)
541-2664; or electronic mail at beck.david@epa.gov.
For issues relating to monitoring, recordkeeping, and reporting for
flexible air permits, contact Barrett Parker, Sector Policies and
Programs Division, Measurement Policy Group (D243-03), U.S.
Environmental Protection Agency, Research Triangle Park, NC 27711;
telephone 919-541-5635, fax number (919) 541-1039; or electronic mail
at parker.barrett@epa.gov.
For other part 70 issues, contact Juan Santiago, Operating Permits
Group, Air Quality Policy Division (C504-05), U.S. Environmental
Protection Agency, Research Triangle Park, NC 27711; telephone (919)
541-1084, fax number (919) 541-5509; or electronic mail at
santiago.juan@epa.gov.
For issues relating to Green Groups, contact Dave Painter, New
Source Review Group, Air Quality Policy Division (C504-03), U.S.
Environmental Protection Agency, Research Triangle Park, NC 27711;
telephone (919) 541-
[[Page 52207]]
5515, fax number (919) 541-5509; or electronic mail at
painter.david@epa.gov.
To request a hearing or information pertaining to a hearing on this
document, please contact Pam Long, Air Quality Policy Division, U.S.
EPA, Office of Air Quality Planning and Standards (C504-03), Research
Triangle Park, North Carolina 27711, telephone number (919) 541-0641,
facsimile number (919) 541-5509; electronic mail e-mail address:
long.pam@epa.gov.
SUPPLEMENTARY INFORMATION:
I. General Information
A. What are the regulated entities?
Entities potentially affected by these proposed actions are
facilities currently required to obtain title V permits under State,
local, tribal, or Federal operating permits programs, and State, local,
and tribal governments that are authorized by EPA to issue such
operating permits. Other entities potentially affected by this proposed
action are facilities required to obtain major NSR permits under State,
local, tribal, or Federal major NSR programs, and State, local, and
tribal governments that issue such permits pursuant to approved part 51
major NSR programs. Potentially affected sources are found in a wide
variety of industry groups. In particular, we believe based on our
experience in implementing our flexible air permit pilot program that
these groups will include, but are not limited to, the following:
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Industry group SIC a NAICS b
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Aerospace Manufacturing....... 372.............. 336411, 336412,
332912, 336411,
335413.
Automobile Manufacturing...... 371.............. 336111, 336112,
336712, 336211,
336992, 336322,
336312, 33633,
33634, 33635,
336399, 336212,
336213.
Industrial Organic Chemicals.. 286.............. 325191, 32511,
325132, 325192,
225188, 325193,
32512, 325199.
Chemical Processes............ 281.............. 325181, 325182,
325188, 32512,
325131, 325998,
331311.
Converted Paper and Paperboard 267.............. 322221, 322222,
Products. 322223, 322224,
322226, 322231,
326111, 326112,
322299, 322291,
322232, 322233,
322211.
Magnetic Tape Manufacturing... 369.............. 334613.
Petroleum Refining............ 291.............. 32411.
Other Coating Operations...... 226, 229, 251, 313311, 313312,
252, 253, 254, 314992, 33132,
267, 358, 363. 337122, 337121,
337124, 337215,
337129, 37125,
337211, 337214,
337127, 322221,
322222, 322226,
335221, 335222,
335224, 335228,
333312, 333415,
333319.
Paper Mills................... 262.............. 322121, 322122.
Pharmaceutical Manufacturing.. 283.............. 325411, 325412,
325413, 325414.
Printing and Publishing....... 275.............. 323114, 323110,
323111, 323113,
323112, 323115,
323119.
Pulp and Paper Mills.......... 262.............. 32211, 322121,
322122, 32213.
Semi-conductors............... 367.............. 334413.
Specialty Chemical Batch 282, 283, 284, 3251, 3252, 3253,
Processes. 285, 286, 287, 3254, 3255, 3256,
289, 386. 3259, except 325131
and 325181.
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a Standard Industrial Classification
b North American Industry Classification System.
B. What should I consider as I prepare my comments for EPA?
1. Submitting CBI
Do not submit this information to EPA through http://www.regulations.gov
or e-mail. Clearly mark the part or all of the information that you
claim to be CBI. For CBI information in a disk or CD-ROM that you mail
to EPA, mark the outside of the disk or CD-ROM as CBI and then identify
electronically within the disk or CD-ROM the specific information that
is claimed as CBI. In addition to one complete version of the comment
that includes information claimed as CBI, a copy of the comment that
does not contain the information claimed as CBI must be submitted for
inclusion in the public docket. Information so marked will not be
disclosed except in accordance with procedures set forth in 40 CFR part
2.
2. Suggestions for Preparing Your Comments
When submitting comments, remember to:
Identify the rulemaking by docket number and other
identifying information (subject heading, Federal Register date and
page number).
Follow directions. The Agency may ask you to respond to
specific questions or organize comments by referencing a Code of
Federal Regulations (CFR) part or section number.
Explain why you agree or disagree; suggest alternatives
and substitute language for your requested changes.
Describe any assumptions and provide any technical
information and/or data that you used.
If you estimate potential costs or burdens, explain how
you arrived at your estimate in sufficient detail to allow for it to be
reproduced.
Provide specific examples to illustrate your concerns, and
suggest alternatives.
Explain your views as clearly as possible, avoiding the
use of profanity or personal threats.
Make sure to submit your comments by the comment period
deadline identified.
C. Where Can I Get a Copy of This Document and Other Related
Information?
In addition to being available in the docket, an electronic copy of
this proposal will also be available on the http://WWW. Following signature by
the EPA Administrator, a copy of this notice will be posted in the
regulations and standards section of our NSR home page located at
http://www.epa.gov/nsr.
D. How Can I Find Information About a Possible Hearing?
Persons interested in presenting oral testimony should contact Pam
Long, Air Quality Policy Division (C504-03), U.S. EPA, Research
Triangle Park, NC 27711, telephone number (919) 541-0641 or e-mail
long.pam@epa.gov at least 2 days in advance of the public hearing.
Persons interested in attending the public hearing should also contact
Pam Long to verify the time, date, and location of the hearing. The
public hearing will provide interested parties the opportunity to
present data, views, or arguments concerning these proposed rules.
[[Page 52208]]
E. How is this preamble organized?
The information presented in this preamble is organized as follows:
I. General Information
A. What are the regulated entities?
B. What should I consider as I prepare my comments for EPA?
C. Where can I get a copy of this document and other related
information?
D. How can I find information about a possible hearing?
E. How is this preamble organized?
II. What is a flexible air permit and the background related to this
action?
A. What is a flexible air permit?
B. What is the statutory background?
C. What is the regulatory background relating to the proposed
revisions to parts 70 and 71?
D. What is the regulatory background relating to the proposed
revisions to parts 51 and 52?
III. What is the purpose of this action?
IV. What experience did we gain from our 12-year pilot permit
experience?
A. What were the benefits of the pilot permits?
B. What were the conclusions of the sources, permitting
authorities, and EPA about flexible permits?
C. What are EPA's recommendations for public participation in
flexible permitting?
V. What are the key elements of this proposal?
A. What are the key elements of proposed revisions to parts 70
and 71?
B. What are the key elements of proposed revisions to parts 51
and 52?
VI. What changes are we are proposing to parts 70 and 71?
A. What is our proposed definition of an AOS, and how does it
provide a source operational flexibility?
B. What information is necessary in a title V permit application
to seek approval of an AOS?
C. What terms and conditions must be included in the title V
permit for approved AOSs?
D. What are some examples of how AOSs and advance approvals can
be used to provide operational flexibility?
E. What is the process for adding or revising advance approvals,
AOSs, and ARMs in issued permits?
F. How do the proposed AOS provisions differ between parts 70
and 71?
VII. What changes are we proposing in parts 51 and 52?
A. What are the benefits of Green Groups?
B. What is a Green Group?
C. How is a Green Group designation incorporated into a title V
permit?
D. What is the legal rationale for Green Groups?
E. What are the conforming regulatory changes we must make to
implement the Green Group concept?
F. What is an example of how a Green Group might be used in
combination with a title V permit?
VIII. What is the effect of these proposed revisions?
A. If these proposed revisions are finalized, what are the
implications for approved part 70 programs?
B. What are the implications for NSR programs?
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
II. What is a flexible air permit and the background related to this
action?
In this section, we first explain what is a flexible air permit. We
then provide an overview of the relevant statutory provisions and
describe the regulatory and other actions taken over the course of the
last decade that are relevant to this proposal.
A. What is a flexible air permit?
A flexible air permit is a title V permit that facilitates
flexible, market-responsive operations at a source through the use of
one or more permitting approaches, while ensuring equal or greater
environmental protection as achieved by conventional permits.\1\ In
particular, flexible permitting approaches allow the source, under
protection of the permit shield, to make certain types of physical and
operational changes without further review or approval by the
permitting authority. One approach includes, for example, obtaining
advance approval for anticipated changes (such as through a minor NSR
action), incorporating the advance approval into the title V permit,
and adding terms in the title V permit as necessary to assure
compliance with all other applicable requirements implicated by the
anticipated changes. Another approach is to establish one or more
alternative operating scenarios (AOSs) in a title V permit to allow
existing emissions units the flexibility to operate in varying ways
and/or at varying rates of production, where such variations would be
subject to different applicable requirements but would not require
prior authorization (i.e., advance approval).
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\1\ We first addressed the concept of a flexibile air permit in
May 1991. See 56 FR 21712, 21748 (May 10, 1991).
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For more than a decade, we participated in a pilot flexible air
permitting program with certain title V sources and permitting
authorities through which we tested and evaluated various permitting
approaches that afford operational flexibility. The lessons learned
through the pilot program, in part, served as the basis for our
adoption of the plantwide applicability limitation (PAL) provisions of
the 2002 NSR Improvement rule. They also serve as a basis for this
rule, where we seek to build upon existing regulatory provisions that
afford operational flexibility. We believe that the flexible permitting
approaches in this proposed rulemaking provide a path forward for
sources to more effectively and proactively manage their title V and
NSR permitting obligations, while ensuring environmental protection.
B. What is the statutory background?
There are two aspects of the CAA that are relevant to this proposed
rule: title V and parts C and D of title I of the Act. In 1990,
Congress promulgated title V and established the operating permit
program. That program requires certain stationary sources to obtain
operating permits as a mechanism for gathering all applicable
requirements of the Act for each affected source into one comprehensive
document.\2\ See H.R. Conference Report No. 101-952, reprinted in
U.S.C.C.A.N. 3867, 3877 (1990).
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\2\ ``Applicable requirements'' is a term that is used in title
V. The EPA has defined the term to include, among other things,
State implementation plan (SIP) rules, the terms and conditions of
preconstruction permits issued under a SIP-approved NSR program, and
requirements pursuant to the new source performance standards
(NSPS), national emission standards for hazardous air pollutants
(NESHAP), and Acid Rain Programs. See 40 CFR 70.2.
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One of the key purposes of the title V operating permit program is
to enable the source, the State or local permitting authority, EPA, and
the public to gain a better understanding of the requirements of the
Act to which the source is subject. The ability to assess and achieve
compliance with the law is improved by virtue of having one
comprehensive operating permit containing all applicable requirements
for a source. The title V permit program does not impose new
substantive air quality control requirements. It does, however, require
that fees be imposed on sources and that certain procedural measures be
followed, especially with respect to determining compliance with
applicable requirements. See, e.g., CAA sections 502(b)(3), 503(b)(2),
and 504(a).
[[Page 52209]]
The Act affirms that State and local governments have primary
responsibility for air quality. See CAA section 101(a)(3). Title V
vests primary responsibility for issuing operating permits with State
and local governments. See CAA section 502. Congress required EPA to
promulgate regulations establishing the minimum elements of a title V
operating permits program. See CAA section 502(b) (articulating ten
minimum elements for State programs). In establishing such minimum
elements, Congress directed that EPA develop ``[a]dequate, streamlined,
and reasonable procedures'' for processing and reviewing permit
applications and for the expeditious review of permit actions. See CAA
section 502(b)(6).
As explained below, EPA promulgated regulations establishing the
minimum requirements for a State operating permit program in 1992.
These regulations are codified at 40 CFR part 70 and are often
referenced as ``part 70.'' In addition to requiring EPA to establish
the minimum elements for the operating permits program, Congress
required each State to develop and submit to EPA for approval an
operating permit program that meets the requirements of the Act and
part 70. See CAA section 502(d)(1). In areas that do not have an
approved State, local, or tribal title V program, EPA administers the
operating permit program as a Federal program pursuant to regulations
set out in 40 CFR part 71. See CAA section 502(d)(3). Title V requires
that each operating permit contain terms sufficient to assure
compliance with all applicable air requirements. See CAA section
504(a).
The other parts of the Act relevant to this rule include part C,
entitled ``Prevention of Significant Deterioration of Air Quality''
(typically referred to as ``PSD''), and part D, entitled ``Plan
Requirements for Nonattainment Areas'' (typically referred to as
``nonattainment major NSR''), of title I of the Act. See CAA sections
160 through 169B (part C) and 171 through 193 (part D). These parts
together are commonly referred to as the major NSR program. This
program is a preconstruction review and permitting program applicable
to new or modified major stationary sources of air pollutants regulated
under the Act. The implementing regulations for the program are
contained in 40 CFR 51.165, 51.166, 52.21, 52.24, and part 51, appendix
S.
The PSD provisions apply to new major sources and to major
modifications at existing major sources for pollutants where the area
in which the source is located is in attainment or unclassifiable with
the national ambient air quality standards (NAAQS). A source that is
subject to PSD must install BACT and perform an air quality analysis
and an additional impacts analysis, and there must be an opportunity
for public participation. See CAA section 165(a). The BACT is an
emissions limitation that is based on the maximum degree of control
that can be achieved, as determined on a case-by-case basis for each
source considering energy, environmental, and economic impacts. See CAA
section 169(3); 40 CFR 51.166(b)(12), 52.21(b)(12), and
51.165(a)(1)(xl). The source's air quality analysis must demonstrate
that the source will not cause or contribute to a violation of any
NAAQS or any maximum allowable increase in ambient concentration either
for a Class I area or as established under the PSD program (typically
referred to as ``PSD increments''). See CAA section 165(a)(3).
Nonattainment major NSR applies to new major sources and to major
modifications at existing major sources for pollutants where the area
in which the source is located is not in attainment with the NAAQS.\3\
Nonattainment major NSR requires the source to comply with lowest
achievable emission rate (``LAER'') and to obtain sufficient emissions
offsets, and there must be an opportunity for public involvement. See
CAA section 173(a); 40 CFR 51.161. The LAER is determined for each
source to reflect the more stringent of the following: (1) The most
stringent emissions limitation that is contained in any State
implementation plan (SIP) for that type of source (if achievable for
the proposed source), or (2) the most stringent emissions limitation
that is achieved in practice for that type of source. See CAA section
171(3); 40 CFR 51.165(a)(1)(xiii).\4\
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\3\ ``Major stationary source'' is defined at 40 CFR
51.165(a)(1)(iv), 51.166(b)(1), and 52.21(b)(1), and ``major
modification'' is defined at 40 CFR 51.165(a)(1)(v), 51.166(b)(2),
and 52.21(b)(2).
\4\ This is a section 307(d) rulemaking. See CAA section
307(d)(1)(J) (addressing regulations under part C of Subchapter I)
and 307(d)(1)(V) (authorizing the Administrator to designate any
action a 307(d) rulemaking).
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In addition to a major NSR program, States are required to have
``minor'' NSR programs, which apply to new and modified sources that do
not meet the emissions thresholds for major NSR. See section
110(a)(2)(C) of the Act. The minor NSR program is part of a State's
implementation plan and is designed to ensure that the construction or
modification of an affected source does not violate any portion of the
SIP and does not interfere with the attainment of the NAAQS or cause
the exceedance of any applicable PSD increments.
C. What is the regulatory background relating to the proposed revisions
to parts 70 and 71?
This proposed rule addresses certain permitting mechanisms for
providing operational flexibility. The concept of operational
flexibility is not a new one. In July 1992, under the authority of
title V of the Act, we finalized the part 70 State operating permit
program regulations.\5\ See 57 FR 32250 (July 21, 1992); 40 CFR part
70. Those regulations include operational flexibility provisions, one
of which is the AOS provision found at 40 CFR 70.6(a)(9). It is this
provision that is the primary subject of these proposed revisions.\6\
This section 40 CFR 70.6(a)(9) generally provides that any permit
issued under part 70 must include terms and conditions for reasonably
anticipated operating scenarios approved by the permitting authority.
EPA promulgated 40 CFR 70.6(a)(9) pursuant to the authority of section
502(b)(6) of the CAA, which directs that operating permit programs
include ``[a]dequate, streamlined, and reasonable procedures'' for
processing and reviewing permit applications and for the expeditious
review of permit actions.
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\5\ In the 1990's, we proposed certain clarifications and
modifications to the part 70 regulations, none of which were ever
finalized. See generally 60 FR 45529 (Aug. 31, 1995), 59 FR 44460
(Aug. 29, 1994). In those proposals, among other things, we
discussed the concept of ``advance NSR'' in relation to AOSs, and
proposed a definition for ``alternative operating scenarios.''
\6\ The EPA included other operational flexibility provisions in
the final part 70 regulations, including 40 CFR 70.4(b)(12), (b)(14)
and (b)(15), which implement section 502(b)(10) of the Act. This
proposed rule does not address these provisions.
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In the final part 70 rule, we emphasized the importance of 40 CFR
70.6(a)(9), noting that a permit that contains approved AOSs ``will be
a more complete representation of the operation at the permitted
facility.'' See 57 FR 32276. We also explained that once a flexible air
permit with approved AOSs is issued, the need for additional permit
modifications will be substantially reduced since the permit will
already contain appropriate terms and conditions to accommodate the
approved operating scenarios. In the final part 70 rule, we did not
place any restrictions on the types of operations that could qualify as
a reasonably anticipated operating scenario.\7\
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\7\ The Federal operating permit program at part 71 addresses
reasonably anticipated operating scenarios in the same fashion as
part 70. See 40 CFR 71.6(a)(9). These proposed revisions affect both
parts 70 and 71 and the revisions that we propose to each part are
virtually identical. For ease of reference, this preamble discussion
refers to the part 70 provisions. The discussion, of course, applies
equally to the part 71 program revisions proposed. Section numbers
given for the part 70 rules correspond directly to the analogous
sections in part 71. The term ``title V permit'' refers to permits
issued under either part 70 or part 71.
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[[Page 52210]]
Shortly after we finalized the part 70 State operating permit
program, we initiated a pilot title V permit program with interested
States, and our program continues to the present. See section IV of
this preamble for more discussion. Companies participating in the pilot
program sought to reduce the cost, time, and delays associated with a
permit revision for each operational change at a facility. We and the
States sought to increase the sources' operational flexibility, while
assuring compliance with applicable requirements, ensuring
environmental protection, and facilitating P2. These pilots typically
allowed for both changes to operations of existing emissions units and
the addition of entirely new emissions units, provided that the changes
were sufficiently well described in the permit application so that the
permitting authority could confirm that all applicable requirements
were identified and that the permit contained terms and conditions
assuring compliance with all applicable requirements.\8\
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\8\ In implementing the pilot projects, EPA and other permitting
authorities sometimes imposed certain constraints in the permits for
advance approvals and AOSs beyond those expressly contained in
applicable requirements or part 70. These additional constraints
varied and were designed to provide permitting authorities the
opportunity to gain experience with different flexible permitting
approaches. Some of these constraints were anticipated to be removed
at the time of permit renewal in the next version of the permit.
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To evaluate the flexible pilot permits program, we conducted a
thorough review of six of the pilot permits for which at the time there
was significant implementation experience.\9\ We reviewed on-site
records to track utilization of the flexible permit provisions,
assessed how well the permits worked, evaluated total emissions
reductions achieved, and analyzed the economic benefits associated with
the permits. Overall, we found that significant environmental benefits
had occurred for each of the permits reviewed. At the time of the
evaluation, each of the sources had achieved 25- to 80-percent
reductions in actual plantwide emissions or emissions per unit of
production. We made a series of findings based on our evaluation of the
permits. See ``Evaluation of the Implementation Experience with
Innovative Air Permits'' and section IV of this preamble, which
summarizes the findings of this study.\10\
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\9\ See ``Evaluation of the Implementation Experience with
Innovative Air Permits.'' A copy of this report is located in the
docket for this rulemaking, or can be accessed at http://www.epa.gov/ttn/oarpg/t5/memoranda/iap_eier.pdf
.
\10\ In August 2000, based in large part on the experience we
gained through the pilot permit program, we issued a draft guidance
document called White Paper Number 3, on which we solicited comment.
See White Paper Number 3, 64 FR 49803 (Aug. 15, 2000). That draft
guidance addressed various flexible permitting approaches, including
the use of the reasonably anticipated AOS provision of 40 CFR
70.6(a)(9), Clean Buildings, and PALs. We received comments on the
proposed rules and draft guidance and, in fashioning this proposal,
considered those comments that addressed advance approval and AOSs
as contained in 40 CFR 70.6(a)(9). As explained further below, we
propose a definition of ``alternative operating scenario'' and
certain other revisions to the part 70 regulations. We also propose
revisions to parts 51 and 52 that provide for Green Groups.
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D. What is the regulatory background relating to the proposed revisions
to parts 51 and 52?
Based on our pilot permit evaluation and our 1996 proposed
modifications to the major NSR program, in December 2002, we finalized
the NSR Improvement rule. In that rule, we promulgated regulations for
PALs in response to comments received on draft White Paper Number 3. As
explained in the preamble to the December 2002 final rule, a PAL is an
alternative approach for determining NSR applicability on a plantwide
basis. Using PALs will allow sources ``to respond rapidly to market
changes,'' and will ``benefit the public and the environment.'' See 67
FR 80206. Specifically, sources with PALs can make changes without
triggering the major NSR preconstruction permitting requirements,
provided such changes remain below the limit established in their PAL
and do not otherwise violate the requirements of the PAL. A PAL is an
important technique that is oftentimes used in tandem with flexible
permitting approaches such as advance approvals and AOSs as described
more fully in this proposal.
The major NSR program applies to ``major stationary sources,''
which include sources whose emissions exceed certain thresholds
established in the statute, and to ``major modifications'' at those
sources, which are modifications that exceed certain significance
levels established in EPA's regulations. Under minor NSR, an owner or
operator applies for a permit to construct or modify a facility,
building, or other emissions unit, where the new construction or
modification does not meet the emissions thresholds for major NSR. If
the proposed construction or modification is approved, the permitting
authority issues a permit that contains emissions limits and other
appropriate terms and conditions as necessary to protect the NAAQS and
the increments and to assure consistency with the SIP.
Through our pilot experience, we found that State minor NSR
requirements are among the most important in designing a flexible air
permit for sources making frequent physical and operational changes
because, absent an up-front authorization for these changes, an
individual review and approval by the permitting authority is typically
required before the changes can be made. Any changes authorized under
minor NSR must be incorporated into the title V permit along with
permit terms as necessary to assure compliance with all applicable
requirements (for example, a MACT standard, which would be applicable
to the source in addition to the ones addressed in the advance approval
issued under minor NSR). The result is that the changes can be
implemented, under protection of the permit shield, without any further
review or approval by the permitting authority. In some cases, one or
more AOSs may be used to complement an advance approval, for example
where the source anticipates varying operation of the changed existing
emissions unit in a manner that would implicate a set of applicable
requirements different from those of the minor NSR advance approval, or
where a different control approach would not be effective until and
unless a particular change would be made to an existing emissions unit.
Given the provisions of their minor NSR programs, most of the
States in which EPA supported flexible permit pilots (``pilot States'')
believed that they could issue construction approval for a wide
spectrum of changes using certain boundary conditions established up
front in the minor NSR permit. The actual conditions needed to
accomplish this varied depending upon the requirements of the different
State minor NSR programs. A number of techniques were successfully used
in pilot permits to authorize a category of changes (i.e., a range of
possible types of changes, such as ``any of various physical changes to
the rollers, drive mechanism, and other components of the coating
section within a coating line'') under minor NSR, including application
of one or more plantwide emissions caps, designation of an entire
process building or related activities as the ``emissions unit'' for
purposes of minor NSR, and designation of an
[[Page 52211]]
existing state-of-the-art emissions capture and control system as
fulfilling State control technology requirements (where they are
applicable) for authorized changes occurring over the 5-year term of
the title V permit. Pilot States, as part of granting advance approvals
under their existing minor NSR programs, frequently required sources to
send a notice to the permitting authority contemporaneous with the
operation of any entirely new emissions unit relying upon the advance
approval.
A common technique for achieving advance approval under minor NSR
found in the pilots was the presence of one or more plantwide emissions
caps. These caps serve to limit the maximum aggregate emissions
associated with the anticipated changes so as to protect relevant
ambient standards and increments and to facilitate an advance approval
of a wide spectrum of changes under minor NSR. They also serve to limit
the potential to emit (PTE) of the source below certain applicability
thresholds in order to prevent implication of otherwise potentially
applicable requirements (e.g., major NSR) or to function as a PAL (in
the case of an existing major stationary source).
III. What is the purpose of this action?
The Agency has learned a great deal over the past decade through
its pilot permit program. In light of that experience, the recent NSR
Improvement rule promulgated in December 2002, and the comments we
received on the proposed revisions to part 70 and draft White Paper
Number 3, we propose revising the part 70 and 71 regulations and part
51 and 52 regulations.
As explained further below, the proposed revisions to the operating
permit programs of parts 70 and 71 add a definition and clarify
requirements for ``alternative operating scenario'' (or ``AOS'') and
add a definition for ``approved replicable methodology'' (or ``ARM'').
The proposed revisions to the major NSR program add a definition and
codify requirements for Green Groups.
The primary purpose of these revisions to parts 70 and 71 is to
build upon the existing regulatory framework and ensure that the
flexible permitting approaches with which we have experience are more
readily and widely used. We recognize that many States' minor NSR and
part 70 programs may already provide for the flexible permitting
approaches proposed and that such States are currently able to
implement these approaches. Because of the diversity of existing State
minor NSR programs and our pilot experience indicating the ability of
many programs to approve categories of future changes in advance of
making those changes, we are not proposing any revisions to the rules
governing State minor NSR programs at 40 CFR 51.160 through 51.164. By
undertaking the part 70 rulemaking, it is not our intention to preclude
States from continuing to develop and use flexible permit approaches,
where their current regulatory structure provides authority to do so.
This rulemaking is instead intended to encourage the use of advance
approvals where available and appropriate, and to eliminate any
uncertainty that may exist with respect to AOSs and to provide a clear
regulatory pathway governing flexible air permit development in that
area by clarifying our 1992 part 70 regulations.\11\
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\11\ Note that other approaches to AOSs and advance approval may
also be acceptable, although they may not provide as much
flexibility as the approaches proposed. For example, some States
include in a title V permit a type of conditional approval under
which a source cannot construct or operate otherwise approved
changes until a minor NSR approval is obtained for them.
Essentially, this approach creates in a title V permit a structure
that is a precursor to an AOS or an advance approval. Once the minor
NSR permit is issued, the source can construct and operate the
changes under the conditional approval, but a title V permit
revision is needed to incorporate the now-available minor NSR terms
and to award the permit shield (where available from the permitting
authority). Where an AOS is involved, this incorporation is also
needed to complete the AOS consistent with 40 CFR 70.6(a)(9). Our
pilot permit experience suggests that in many instances changes
subject to minor NSR can be approved in advance, although the
ability for a State to provide such approvals will vary depending on
the actual provisions of individual State rules. As a result, where
advance approval of changes subject to minor NSR is available, we
encourage its incorporation into the title V permit after or
concurrent with obtaining the necessary minor NSR approvals in order
to provide a permitting strategy with greater operational
flexibility, certainty, and permitting efficiency than does a
conditional approval approach.
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The proposed revisions to parts 51 and 52 affecting major NSR
programs will increase options for flexible permits under that program.
Namely, the proposed provisions for Green Groups will offer operational
flexibility options for a defined section of a plant. This option would
augment the plantwide strategy previously promulgated in the NSR
Improvement rule (i.e., PALs). The proposed revisions would modify the
major NSR regulations in a limited way. Consistent with the current NSR
requirements, we propose to clarify that the definition of emissions
unit would allow a number of emission activities, meeting certain
criteria, to be treated as a single emissions unit (i.e., a ``Green
Group''). We are proposing to change the current NSR requirements to
provide expressly for Green Groups so as to authorize in a major NSR
permit that emissions increases and changes within such a group can
occur over a 10-year period, provided the increases and changes are
authorized in advance through major NSR and the emissions activities
associated with the Green Group are controlled to the level determined
to be BACT/LAER. Also, the requirements of 40 CFR 52.21(j)(4) and
51.166(j)(4) requiring reevaluation of BACT for phased construction
projects and of 40 CFR 52.21(r)(2) requiring continuous construction to
commence within 18 months would not apply to NSR permits involving
Green Groups.
We believe that these proposed revisions will increase operational
flexibility, while ensuring environmental protection and compliance
with applicable requirements. Moreover, based on our pilot experience,
we anticipate that these revisions will promote improved environmental
performance, although we recognize that the nature of the improvements
will depend on the numbers and types of sources that opt to use the
flexible permitting approaches described in this document.
IV. What experience did we gain from the 14-year pilot permit program?
This section summarizes the benefits of the pilot permits; includes
an overview of the sources', permitting authorities', and our
conclusions concerning the effectiveness of the pilot permits; and
presents our recommendations regarding public participation in flexible
permitting. Through the pilot permit program,\12\ which began in 1993,
we sponsored various projects, including projects undertaken through
the Agency's ``Pollution Prevention in Permitting Program'' (P4). The
pilot program generally involved the issuance of flexible air permits
designed to accommodate operational flexibility.
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\12\ Sources at the following locations participated in our
pilot permit program: (1) 3M (St. Paul, MN); (2) Intel (Aloha, OR);
(3) Lasco Bathware (Yelm, WA); (4) Imation (Weatherford, OK); (5)
Cytec (Connecticut); (6) DaimlerChrysler (Newark, DE); (7) Merck
(Elkton, VA); (8) Merck (Barceloneta, PR); (9) Saturn (Spring Hill,
TN); (10) BMW (Spartanburg, SC); (11) Eli Lilly (West Lafayette,
IN); (12) 3M (Nevada, MO); and (13) Imation (Camarillo, CA).
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The pilot permits facilitated operational flexibility by first
obtaining advance approval under NSR. Frequently the authorizations
involved changes that were to occur under a PAL or other facility-wide
cap on emissions which, once approved by the relevant permitting
authority, served both to assure that major NSR would not be
[[Page 52212]]
applicable to changes occurring under the cap and to assure that
ambient standards would be protected consistent with the requirements
of minor NSR.\13\ These caps were then incorporated into the title V
permit with appropriate permit terms and conditions. In most cases,
once these caps were incorporated into a title V permit, sources did
not need to seek additional approvals from the title V permitting
authority prior to implementing the changes authorized under the caps.
As necessary, the title V permit would also contain additional terms
and conditions needed to assure compliance with any other applicable
requirements applying to such changes.
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\13\ The VOC emissions caps used in the pilots were determined
to be adequate for purposes of safeguarding the ozone NAAQS, but for
other pollutants (e.g., air toxics) States sometimes required a
replicable modeling procedure to screen the impacts of individual
emissions increases relative to acceptable ambient toxics levels.
Here an ambient dispersion model, complete with implementation
assumptions, is approved into the minor NSR permit to evaluate any
new pollutant of concern or increased existing pollutant emissions.
Failure of a particular change to meet the screening levels
triggered the need for case-by-case review of that change from the
permitting authority.
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As noted above, following issuance of the pilot permits, we
conducted an in-depth review of six of the permits.\14\ In selecting
the permits to review, we focused our evaluation on those pilots with
sufficient implementation experience to provide a reasonable historical
record of performance, and we continue to believe that these pilots
represent a sufficiently diverse reference point from which to judge
the effectiveness of flexible air permits over a broad range of
sources. Those reviews involved: (1) Detailed analyses of the sources'
and permitting authorities' experiences developing and implementing the
pilot permits; (2) a thorough review of information available in the
public record at the permitting authority; (3) discussions with source
personnel; (4) site visits to the source and meetings with permitting
authorities; and (5) independent verification of compliance status and
data collection and management techniques, including recordkeeping and
related requirements.
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\14\ The six permits that we analyzed were: (1) Intel (Aloha,
OR); (2) 3M (St. Paul, MN); (3) Lasco Bathware (Yelm, WA); (4)
DaimlerChrysler (Newark, DE); (5) Saturn (Spring Hill, TN); and (6)
Imation (Weatherford, OK).
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Our analyses revealed several benefits of the flexible permitting
approaches used in the pilots, and those benefits are summarized
briefly below. We invite comment on any similar or different
experiences others have had in piloting flexible air permits,
particularly where these experiences are relevant to this rulemaking.
A. What were the benefits of the pilot permits?
This section provides an overview of the environmental,
informational, economic, and administrative benefits of the flexible
pilot permits. For additional information on these and other benefits
of the pilot program, please refer to the ``Evaluation of the
Implementation Experience with Innovative Air Permits,'' which
documents all of our findings concerning the six pilot permits that we
evaluated.\15\
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\15\ Among other things, the report confirmed that the flexible
permits are enforceable in a practical manner by EPA and permitting
authorities. See Report at pages 5, 20. See footnote 9 of this
preamble for information on how you can obtain the report.
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1. Environmental Improvements Achieved Using Flexible Permits
In our evaluation, we documented several environmental performance
benefits of the flexible pilot permits, including that the permits
facilitated emissions reductions and increased P2 efforts. In
particular, as discussed further below, the emissions cap framework in
the flexible permits enabled significant reductions in actual plantwide
emissions and/or emissions per unit of production. For example, of the
five sources that had operated under their flexible permits for 3 or
more years, all five achieved 30-to 80-percent reductions in actual
plantwide emissions and/or emissions per unit of production. Actual
emissions from the sixth source were reduced by 27 percent in the first
year of operation under its flexible permit, but it is difficult to
draw conclusions based on a single year of data. One company, using P2,
lowered its actual volatile organic compound (VOC) emissions by 70%
(from 190 tons per year (tpy) to 56 tpy), while increasing production.
This allowed the facility to commit to keeping its VOC emissions below
the major source threshold (i.e., become a ``synthetic minor'' source)
so that it was no longer subject to major NSR. Another company lowered
its actual VOC emissions from 1,400 tpy to less than 800 tpy, primarily
through P2 associated with vehicle coatings and plant solvent usage.
We attribute the environmental performance improvement benefits of
the flexible permits to several factors. First, several companies
reported that the emissions caps had a ``focusing effect,'' drawing
company personnel(s attention on how to manage most effectively all of
the activities within the plant, even those not subject to regulation,
in an effort to minimize total plantwide emissions.\16\ An emissions
cap also creates incentives for companies to pursue additional
emissions reduction opportunities to increase the margin of compliance,
which is the difference between the level of the emissions cap and the
source's actual total plantwide emissions. Larger compliance margins
typically reduce the risk of noncompliance with an emissions cap and
create room under the cap to accommodate future emissions increases
related to production or other operational changes. The cap on
emissions from the plant, which is set during permitting at a level
judged to be environmentally protective, ensures that such future
emissions increases together with existing emissions will not exceed
this protective level. To obtain a sufficient margin of compliance with
these caps, sources frequently voluntarily controlled emissions on
grandfathered units, which are units that would otherwise not be
subject to control, and increased the stringency of control on
regulated units.
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\16\ See the pilot permit report, ``Evaluation of the
Implementation Experience with Innovative Air Permits,'' page 22.
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Additionally, we found that the use of advance approvals and AOSs
improved operational efficiency at the plants because companies knew in
advance what changes were authorized, making resource allocation more
efficient and accommodating the typically incremental, iterative nature
of industrial process improvements. We also found that P2-related
projects became more attractive to the companies when advance approved
because such projects could be undertaken without the delay and
uncertainty of future case-by-case approvals. In addition, P2-related
projects reduced emissions and enabled sources to comply more easily
with emissions limits such as plantwide emissions caps.
2. Informational Benefits Achieved Using Flexible Permits
We have consistently maintained that including advance approvals
and AOSs in a title V permit ensures that the permit presents a
complete representation of the operations of the permitted facility.
See 57 FR 32276; July 21, 1992. By requiring information concerning
flexible permits as part of the permit application, EPA and the
permitting authorities are better able to assess, in aggregate, all
proposed operations and, more significantly, to
[[Page 52213]]
determine all relevant applicable requirements and to include in the
draft permit terms and conditions for each approved scenario to assure
compliance with those applicable requirements and the requirements of
part 70. By comparison, conventional permitting approaches provide for
a more narrow, case-by-case view of facility modifications, soliciting
comment only on the specific change proposed and requiring individual
permitting actions in response to each request by the permittee for a
change in the permit.
Our pilot experience confirmed the significant value of presenting
a comprehensive picture of a source(s operations over the term of the
title V permit. Specifically, we found that with proposed flexible
permits involving changes under a PAL or other emissions cap,
permitting authorities were better able to understand the scope of
planned changes at the source and the maximum, cumulative environmental
effects of those changes. In addition, the flexible permit applications
provided increased information to permitting authorities and the public
in areas such as plantwide emissions performance and P2 activities, as
compared to information typically available under conventional permit
approaches. Likewise, permitting authorities indicated that on balance,
flexible air permits enhanced the availability of information to the
public during permit implementation.
Moreover, through the pilots, we found that early public outreach
and involvement can be very useful in situations where new permitting
techniques have not previously been used in a particular jurisdiction.
We encourage permitting authorities to consider early outreach and
public involvement when implementing such permitting techniques until
the techniques become more widely used and public familiarity with them
increases, recognizing that other factors (e.g., permit complexity)
should factor into the permitting authority(s consideration of
supplemental public outreach efforts.
Our evaluation of the six pilot permits also revealed the
importance of reporting related to plantwide applicability limits. The
type of reporting required in several of the flexible permits is now
codified in the PAL provisions of the December 2002 NSR Improvement
rule.
3. Economic Benefits Achieved Using Flexible Permits
Participating companies in the pilot program reported that a
flexible air permit significantly reduces the uncertainty and
transaction costs associated with the title V permitting process
because the source obtains approval of the changes it reasonably
anticipates implementing during the 5-year term of the permit at one
time. Based on our evaluation of the six pilot permits, we found that
the increased certainty and reduced transaction costs improved
participating companies' ability to compete effectively in the market
and enabled them to retain, and in some cases, create jobs. For
example, one company reported that its pilot permit allowed it to
remain highly responsive to the marketplace and thereby avoid either
lost sales and/or permanent loss of market share. An automotive company
indicated that its flexible permit was a principal factor in the
plant's selection to manufacture an engine model to be used in the
company's global vehicle assembly operations, leading to the creation
of 700 jobs. The permit helped the plant secure the engine contract
because it enabled the plant to reduce the project time line for
production of the new engine to 24 months and to accommodate future
changes with minimal delay.\17\
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\17\ See ``EPA Flexible Permit Implementation Review: Saturn
Permit Review Report,'' pages 9 and 34, which is available at http://www.epa.gov/ttn/oarpg/t5/memoranda/iap_sprr.pdf
.
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Several companies also indicated that obtaining authorization of
reasonably anticipated changes improved the predictability of change
implementation time frames for project planning and avoided what can be
substantial opportunity costs. For example, one company reported that
its flexible permit likely saved hundreds of business days associated
with making operation and process changes to ramp up production for new
products, respond to market demands, and optimize production processes.
Industry estimates of the opportunity costs of production downtime and
time delays run as high as millions of dollars in just a few days due
to lost sales and other factors.\18\
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\18\ Findings are discussed in more detail in the ``Evaluation
of Implementation Experiences with Innovative Air Permits'' report,
under Finding 8.
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Notwithstanding that the implementation of flexible air permits
often was associated with more production-related jobs, pilot companies
also reported that flexible air permits significantly reduced permit-
related staff time and related resource costs because there was no
longer a need to seek and process multiple case-by-case permit actions
because the changes reasonably anticipated at the facility were already
included and approved in the permit. For example, an automotive company
estimated that it saved approximately 505 hours of staff time during
its initial flexible permit term. Another pilot company reported
permit-related staff time savings of 1,200 to 1,600 hours per year
during its initial title V permit term. In both cases, companies
reported that the time savings enabled environmental personnel to focus
more time and attention to other environmental management activities,
including P2. Companies further indicated that the time necessary to
record changes in operating scenarios in the on-site log, as required
by 40 CFR 70.6(a)(9), was significantly less than the permit-related
staff time necessary to prepare permit applications under a general
change-by-change permitting approach.
4. Administrative Benefits Achieved Using Flexible Permits
Our pilots evaluation found that the flexible permits resulted in a
net cost savings both for the source, as noted above, and for the
permitting authority. We specifically found that the resources
permitting authorities expended on processing permitting applications
under title V and the NSR programs were reduced under the pilot
program, since the operational flexibility provisions, like 40 CFR
70.6(a)(9), eliminated the need to submit a permit application for each
operational change. For example, one permitting authority estimated
that each facility change made pursuant to a flexible permit saved the
permitting authority approximately 20 to 40 hours in staff time that
otherwise would have been incurred had the facility, instead of
obtaining the advance approvals and AOS, sought title V permit
modification on a change-by-change basis. In fact, permitting
authorities reported that the administrative cost savings during
implementation of the pilot flexible permits indicate that increased
use of flexible permitting will enable them to reduce permitting
backlogs and to focus resources on other higher priority environmental
needs.
These cost savings must be put in context of a higher front-end
cost to design an acceptable permit approach to pilot (a cost that
should decrease as more experience with flexible permits occurs in
tandem with a better defined policy). The two participating permitting
authorities that attempted to quantify this effect believed that, even
with the higher front-end design costs associated with their pilot, the
initial experience suggested there would be a net reduction in the
overall administrative costs associated with
[[Page 52214]]
these permits after 2-3 years of implementation. We believe that the
administrative benefits achieved for the evaluated pilot permits are
broadly indicative of the benefits generally available from flexible
air permits. In fact, as flexible air permitting becomes more
mainstream, we expect the front-end costs to design such permits to be
reduced, resulting in faster recouping of these expenses and greater
benefits over time.
B. What were the conclusions of the sources, permitting authorities,
and EPA about flexible permits?
The sources that obtained a flexible air permit maintain that such
a permit is a valuable business asset. These sources regularly relied
upon the operational flexibility provided in the permit to take
advantage of opportunities in the market place. These sources also
indicated that the following circumstances heightened the need for and
benefits achieved using a flexible air permit:
Short time frames for bringing new products to market
(time-to-market needs).
Need to accommodate rapid shifts of product lines,
processes, and production levels to enable optimal asset utilization in
a company's network of facilities.
Active advanced manufacturing programs (e.g., lean
manufacturing, Six Sigma, agile manufacturing) that require rapid and
iterative changes to operations and equipment.\19\
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\19\ These manufacturing concepts have been defined in various
ways. Generally, however, lean manufacturing is defined as an
initiative focused on eliminating all waste in manufacturing
processes. Principles of lean manufacturing include zero waiting
time, zero inventory, scheduling (internal customer pull instead of
push system), batch to flow (cut batch sizes), line balancing, and
cutting actual process times. Six Sigma is defined as a rigorous and
disciplined methodology that utilizes data and statistical analysis
to measure and improve a company's operational performance,
practices, and systems. Six Sigma identifies and prevents defects in
manufacturing and service-related processes. In many organizations,
it simply means a measure of quality that strives for near
perfection. Agile manufacturing emphasizes the ability to thrive and
prosper in an environment of constant and unpredictable change and
includes the use of tools such as rapid prototyping, rapid tooling,
and reverse engineering to address customers who require small
quantities of highly custom, design-to-order products, and where
additional services and value-added benefits like product upgrades
and future reconfigurations are as important as the product itself.
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Anticipated renovation or expansion projects.
Active P2 programs with continual process improvements.
The permitting authorities in the pilot program concluded that the
permits provided significant environmental performance and
administrative benefits. They also expressed support of flexible
permitting techniques as a permitting option. The permitting
authorities believed that flexible permits are particularly effective
when applied to sources with demonstrated operational change needs and
the operational and technical capacity to meet all relevant
requirements associated with advance approvals, AOSs, PALs, and other
operational flexibility provisions.
In general, based on our pilot experience, we believe that sources
with certain characteristics are the ones that can both meet the
requirements of operational flexibility provisions and benefit from
them. These characteristics include: A strong compliance history,
maintenance of a well-documented and effective environmental management
system, commitment to continuous environmental improvement,
attentiveness to P2, ability to track and manage operational changes
and emissions, and the existence of good community relations. The types
of sources that exhibit these characteristics typically include, for
example, the members of EPA's National Environmental Performance Track
Program (see http://www.epa.gov/performancetrack/) and similar State
environmental leadership programs. Our Performance Track program
illustrates our ongoing commitment to reward and recognize exemplary
environmental performance.
We currently intend to allocate our implementation resources for
the final rule on a priority basis to assist Performance Track
facilities that wish to obtain flexible air permits. More specifically,
we intend to deploy resources and tools designed to assist Performance
Track facilities in their efforts to capture the opportunities provided
through flexible air permits. Our efforts to facilitate the
implementation of flexible permits could include, for example,
education and outreach components that would allow Performance Track
members to assess the costs and benefits of a flexible permit. We also
intend to provide EPA technical resources and expertise through
identified points of contact to facilitate the resolution of technical
and other issues (should any arise) associated with implementing a
flexible air permit at a Performance Track facility. We encourage State
permitting authorities to consider a similar prioritization of
resources when issuing flexible air permits to sources that are
similarly situated to Performance Track companies.
C. What are EPA's recommendations for public participation in flexible
permitting?
Based on our experience with pilot permits, we believe that
flexible permits provide at least as much environmental protection as
conventional permits and promote superior environmental performance.
Nevertheless, we also recognize that flexible permits will contain
features, such as AOSs, ARMs, advance approval of minor NSR, or Green
Groups, that may not be familiar to the reviewing public. For this
reason, we recommend that permitting authorities consider using their
discretion to enhance the public participation process when warranted
for a particular flexible permit. Some ideas for doing so are described
below.
During the permitting process, permitting authorities could
consider making the permit application available to the public soon
after receipt. We found for these pilot permits that early outreach to
the community, rather than waiting until the draft permit was prepared,
was an effective public participation strategy.
The minimum public comment period required for a title V permit
renewal or significant permit modification is 30 days. Where a
significant amount of a permit's content consists of terms to
incorporate operational flexibility, we suggest that you consider
expanding the comment period to 45 days or more. Note, however, that
for some of our pilot permits, early outreach to the public was
sufficient to resolve community questions and comments early in the
process, so that by the time of the public hearing and comment period
no adverse comments were received.
Finally, in order to ensure adequate technical support and
accessibility for the public in their efforts to understand and comment
upon flexible air permits, we suggest that States provide a principal
point of contact for responding to technical questions and ensure the
availability of draft permits, applications, and technical support
documents on an Internet Web site. We believe that any additional costs
here will be offset by the subsequent administrative cost savings to
the permitting authority resulting from the reduced need to process
permit revisions for sources with flexible permits.
V. What are the key elements of this proposal?
This section summarizes the key elements of this proposal. A more
detailed discussion of these elements as well as other proposed
regulatory
[[Page 52215]]
changes are provided below in sections VI and VII.
A. What are the key elements of proposed revisions to parts 70 and 71?
There are several key regulatory revisions that we are proposing to
parts 70 and 71. First, we are proposing to modify 40 CFR 70.6(a)(9)
generally to refer to ``alternative operating scenarios,'' as opposed
to ``operating scenarios.'' In addition, we are proposing to define the
term ``alternative operating scenario (AOS)'' and codify certain
requirements described in this proposal for AOSs. Specifically, we
propose to define ``alternative operating scenario (AOS)'' as a
scenario authorized in a part 70 permit that involves a physical or
operational change at the part 70 source for a particular emissions
unit, and that subjects the unit to one or more applicable requirements
that differ from those applicable to the emissions unit prior to
implementation of the change or renders inapplicable one or more
requirements previously applicable to the emissions unit prior to
implementation of the change.
This document also discusses our proposal for ``approved replicable
methodologies'' (ARMs) and the way in which they may be approved into
the title V permit by the permitting authority. We are proposing to
define an ARM as part 70 permit terms that: (1) Specify a protocol
which is consistent with and implements an applicable requirement, or
requirement of part 70, such that the protocol is based on sound
scientific/mathematical principles and provides reproducible results
using the same inputs; and (2) require the results of that protocol to
be used for assuring compliance with such applicable requirement or
requirement of part 70, including where an ARM is used for determining
applicability of a specific requirement to a particular change. An ARM,
however, cannot modify an applicable requirement in any way. As
explained further below, an ARM can be particularly useful in
facilitating the implementation of advance approvals and AOSs, but can
also be used independent of them.
Also in this document, we are proposing that a source include in
its semi-annual monitoring reports under 40 CFR 70.6(a)(3)(iii)
information relating to any AOS and/or ARM implemented during the
reporting period. This information should help permitting authorities
remain informed as to which AOSs and ARMs in the title V permit are
being implemented at the site and at which time.
We are not proposing revisions to any applicable requirement (other
than revisions to parts 51 and 52 providing for Green Groups--see
section VII below) in order to facilitate advance approvals. As
mentioned above, our pilot experience confirms that obtaining advance
approval under minor NSR is often a critical element in the design of a
flexible air permit. This experience also suggests that many State
minor NSR programs may already provide the legal authority necessary to
issue minor NSR permits that accommodate various types of operational
flexibility which can be readily incorporated into title V permits. We
are therefore not proposing any revisions to the minor NSR regulations.
Nonetheless, we encourage States to implement advance approvals in
response to requests by sources under their existing minor NSR programs
as appropriate and to seek additional authority where they do not
currently have such discretion. Based on our pilot experience, we also
believe that the ability to advance approve a particular change with
respect to other applicable requirements requiring a specific
authorization can often be determined without further regulatory
changes.
Similarly, we are not proposing to revise part 70 to address how
advance approvals might be accomplished. We believe that part 70
already requires incorporation of the terms in a permit issued to
advance approve changes under certain applicable requirements. For
example, permit terms contained in a State's minor NSR permit are
themselves deemed to be applicable requirements as defined in section
70.2 and, as such, are to be included in the title V permit for the
relevant source. Frequently, however, the permitting authority may need
to augment the terms of NSR permits authorizing the advance approval of
certain changes in order that these changes can be made without further
review or approval. These terms would be added as necessary to assure
compliance with other applicable requirements also implicated by the
advance approved changes which were unaddressed in the specific
authorizations obtained for them. As would be the case for any other
applicable requirement, the part 70 permit must meet the requirements
of part 70 (e.g., monitoring, reporting, and compliance certification)
with respect to advance approvals. When the title V permit terms
relating to advance approvals are effective, then the changes which
were advance approved would occur under protection of the permit shield
(where available and granted by the permitting authority).
B. What are the key elements of proposed revisions to parts 51 and 52?
\20\
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\20\ Although we are proposing certain revisions to the major
NSR program, we are proposing no changes to any other applicable
requirement, as that term is defined in 40 CFR 70.2.
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With this document, we propose adding a definition of ``Green
Group.'' We also propose to add monitoring, recordkeeping, reporting,
and testing safeguards applicable to Green Groups to enhance the
availability of information and ensure that these groups function as
intended.
A Green Group consists of designated emissions activities that are
ducted to one common air pollution control device that is determined to
meet BACT or LAER, as applicable, for the entire group of emissions
activities taken as a whole. A Green Group is, by definition, a single
emissions unit for purposes of major NSR. In addition to designated
existing emissions activities, a Green Group may include changes (e.g.,
reconfiguration and/or expansion) to these existing activities and/or
the addition of new emissions activities ducted to the control device,
either of which could result in an increase in capacity and a
significant increase in actual emissions. To establish a Green Group,
the source must go through the major NSR permitting process and obtain
a permit. To protect the NAAQS, PSD increments, and Class I areas, the
proposed rules require an annual emissions limit and any necessary
short-term limits for the Green Group, as well as comprehensive
monitoring, reporting, recordkeeping, and testing under NSR for Green
Groups to assure compliance with the limit(s).\21\
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\21\ The NAAQS and increments for some pollutants are
established over short-term periods as well as annually. For
example, annual, daily, and 3-hour NAAQS and increments are defined
for sulfur dioxide. Accordingly, some NSR permits include emissions
limits for these shorter periods.
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VI. What changes are we proposing to parts 70 and 71?
We are proposing revisions to parts 70 and 71 to build upon the
existing framework in 40 CFR 70.6(a)(9), which authorizes AOSs. As
discussed below in section VI.A, we are proposing to add a definition
for AOS and to provide for the use of consistent terminology for AOSs.
In section VI.B, we describe the information that the source must
provide in a title V permit application under 40 CFR 70.5(c) when
seeking approval of an AOS, and in section VI.C we discuss the terms
that must be included in a title V permit for an AOS and for an ARM.
Section VI.D presents two examples of flexible permits using
[[Page 52216]]
AOSs. In section VI.E, we address additional issues related to AOSs,
and in section VI.F we detail the minor differences between the
proposed revisions for part 70 and part 71. In the case of both AOSs
and ARMs, the State must have sufficient authority to grant them if
proposed by a source, but the permitting authority retains the
discretion as to the appropriateness of doing so on a case-by-case
basis, depending on the specific facts of the situation.
A. What is our proposed definition of an AOS, and how does it provide a
source operational flexibility?
As mentioned previously, the concept of an AOS is not a new one.
Under existing 40 CFR 70.6(a)(9), a source may request in its permit
application that the permitting authority approve reasonably
anticipated operating scenarios. If the permitting authority determines
that the proposed operating scenarios are consistent with the
requirements of part 70 and approves them, it would include those
scenarios in the source's part 70 permit, and the source may implement
them without further review or approval. Fundamentally, the permitting
authority must ensure that the proposed operating scenarios are
adequately described such that all applicable requirements associated
with each scenario are identified and appropriate terms and conditions
to assure compliance with these requirements are included in the
permit. In addition, the permitting authority must ensure that the
source obtained all specific authorizations required under any
applicable requirements (primarily those under minor NSR). The
provisions of 40 CFR 70.6(a)(9) were promulgated consistent with
section 502(b)(6) of the Act, which mandates the streamlining of the
application and permitting processes.
There may be situations where a permitting authority does not
approve an AOS which has been proposed by a source for a particular
emissions unit. For example, a permitting authority may reject an AOS
proposed by a source if it determines that the source's description of
the scenario is insufficient to identify all applicable requirements or
craft appropriate terms and conditions to ensure compliance with
applicable requirements, or if required authorizations under applicable
requirements triggered by the AOS have not been obtained.
To clarify our intent regarding AOSs, we propose the following
definition at 40 CFR 70.2:
Alternative operating scenario (AOS) means a scenario authorized
in a part 70 permit that involves a physical or operational change
at the part 70 source for a particular emissions unit, and that
subjects the unit to one or more applicable requirements that differ
from those applicable to the emissions unit prior to implementation
of the change or renders inapplicable one or more requirements
previously applicable to the emissions unit prior to implementation
of the change.
Thus, the change at the part 70 source must be physical or
operational in nature and must either subject a particular emissions
unit to at least one new applicable requirement or eliminate at least
one requirement that applied to the unit prior to the change. In
addition, the change, in order to be eligible for an AOS, must be
allowable under all applicable requirements.\22\ For example, a change
allowed under an applicable MACT standard but also subject to minor NSR
would not be eligible for inclusion in an AOS until the source obtains
the necessary preconstruction approval. That is, the source requests
and obtains from the permitting authority a minor or major NSR permit,
as applicable, authorizing the change to occur, and the terms of the
NSR permit are then incorporated into the source's title V permit as
part of an AOS. We are proposing this definition not to change the
current requirements for AOSs but rather to foster a common and
consistent understanding of the types of situations that AOSs can
address.
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\22\ Failure to anticipate and include a particular change under
an AOS does not in and of itself bar the source from implementing
the change if it can satisfy the requirements of the off-permit
provisions in part 70, such as those set forth at 40 CFR 70.4(b)(12)
and (b)(14). The permit shield does not extend to changes made
pursuant to these provisions. See, e.g., 40 CFR 70.4(b)(12)(i)(B),
(b)(12)(ii)(B), (b)(14)(iii). For example, during the term of its
part 70 permit, a source might obtain approval under minor NSR to
construct and operate a new emissions unit. Where available and
granted by the permitting authority, the source can implement the
change under the off-permit provisions, assuming that the change is
not addressed or prohibited by the terms of the source's part 70
permit.
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The types of physical or operational changes which could trigger an
AOS can vary widely. Such changes potentially encompass a wide spectrum
of activities undertaken by a source which cause one or more applicable
requirements to apply (or to no longer apply) to the emissions unit
undergoing the change. Nonetheless, these changes must be consistent
with any limitations contained in applicable requirements that are
triggered. Thus, anticipated physical and operational changes must be
described adequately to identify the applicable requirements.
In some cases, physical or operational changes may be exempt from
certain applicable requirements but not from others. For example, the
New Source Performance Standards (NSPS) and major NSR regulations
specifically exempt from their purview certain types of changes, such
as those that do not reach the threshold for a ``modification.'' These
same changes, however, could still implicate other applicable
requirements. For example, a switch to another fuel which a unit is
already capable of accommodating could trigger a SIP requirement or a
Maximum Achievable Control Technology (MACT) standard, while being
exempt from NSPS and major NSR. Such SIP and MACT requirements must,
therefore, be identified as applicable requirements in an application
for an AOS governing the fuel switch.
Under this proposal, activities that do not involve a physical or
operational change to the regulated equipment do not constitute an AOS,
even when such change is made to switch between compliance options
provided for in an applicable requirement. For example, suppose a
source chooses to switch between the compliance options allowed under
an applicable requirement (e.g., a MACT standard or NSPS). Under the
Printing and Publishing Industry MACT standard (40 CFR part 63, subpart
KK), a product and packaging rotogravure affected source that uses
compliant inks and coatings (i.e., inks and coatings with low HAP
content) may demonstrate compliance for each month by any one of six
compliance options set out in the standard. Each of the compliance
options involves slightly different applicable requirements in that
different characteristics of the inks and coatings must be tracked and
different calculations must be carried out monthly to demonstrate
compliance.
We propose that a source may switch between such compliance options
without including AOSs for each compliance option in its permit.
Rather, the compliance options may simply be included in the permit as
alternative requirements of the applicable standard. We acknowledge,
however, that this approach may raise issues regarding whether an
operational change at the source has triggered the change in the
compliance option. For example, subpart KK also provides for compliance
options that use an add-on control device rather than compliant inks
and coatings. If a source alternates between compliant materials (using
one of the six associated compliance options) and noncompliant
materials (complying through use of a thermal oxidizer), should this be
characterized
[[Page 52217]]
primarily as a shift for compliance purposes that does not require an
AOS in the permit, or as an operational change requiring an AOS? What
if the source alternates among the compliance options for compliant
inks and coatings based on the characteristics of the materials that it
uses in each month? We request comment on the issue of whether a switch
from one compliance option to another is better characterized as
allowable under an applicable requirement or as a physical or
operational change that triggers a different applicable requirement and
therefore requires an AOS. Regardless of the approach ultimately
adopted, we strongly recommend that permitting authorities and sources
work together to include in the permit those compliance options allowed
under the applicable requirement that a source may reasonably
anticipate using during the term of the permit. Whether incorporated as
AOSs or simply as compliance alternatives, we believe that a title V
permit can be fashioned to allow a source to switch between compliance
options without needing a permit revision to do so.
The second criterion for a shift in operating scenario under this
proposed definition is that the triggering change must cause: (1) At
least one applicable requirement to apply which was not in effect
before the change; and/or (2) at least one applicable requirement to no
longer apply as a result of the change. ``Applicable requirement'' as
defined in 40 CFR 70.2 includes all the separate emissions reduction,
monitoring, recordkeeping, and reporting requirements of a particular
standard or SIP regulation and all the terms and conditions of
preconstruction permits issued pursuant to regulations approved or
promulgated through rulemaking under title I of the Act.
As such, AOSs can be quite effective where existing units at
sources simply make physical or operational changes that do not require
any advance approval, but they nonetheless implicate one or more
different applicable requirements. This may occur, for example, where
an existing boiler is permitted to combust different fuels, which
implicate different sets of applicable requirements. We elaborate on
this situation below in section VI.D, Example 1. Example 2 in that
section presents a situation where AOSs are used in conjunction with
advance approvals.
Under the second criterion above, AOSs are often separate and
distinct from advance approvals. For example, we propose that the
addition of a new emissions unit pursuant to an advance approval does
not require an AOS, unless the particular unit, once operational,
requires the flexibility to make subsequent physical or operational
changes that will cause applicable requirements to apply that are
different from those applicable to the authorized baseline scenario for
the new unit upon operation. We believe that construction and operation
of a new unit authorized in an advance approval does not represent a
shift in operating scenario for the unit, but rather represents
beginning its initial or baseline operation.\23\ However, we solicit
comment on whether such new unit additions should instead be
characterized as AOSs.
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\23\ An advance approval that is incorporated into a part 70
permit remains subject to all the conditions of the underlying
authorization. For example, if an underlying minor NSR permit is
contingent upon the source commencing construction of the authorized
change(s) within a certain period, the authorization in the part 70
permit also will lapse if the source fails to meet the required
deadline. The source is responsible for obtaining any extensions or
additional authorizations as necessary to keep the advance approval
in the part 70 permit in effect.
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Similarly, incorporation in a part 70 permit of an advance approval
contained in an authorizing NSR permit for a physical or operational
change to an existing emissions unit frequently would not require an
accompanying AOS, where the terms of the NSR permit containing the
advance approval are effective for the unit upon issuance of the part
70 permit. For example, suppose a source, in the process of renewing
its part 70 permit, obtains a minor NSR permit that advance approves a
change to an existing emissions unit, and the NSR permit includes new
requirements (such as an increased level of control and associated
MRRT) that do not currently apply to the unit in its baseline
operations. If the source agrees to include the new NSR requirements in
its part 70 permit effective upon issuance and, notably, prior to
making the authorized change, no AOS is needed to supplement the
advance approval.\24\ This is because no applicable requirements will
begin to apply, or cease to apply, when the authorized change is
subsequently implemented. One or more AOSs, however, would be needed in
the permit if the source wishes to build in the flexibility to make
subsequent physical or operational changes at the emissions unit that
would trigger new applicable requirements or cause existing
requirements to no longer apply.
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\24\ If any other applicable requirements would be triggered by
the change that are not addressed by the minor NSR advance approval,
they also must be included in the part 70 permit and become
applicable upon its issuance. Alternatively, such requirements may
be prevented from applying through limits contained in the permit
(e.g., a PAL or PTE cap(s)).
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In contrast, the proposed definition of AOS does include scenarios
where the new applicable requirements implicated by advance approved
changes at existing units are not effective until the source actually
makes the change. For example, an advance approval might authorize
modifications to an existing process line under minor NSR, provided
that the source meets an NSPS applicable to the line upon its
modification. Alternatively, we also propose that this situation could
be characterized as an authorized advance approval that does not
require incorporation of an AOS into the part 70 permit. That is, no
AOS would be required where implementation of an authorized change
irreversibly triggers the new applicable requirement(s), such that the
emissions unit cannot return to its baseline status in the future. As
such, this scenario is the creation of a new baseline scenario,
analogous to the addition of a new emissions unit. We solicit comment
on this issue and the two approaches we have proposed. We also solicit
comment in general on our proposal to distinguish from AOSs all advance
approvals, including those involving the addition of new units.
In addition to proposing a definition of AOS, we are also
clarifying the regulations, because the regulations use inconsistent
terminology when referring to AOSs. See e.g., 40 CFR 70.4(d)(3)(xi)
(referring to ``(alternate scenarios''). For consistency purposes, we
propose to use the term ``alternative operating scenarios'' (or AOSs)
throughout the regulations when referring to an alternative operating
scenario under 40 CFR 70.6(a)(9). See proposed 40 CFR 70.4(d)(3)(xi)
and 40 CFR 70.5(c)(2) and (7). Note also that any specific ``AOS''
listed in a permit refers to a specific operating scenario which
differs importantly from the previous scenario (also contained in the
permit) in that one or more different applicable requirements are
implicated by the shift in operating scenarios. The scenario that
reflects the current operations and applicable requirements of the
source at the time of permit issuance is called the ``baseline
scenario.''
A key objective for a source requesting an AOS is to identify and
describe in the title V permit application those changes that are
reasonably anticipated to occur for each emissions unit during the term
of the title V permit. This proposal clarifies that AOSs can be used to
provide operational flexibility for a variety of situations, ranging
from a single specific
[[Page 52218]]
anticipated alternative scenario to multiple scenarios, including
somewhat less specific (but still nonetheless bounded) scenarios. In
all situations, however, the contemplated changes must be described in
the permit application in sufficient detail for the relevant emissions
units such that the permitting authority can determine whether all
applicable requirements have been identified and can craft appropriate
terms and conditions to assure compliance with such requirements. Where
differing applicable requirements would apply to a particular emissions
unit, depending upon the nature and extent of the change made, the
permit should contain alternative terms and conditions as needed to
assure compliance with all applicable requirements under each AOS which
is reasonably anticipated to occur.
If the permitting authority approves the proposed AOSs for a
particular emissions unit, it will include in the title V permit a
description of the anticipated changes associated with each approved
AOS, and for each AOS will include associated applicable requirements
and terms and conditions that assure compliance with each identified
applicable requirement, as well as terms and conditions that assure
compliance with the related part 70 requirements relevant to the AOSs.
Alternative operating scenarios may vary in their complexity. At
one extreme is a simple situation where a source seeks approval for
operating scenarios that involve a very specific type and number of
changes to the defined baseline operations of the relevant emissions
unit(s) (i.e., the changes can be described exactly). An example of
this situation is the combustion of various fuels in a boiler capable
of burning different fuels (where combustion of each type of fuel is
subject to different SIP requirements). See Example 1 discussed below.
A more complex situation involves sources seeking approval for AOSs
encompassing a wider spectrum of reasonably anticipated changes.
Sources here may not be able to determine precisely in advance (i.e.,
at the time of permitting) which of the changes and implicated AOSs
will be implemented for the relevant emissions unit(s). Depending on
future market behavior, the source eventually may implement all or only
some of these changes.
The type of detail needed to describe an AOS and the changes
anticipated to occur under it can vary. Certainly the need for greater
detail is dependent upon what is required to determine the applicable
requirements implicated by the anticipated changes. In many cases, the
number of applicable requirements for anticipated changes can be
reduced, without loss of flexibility, through strategic use of boundary
conditions on the AOS. Boundary conditions help to define the relevant
applicable requirements implicated by authorized physical or
operational changes, which, in turn, enables the permitting authority
to assure that all applicable requirements and requirements of part 70
are contained in the permit when designing AOSs.\25\ For example,
operational restrictions (such as those on the type or amount of
materials combusted, processed, or stored) can be used to delineate the
scope of the AOS by limiting which applicable requirements apply under
them.
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\25\ Boundary conditions can also be used to restrict the scope
of advance approvals. The pilots primarily used boundary conditions
for this purpose. Such conditions typically involved restrictions
that prevented certain different applicable requirements from
applying to the changes otherwise authorized under minor NSR. For
example, a source owner opted to avoid the applicability of major
NSR by accepting an emissions limit that restricts the PTE of the
source to below the threshold at which that requirement would apply,
or, in the case of an existing major stationary source, a PAL that
designates an emissions limit below which major NSR would not apply
to changes made at the source.
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The approaches approved to assure compliance with applicable
requirements can also affect the implementation of anticipated AOSs
and, therefore, indirectly affect the changes approved under them. That
is, authorized changes must not adversely impact the effectiveness of
the control devices or monitoring approaches required by an AOS
approved in the permit. For example, changes involving substances which
are not effectively controlled by the control device required in the
permit could not be approved. This would also be true for physical or
operational changes which would render inaccurate the monitoring
procedures approved in the permit for assuring compliance with an
applicable requirement (e.g., PTE limit).
Compliance assurance terms for AOSs and advance approvals can be
greatly simplified where the applicable requirements can be streamlined
(i.e., the compliance terms are based on the most stringent requirement
applicable to the proposed changes and are effective upon permit
issuance). In guidance generally referred to as ``White Paper Number
2,'' we interpreted our part 70 rules to allow sources to streamline
multiple applicable requirements that apply to the same emissions
unit(s) into a single set of requirements that assure compliance with
all the subsumed applicable requirements.\26\ If all the applicable
requirements that apply to a set of changes are streamlined in the
permit and the permitting authority approves the proposed streamlining,
the source need only comply with the streamlined requirement. This
benefits all parties by simplifying and focusing the compliance
requirements contained in the permit.
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\26\ As explained in White Paper Number 2, sources that seek to
streamline applicable requirements should submit their request as
part of their title V permit application, identifying the proposed
streamlined requirements and providing a demonstration that the
streamlined requirements assure compliance with all the underlying,
subsumed applicable requirements. Upon approval of the streamlined
requirements, the permitting authority would place the requirements
in the title V permit. See ``White Paper Number 2 for Improved
Implementation of the Part 70 Operating Permits Program,'' March, 5,
1996, for the complete guidance on the streamlining of applicable
requirements (http://www.epa.gov/ttn/oarpg/t5/memoranda/wtppr-2.pdf
). Where the source wishes to streamline the advance approval
under NSR with all other relevant applicable requirements, the same
title V permit application can address both actions.
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It should be noted that changing to an AOS cannot be used to
circumvent applicable requirements or to avoid an enforcement action. A
switch to an AOS does not affect the compliance obligations applicable
to a source under its previous operations.
B. What information is necessary in a title V permit application to
seek approval of an AOS?
Because the application forms the basis for the content of the
title V permit, the discussion below is relevant to the content of a
permit that authorizes AOSs. This section clarifies the requirements
for a complete application and discusses minor proposed revisions to
these requirements.
The provisions of 40 CFR 70.5(c) contain the information that must
be submitted in a complete title V permit application, including
information concerning proposed AOSs.\27\ We are proposing minor
revisions to 40 CFR 70.5(c) to clarify how certain aspects of the
requirements in that section should be addressed when a source applies
for approval of AOSs.
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\27\ For the complete text of the elements that must be included
in a title V application, see 40 CFR 70.5(c).
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Under the provisions of 40 CFR 70.5(c), the source generally must
describe the emissions of all regulated air pollutants (as defined at
40 CFR 70.2) from any emissions unit, identify all applicable
requirements that apply to each emissions unit, and describe how it
will meet these applicable requirements. The source must provide this
information for existing operations
[[Page 52219]]
(i.e., baseline operations) and for any reasonably anticipated changes
for which an AOS is proposed. The description of AOSs in title V permit
applications may vary depending on the situation (as previously
discussed). However, in every case the level of detail in the
description must be sufficient for the permitting authority to write
permit terms and conditions that assure compliance with all applicable
requirements and the requirements of part 70 that will apply to the
proposed AOS. See 40 CFR 70.5(c)(3)-(7); 40 CFR 70.6(a)(9)(iii). If the
source adequately describes proposed AOSs in the part 70 permit
application and the permitting authority includes them in the permit
consistent with 40 CFR 70.6, the source may subsequently implement the
physical and operational changes under protection of the permit shield
(where available and granted by the permitting authority) without
triggering the permit modification provisions of 40 CFR 70.7.
Similarly, the source must meet the provisions of 40 CFR 70.5(c)
concerning advance approvals which are to be incorporated into the
title V permit. Where a change is authorized in an NSR permit and the
permit contains terms which would be effective upon issuance of the
title V permit and would assure compliance with all applicable
requirements, then a straightforward incorporation of the terms of the
NSR permit into the title V permit is all that is necessary. However,
where the NSR advance approval terms would be effective upon title V
permit issuance but would not address some other requirement(s) that
will apply to the NSR-authorized changes (e.g., a MACT standard), then
additional information about the changes relative to these other
requirements must be provided to the permitting authority in the part
70 application. The permitting authority would then develop permit
terms sufficient to assure compliance with all requirements applicable
to the NSR-approved changes as part of the title V permit issuance,
modification, or renewal process. Use of a streamlined limit is one
acceptable approach when requested by the source (see footnote 26 and
example 3 below).
We are proposing to revise 40 CFR 70.5(c)(2) and (7) to use the
term ``AOS'' in the interest of consistent terminology. Existing 40 CFR
70.5(c)(2) uses the term ``alternate scenario,'' while existing 40 CFR
70.5(c)(7) uses ``alternative operating scenario.'' We believe that
revising these paragraphs to use consistent terminology, along with
proposing a definition for ``AOS'' and conforming changes in other
sections, will improve the clarity of the affected paragraphs and
reduce any confusion.
We are also proposing to revise 40 CFR 70.5(c)(3)(iii), (c)(7), and
(c)(8) to clarify our intent regarding the information that must be
included in an application that proposes AOSs for approval by the
permitting authority. The proposed revisions to each of these sections
are described below, along with the rationale for proposing them.
The introductory text in 40 CFR 70.5(c) states generally that the
application must include information for each emissions unit. Existing
40 CFR 70.5(c)(3)(iii) further requires that the application provide
the emissions rate in tpy and in such terms as are necessary to
establish compliance consistent with the applicable reference test
method. We are proposing to clarify this regulatory requirement as it
applies to sources subject to title V permitting requirements that
employ an emissions cap (e.g., PALs, PTE, Green Groups). In particular,
we are proposing that for the operation of any emissions unit
authorized under an annual emissions cap, a source can meet 40 CFR
70.5(c)(3)(iii) by reporting the aggregate emissions associated with
the cap. For example, a source may take a plantwide cap on its PTE so
that it will not become a major source for purposes of PSD, thereby
assuring that PSD will not apply to any changes made at the source. For
purposes of the title V permit application and this emissions cap, the
source need not provide individual tpy figures for any new or modified
emissions units authorized under minor NSR. Rather, emissions from such
units would be reported in the title V permit application as part of
the aggregate emissions under the PTE cap. Additional information may,
however, be required to describe the scope of any changes authorized in
minor NSR to occur under any emissions cap or to provide additional
information relevant to other requirements applicable to these changes.
Under the proposed approach, an emissions cap can act as a
constraint on annual emissions from each emissions unit under the cap
as well as on the aggregated emissions from the group of units. That
is, in the extreme, a unit could emit up to the full amount of the cap
if all other units under the cap had zero emissions. Thus, for a group
of emissions units under an annual emissions cap, the 40 CFR
70.5(c)(3)(iii) requirement for unit-by-unit tpy figures can be met by
reporting in the permit application that the emissions cap represents
the upper limit on emissions both from each unit in the group and from
the entire group. This proposed revision to 40 CFR 70.5(c)(3)(iii)
simply clarifies that in this particular situation, more specificity is
not needed. Reporting emissions data in the above proposed manner in
the title V permit application is permissible (including in the case of
a plantwide emissions cap), except where the permitting authority
determines that more specific tpy information is needed (e.g., where an
applicable requirement for a specific emissions unit depends on the
emissions type or level).
We are proposing to revise 40 CFR 70.5(c)(7) in two ways. The
existing language in 40 CFR 70.5(c)(7) specifies that the application
must include ``additional information as determined to be necessary by
the permitting authority to define alternative operating scenarios
identified by the source pursuant to 40 CFR 70.6(a)(9) of this part or
to define permit terms and conditions implementing 40 CFR 70.4(b)(12)
or 40 CFR 70.6(a)(10) of this part.'' First, we propose to modify the
existing language to clarify that the permitting authority can require
additional information from the source not only for adequately defining
the AOS, but also, as necessary, to craft permit terms and conditions
implementing the proposed AOSs under 40 CFR 70.6(a)(9). We believe that
this proposed revision is implicit in the existing language of 40 CFR
70.5 (e.g., 40 CFR 70.5(c)(5)), but that a clarification is
appropriate.
Second, we propose to revise 40 CFR 70.5(c)(7) to clarify that the
application must include documentation demonstrating that the source
has obtained all specific authorizations required under the applicable
requirements relevant to any proposed advance approvals or AOSs, or a
certification that the source has submitted a complete application for
obtaining such authorizations. Based on our pilot experience, we expect
that proposed advance approvals and certain AOSs will involve one or
more of the following applicable requirements: minor NSR, major NSR,
and section 112(g) of the Act. These applicable requirements all
require permits or other authorizations prior to construction or
modification of a source.\28\ (In some cases, the overall
[[Page 52220]]
approach might be to avoid triggering applicable requirements that
require additional authorizations, such as by adopting a PAL or
accepting a PTE limit.)
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\28\ Some State, local, and Tribal air control programs include
``State-only'' requirements (i.e., requirements not enforceable by
EPA) that require source owners or operators to obtain authorization
prior to construction. In instances where the permitting authority
elects to include such requirements in the part 70 permit, there are
benefits to addressing them as part of a comprehensive permit
flexibility solution. These requirements should, however, be labeled
as ``State-only'' consistent with 40 CFR 70.6(b)(2). Options for
flexible permit conditions to address State-only applicable
requirements potentially range widely, depending on the State's
interpretation of its ability to authorize changes in advance under
these requirements.
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It is important to stress that an AOS merely incorporates
authorizations given under applicable requirements and does not
independently authorize changes that are subject to review and require
specific approval. For this reason, we are proposing the above revision
in the application requirements, along with a related revision to the
AOS provisions of 40 CFR 70.6(a)(9), stating that the permitting
authority cannot approve an AOS until all of the necessary
authorizations required under the relevant applicable requirements have
been obtained. It is possible to process the title V permit and, where
needed, a corresponding NSR permit concurrently, but the title V permit
approving an AOS cannot be issued before any necessary preconstruction
approval has been obtained.
Some applications for AOSs and advance approvals may also contain
information needed to establish one or more ``approved replicable
methodologies'' (ARMs). In section VI.C.2.b of this preamble, we
discuss ARMs and their incorporation into part 70 permits. An ARM is an
objective protocol for determining values pertaining to compliance or
applicability requirements, such as temperature or emissions. Approved
replicable methodologies are permit terms that are consistent with and
implement an applicable requirement or requirement of part 70. A source
that wishes to have an ARM included in its permit must provide
sufficient information in its application to define the replicable
methodology, its intended function, the instructions for its use, and
the type of data required for its implementation. See 40 CFR
70.5(c)(5)-(c)(7). See section VI.C.2.b for more information on ARMs.
Finally, we are proposing to revise 40 CFR 70.5(c)(8), which
requires each part 70 permit application to include a compliance plan.
The existing paragraph addresses applicable requirements with which the
source is in compliance, applicable requirements that will become
effective during the permit term (e.g., a newly promulgated emission
standard), and applicable requirements with which the source is not in
compliance at the time of permit issuance. We are proposing to revise
this section in two places to clarify that such plans must address AOSs
when applications include them. This proposal would add language to
clarify that, for applicable requirements associated with an AOS, the
compliance plan must contain a statement that the source will meet such
requirements upon implementation of the AOS or, if a requirement
becomes applicable after implementation of the AOS, in a timely manner.
We believe that this revision appropriately fills a gap in the existing
language. See proposed 40 CFR 70.5(c)(8)(ii)(D) and (iii)(D).
We solicit comment on whether the proposed rule revisions noted
above provide sufficient clarity as to how the application requirements
of 40 CFR 70.5(c) are to be applied to sources that seek approval of
AOSs and/or incorporation of advance approvals. We also seek comment on
whether the proposed revisions are necessary or if additional revisions
are needed to ensure that permit applications contain sufficient detail
to identify all applicable requirements associated with an AOS and/or
advance approval. If you believe that additional regulatory revisions
are needed, please identify the proposed change and explain why it is
needed.
C. What terms and conditions must be included in the title V permit for
approved AOSs?
Existing 40 CFR 70.6 details the required content of a title V
permit, including the requirements for reasonably anticipated operating
scenarios. In this section of the preamble, we discuss how the existing
permit content requirements of 40 CFR 70.6 apply to AOSs and how the
rule revisions we are proposing are consistent with this intent.
To standardize the terminology in 40 CFR 70.6, we are proposing to
use the term ``alternative operating scenario'' (or its acronym
``AOS'') throughout 40 CFR 70.6(a)(9) as we have done in the other
sections of the rule. The proposed revisions to 40 CFR 70.6(a)(9) also
clarify that the title V permit must contain terms and conditions to
describe the AOSs, to assure compliance with the applicable
requirements implicated by the AOSs, and to assure compliance with the
requirements of part 70. Finally, as explained below, we are proposing
to modify 40 CFR 70.6(a)(1) to clarify that ARMs are one type of
operational requirement or limitation that assures compliance with
applicable requirements. These items are discussed below.
As previously mentioned, no AOS is needed where the changes would
occur under an advance approval contained in an authorizing permit
whose terms are incorporated in the part 70 permit, as well as any
other applicable requirements which would apply to the advance approved
changes, and those terms are effective upon issuance of the part 70
permit. For example, our pilot experience suggests that no additional
flexibility provisions may be needed in a title V permit beyond the
incorporation of NSR permit terms establishing an advance approval
under minor NSR and a PAL or PTE limit that prevents the applicability
of major NSR.\29\ On the other hand, AOSs can be particularly useful
either where: (1) A new or existing unit with frequently changing
operations would be subject to certain emissions standards in different
ways depending on the type of materials used, rate of production, and
type and/or amount of product produced; or (2) an existing unit would
be subject to an applicable requirement associated with an advance
approved change only upon implementation of the authorized change.
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\29\ As needed, additional terms would be added to assure
compliance with applicable requirements beyond NSR that are
implicated by the advance approved changes.
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1. Terms and Conditions To Describe Approved AOSs
If the permitting authority approves an AOS, the permit must
include a description of the baseline operating scenario for each
included emissions unit, the authorized physical or operational changes
included in each AOS, and the applicable requirements that apply under
each scenario (including those requirements newly applying or not
applying as a result of the authorized changes). Expectations for AOS
descriptions in the permit are similar to those previously identified
for AOS descriptions in complete applications. As mentioned previously,
the type of detail in such descriptions and the need for one or more
boundary conditions can vary depending on the nature of the change and
the applicable requirements implicated by the changes. A permit with an
AOS for a particular emissions unit normally would include a
description of the unit operating in its baseline mode of operation.
For each approved AOS, the physical and operational changes which have
been authorized should then be identified relative to this baseline
operation. In all cases, the description of each AOS must be adequate
to link the triggered
[[Page 52221]]
applicable requirements to the terms which assure compliance with them.
We are proposing revisions to 40 CFR 70.6(a)(9) to clarify what
constitutes an acceptable description for an AOS (see proposed revision
to 40 CFR 70.6(a)(9)(iii)). We are also proposing a revision to 40 CFR
70.6(a)(9)(iii) to make clear that the permitting authority cannot
approve an AOS until all of the necessary authorizations relevant to
the applicable requirements have been obtained, that is, until the
source has been approved to proceed by the permitting authority where
such prior authorization is required (e.g., approvals under major and
minor NSR and section 112(g) of the Act).\30\ Finally, as mentioned,
where a source is unable to predict, at the time of permit issuance,
which of several reasonably anticipated changes it actually will make,
it can seek approval for a range of changes and applicable requirement
combinations at a particular emissions unit by including multiple AOSs.
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\30\ See footnote 22.
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2. Terms and Conditions To Assure Compliance With Applicable
Requirements
In this section, we discuss our proposal related to permit content
to assure compliance with all applicable requirements.
a. Proposed Clarifications to the AOS Provisions
The provisions of 40 CFR 70.6(a)(9)(iii) require that, for each AOS
for an emissions unit, the permit must contain terms and conditions to
assure compliance with all the applicable requirements that apply to
the emissions units operating in that AOS. This means that the permit
must include, for each relevant emissions unit, the applicable
emissions limits, compliance approaches, and monitoring, recordkeeping,
reporting, and testing (MRRT) requirements as required by the
applicable requirements as well as those required otherwise under 40
CFR 70.6(a)(3) (e.g., periodic monitoring) for the compliance
approaches. In addition, the permit must incorporate all advance
approvals, such as those authorized under NSR, as well as the
description of changes authorized in each AOS as described above. For a
permit containing more than one AOS for an emissions unit, the permit
must contain a clear description of each one so that there is no
confusion with respect to which AOS is implicated at any given time.
b. Proposed Revisions for ARMs
As stated, title V permits are required to assure compliance with
all applicable requirements. Sometimes, changes occur at a source that
may cause the need to recalculate/update a value used either in
determining compliance of the source with an applicable requirement or
in determining the applicability of a requirement. An advance approval
or an AOS can incorporate flexibility in a permit, but the scope of
changes that can be authorized in them can be severely limited with
respect to a particular applicable requirement, if the changes require
case-by-case review/approval procedures and possible permit revision in
order to ensure ongoing compliance with all applicable requirements. To
facilitate implementation of advance approvals and AOSs, and to
encourage other permitting techniques that reduce in general the need
for permit modifications (in a manner consistent with part 70), we are
proposing the use of an ARM that has been approved by a permitting
authority and incorporated into a title V permit.
In particular, we are proposing to define ``approved replicable
methodology'' or ``ARM'' at 40 CFR 70.2 as title V permit terms that:
(1) Specify a protocol which is consistent with and implements an
applicable requirement or requirement of part 70, such that the
protocol is based on sound scientific/mathematical principles and
provides reproducible results using the same inputs; and (2) require
the results of that protocol to be used for assuring compliance with
such applicable requirement or requirement of part 70, including where
an ARM is used for determining applicability of a specific requirement
to a particular change. Within the scope of this definition, an ARM may
be used to assure that a given requirement does not apply in a
particular situation.
The terms of an ARM must specify when the ARM is to be used, the
applicable methodology (e.g., equation or algorithm) and the purpose
for which the output obtained upon the execution of the prescribed
methodology will be used (e.g., to determine compliance with an
applicable requirement or to modify the level of the parameters used to
determine compliance in the future). All necessary terms and conditions
must be included in the permit at the time the ARM is approved so that
no permit revision will be required in the future to implement the ARM.
It is important to emphasize that an ARM, like any provision of a
part 70 permit, cannot modify, supersede, or replace an applicable
requirement, including, but not limited to, any monitoring,
recordkeeping, or reporting required under applicable requirements.\31\
Instead, ARMs are a strategic approach for incorporating into a title V
permit relevant applicable requirements and the requirements of part
70. The ARM provides a method for obtaining and updating information
consistent with the intent of applicable requirement(s) or
requirement(s) of part 70 in such a manner so as to avoid the need to
reopen or revise the permit to incorporate the updated information. As
such, an ARM must work within and be consistent with the applicable
part 70 rules that govern permit revisions.
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\31\ Under the authority of 40 CFR 70.6(a)(3), however, the
permit can also contain additional streamlined monitoring or gap-
filling periodic monitoring as needed to assure compliance with
applicable requirements. An ARM can operate on the information
gathered under these obligations as well.
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The protocol to obtain information under an ARM must be objective
and scientifically valid and reliable--such as an EPA test method or
monitoring method (usually specified in the applicable requirement
itself.) Note that an ARM also includes the instructions governing how
the results of the protocol are to be used. For example, an ARM could
specify that firebox temperature measurements taken during a
performance test of a thermal oxidizer be used to revise a previously
imposed minimum firebox operating temperature of the oxidizer.
We believe that ARMs are authorized under title V of the Act and
its implementing regulations. Section 502 sets forth the minimum
elements for a State operating permit program. Among other things,
section 502 provides that for a State operating permit program to be
approved, the permitting authority must have adequate authority to
``issue permits and assure compliance by all sources required to have a
permit * * * with each applicable standard, regulation or requirement''
under the Act. See CAA section 502(b)(5)(A). Section 504(a) of the Act
also requires that each title V permit contain ``enforceable
limitations and standards * * * and such other conditions as are
necessary to assure compliance with applicable requirements of this
Act, including the requirements of the applicable implementation
plan.'' The Act further provides that any State operating permit
program must include ``adequate, streamlined, and reasonable procedures
* * * for expeditious review of permit actions.'' See CAA section
502(b)(6).
[[Page 52222]]
The part 70 regulations implement these requirements. Section 70.4
sets forth the required elements for a State operating permit program.
Such State programs must provide for the issuance of permits that
contain appropriate terms and conditions that assure compliance with
all applicable requirements and the requirements of part 70. See
generally 40 CFR 70.4(3)(i)-(ii), (v). The threshold requirement that a
part 70 permit contain terms and conditions that assure compliance with
applicable requirements and the requirements of part 70 is also
reflected in other parts of the part 70 regulations. See, e.g., 40 CFR
70.5(c)(4)-(5), 70.6(a)(1)(i), 70.6(a)(9)(iii). For example, 40 CFR
70.6(a)(1) provides that the permit include ``those operational
requirements and limitations that assure compliance with all applicable
requirements.'' Section 70.6(a)(1)(i) further provides that the permit
shall identify the origin and authority for each term and condition.
See 57 FR 32275 (``Section 70.6(a)(1)(i) requires that the permit
reference the authority for each term and condition of the permit.
Including in the permit legal citations to the provisions of the Act is
critical in defining the scope of any permit shield, since the permit
shield, if granted, extends to the provisions of the Act included in
the permit.''). An ARM, as proposed now, constitutes permit terms
designed to assure compliance with applicable requirements or the
requirements of part 70 and accordingly falls squarely within the
authority of title V and its implementing regulations.
In our pilot experience, we found that some permitting authorities
already use part 70 permit terms (similar to ARMs) that assure
compliance with applicable requirements or the requirements of part 70,
are self-implementing, and avoid the need for the source to seek
multiple permit revisions. Based on our experience in the pilot program
with such permitting techniques and in an effort to encourage efficient
permitting techniques, we propose to define an ARM in the manner
described above.
Under the proposed ARM definition, an ARM may be used to implement
an applicable requirement. As an example of one type of ARM, consider a
source subject to the MACT standard for Paper and Other Web Coating (40
CFR part 63, subpart JJJJ), which requires a 95 percent reduction in
HAP emissions for existing sources. Like many emission standards,
subpart JJJJ requires the source to assess ongoing compliance with the
emissions limit by monitoring an operating parameter of the air
pollution control device. Where a source uses a thermal oxidizer to
comply with the emissions limit, the rule requires the source to
conduct a performance test to demonstrate initial compliance and to
demonstrate ongoing compliance by continuously monitoring the
combustion temperature in the combustion chamber of the oxidizer. To
establish the minimum combustion temperature that will serve as the
basis for future compliance determinations, subpart JJJJ requires the
source to monitor the combustion temperature throughout the performance
test, and to calculate the average combustion temperature achieved by
the oxidizer during the test. Provided that the performance test
demonstrated compliance with subpart JJJJ, the average combustion
temperature determined during the test is established as the minimum
temperature limit for the oxidizer in the permit. This value may change
with each successive performance test that demonstrates compliance.\32\
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\32\ Although subpart JJJJ requires only an initial performance
test, many States require periodic performance tests to verify that
the control device continues to achieve the emissions limit. Where
this is the case, the operating limit typically is recalculated
based on the temperature during each test.
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A source subject to subpart JJJJ proposes to use an ARM consistent
with this standard to accommodate anticipated changes in the operating
parameter limit resulting from future performance demonstrations
without requiring a permit revision. The ARM would consist of the test
methods and procedures specified under subpart JJJJ for demonstrating
compliance and determining the minimum oxidizer temperature which
indicates compliance with the standard (as described in the paragraph
above). Upon approval of the ARM into the permit, the source would no
longer be required to revise the permit each time it conducted a
performance demonstration to place the most recent temperature value
indicative of compliance on the face of the permit. Instead, the permit
would require the source to: (1) Use the ARM (i.e., the test methods
and procedures required under subpart JJJJ) to determine the
temperature value indicative of compliance; (2) maintain records of
this temperature; and (3) use this temperature for all compliance
monitoring and reporting purposes dictated by subpart JJJJ, until and
unless the permittee implements the ARM again. If the permitting
authority for the source requires regular performance tests, the
schedule for such tests also could be included in the ARM.
The MACT General Provisions (40 CFR part 63, subpart A) also apply
in part to sources subject to subpart JJJJ. The General Provisions
include the following provisions related to conducting performance
tests: Requirements for notifications; quality assurance (including
submission of a site-specific test plan as requested by the permitting
authority); the test method audit program; conduct of tests; and data
analysis, recordkeeping, and reporting. The ARM does not abrogate such
procedural requirements, it simply incorporates these requirements in
the permit.
A second type of ARM may be used in a part 70 permit to ensure that
a legal limit requested voluntarily by the source effectively
constrains the source's PTE below a certain threshold so as to avoid
the applicability of certain requirements. By complying with such PTE
limits, sources demonstrate on an ongoing basis that they are not
subject to a requirement that would otherwise be triggered at a
particular emissions threshold. Some PTE limits are applicable
requirements (e.g., if imposed by a SIP program or as a condition of an
NSR permit). In addition, part 70 operating permits can be used as a
legal mechanism for establishing EPA and citizens' authority to enforce
terms and conditions limiting a source's PTE. See 40 CFR 70.6(b)(1).
Permitting authorities have some discretion in fashioning such terms
and conditions. We believe that the ARM concept could be used to
establish effective PTE limits in agreement with 40 CFR 70.6(b)(1).\33\
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\33\ We have proposed in the definition of ARM that the
otherwise qualifying replicable protocol be consistent with and
implement an applicable requirement or requirement of part 70
(emphasis added). Limits on PTE may be established pursuant to part
70, and such a PTE limit would be a requirement of part 70 and thus
could be in part implemented through an ARM.
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As an example of how the ARM concept can be used to assure
compliance with a PTE limit, consider a source in the process of
renewing its title V permit that proposes to take a PTE limit of 99 tpy
on its VOC emissions to avoid being classified as a major VOC source.
The PTE limit, once approved and incorporated into the title V permit,
has the effect of exempting the source from major NSR requirements that
only apply to existing major VOC emitters. To assure compliance with
the 99 tpy PTE limit, the source proposes a quantification methodology
to the permitting authority by which the source would determine total
VOC emissions on an ongoing basis.\34\ In this
[[Page 52223]]
instance, the source will determine VOC emissions with an equation that
sums all the individual VOC emissions from each emissions unit.
Provided that this methodology relies on objective, repeatable
protocols (i.e., the method of calculating the individual units' VOC
emissions is clear) it can become an ARM when approved by the
permitting authority and included in the title V permit. The ARM would
include requirements governing when the procedures were to be used and
how the values to be input into the equation would be determined.
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\34\ In the above PTE example, assume that the emissions
determinations were based on emissions factors derived from a stack
test. If there is a possibility that a subsequent stack test may be
performed, which would require revision of those emissions factors
in the near future, the source or permitting authority may consider
including in the permit an ARM. The ARM could direct the source to
use emissions factors derived from the most recent stack test,
rather than listing specific factors in the PTE equation contained
in the permit, eliminating the need for a permit revision once new
factors are established.
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We found permit terms, similar to ARMs, to be useful in maintaining
the effect of the advance approvals found in the flexible permit
pilots. Two of the pilot permits contained replicable testing
procedures. These procedures, once implemented, determined the control
device operating parameter values that the source must monitor to
demonstrate compliance with capture and destruction efficiency
requirements (i.e., the applicable requirement). Without the replicable
testing procedures in the permit, those values would have been included
on the face of the permit, and the source would have had to seek a
permit revision each time it repeated the testing procedures and the
operating parameter values changed.\35\ Another pilot permit specified
the process by which an emissions factor could be updated and used to
determine whether the source's emissions remained under a PTE cap. By
including this process (replicable testing and/or emissions factor
updating procedures) in the permit instead of specific operating values
and emissions factors, the source could update those values and
indicate compliance based on the latest results consistent with the
replicable testing procedures in the title V permit, and forego a
permit revision each time the values change.
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\35\ Although an ARM can reduce the number of permit revisions a
source must make, it cannot modify an applicable requirement. For
example, there are some instances where the applicable requirement
requires a notice to the permitting authority, such as where the
requirement calls for notice of a performance test or the submission
of certain performance test results. An ARM does not abrogate these
requirements.
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In addition to proposing a definition of an ARM, we also propose
modifying 40 CFR 70.6(a)(1) to include a reference to ARMs, because
ARMs are an example of permit terms that assure compliance with
applicable requirements. Although we do not believe that the proposed
regulatory change to 40 CFR 70.6(a)(1) is needed, given that all
permits must include terms that assure compliance with applicable
requirements and the requirements of part 70, we are proposing the
change to promote clarity. We recognize that we could modify other
provisions of part 70, such as 40 CFR 70.6(a)(9),\36\ to include a
reference to ARMs, but given the structure and content of the existing
regulations, we do not believe such additional changes are needed. We
solicit comment, however, on whether additional regulatory changes
would be useful to encourage the use of this efficient permitting
technique.
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\36\ In pertinent part, 40 CFR 70.6(a)(9) provides that for an
AOS, the part 70 permit must contain appropriate terms and
conditions to ensure that ``all applicable requirement and the
requirements of this part'' are met. An ARM constitutes an example
of such permit terms.
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3. Terms and Conditions To Assure Compliance With Other Part 70
Requirements
In addition to the terms and conditions to assure compliance with
all applicable requirements, the permit must contain terms and
conditions that assure compliance with the requirements of part 70.
Section 70.6(a)(9)(i) currently requires ``the source,
contemporaneously with making a change from one [AOS] to another, to
record in a log at the permitted facility a record of the [AOS] under
which it is operating.'' We are proposing to clarify this provision to
identify more clearly the information that must be included in the log
and when the log must be updated.
Overall, we expect that the log will be clear and complete in its
description of which AOS and associated permit terms and conditions are
being implemented. Specifically, we propose that the source be required
to maintain an on-site log that includes, for each time an AOS is
implemented at the source: the operational or physical change which
causes the shift to the AOS, the emissions unit included under the
scenario, a reference to the applicable requirement(s) (including those
newly applicable to the emissions unit as a result of the change), a
reference to the applicable permit terms and conditions which apply to
the AOS and are implemented by the source, and the dates when the
source operated under the AOS (see proposed 40 CFR 70.6(a)(9)(i)).\37,\
\38\ A source can cross-reference the permit in providing the
information required for the log, but the cross-reference must be clear
and specific and all of the information required for the log must be
identified, including, but not limited to, the identity of the AOS
implemented and if alternative terms and conditions are provided for
such AOS, which terms and conditions were actually implemented by the
source.
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\37\ Certain applicable requirements require that additional
information be included in an on-site log. These data can be
combined with that which would be required under the proposed part
70 revisions. For example, the Pharmaceuticals Production MACT
standard (40 CFR part 63, subpart GGG) requires the source to log
considerably more information about its ``operating scenario.'' See
40 CFR 63.1259(b)(8) and the definition of ``operating scenario'' at
40 CFR 63.1251.
\38\ A source, however, would not need to log a change to an
emissions unit unless an AOS is implicated by the change, or a
source stops operating under an AOS and returns to baseline
operating conditions as a result of the change. In particular, no
log entry is needed for a source making a change where the change
has been advance approved under minor NSR, the title V permit
contains the advance approval, and these terms are in effect upon
issuance of the title V permit (i.e., no AOS is involved).
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We are seeking comment on whether our proposed revisions to 40 CFR
70.6(a)(9)(i) appropriately clarify the required content of the on-site
log of AOSs operated at the source. We also seek comment on whether we
have achieved the proper balance between the need for information and
the need to minimize administrative burden in proposing that log
entries be required only when a source adopts a different AOS. Is the
proposed log content adequate to determine which AOS is being
implemented by the source?
Existing 40 CFR 70.6(a)(9)(ii) states that the title V permit may
extend the permit shield described in 40 CFR 70.6(f) to all terms and
conditions under each AOS. We are not proposing to change this
paragraph, other than to adopt the term ``AOS'' for consistency. Thus,
the permit shield, where provided for by the permitting authority, may
be extended to the terms and conditions of ARMs and AOSs, provided they
have been the subject of notice and comment. See 57 FR at 32277 (July
21, 1992); see also 40 CFR 70.7(e)(2)(vi). The contents of the on-site
implementation log, such as its description of requirements which apply
to a particular AOS, are not permit provisions for purposes of the
permit shield. Thus, a source will not be deemed to be in compliance
with applicable requirements of the Act simply because it is in
compliance with the description of applicable requirements contained in
the log (if the description is inaccurate). Similarly, a source owner
or operator who
[[Page 52224]]
incorrectly applies the procedures and criteria for an ARM contained in
the permit will be considered not to be in compliance with the terms of
the permit (and therefore not in compliance with the Act).
Finally, we would like to clarify our expectations for how
monitoring relative to AOS implementation is to be included in the
semi-annual monitoring reports required by 40 CFR 70.6(a)(3)(iii)(A).
In general, the semi-annual reports must identify the AOS(s)
implemented during the 6-month period and include monitoring
information relating to such AOS(s). Such monitoring information
provides permitting authorities important information on source
operations. The information also helps inform the permitting authority
as to the frequency and duration of the AOSs actually implemented.
In addition, the semi-annual monitoring reports must identify any
ARMs implemented in the 6-month period. For ARMs that generate values
related to parametric monitoring (e.g., an ARM used to determine the
new value of a control device operating limit after a performance test,
or an ARM used to determine compliance with a PTE limit), the source
must also include the results of the ARM used during the 6-month period
in the semi-annual report. The report will, therefore, summarize the
monitoring data referenced to the emissions unit, emissions limit, and
ARM output.
D. What are some examples of how AOSs and advance approvals can be used
to provide operational flexibility?
In this section, we present two examples to illustrate how to apply
the requirements of 40 CFR 70.5(c) and 70.6(a)(9) to AOSs. The first
example is for an AOS that involves the use of an existing boiler with
dual fuel capability. The second example uses a combination of advance
approvals and AOSs to add solvent storage tanks over the term of a
source's title V permit.
Example 1: Boiler With Dual Fuel capability
This is a simple example of an AOS, and the application and
permitting requirements are quite straightforward. The relevant
emissions unit is an existing boiler that is authorized for and capable
of burning either distillate fuel oil or natural gas. The boiler is
part of a major stationary source subject to the title V permitting
requirements. The boiler is subject to a pre-existing minor NSR permit
which authorized its construction and limited its subsequent total
emissions, and to different SIP emissions limits (and associated MRRT
requirements) depending on which fuel is in use. The minor NSR permit
remains in effect. The source reasonably anticipates that it may wish
to switch fuels during the term of its title V permit, and proposes to
the permitting authority to designate combustion of natural gas as the
baseline operating scenario and address the combustion of distillate
fuel oil as an AOS.
In this example, the minor NSR permit terms (previously used to
authorize construction of the boiler), the applicable SIP emissions
limits, and the associated MRRT requirements are the only applicable
requirements. The boiler is not subject to any of the NSPS for ``steam
generating units'' (i.e., boilers) because of its size and date of
construction. That is, it is below the size cutoff for the NSPS that
were in effect when it was built (40 CFR part 60, subparts D, Da, and
Db), and it was built prior to the cutoff date for the NSPS that does
cover boilers of its size (subpart Dc). By virtue of its construction
date, size, and fuel, the boiler is classified as an existing large
liquid fuel unit under the MACT standard for Industrial, Commercial,
and Institutional Boilers and Process Heaters (40 CFR part 63, subpart
DDDDD). As such, the only applicable requirement under the MACT
standard is to submit an ``initial notification'' to the permitting
authority, which the source has already done.
When distillate oil is fired, the boiler is subject to limits of 10
percent opacity and 1 percent sulfur in the fuel. No such restrictions
apply when natural gas is being fired. Different SIP emissions limits
also apply to emissions of particulate matter, nitrogen oxides, and
carbon monoxide for each fuel. This existing unit was constructed under
a minor NSR permit, but switching between the fuels will not trigger
minor or major NSR, an NSPS, or the MACT standard because the boiler
was designed to accommodate both fuels, and it has historically been
authorized to use both fuels in its State operating permits. Thus, the
anticipated fuel switches are operational changes that trigger only
different SIP requirements.
The design of the burners in the boiler, coupled with proper
operation and maintenance, is sufficient to meet the SIP limits for
both fuels for particulate matter, nitrogen oxides, and carbon
monoxide, as well as opacity when distillate oil is fired (based on
performance tests). To meet the percent fuel sulfur requirement for
distillate oil firing, the source will purchase fuel at or below 1
percent sulfur. In addition, under the terms of its existing (and still
effective) minor NSR permit, the source will have to provide periodic
analyses of the percent sulfur in the fuel, as well as whenever the
source changes fuel suppliers.
To establish the AOS, the permit would identify and describe the
AOS, in this case combustion of distillate oil, and identify all
applicable requirements which apply when distillate oil is combusted.
The permit must also include terms and conditions that assure
compliance with all applicable requirements (as required under proposed
40 CFR 70.6(a)(9)(iii)), and include a requirement for the source to
keep a contemporaneous log that records the information required by
proposed 40 CFR 70.6(a)(9)(i), including, but not limited to: the
affected emissions unit (i.e., the boiler), a reference to the
applicable requirements applying to the boiler when burning distillate
oil, a reference to the applicable permit terms which assure compliance
with these requirements, and the dates the source began and ceased
combustion of distillate oil. Since the MRRT applicable requirements
detail all the relevant compliance procedures, there is no need for
additional permit information to be contained or cross-referenced into
the log for this purpose.
The title V permit for the source also must require the source to
submit a semi-annual monitoring report. See 40 CFR 70.6(a)(3)(iii)(A).
In this example, once the facility implements the AOS (i.e., begins
combusting distillate fuel oil), the next monitoring report would
identify, for the relevant time periods, the AOS implemented and
provide monitoring information relative to that AOS. The report would
also contain monitoring information for the baseline natural gas
combustion operations, if the source operated both in the baseline mode
and under the AOS during the 6-month reporting period.
Example 2: Future Addition of Volatile Organic Liquid (VOL) Storage
Tanks
A synthetic organic chemical manufacturing facility located in an
ozone attainment area seeks a title V permit renewal and intends to add
VOL storage tanks to an existing tank farm and store various VOLs at
different times in the new and existing tanks over the term of its
renewed permit. The source will have to obtain all necessary advance
approvals in a minor NSR permit for construction of the new tanks. In
addition, the source will apply for AOSs in its title V permit to
address future operating scenarios involving storing different VOLs at
different times in the new tanks and also its existing tanks (since
these scenarios will
[[Page 52225]]
implicate different applicable requirements)
Advance Approvals
In this example, the source applied for advance approvals under NSR
to authorize the construction of up to 10 new VOL storage tanks of up
to 30,000 gallons in capacity. Because the source operates under a VOC
PAL, the new tanks will not trigger major NSR for VOC. In its minor NSR
permit application, the source proposed to the permitting authority
that this emissions cap, by limiting aggregate VOC emissions (including
those from the new tanks), would also satisfy the requirements of minor
NSR related to the protection of the NAAQS and PSD increments.\39\
Although the source does not know precisely the sizes or number of the
new tanks or the materials to be stored in them, it acknowledged in its
minor NSR permit application that the requirements of the NSPS for
Volatile Organic Liquid Storage Vessels (40 CFR part 60, subpart Kb)
would apply to each new tank. In addition, the source stated that it
would use a submerged fill pipe for tanks with capacity of 2,000
gallons or more which is the SIP requirement for such tanks when they
otherwise are not required to be controlled to comply with subpart Kb.
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\39\ Under the provisions of parts 51 and 52, a major NSR PAL
does not inherently affect the applicability of minor NSR. Some
State minor NSR rules may vary on this point, but for purposes of
this example we assume that minor NSR continues to apply beneath the
major NSR PAL.
---------------------------------------------------------------------------
The source did not address any other SIP requirements for VOL
storage tanks in its application because these requirements do not
apply to tanks with capacity below 40,000 gallons, and the source is
not seeking approval for any new tanks over 30,000 gallons in capacity.
In addition, although it is subject to the MACT standard for the
Synthetic Organic Chemical Manufacturing Industry (typically referred
to as the ``Hazardous Organic NESHAP'' or the ``HON,'' 40 CFR part 63,
subpart G), the source did not address the requirements of this
standard in its minor NSR application because the State in which this
example source is located implements MACT standards through its title V
permit program (see below) rather than in the context of its minor NSR
program.\40\
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\40\ The acronym ``NESHAP'' stands for National Emission
Standards for Hazardous Air Pollutants. The NESHAP promulgated in 40
CFR part 63 are typically referred to as MACT standards.
---------------------------------------------------------------------------
The control requirements of subpart Kb vary with the size of the
storage tank and the maximum true vapor pressure of the stored liquid.
An advance approval must describe the changes that the source may
implement, which in this example consist of the reasonably anticipated
combinations of new tank size and stored liquid vapor pressure, along
with the requirements (i.e., subpart Kb and SIP provisions) that would
apply for each. One way to do so would be to use a table such as Table
VI-1 below, which uses metric units to match the metric units used in
subpart Kb. Note that because the source in this example sought advance
approval only for new tanks up to 30,000 gallons (114 cubic meters
(m\3\)) in capacity, the table addresses only tanks up to this size
even though subpart Kb contains provisions specific to larger tanks.
Table VI-1.--Advance Approvals for New Tanks a
----------------------------------------------------------------------------------------------------------------
Stored liquid maximum Emissions limitation
Tank size, V (m\3\) true vapor pressure, VP from 40 CFR part 60, MRRT citations from 40
(kPa) subpart Kb CFR part 60, subpart Kb
----------------------------------------------------------------------------------------------------------------
V < 75............................... Any.................... Not applicable......... Not applicable.
75 < = V < = 114....................... VP < 15.0.............. Not applicable......... Not applicable.
75 < = V < = 114....................... 15.0 < = VP < 27.6...... None................... Sec. Sec. 60.116b(a)-
(e).
Sec. 60.112b(a)(1) Sec. 60.113b(a), Sec.
Fixed roof w/internal 60.115b(a), Sec.
floating roof; or Sec. 60.116b(a)-(c),
(e).
75 < = V < = 114....................... 27.6 < = VP < 76.6...... Sec. 60.112b(a)(2) Sec. 60.113b(b), Sec.
External floating 60.115b(b), Sec.
roof; or Sec. 60.116b(a)-(c),
(e).
Sec. 60.112b(a)(3) Sec. 60.113b(c) or
Closed vent system and (d), Sec. 60.115b(c)
control device >= 95% or (d), Sec. Sec.
efficient. 60.116b(a), (b), (e).
75 < = V < = 114....................... 76.6 < = VP............. Sec. 60.112b(b) Sec. 60.113b(c) or
Closed vent system and (d), Sec. 60.115b(c)
control device >= 95% or (d), Sec. Sec.
efficient. 60.116b(a), (b), (e).
----------------------------------------------------------------------------------------------------------------
\a\ The source is authorized to add up to 10 new tanks, each of which is covered by the scope of Table IV-1. A
permanent submerged fill pipe is required for any of the 10 advance approved tanks with capacity >=7.6 m \3\
that is not controlled with an internal floating roof, external floating roof, or closed vent system and 95%-
efficient control device.
In this example, the permitting authority granted advance approval
in a minor NSR permit for the source to construct tanks meeting each of
the conditions described in Table VI-1. The permitting authority
determined that no further restrictions on the proposed tanks other
than SIP and subpart Kb compliance and the major NSR PAL for VOC
emissions would be necessary in the minor NSR permit, because the
maximum number of proposed new tanks could be accommodated within the
source's VOC PAL (due to pollution prevention (P2) initiatives
undertaken by the source) and would not cause concern with NAAQS or PSD
increment protection or Class I area impacts. In this case, the
permitting authority chose to incorporate Table VI-1 directly into the
minor NSR permit to identify the requirements which apply to the new
tanks, regardless of size, type, and/or number.
Title V Renewal With AOSs
The source's title V renewal application would identify both the
existing emissions units (i.e., the units currently comprising the tank
farm) and the new tanks authorized under the minor NSR permit advance
approval, and would contain any AOSs that the source wants to propose.
The title V application must identify all applicable requirements that
are implicated by each proposed AOS.
The source has opted to make the universe of requirements
potentially applicable to the advance approved new tanks more
manageable by accepting a boundary condition, specifically a maximum
tank volume of 30,000 gallons (114 m \3\). This condition does not
restrict the source's flexibility, since only tanks at or below the
30,000 gallon threshold are anticipated to be constructed, but it does
have the effect
[[Page 52226]]
of precluding the applicability of the NSPS requirements that would
apply to tanks above that size.\41\ The source also has committed to
store only materials with maximum true vapor pressure of less than 15
pounds per square inch (psi) (103 kilopascals (kPa)). This ceiling on
vapor pressure does not affect the applicability of control
requirements, but is necessary for calculating maximum theoretical
emissions from the new tanks and assessing the ability of existing add-
on control devices to accommodate any increased emissions. The existing
tanks are all currently within these boundary conditions. The source
wishes to retain the option to store materials that contain HAPs in all
of the tanks, which could implicate the requirements for storage
vessels in the HON. In this example, the facility was originally
constructed in the late 1980's, so the existing tanks are subject to
the requirements of subpart Kb, and the source is considered an
existing ``affected source'' for purposes of the HON. The applicable
requirements to be listed in the renewal application for the new and
existing tanks include the SIP emissions limitations, the requirements
of subpart Kb, the requirements of the minor NSR permit (which are
identical to the requirements of the SIP and subpart Kb as set out in
the advance approvals in Table VI-1), and the requirements of the HON.
---------------------------------------------------------------------------
\41\ The limit on tank size applies only to the advance approved
tanks. The source retains the ability to construct tanks larger than
30,000 gallons, but would have to go through the normal
preconstruction permitting to construct a larger tank.
---------------------------------------------------------------------------
The source has conducted a streamlining analysis of applicable
requirements related to the emissions limitations for each tank.\42\
The source provided supporting documentation in its permit application
for this streamlining analysis, and the permitting authority reviewed
and approved it. The analysis shows that for new and existing tanks
that are storing materials that do not contain HAPs, compliance with
the requirements of subpart Kb also will satisfy the control
requirements of the SIP. For tanks not storing HAPs, the SIP
requirements are the most stringent applicable requirements only when
subpart Kb does not apply (i.e., when the tank size and/or vapor
pressure are below the respective applicability limits for subpart Kb).
---------------------------------------------------------------------------
\42\ See section VI.A of this preamble and footnote 26 for more
on the streamlining of applicable requirements in a title V permit.
---------------------------------------------------------------------------
For tanks that are storing materials that contain HAPs and are
subject to the HON (i.e., capacity >= 38 m\3\), the HON specifies that
subpart Kb does not apply.\43\ Tanks storing HAPs that are below the
size cutoff for HON applicability are also below the applicability
cutoff for subpart Kb (which is 75 m\3\); thus, at this facility
subpart Kb does not apply to new or existing tanks that store materials
containing HAPs. The streamlining analysis provided by the source and
approved by the permitting authority shows that compliance with the
requirements of the HON will satisfy the control requirements of the
SIP for both the new and existing tanks that store HAP-containing
materials. The SIP requirements are most stringent only for HAP-
containing tanks that are below the size and/or vapor pressure cutoffs
for control under the HON.
---------------------------------------------------------------------------
\43\ The HON applies to specified organic HAPs that are a subset
of the total HAP list. For this example, we use ``HAP'' to refer to
those HAPs covered by the HON.
---------------------------------------------------------------------------
To maintain the flexibility to change the material stored in each
tank (an operational change), the source requested AOSs in its title V
permit. (The source does not expect to modify the volume of any
existing storage tanks, or of any new tanks after they are initially
constructed, and therefore did not request AOSs to address such
physical changes.) Each set of operating conditions that implicates a
different set of applicable requirements would require an AOS. The
necessary AOSs vary depending upon the capacity of a given tank. For
example, no AOSs are needed for a new or existing storage tank that has
a capacity of less than 7.6 m\3\ because no requirements apply
regardless of the characteristic of the material that is stored in the
tank (tanks of this size are below the applicability cut-offs for the
SIP, subpart Kb, and the HON). As a result, a new or existing tank of
this size has only a baseline operating scenario, and no AOSs are
necessary. Similarly, no AOSs are needed for tanks that are between 7.6
m\3\ and 38 m\3\ because only the SIP requirements apply to these tanks
regardless of the liquid that is stored. A tank that is between 38 m\3\
and 75 m\3\ needs a baseline operating scenario and one AOS to enable
switching between storing a material that contains HAP and one that
does not. In both cases, the SIP control requirements apply, but when
HAPs are stored the source must also maintain the records required
under the HON. That is, when HAPs are stored, an additional applicable
requirement is triggered for the tank.
Several operating scenarios are needed for both new and existing
tanks between 75 m\3\ and 114 m\3\. The possible scenarios for these
tanks are outlined in Table VI-2.
Table VI-2.--Authorized Operating Scenarios for New and Existing Storage Tanks With Capacity Between 75 m\3\ and
114 m\3\
----------------------------------------------------------------------------------------------------------------
VP or VPH, as Most stringent
Operating scenario No. Tank size, V Are materials with applicable (kPa) applicable control
(m\3\) HAPs stored? \a\ requirements
----------------------------------------------------------------------------------------------------------------
1............................... 75 < = V < = 114.... No................ VP < 15.0......... SIP.
2............................... 75 < = V < = 114.... No................ 15.0 < = VP < 27.6. SIP.
3............................... 75 < = V < = 114.... No................ 27.6 < = VP < 76.6. NSPS.
4............................... 75 < = V < = 114.... No................ 76.6 < = VP........ NSPS.
5............................... 75 < = V < = 114.... Yes............... VPH < 13.1........ SIP.
6............................... 75 < = V < = 114.... Yes............... 13.1 < = VPH < 76.6 HON.
7............................... 75 < = V < = 114.... Yes............... 76.6 < = VPH....... HON.
----------------------------------------------------------------------------------------------------------------
\a\ The following symbols are used in this column:
VP = stored liquid maximum true vapor pressure.
VPH = stored total HAP maximum true vapor pressure.
As seen in Table VI-2, seven operating scenarios are approved for
new and existing storage tanks in this size range. The source included
this table in its title V permit application, along with the details
about the applicable requirements (including control and MRRT
requirements) for each operating scenario. For each
[[Page 52227]]
existing tank in this size range, the source specified the baseline
operating scenario and designated the others as AOSs. For any new tanks
in this size range, a baseline operating scenario from the scenarios
authorized in Table VI-2 either was identified at the time of minor NSR
permitting (if known), or will be identified at the time of
construction and operation. Table VI-2 is, therefore, a convenient
means to describe efficiently the individual operating scenarios that
are approved with respect to the new and existing tanks at the source.
The title V permit containing the approved streamlined limits must
also identify the subsumed applicable requirements. The permit also
must contain terms requiring the source to keep an on-site log
recording the use of authorized AOSs. The log entries would include,
upon shifting to or from the storage of HAP materials or materials of
different vapor pressure which implicate different requirements, the
following: the size of the tank involved (new or existing); the maximum
true vapor pressure of the stored material (if no HAPs are stored) or
the total HAP maximum true vapor pressure (if the stored material
contains HAPs); the control option employed; the applicable
requirements that apply (including emissions limitations and MRRT
requirements); and the date that the relevant storage commenced.
After an existing tank's initial shift from its baseline scenario,
the on-site log would identify at all times which AOS was in effect for
that tank. For a new tank, the on-site log would be used to record the
initial baseline operating scenario and any AOSs into which the tank
subsequently shifted. For example, if the source switched from storing
a HAP-containing material to material with no HAPs, the source would
enter that switch into the on-site log, giving the date of the switch,
identifying the new AOS, and providing information about which
applicable requirements (permit terms and conditions) were implicated
for that AOS.
E. What is the process for adding or revising advance approvals, AOSs,
and ARMs in issued permits?
An advance approval, AOS, or ARM may be added to a title V permit
through permit issuance or renewal or through the permit modification
process. When an existing permit is to be modified, the appropriate
modification track (significant or minor) depends on the nature of the
proposed advance approval, AOS, or ARM or the proposed revisions to
them and whether it would qualify as a minor permit modification. See
40 CFR 70.7(e)(2)(i). Note also that the permit shield, where
available, can be extended to advance approvals, AOSs, and ARMs added
through a significant permit modification, but not to those added
through minor permit modification procedures (per existing 40 CFR
70.7(e)(2)(vi)). See section VI.C.3 above for more on AOSs and ARMs and
the permit shield.
F. How do the proposed AOS provisions differ between parts 70 and 71?
Part 70 contains only the requirements for State operating permit
programs and is not divided into subparts. Part 71 contains two
subparts. Subpart A of part 71 contains the general Federal operating
permit program, while subpart B contains provisions for a limited,
Federal title V permit program to establish alternative emissions
limitations for early reductions sources that have demonstrated
qualifying reductions of HAP under section 112(i)(5) of the Act. Thus,
subpart A of part 71 is analogous to the entire part 70.
A general difference between the part 71 and part 70 operating
permit programs is the identity of the permitting authority. Under part
70, non-Federal agencies are the permitting authorities. A part 71
permit may be issued by EPA, where there is not an approved State
program or where a State has failed to revise a permit in response to
an objection from the Administrator, or it may be issued by a
permitting authority that has been delegated authority to issue part 71
permits on behalf of EPA. Currently, part 71 permits are generally
issued for sources operating in Indian country.
For the most part, the proposed revisions to the part 71 operating
permit program mirror exactly the proposed revisions to part 70. That
is, the proposed language is identical, and the sections of the rule
that would be revised differ only by being in part 71 instead of part
70. For example, we are proposing the same language on AOS permit
content in 40 CFR 70.6(a)(9) and 71.6(a)(9). However, there is one
place where the structure of the part 71 operating permit program does
not parallel that of part 70, and therefore the revisions proposed are
different.
Specifically, 40 CFR 70.4(d)(3)(xi) is one of the places in part 70
that we have proposed to substitute the term ``AOSs'' for purposes of
consistent terminology. There is no analogous section in part 71, so we
are not proposing an analogous revision.
We solicit comment on these topics and all aspects of this proposal
regarding part 70. We also note that if a commenter believes that
additional or different regulatory revisions are needed, they should
identify the specific revisions and the basis for these revisions.
VII. What changes are we proposing in parts 51 and 52?
We propose to modify the major NSR regulations in a limited way.
Specifically, we propose to allow a number of emission activities to be
treated as a single emissions unit (i.e., a ``Green Group''). Emissions
from each of these activities would be routed to a common emission
control device meeting BACT/LAER, and future emissions and changes
within the Green Group would be approved over a 10-year period in a
major NSR permit. In addition, we are proposing that Green Groups not
be subject to the provisions of 40 CFR 52.21(j)(4) and 51.166(j)(4)
requiring reevaluation of BACT for phased construction projects or of
40 CFR 52.21(r)(2) requiring continuous construction to commence within
18 months. These provisions would remain in effect for permits issued
to emissions units other than Green Groups. We are proposing these
changes because we believe the anticipated benefits of permitting Green
Groups, similar to those studied in pilot projects and discussed in
section IV.A, warrant allowing the sources more time to construct
before the permit expires.
The approach we are proposing represents an extension of our
December 2002 NSR Improvement regulations and reflects strategies that
we believe ensure environmental protection while providing additional
operational flexibility to sources. In particular, we intend Green
Groups to complement the use of plantwide emissions caps (e.g., PALs)
by providing a flexible permitting option for a section of a plant.\44\
Like PALs, we propose that Green Groups would be a mandatory minimum
element of a State NSR program under which the permitting authorities
retain discretion as to when to approve individual Green Groups
requested by
[[Page 52228]]
sources.\45\ We also take comment on whether instead the Green Groups
should be a voluntary rather than a mandatory program element for
States.
---------------------------------------------------------------------------
\44\ The companies in two of our pilots conveyed a clear desire
to pursue an approach similar to the Green Group options described
in this proposal. One of these facilities is a synthetic minor
source of VOC emissions for purposes of PSD applicability, and is
therefore not subject to major NSR. The source did, however, agree
to meet a best technology requirement under the State's minor NSR
program in order to authorize a range of changes with VOC emissions
conveyed to a highly efficient carbon adsorption system. The second
facility went through major NSR to obtain authorization for a wide
spectrum of related changes anticipated to occur in a complex of
buildings all ducted to a common state-of-the-art control
technology.
\45\ The major NSR rules refer to the ``reviewing authority,''
while part 70 refers to the ``permitting authority.'' For purposes
of consistency with the other sections of this preamble, we use the
term ``permitting authority'' in this section. In these discussions,
this term is intended to have the same meaning as ``reviewing
authority.''
---------------------------------------------------------------------------
Sources that need to alter their operations rapidly in response to
market pressures (including expanding production) and that have
controlled portions of their plants to BACT/LAER (either voluntarily or
as part of their efforts to meet applicable MACT or other requirements)
are good candidates for the Green Group provisions. Such well-
controlled sources may have limited growth potential under a PAL,
especially compared to sources with less well-controlled baseline
emissions. Other candidates for Green Groups are sources in which only
a portion of the facility accounts for all or nearly all anticipated
changes or large, complex plants with many diverse operations producing
a variety of products. This option for Green Groups would help provide
effective alternatives for the diverse universe of sources potentially
subject to major NSR.
The Green Group provisions proposed encourage a wide spectrum of
sources to construct specified types of changes for a 10-year period
with greater certainty and flexibility in exchange for implementing
BACT/LAER, regardless of whether or to what extent the source may have
been subject to the current major NSR regulations. That is, the Green
Group provisions, if finalized, would provide an alternative means to
comply with major NSR and not require an evaluation of whether major
NSR would otherwise apply. For example, a source might propose a Green
Group that would result in a net decrease in actual emissions (i.e.,
application of controls to meet BACT/LAER, as applicable, reduces
actual emissions by an amount greater than the increased emissions
associated with the changes authorized for the Green Group). Under
these circumstances, the source voluntarily subjects to major NSR the
changes and existing operations included within the Green Group,
presumably to obtain greater flexibility and certainty in return for
implementing a BACT/LAER level of control.
A. What are the benefits of Green Groups?
For several reasons, we believe that the environment and the public
will benefit from Green Groups. First, we believe that substantial
environmental benefits will occur, because a Green Group requires all
included emissions activities to be controlled to the level of BACT or
LAER. The BACT or LAER would apply to existing emissions activities
(which otherwise would remain uncontrolled or be subject to less
stringent control requirements), as well as to emissions activities
that are modified or added pursuant to the Green Group authorization.
In the absence of a Green Group, existing emissions activities would
not be subject to BACT or LAER controls until such time as they were
modified. Such modifications might not ever occur, or might occur far
into the future. Even where a modification did occur, evaluated alone,
many modifications would likely not be subject to major NSR. Some new
emissions activities might also not be subject to major NSR because
their emissions are below applicability thresholds or because they
``net out'' of review. For example, a VOC source might make one or more
unrelated modifications, each of which are less than significant (i.e.,
would result in increases in VOC emissions of 39 tpy or less). These
modifications would ordinarily not be covered by NSR; however, when
grouped together as a Green Group, they would undergo NSR and be
subject to BACT/LAER.
Even when individual changes are proved to be subject to major NSR,
the resulting BACT may in some cases be less stringent than that
required for a Green Group. Considering the entire Green Group,
including all the authorized future changes, in a single major NSR
action will drive a BACT analysis toward the maximum level of control
due to the economies of scale that occur in calculating the cost
effectiveness of controls. We believe these environmental benefits will
more than offset the possibility that a future BACT or LAER
determination for new approved expansion might be marginally more
stringent than the BACT/LAER determination at the time of the Green
Group designation.
Moreover, we expect benefits to occur from the better and more
frequent type and amount of monitoring that will be required for Green
Groups. Currently, for a typical emissions unit subject to major NSR,
the permitting authorities decide on a case-by-case basis the types of
MRRT appropriate for the permitted emissions activities, consistent
with the underlying applicable NSR requirements. We are proposing that
a Green Group be subject to MRRT requirements that are patterned on the
existing requirements for PALs. In addition, there are proposed
safeguards to ensure that the air pollution control device continues to
function as intended throughout the Green Group designation period.
These proposed requirements will significantly improve the monitoring
data available to the source, the permitting authority, and the public,
and thus, will better ensure ongoing compliance.
Green Groups will also promote greater administrative efficiency
for permitting authorities and sources, because once a group of
activities qualifies, it will have increased flexibility to make
approved changes rapidly in response to market demands without needing
to undergo additional preconstruction permitting review. In addition,
permitting authorities benefit from increased administrative
efficiency, because the Green Group eliminates iterations of permitting
processes that produce little or no environmental benefit.
B. What is a Green Group?
1. Defining the Scope of a Green Group
This notice proposes to define a Green Group as one emissions unit
that is composed of designated emissions activities ducted to one
common air pollution control device \46,\ \47,\ \48\ that is determined
for this group to meet BACT or LAER, as applicable. A Green Group is a
framework established under major NSR for the advance approval of
anticipated changes within the group. These changes can occur over a
10-year phase, as described in the permit. Separate Green Groups must
be established for emissions activities that are ducted to separate air
pollution control devices.
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\46\ The source may maintain a back-up control device; however,
all emissions from the Green Group must be directed to a dedicated,
common pollution control device.
\47\ Emissions activities are the component equipment that makes
up the Green Group. For example, a Green Group could include
multiple coating lines, and each individual coating line could be
considered an emissions activity within the Green Group. Note that
some or even several of these might be individually regulated under
one or more other applicable requirements but are combined into one
emissions unit for purposes of NSR.
\48\ In order to qualify for the Green Group designation, all of
the emissions activities that are identified as part of the Green
Group must be conveyed to a common air pollution control device to
meet the BACT or LAER limit, as appropriate, depending on whether
the area is designated attainment or non-attainment for the
pollutant of concern. Although this Green Group proposal requires
that the emissions from the Green Group be ducted to a common air
pollution control device, consistent with existing EPA policy, the
source can use other control measures in addition to the common
control device to meet BACT or LAER. Such additional measures can
include P2, work practices, or operational standards.
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[[Page 52229]]
In addition to current, designated emissions activities, a Green
Group may include future changes (e.g., reconfiguration and/or
expansion) to these existing activities and/or the addition of new
emissions activities. Either of these activities could result in an
increase in emissions, if the permitting authority considers and
authorizes such future changes as part of the NSR permitting process.
We are proposing that the NSR permit must sufficiently describe the
future new and existing emissions activities that comprise a Green
Group and include terms and conditions for them, such as annual and
short-term emissions limits. These terms and conditions assure that the
Green Group activities will be properly operated to protect air quality
as well as to meet BACT/LAER, as applicable.
In its permit application, the source must describe the new and
existing emissions activities to be included in a Green Group in
sufficient detail to allow the permitting authority to determine BACT
or LAER (as applicable) for the Green Group taken as a whole and to
conduct an ambient air impact analysis to safeguard relevant ambient
increments and standards (including the determination of any offsets
necessary in non-attainment areas) or any relevant Class I areas. The
application, therefore, must provide information about the current
existing emissions activities and the types of changes to be
implemented, including specifics on emissions characteristics and the
maximum total amount of emissions that will be generated by the Green
Group's emissions activities after fully implementing the changes. If
the source is unable to sufficiently describe the new and existing
emissions activities that comprise the Green Group and the associated
emissions, the permitting authority will not be able to issue a major
NSR permit with a Green Group designation.
The information needed to describe the type of changes authorized
is expected to vary on a case-specific basis and will depend on the
type of control approach approved for BACT/LAER and the emissions
characteristics of the included emissions activities and of the changes
which are permitted to occur to them. That is, certain control devices
like carbon absorbers and scrubbers may exhibit varying effectiveness
in the removal of different substances. As a result, authorized changes
subject to a BACT/LAER determination requiring such a control device
would be constrained to exclude emissions of substances that cannot be
controlled sufficiently by the device. Moreover, the amount of detail
needed to describe the future changes may increase where BACT is
determined to be less than the most stringent technology for the
proposed construction project(s). Similarly, the scope of authorized
changes must be limited to ensure that they are compatible with the
relevant monitoring, recordkeeping, and testing provisions of the
permit. In addition, there may need to be restrictions on how the
changes occur to ensure the effectiveness of the approved control
device. For example, in certain situations, increased productive
capacity may need to be permitted to occur in a manner which would not
overload the control device for the Green Group.
The type of detail required in a permit to describe the authorized
changes in the Green Group must also be sufficient under the proposed
approach to allow the permitting authority to determine, when a change
subsequently is implemented, whether the permitting authority
contemplated that change in the scope of the advance approval contained
in the major NSR permit. As a minimum, we expect that changes be
described relative to the existing operations comprising the Green
Group. That is, the permit must contain a detailed snapshot of the
existing emissions activities included in the Green Group, and any
approved changes would then be described as categories of changes to
these baseline activities that maintain their fundamental integrity.
Such changes might include: (1) Changes in products; (2) changes in raw
materials; (3) reconstruction and/or replacement of existing process
equipment; (4) increased capacity (either as changes to existing
equipment or as new equipment); and (5) additions of new production
lines and/or new support units.
When products or raw materials will be changed, the description
should specify what the range of new products or raw materials might be
and their compatibility to the existing emissions controls. When
equipment will be added, reconstructed, or replaced, the permit should
specify whether capacity might be changed and to what extent. Depending
on its potential relevance to the BACT/LAER determination, the
description might specify the maximum size and/or capacity of any
changed or new equipment. In some situations, it might be necessary to
describe the different types of authorized changes more specifically.
This proposed approach for describing authorized future changes is
consistent with the approaches taken in our evaluated flexible permit
pilots and with our previously mentioned recommendations for describing
AOSs in a title V permit.\49\ Provided that all of the emissions
activities identified as part of the proposed Green Group are vented
through a common control device and approved through the major NSR
permitting process, the source would be authorized (for purpose of
major NSR) to implement over a 10-year period the changes that are
advance approved in the permit without triggering further NSR review.
For physical and operational changes a source undertakes that are not
included in a Green Group, the applicability of NSR to those changes
would be determined as these changes occur, in accordance with existing
major and minor NSR procedures.
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\49\ Note that additional detail to describe the new and
existing activities of a Green Group may be necessary for title V
purposes. For example, more detail would be necessary to identify
those emissions activities included in the Green Group that are also
subject to other applicable requirements (e.g., MACT or NSPS).
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An emissions activity cannot be included in a Green Group some of
the time and excluded at other times. Stakeholders suggested allowing
such ``intermittently-included'' activities during pilot project
discussions to address emissions activities that are subject to
different applicable requirements depending on their operations. For
example, a web-coating operation might be subject to the Pressure
Sensitive Tape and Labels NSPS (40 CFR part 60, subpart RR) when
manufacturing certain products, and not subject to any applicable
requirement or emissions limitation when manufacturing other products.
Some stakeholders suggested that such a coating operation could be
included in the Green Group (and subject to the Green Group control
approach) when subject to the NSPS, but excluded (and not subject to
control) when its operations are not subject to the NSPS. We rejected
this approach because of the increased complexity and the significant
additional recordkeeping burden. Accordingly, after undergoing major
NSR as part of the Green Group, the emissions activity remains subject
to the requirements of the major NSR permit, including the BACT or LAER
emissions reduction requirements, regardless of changes in the
applicability of any other requirement.
If a source removes a particular emissions activity from an
established Green Group at any time during its 10-year duration, the
removed emissions activity will be subject to major NSR. For example,
suppose that a Green Group consists of four emissions
[[Page 52230]]
activities and that the source proposes to withdraw activity No. 4 from
the Green Group after its establishment. In order to do so, the
permitting authority would subject activity No. 4 to major NSR as if it
were a new major modification (i.e., contemporaneous BACT/LAER, as
applicable, and ambient reviews). Simultaneously, the permitting
authority (in the same major NSR action) would adjust downward the
emissions limit of the Green Group (see discussion below) to account
for the amount of emissions previously attributed to activity No. 4
(i.e., its baseline actual emissions and any emissions growth targeted
to occur at activity No. 4). In addition, the permitting authority
would verify that the original BACT/LAER limit could be met as it would
now be applicable to the remaining emissions activities.
2. Emissions Limits for Green Groups
In general, two types of emissions limits must be set in the major
NSR permit for Green Groups: (1) An emissions limit to constrain
overall emissions for the Green Group; and (2) a limit to ensure that
BACT/LAER technology is being employed and is effective (e.g., lbs/gal,
percent reduction). These two limits complement each other and
collectively implement the core provisions of the Green Group. The
amount of any emissions increase from authorized changes would be
limited by the annual emissions cap and the BACT/LAER emissions
limitation, both of which would be placed in the major NSR permit.
An enforceable mass emissions limit must be determined for the
pollutant for which the Green Group is established. We propose that the
total emissions from the Green Group be limited by the annual emissions
limit (on a 12 month total, rolled monthly basis) for the Green Group
pollutant. The annual emissions limit would be set at the actual
emissions associated with all the emissions activities included in the
Green Group and controlled to the BACT/LAER level, as applicable. The
annual emissions limit would also include any emissions increases that
result from changes to existing emissions activities and/or changes to
add new emissions activities that are authorized by the permit. The
annual limits and any necessary short-term limits \50\ for a Green
Group must be set at a level demonstrated to safeguard applicable
ambient standards and increments (i.e., NAAQS and PSD increments).
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\50\ The NAAQS and increments for some pollutants are
established over short-term periods as well as annually. For
example, annual, daily, and 3-hour NAAQS and increments are defined
for sulfur dioxide. Accordingly, some NSR permits include emissions
limits for these shorter periods.
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We propose that the annual emissions limit for a Green Group be
developed in two steps. The first step is to calculate the group's
baseline for actual emissions using the same methodology that is used
in setting a PAL under the existing major NSR regulations. This
baseline would therefore equal the baseline actual emissions (as
defined in the major NSR regulations) for all the emissions activities
in the group that existed during a 24-month period selected by the
source within the 10 years preceding the Green Group permit
application, minus the emissions of any of these existing activities
that have been shut down since the 24-month period, plus the PTE of any
emissions activities added within the group since the 24-month period.
Baseline actual emissions must be adjusted downward for any non-
compliant emissions during the 24-month period and for any emissions
limitations that have become applicable since the end of the 24-month
period. That is, a downward adjustment is necessary if any legally
enforceable emissions limitation restricts an emissions activity's
ability to emit the Green Group pollutant or to operate at levels that
existed during the selected 24-month period. See the December 2002
preamble discussion of baseline actual emissions at 67 FR 80195. (Note
that the definition of ``baseline actual emissions'' differs somewhat
for electric utility steam generating units (EUSGUs) and other types of
emissions activities. The preceding discussion applies to non-EUSGUs.)
In addition, these baseline actual emissions must be adjusted downward
as necessary to reflect application of the BACT/LAER to the Green
Group.
The second step in setting the annual emissions limit for a Green
Group is to calculate the emissions increase from any new emissions
activities or planned changes to existing activities that are approved
as part of the permit (i.e., an emissions increase increment to address
the planned changes over a 10-year period.) This would be added to the
baseline actual emissions level determined in the first step. Thus, the
total Green Group annual emissions limit should reflect the actual
emissions associated with all new and existing emissions activities
included in the Green Group, all of which are controlled to the BACT/
LAER level, as applicable.
In an attainment area, in reviewing the application, the permitting
authority should weigh such factors as the available PSD increment(s)
in the area in determining whether to approve the annual limit proposed
by the source for the Green Group. In a nonattainment area, the
authorized emissions increase must be offset at the ratio prescribed by
the Act or the applicable State, Tribal, or Federal implementation
plan.
To the extent that they can be quantified, fugitive emissions also
must be addressed for Green Groups as required under the Act and by EPA
according to applicable major NSR regulations and requirements and
guidance. This includes determining fugitive emissions from all
existing emissions activities in the Green Group, as well as all
increases in fugitives and maximum total fugitive emissions that will
be generated in the future by the emissions activities in the Green
Group. Such treatment of fugitive emissions is intended to be the same
approach as that currently required for PALs.
An emissions limit or performance specification separate from the
Green Group emissions limit determined above also must be set to
reflect the application of BACT or LAER, as applicable. The format for
these limits can vary (e.g., pounds of emissions per material input or
per product output; or a percent removal efficiency) but are typically
different from the tpy format of the limit applying to total annual
emissions. In some cases, separate, additional BACT/LAER limits may be
necessary to govern low concentration situations (e.g., the source
would be required to meet either 98 percent removal efficiency or a 20
parts per million (ppm) outlet concentration) and to address startup,
shutdown, and malfunction situations.
We also propose that a Green Group may meet the applicable BACT or
LAER level of control through use of P2 alternatives for component
emissions activities during some periods of operation instead of always
sending all emissions to the common air pollution control device. Each
of the P2 alternatives must independently qualify as achieving a BACT
or LAER level of control in the major NSR permitting process. For
example, an emissions activity such as a paint spray booth operation
would be ducted to a common air pollution control device such as a
thermal oxidizer to control VOCs from multiple emissions activities in
a Green Group. As a P2 alternative, BACT or LAER might be established
based on the use of compliant materials \51\ in the
[[Page 52231]]
spray booth operation. In this case, we propose that each of the
included emissions activities must have ductwork extending to the
common air pollution control device, but the source would be allowed to
bypass the control device during periods when the source elects to use
P2 consistent with the BACT or LAER determination on compliant
materials. Notwithstanding, at all times, all activities included in
the Green Group would be meeting a BACT (or LAER as applicable) level
of control.
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\51\ For surface coating operations, ``compliant materials''
means coatings and solvents that are formulated to meet emissions
limits without need of add-on controls. For example, coatings may be
formulated with high solids content and low VOC content.
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We believe that providing for a P2 alternative will encourage P2 at
sources that wish to obtain a Green Group designation and provide an
opportunity for sources that are pursuing P2 to adopt a Green Group.
Accordingly, we are soliciting comment on whether such an option is
appropriate and should be included in the Green Group program. We
further request comment on whether this proposal goes far enough in
encouraging P2. In particular, we take comment on whether we should
allow a Green Group to be based on use of a P2 approach, rather than a
common air pollution control device.
For the emissions activities that comprise the Green Group, we are
not proposing to require that each emissions activity that is part of
the Green Group designation be limited to a specific tons-per-year
allocation. Instead, we propose that the annual aggregate limit is
acceptable for the emissions activities that comprise the Green Group.
For example, if each of the five emissions activities that are part of
a Green Group contributes 50 tpy to the total annual aggregate limit of
250 tpy, we are proposing that the Green Group be subject only to a
limit of 250 tpy for these emissions activities. A permitting
authority, therefore, should not require a 50 tpy limit on each of the
five emissions activities.\52\ This is because for PSD purposes, the
source must determine BACT based upon the total amount of annual
emissions, and the air quality impacts associated with such emissions
(which all are emitted from the stack of the common air pollution
control device) are accounted for in the NSR permitting process.
Comparable reasoning applies for nonattainment major NSR purposes. We
solicit comment on whether this approach is appropriate or whether
there are other considerations we should take into account.
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\52\ In some cases, a source may have previously taken an
emissions limit on a new or modified emissions unit to remain below
major NSR applicability thresholds (often referred to as an ``(r)(4)
limit'' based on Sec. 52.21(r)(4)). Once the unit is included with
a Green Group, it has gone through major NSR, and the (r)(4) limit
will no longer apply.
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Changes in emissions at ancillary units not included in the Green
Group but serving it (such as storage tanks or utilities) must be
accounted for in the air quality analysis conducted to evaluate ambient
air quality and increment protection to the extent such emissions
changes are required to be considered under the existing NSR
regulations.\53\ Ultimately, the permitting authority must determine
the extent to which the requested expansion will be allowed under major
NSR, taking into account the demonstrated need of the source, public
comments received, and the air quality status of the affected area.
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\53\ The EPA has issued a Notice of Proposed Rulemaking that
addresses, in part, the issues of ``debottlenecking'' and
``increased utilization.'' See 71 FR 54235, September 14, 2006. In
this rulemaking on flexible air permits, we do not intend to change
current requirements related to ``debottlenecking'' or ``increased
utilization,'' but we will follow, as applicable, any final rule
changes occurring as a result of the September 2006 proposal.
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In some cases, a source may have previously taken an emissions
limit on a new or modified emissions unit to remain below major NSR
applicability thresholds (often referred to as an ``(r)(4) limit''
based on 40 CFR 52.21(r)(4)).\54\ The major NSR rules provide that if
(r)(4) limits are relaxed, the associated emissions unit must undergo
major NSR review ``as though construction had not yet commenced on the
source or modification.'' We propose to clarify, without rule revision,
the interface between (r)(4) limits and Green Groups as follows: When a
unit with an (r)(4) limit is included as one of the emissions
activities in an application for a Green Group, the (r)(4) limit no
longer applies, provided that the NSR review process considers the unit
as if construction had not yet commenced on it.\55\ Moreover, any
(r)(4) limit would no longer apply even after the expiration of any
Green Group.
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\54\ Parallel requirements are found at 40 CFR 51.165(a)(5)(ii)
and 51.166(r)(2).
\55\ The baseline actual emissions for a unit with an (r)(4)
limit are calculated just as for any other emissions activity
included in a Green Group, complete with the reduction for the
effect of the required BACT/LAER control. However, such units may be
among the emissions activities with authorized future physical or
operational changes, and emissions from such units could
subsequently increase (as part of the authorized emissions increase
increment), but under BACT/LAER controls.
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Under the current NSR regulations, an emissions change is only
creditable to the extent the Administrator has not previously relied on
it in issuing a major NSR permit. See 40 CFR 52.21(b)(3)(i).
Accordingly, emissions increases and decreases that occur at the
emissions activities in a Green Group during the effective period of
the Green Group designation are not included in netting calculations to
determine whether changes that occur at the emissions units outside the
Green Group result in a major modification. However, if the source
reduces actual emissions from the Green Group below the emissions limit
established for the Green Group in its NSR permit, the source may
generate a credit for the difference between the permitted limit that
qualified the unit as a Green Group and any new, lower emissions
limitation established, if such reductions are surplus, quantifiable,
permanent, and enforceable from a practical standpoint.\56\ If however,
an established Green Group wishes to increase its emissions beyond its
permitted tpy limit, reductions achieved by units outside the Green
Group cannot be used to generate emissions reductions to net the Green
Group out of NSR. If an established Green Group wishes to increase its
emissions, it must go through NSR again to establish a new limit, which
would be effective for a new 10-year timeframe. In addition, we also
propose to add a restriction that no credit can be generated from
eliminating emissions increases that were authorized under the Green
Group permit but never realized. Without this restriction, sources
would be allowed to generate credits for authorized expansion that
never occurred.
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\56\ Such credits in order to be used as an emissions offset
must also be federally enforceable.
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In nonattainment areas, sources are required to obtain offsetting
emissions reductions for the significant emissions increases that are
authorized under a major NSR permit. Depending on the nonattainment
pollutant and classification of the nonattainment area, the source may
be required to obtain offsets in excess of the emissions increase at a
specified ratio. For example, in accordance with the existing NSR
requirements, in a serious ozone nonattainment area, a source must
obtain VOC offsets in an amount 1.2 times the significant VOC emissions
increase. A source that applies for a Green Group designation in a
nonattainment area must obtain offsets for the approved increase in
emissions of the Green Group pollutant (i.e., the difference between
the level approved in the Green Group permit and the baseline actual
emissions of the group). Under existing NSR requirements, offsets must
be federally enforceable at the time the major NSR permit designating
the Green Group is issued, in accordance with section 173(a) of the
CAA, but need not be achieved until the
[[Page 52232]]
new or modified source commences operation, consistent with section
173(c) of the CAA. We propose that for Green Groups, the offsets must
be in effect by the time the first authorized change among the
activities in the Green Group (e.g., equipment modification or
addition) commences operation. To simplify the process and
recordkeeping, and to assure that offsets are in place as required, we
propose that the entire amount of offsets required by the permit must
be in effect at the time that the first authorized change (e.g.,
modified or added emissions activity) begins operation. Alternatively,
we seek comment on whether it is only necessary to require the source
to obtain offsetting emissions reductions in sufficient quantity to
offset: (1) The actual changes within the Green Group as they occur; or
(2) each phase of construction before its operation.
In some cases, a source with an established Green Group may
subsequently request the permitting authority to allow the addition of
greater emissions than are permitted by the existing annual emissions
limit. Here, we propose that the permitting authority be able to
either: (1) Establish a higher annual emissions limit to accommodate
the desired new emissions increase as part of a comprehensive major NSR
process (this process would reestablish the Green Group, including a
reevaluation of the prior BACT/LAER determination); or (2) terminate
the Green Group while retaining its emissions limits and other
requirements and then subject the emissions of new project(s) to the
applicable NSR process. Similarly, if a source with a Green Group
exceeds its Green Group emissions limit, then the source will be
subject to appropriate enforcement action. In addition, the source
would be subject to enforcement action for any violations of other
applicable requirements (e.g., MACT, NSPS) that would also apply to
emissions activities included in the Green Group.
3. Monitoring, Recordkeeping, Reporting, and Testing (MRRT)
Requirements for Green Groups
As mentioned, the major NSR review process must also determine the
level of MRRT to assure compliance with both the control technology
requirement and the emissions limit(s). A source must monitor all
emissions activities that comprise the Green Group to ensure compliance
with the Green Group limit. These monitoring, recordkeeping, and
reporting requirements are incorporated into the NSR permit that
establishes the Green Group.
As explained above, in December 2002, we promulgated revisions to
the major NSR program, which included, among other things, MRRT
requirements for tracking emissions associated with a PAL.\57\ In these
proposed regulations, the same MRRT we promulgated in December 2002 for
PALs would also be required to track a source's compliance with the
Green Group emissions limit set forth in the major NSR permit. Further,
we are proposing additional MRRT provisions to assure that the common
air pollution control device achieves BACT or LAER. More specifically,
the permit must require the owner or operator to monitor and record
data sufficient to ensure that the common control device for the Green
Group accommodates emissions resulting from the emissions activities
that comprise the Green Group and that it achieves the level of
emissions reduction required under the applicable BACT or LAER
requirement.\58\
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\57\ See 67 FR 80221 for a discussion of the MRRT requirements
promulgated for PALs by the Agency in December of 2002.
\58\ Note that BACT/LAER requirements in terms of percent
reduction can be difficult or impossible to achieve during periods
of low or dilute flow. Where a percent reduction requirement is
imposed, we recommend that the BACT/LAER determination include an
alternative concentration standard for such periods. For example,
BACT/LAER for VOC control might be 98 percent reduction or an outlet
concentration of 20 ppm by volume on a dry basis.
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We are not proposing to require a source to notice individual
changes at Green Groups. However, changes which are also subject to a
MACT standard or NSPS may well be required to file a notice under the
General Provisions requirements of those programs. State permitting
authorities may under other regulatory authorities require additional
records and notices for certain changes (e.g., notices for new units
under State air toxics program, or a notice for a new emissions unit
added to the site of a source with a title V permit under an approved
off permit procedure) to assure compliance under these other
authorities. In addition, we propose that the source submit a semi-
annual report that, in part, contains a list of any emissions
activities included in the Green Group that were added during the
preceding 6-month period. We encourage permitting authorities to
combine this report with the 6-month monitoring report otherwise
required under part 70 (see 40 CFR 70.6(a)(3)(iii)(A)). We request
comment on this approach to recordkeeping, reporting, and notification
requirements. In particular, we solicit comment on the appropriateness
of applying the mentioned 2002 PAL monitoring requirements to Green
Group emissions limits.
4. Public Participation for Green Group Designations
Because Green Groups must be established in a major NSR permitting
action, the public is assured of an opportunity to participate in the
process. Major NSR regulations require the permitting authority to
notify the public when it makes a preliminary determination regarding a
permit application, to make the application and associated materials
available for public inspection, and to provide an opportunity for a
public hearing and for a written comment period of not less than 30
days.\59\ In the case of a proposed Green Group permit, the annual
emissions limit that would be established for the Green Group
highlights the maximum possible annual emissions increase for public
review. The other aspects of the proposed Green Group also would be
highlighted for comment, including the preliminary BACT/LAER
determination, description of anticipated expansion, and the proposed
requirements for monitoring, recordkeeping, and reporting.
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\59\ See 40 CFR part 124 for permits issued under Sec. 52.21.
See Sec. 51.161 for permits issued under State programs approved
pursuant to Sec. Sec. 51.165 and 51.166.
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In addition to the opportunity for public participation typically
provided consistent with our major NSR regulations, we recommend that
the permitting authority consider using its discretion to enhance the
public participation process as necessary to provide adequate review
opportunity for individual Green Group permits. We expect that this may
be advisable when the first Green Groups in an area are being
established or when unique and/or complex issues arise in a particular
case. See section IV.C above for additional discussion on the types of
enhanced public participation and when it might be appropriate.
5. Duration and Renewal of the Green Group Designations
We propose that the Green Group designation last for a single 10-
year period. Any emissions activities that are advance approved and
constructed during the effective period of the Green Group designation
benefit from Green Group flexibility. At the end of the 10-year period,
the original Green Group designation ends.
After 10 years, the source may apply for a new Green Group
designation by going through the same procedures as for the initial
Green Group designation,
[[Page 52233]]
including going through a new major NSR permitting exercise and a new
BACT/LAER determination. To avoid a gap between the expiration of the
initial Green Group designation and the effective date of a new
designation, we propose a renewal process similar to the process for
PALs. Specifically, a source that wishes to reestablish its Green Group
must submit a major NSR application to the permitting authority at
least 6 months prior to, but not earlier than 18 months from, the
expiration date of the Green Group. If the source submits a complete
application within this period, the existing Green Group requirements
would continue to be effective until the new major NSR permit
reestablishing the Green Group is issued.\60\ We take comment on the
need to require an earlier submittal time (i.e., earlier than 6 months
prior to expiration) given that a BACT/LAER reevaluation is involved.
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\60\ In order to streamline the process to update as necessary
the corresponding title V permit, the permitting authority might:
(1) Structure the permit to retain the initial BACT limit and
support conditions unless affirmatively revised; and (2) revise the
title V permit in parallel to revising the NSR permit or use an
``enhanced NSR'' process to do so in order to optimize use of
comment periods and opportunities for public hearings.
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If the applicant does not wish to reestablish the Green Group
designation, the source would simply allow the designation to expire
and then become subject to the major NSR applicability test for future
changes.\61\ However, the major NSR permit does not expire, and the
emissions unit defined by the Green Group would remain permanently an
emissions unit for purposes of major NSR, subject to the BACT or LAER
control requirement, annual emissions limit (and any shorter-term
limits), and MRRT requirements imposed by the Green Group permit. We
take comment whether to allow the source to divide up the Green Group
into smaller emissions units and to allocate the emissions limit
correspondingly.
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\61\ We expect that in most cases this will be the actual-to-
projected-actual applicability test adopted in the December 2002 NSR
Improvement rulemaking. The actual-to-projected-actual test is
currently in effect in all jurisdictions where Sec. 52.21 applies,
including in States and Indian country. For nonattainment major NSR
and SIP-approved PSD programs, States are currently in the process
of revising their SIPs to incorporate the actual-to-projected-actual
test (or some other preferred approach if they can demonstrate that
it is at least as stringent as the actual-to-projected-actual test).
Thus, the actual-to-projected-actual test (or an approved
alternative approach) should be in effect in all jurisdictions by
the time that Green Groups begin to expire.
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We are proposing the 10-year duration of a Green Group designation
for two reasons. First, we believe that this time frame represents a
balance between the useful life of the emissions control system and the
time frame in which additional major NSR review is likely to result in
little, if any, added environmental benefit.
Prior to the December 2002 NSR Improvement rulemaking, we examined
the useful life of air pollution control devices. Based on the
guidelines for equipment life for nine commonly used emissions control
technologies,\62\ we determined that a reasonable average equipment
life is 15 years. See 87 FR 80229. We also looked at the incremental
improvement in control technology over time. Over the 15-year period
that we studied (1988-2002), we did not find any data to suggest that
improvements in control technology are occurring that are of sufficient
magnitude to lead to BACT determinations requiring replacement of
control systems on existing units that are equipped with BACT.\63\
Thus, we believe that 15 years likely represents a reasonable balance
between the useful life of air pollution control devices and the time
frame in which a new BACT determination would require additional
emissions control. Ten years represents a more environmentally cautious
approach to balancing these factors.
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\62\ Vatavuk, William, ``Part II, Factors for Estimating Capital
and Operating Costs,'' Chemical Engineering, Nov. 3, 1980.
\63\ See ``Supplemental Analysis of the Environmental Impact of
the 2002 Final NSR Improvement Rules,'' EPA, November 21, 2002, pp.
10-11 and Appendices C and D. Available at http://www.epa.gov/NSR/documents/nsr-analysis.pdf
.
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Second, a 10-year duration for a Green Group is supported by the
rationale we used in choosing a 10-year period for the duration of
PALs. For PALs we concluded that a 10-year period was necessary to
ensure that the normal business cycle would be captured generally for
any industry. See 67 FR 80216. The PAL's 10-year period also was
intended to balance the need for regulatory certainty, the
administrative burden, and a desire to align the PAL renewal with the
title V permit renewal. See 67 FR 80219. These reasons also apply with
equal force in guiding the selection of a similar 10-year period for
Green Groups.
As a practical matter, we realize that the ``ideal'' duration for a
Green Group will vary somewhat by emissions control technology and by
pollutant; however, we believe using a single time frame will provide
simplicity in the rules. We have chosen to propose a 10-year duration
for Green Groups to maintain consistency with PALs and to maximize the
environmental benefits of Green Groups.
We are also taking comment on a 15-year duration for a Green Group
designation. As discussed above, we believe that air pollution control
technology typically is quite stable during this period. In addition,
the fact that BACT/LAER is determined for the entire Green Group taken
as a whole (including authorized expansions), rather than for
individual changes piecemeal, is likely to result in more effective and
more costly controls than would be applied under mainstream major NSR
permitting. As a result, it is even less likely that a subsequent BACT/
LAER determination at a Green Group would require a new control device
within a 15-year period. Thus, we believe that a 15-year period could
also represent a reasonable and appropriate duration for Green Groups.
We propose that the effective date of a Green Group designation
would be the effective date of the major NSR permit that designates the
Green Group. We propose that the Green Group designation lasts for a
period of 10 years from the effective date.
If construction or modification of a control device is required by
the BACT/LAER determination in the Green Group permit, no advance
approved changes in the permit are allowed to occur before that
construction or modification is completed. That is, new and modified
emissions activities within the Green Group may not be operated until
the new or modified control device is in operation. This will result,
in effect, in a reduction of the 10-year duration for the Green Group
by the length of time between the effective date of the permit and the
beginning of operation of this control device in order to comply with
BACT/LAER.
We do not believe, however, that the unchanged, existing emissions
activities in the Green Group should be required to cease operation
while the control device is constructed or modified. This would be the
outcome if these emissions activities were required to meet the BACT/
LAER emissions limitation(s) on the effective date of the Green Group
permit. Accordingly, we are proposing that, where the BACT/LAER
determination requires a new or modified control device, the Green
Group permit may provide that the existing emissions activities within
the Green Group are not required to meet the BACT/LAER emissions
limitation(s) or the annual emissions cap for the Green Group until the
new or modified air pollution control device is in operation. In the
interim, such emissions activities may continue to
[[Page 52234]]
meet pre-existing emissions limitations. In contrast, where the
existing control device has been determined to represent BACT/LAER
without modification, all existing emissions activities must meet BACT/
LAER upon the effective date of the Green Group permit.
A situation that can result in termination of a major NSR permit
under the existing NSR rules is related to the timely commencement of
the program of construction authorized by the permit. Section
52.21(r)(2) of the existing federal PSD rules provides that approval to
construct shall become invalid if construction is not commenced within
18 months after receipt of such approval, if construction is
discontinued for a period of 18 months or more, or if construction is
not completed within a reasonable time. The Administrator may extend
the 18-month period upon a satisfactory showing that an extension is
justified.\64\
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\64\ The Federal PSD rules apply in jurisdictions that do not
have their own approved PSD programs, including a number of States
(to which we have delegated implementation or in which EPA directly
administers the program) and in Indian country. Many State and local
major NSR programs include similar provisions.
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We are proposing to exclude Green Groups from the section 52.21
(r)(2) provisions. However, we are also proposing a new safeguard for
those Green Groups that rely on a new or upgraded BACT/LAER air
pollution control device. Although the Green Group designation becomes
effective on the effective date of the permit, the source must complete
construction on the new air pollution control device before any changes
advance approved in the permit can be operated. See section VII.D for
more discussion of the rationale for this proposal.
We believe that Green Group activities also should be exempted from
the paragraph (j)(4) provisions of both 40 CFR 52.21 and 51.166.
Currently, the (j)(4) provisions require for phased construction
projects that the BACT determination be reviewed and modified as
appropriate at the latest reasonable time which occurs no later than 18
months prior to commencement of construction of each independent phase
of the project. There is no need to evaluate the interdependence of
changes since, under the proposed Green Group approach, the Green Group
is considered one ongoing program of change over a 10-year period.
Accordingly, we propose to remove the applicability of 40 CFR
52.21(j)(4) and 51.166(j)(4) from Green Groups. See section VII.D for
our rationale concerning this proposal.
6. How are Green Groups similar to PALs?
We also take comment on whether a Green Group is a form of PAL. As
noted previously, the Green Group establishes an actual emissions-based
limitation for a logical collection of emissions activities (i.e., all
those ducted to a common control device). The Green Group approach
relies upon several of the same principles and techniques used in
establishing and managing growth for sources with PALs and other types
of emissions caps. We experimented with PALs and emission caps as part
of the pilot program and have, as a result, a significant amount of
development, implementation, and emissions tracking experience using
these approaches. Specifically, a Green Group is established based on
the actual emissions, plus authorized emission increases associated
with the addition or modification of emissions activities. The
authorization of additional capacity for new or modified emissions
activities provides sources with the ability to respond to market
changes and eliminates administrative burden associated with multiple
permit actions. In exchange, the emissions associated with a Green
Group are constrained by an emissions cap for an established period of
time. It offers substantial environmental benefits by assuring that all
emissions activities within the group are well-controlled and
eliminates the ability of the Green Group to undertake insignificant
emissions increases that could go unreviewed as separate, independent
projects.
Although the Green Group builds an emissions increase into the
initial cap, it does so in a way which complies with all the
requirements that we established for increasing a PAL. Moreover, the
approved increase in actual emissions is allowed only if it is due to
the expansion authorized to occur within the Green Group, since the
BACT/LAER requirement prevents any backsliding in the control of
existing emissions activities in the Green Group. Thus, subsequent
changes in the Green Group whose actual emissions (in combination with
those of existing activities included in the Green Group) do not exceed
the Green Group emissions limit and will be ducted to a control device
determined to meet BACT/LAER, as applicable, have already been
regulated under major NSR in anticipation of the changes being made. We
solicit comment as to whether the Green Group is a permissible
application of the PAL principles as applied to a logical collection of
emissions activities that are ducted to a common control device and, if
so, what increase in emissions for existing emissions activities and/or
increases for new emissions activities can be authorized to occur under
a major NSR permit. We also seek comment on the potential applicability
of these same PAL principles to a proposed Green Group that involves
only new emission activities ducted to a common pollution control
device authorized under major NSR.
C. How is a Green Group designation incorporated into a title V permit?
Major and minor NSR permit terms and conditions are applicable
requirements for purposes of title V. As such, they must be
incorporated into the source's title V permit. These proposed major NSR
rules list the required content for a NSR permit that designates a
Green Group. Part 70 requires that these permit terms and conditions be
incorporated into the source's title V permit according to the
provisions of the applicable title V permit program (but no later than
when the title V permit is renewed). One potential route for
incorporating these terms and conditions into the title V permit is
through an administrative amendment, if an ``enhanced'' NSR process is
used to designate the Green Group. See 40 CFR 70.7(d)(v). This
mechanism is available if the EPA-approved NSR program includes both
procedural requirements substantially equivalent to the requirements of
40 CFR 70.7 and 70.8 and substantive requirements substantially
equivalent to those contained in 40 CFR 70.6.\65\
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\65\ Section 70.6 describes the required elements of permits
issued under part 70 such as emissions limits, applicable
requirements, permit duration, and MRRT. Section 70.7 describes the
process for issuing, renewing, reopening, and revising permits.
Section 70.8 describes the process by which EPA will review permits
and State programs, object to permits, and act on public petitions.
It also requires the permitting authority to give notice of each
draft permit to any affected State and to consider its comments.
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We expect that in many cases, the emissions activities included in
the Green Group will be subject to other applicable requirements, such
as SIP requirements, NSPS, and/or MACT standards. In such cases,
concurrently with the major or minor NSR process, as applicable, the
source can seek to modify its title V permit to include baseline
operating terms and conditions and/or AOSs (as necessary) to address
and assure compliance with all applicable requirements that apply to
the authorized emissions activities comprising the Green Group,
including any advance approvals. Because the BACT or LAER requirement
that applies to the Green Group typically is the most
[[Page 52235]]
stringent of the applicable requirements, Green Groups are often good
candidates for streamlining as mentioned in section VI.A, footnote 26,
and section VII.F of this preamble.
This proposal provides permit flexibility in that a source can
obtain a Green Group through the major NSR permit process (which
constitutes the required NSR authorization for future changes in the
group) and, at the same time, modify its title V permit to include the
Green Group and AOSs, as necessary, to address the other applicable
requirements that apply to the emissions activities in the Green Group.
The approval of the Green Group changes with regard to all relevant
permitting requirements means that the source can implement these
changes authorized under protection of the permit shield without
seeking any further title V approvals.
D. What is the legal rationale for Green Groups?
The basic CAA provisions establishing permitting requirements for
attainment/unclassifiable areas (the PSD requirements) under part C of
title I, and for nonattainment areas under part D of title I, are the
basis for this action. With respect to the PSD requirements, CAA
section 165(a) provides, in relevant part--
No major emitting facility on which construction is commenced
after the date of the enactment of [the 1977 CAA Amendments], may be
constructed in any area to which this part applies unless--
(1) a permit has been issued for such proposed facility in
accordance with this part setting forth emission limitations for
such facility which conform to the requirements of this part * * *
The term ``construction'' is defined to refer to both construction of a
new source and ``modification'' of an existing source. See CAA section
169(2)(C).
With respect to the nonattainment major NSR requirements, section
172(c)(5) of the Act provides that nonattainment SIP provisions ``shall
require permits for the construction and operation of new or modified
major stationary sources anywhere in the nonattainment area, in
accordance with section 173.'' Section 173(a), in turn, provides that
``permits to construct and operate may be issued if [certain
requirements are met].''
These PSD and nonattainment major NSR provisions contain no
specific requirements concerning the maximum length of time that may
elapse between the issuance of the permit and the beginning of
construction, the maximum length of time that the construction may
take, whether the construction may occur in phases, or the maximum
period of time that may elapse between any construction phases. By
comparison, other, related major NSR provisions of the Act do contain
timing requirements. For example, for PSD purposes, section 165(c)
directs the permitting authority to grant or deny the permit within one
year after the date of filing of the completed permit application. As a
second example, for nonattainment major NSR purposes, section
173(a)(1)(A) directs that emission offsets must be obtained ``by the
time the source is to commence operation.'' The lack of specific timing
requirements concerning construction in the relevant provisions of
sections 165(a), 169(2)(C), 172(c)(5), and 173(a) means that EPA has
flexibility in determining the circumstances under which construction
timing requirements are necessary, and in promulgating regulations to
that effect.\66\
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\66\ It should be noted that for purposes of section 165(a), as
quoted above, the term ``commenced'' is defined, under section
169(2)(A), as follows: ``The term `commenced' as applied to
construction of a major emitting facility means that the owner or
operator has obtained all necessary preconstruction approvals or
permits required by Federal, State, or local air pollution emissions
and air quality laws or regulations and either has (i) Begun, or
caused to begin, a continuous program of physical on-site
construction of the facility or (ii) entered into binding agreements
or contractual obligations, which cannot be canceled or modified
without substantial loss to the owner or operator, to undertake a
program of construction of the facility to be completed within a
reasonable time.'' This definition of ``commenced,'' in context,
served the purpose of subjecting a source to the PSD requirements
when the source undertook the actions included in the definition,
and thereby ``commenced'' construction, even if EPA had, by
regulations promulgated prior to enactment of the PSD provisions in
the 1977 Clean Air Act Amendments, attempted to exempt the source
from regulatory PSD review. For present purposes, the fact that
Congress defined ``commenced'' to include construction timing
requirements for the narrow purpose described above, but did not
apply such requirements to construction more broadly, further
supports our view that we have discretion in applying construction
timing requirements.
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By notice dated June 19, 1978, we promulgated certain requirements
concerning phased construction. See 43 FR 26380. Under those
requirements:
Approval to construct shall become invalid if construction is
not commenced within 18 months after receipt of such approval, if
construction is discontinued for a period of 18 months or more, or
if construction is not completed within a reasonable time. The
Administrator may extend the 18-month period upon a satisfactory
showing that an extension is justified. This provision does not
apply to the time period between construction of the approved phases
of a phased construction project; each phase must commence
construction within 18 months of the projected and approved
commencement date.
See 40 CFR 52.21(r)(2).
For phased construction projects, the determination of best
available control technology shall be reviewed and modified as
appropriate at the latest reasonable time which occurs no later than
18 months prior to commencement of construction of each independent
phase of the project. At such time, the owner or operator of the
applicable stationary source may be required to demonstrate the
adequacy of any previous determination of best available control
technology for the source.
See 40 CFR 52.21(j)(4) and 51.166(j)(4).
We stated as the reason for these requirements:
The Administrator is concerned about the issuance of permits for
phased construction projects that would have the effect of
``reserving'' the increment for a single source, thereby limiting
growth options in the area. The options are to not issue phased
construction permits at all or to limit the conditions under which a
phased construction may reserve an increment well into the future.
The Administrator intends to implement the latter option when plans
for a phased project are certain and well-defined. One mechanism to
be used is to reassess the BACT determination for the later phases
of the project prior to construction to ensure that the most up-to-
date control technology will be used. The Administrator will specify
at the time that the original permit is issued which BACT
determinations will be reassessed. The Administrator may also adopt
regulations in the future to deal with this issue more
comprehensively.
See 43 FR 26396.
The EPA proposes to exclude Green Groups from the requirements of
40 CFR 52.21(r)(2), 52.21(j)(4), and 51.166(j)(4) on policy grounds.
The Green Group designation provides a vehicle for a source willing to
describe its construction plans in its permit, as well as employ BACT/
LAER emission controls and comply with other major NSR requirements, in
return for the ability to make a variety of changes without the
burdensome process of iterative permitting actions. We believe that
making such changes (as authorized within Green Groups) can be fairly
described as merely implementing the major NSR permits as approved.
That is, no authorized changes over the 10-year period need to be
reevaluated as a possible new modification since those changes have
already been subjected to major NSR, including a determination of BACT/
LAER requirements and the approval of ambient air quality impacts or
the acquisition of offsets. We believe that the exclusion of Green
Groups from these provisions is needed to provide an adequate level of
certainty and flexibility to participating sources (i.e., the certainty
that a BACT/LAER
[[Page 52236]]
determination will last a reasonable duration). This proposal would
ensure the basic premise of the Green Group approach (i.e., sources are
just making those changes contemplated and approved by the permit). It
would do so by requiring the description of the changes in the permit
to be sufficiently detailed to assure compliance with the required
BACT/LAER and monitoring approaches and to distinguish the changes from
those not authorized to occur under the approved Green Group. We are
proposing a safeguard, in that any changes advance approved for a Green
Group relying on a new or modified control device to meet BACT/LAER
could not be implemented until the control device meets the BACT/LAER
determination in the permit.
It is within our discretion to remove Green Groups from 40 CFR
52.21(r)(2), 52.21(j)(4), and 51.166(j)(4) through rulemaking when
doing so better serves the purposes of the major NSR program.\67\ As
noted above, the 40 CFR 52.21(r)(2) provisions were established by EPA
in rulemaking to safeguard against sources tying up increment
consumption rights without making a substantial financial investment
and against sources inappropriately avoiding the application of control
technology improvements that might have occurred since their permit was
issued. (See 43 FR 26396, June 19, 1978.) For several reasons, we do
not believe that these concerns apply to Green Groups as we are
proposing them.
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\67\ Indeed, as quoted above, 40 CFR 52.21(r)(2) explicitly
provides that ``[t]he Administrator may extend the 18-month period
upon a satisfactory showing that an extension is justified.''
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First, at least in the case when a new or modified air pollution
control device is required, the source under this proposal must make
substantial financial commitment to comply with the Green Group
designation. This type of source has every incentive to complete the
construction of the air pollution control device expeditiously because,
as described above, the remaining period for the Green Group
qualification is reduced accordingly.
Further, based on our overall pilot permit experience, sources that
wish to obtain a flexible permit approach are likely to use it for
changes at multiple emissions activities that could be constructed over
several years. Our evaluation of the pilot permits found that the
authorized flexibilities were used extensively and frequent changes
were made.
In addition, once the air pollution control technology is in
operation, we do not believe significant additional environmental
benefits will be gained by requiring the source to revisit the BACT or
LAER determination for the changes that are approved as part of the
Green Group, but may not be constructed for several years. As noted
above, we do not believe that there will be significant incremental
improvements in state-of-the-art control technology over a 10-year
period. Moreover, the incentive to be able to make changes within a
Green Group without further reviews or approvals can lead sources to
employ BACT/LAER emissions controls when they are not required to do
so, in order to establish a Green Group.
Finally, we believe that Green Groups are likely to involve
controls that are state-of-the-art air pollution control devices since
the device must be sized and designed to accommodate all of the
emissions associated with the emissions activities that comprise the
Green Group, including the authorized emissions increase. We believe
that the BACT determination for a Green Group is likely to be more
stringent than BACT for the individual existing emissions activities or
for the individual authorized changes alone because it will likely be
more cost effective to control a larger amount of emissions. The BACT
or LAER selected for the Green Group is based on the emissions
associated with all of the approved emissions activities, and the BACT
or LAER level must be achieved (at least in part) through the use of a
common air pollution control device.
For essentially the same reasons for removing the applicability of
40 CFR 52.21(r)(2) provisions from Green Groups activities, we believe
that these activities should be exempted from the (j)(4) provisions of
both 40 CFR 52.21 and 51.166. The (j)(4) provisions currently require
for phased construction projects that the BACT determination be
reviewed and modified as appropriate at the latest reasonable time
which occurs no later than 18 months prior to commencement of
construction of each independent phase of the project. There again is
no need to evaluate the interdependence of changes since, under the
proposed Green Group approach, a continuum of changes is likely over a
10-year period while a change in the BACT determination is not.
On the other hand, we do not propose to exclude the provisions of
40 CFR 52.21(r)(4), 51.166(r)(2), and 51.165(a)(5)(ii) from applying to
NSR permitting actions to establish Green Group designations. These
provisions subject a source to major NSR upon the relaxation of certain
permit terms that had allowed the source to avoid major NSR. In the
designation of a Green Group, the emissions unit (which could include
an emissions activity to which an (r)(4) limit was attached) will
undergo major NSR review and be subject to BACT or LAER. Thus, there is
no need to specifically exempt Green Groups from the provisions of 40
CFR 52.21(r)(4), 51.166(r)(2), and 51.165(a)(5)(ii) during the life of
a Green Group or after its expiration.
This legal rationale for Green Groups differs from the legal
rationale for Clean Units, a provision in the 2002 NSR Improvement
rules that the U.S. Court of Appeals for the D.C. Circuit vacated in
State of New York, et al., v. U.S. EPA, June 24, 2005, 413 F.3d at 40.
As noted above, an existing stationary source triggers NSR when it
makes a ``modification,'' which is defined, under CAA section
111(a)(4), as ``any physical change. * * * which increases the amount
of any air pollutant emitted'' by the source. The EPA based the Clean
Unit provision on the premise that the source's construction activities
following permit approval do not constitute a ``modification'' under
CAA section 111(a)(4), and therefore do not trigger application of NSR,
even if they constitute a physical change, as long as the change does
not increase the source's permit allowable emissions. We interpreted
the term ``increase[ ]'' under CAA section 111(a)(4) to authorize an
``allowables'' measurement, at least when a source meets the
requirements for Clean Units. The D.C. Circuit vacated this provision
on grounds that in the context of section 111(a)(4), the plain language
meaning of the term ``increase[ ]'' refers to actual emissions, not
allowable emissions. In contrast, this legal rationale for Green Groups
is based on the premise that the changes and emissions activities that
occur within a Green Group are specifically authorized to occur as a
result of undergoing, not avoiding, major NSR. Conversely, other
changes that a source seeks to implement, but are not authorized in the
Green Group, cannot occur without first obtaining all necessary
preconstruction approvals that would apply to such changes. The
determination of whether the newly proposed, but unauthorized changes
trigger NSR would be made using the ``actual-to-projected-actual test''
upheld by the D.C. Circuit in 2005.
As noted above, the CAA permit provisions do not by their terms
specify timing requirements for phased construction. Current
regulations authorize phased construction activities, within certain
constraints, and those constructions activities cannot be
[[Page 52237]]
considered to be ``physical change[s]'' that could amount to a
``modification.'' This proposal is based on the same legal rationale,
and simply relaxes those regulatory constraints under certain
circumstances, for the policy reasons described above.
E. What are the conforming regulatory changes we must make to implement
the Green Group concept?
We are proposing regulatory language for 40 CFR 51.165, 51.166, and
52.21 to add Green Group provisions. For Green Groups, we propose to
add new provisions at 40 CFR 51.165(i), 51.166(z), and 52.21(dd). We
are also proposing to revise 40 CFR 52.21(j)(4) and (r)(2) and 40 CFR
51.166(j)(4) to exempt Green Groups from these provisions.
In addition, for Green Groups, we propose to amend as necessary the
existing provisions related to netting, emissions offsets, and
determining the emissions increase that will result from a proposed
project. See this proposed regulatory language for the full range of
these changes, for example in 40 CFR 52.21(a)(2)(v).
We are also proposing to make conforming changes to the regulatory
language in appendix S of part 51, although we have not provided
specific regulatory language in this proposal. Appendix S contains the
permitting program for major stationary sources in nonattainment areas
lacking an approved part D NSR program. It applies for the transition
period between a new nonattainment designation and our approval of a
SIP revision to implement the nonattainment NSR requirements (i.e., 40
CFR 51.165) in the area (see 40 CFR 52.24(k)). We recently revised
appendix S to conform to our December 2002 NSR regulations (see 72 FR
10367, March 8, 2007). At the same time that we would finalize the
changes to 40 CFR 51.165, 51.166, and 52.21, we intend to finalize
analogous ones in appendix S. Because the Green Group provisions would
be conforming changes and the public has the opportunity to review and
comment on the conceptual framework and regulatory language proposed,
we will not solicit additional comments on these provisions as they
apply in appendix S.
F. What is an example of how a Green Group might be used in combination
with a title V permit?
Examples 1 and 2 in section VI.D described how AOSs and
incorporation of advance approvals in a part 70 permit could be used to
provide flexibility in certain situations. The following example 3
describes how Green Groups can provide operational flexibility across
applicable requirements through streamlining.
Example 3: Magnetic Tape Plant With Multiple Future Changes
This example illustrates a Green Group and indicates how a source
and permitting authority can streamline Green Group requirements with
other applicable emissions control requirements to craft a flexible
title V permit that authorizes a range of changes at the source while
minimizing the permit terms and conditions necessary to assure
compliance with all the associated applicable requirements. In this
example, a magnetic tape manufacturing facility located in an
attainment area consists of two large production buildings (i.e.,
Buildings 1 and 2), each with seven magnetic tape process lines. In
particular, the source has web coating lines used in the manufacture of
magnetic data storage media as well as equipment for handling raw
materials associated with coating operations, storage of products or
materials, and power boilers to support the process activities.
Five of the existing magnetic tape coating lines in Building 1 are
subject to the MACT standard (part 63, subpart EE), which requires a
95-percent HAP emissions reduction from the process lines and
associated solvent storage tanks, mixing vessels, solvent recovery
equipment, and waste handling devices. Two of these five lines are also
subject to the NSPS for magnetic tape coating (part 60, subpart SSS),
which requires up to 95-percent control of VOCs from coating lines and
mixing vessels. The other two lines are not regulated under part 60 or
part 63 because they are grandfathered from NSPS subpart SSS and do not
emit any HAP. However, these two lines are subject to an emissions
limitation under the SIP that requires an 80-percent reduction in VOC
emissions. For major modifications, major NSR in this PSD area would
require, for this source, application of BACT (determined on a case-by-
case basis), along with a determination that the VOC emissions
increase, among other things, will not cause or contribute to an
exceedance of the ozone NAAQS or have an adverse impact on the air
quality related values of any Class I area. The existing storage tanks
are grandfathered from the NSPS (part 60, subpart Kb), but are subject
to the MACT standard (subpart EE) to the extent that they store HAP.
The VOC emissions from the equipment in Building 1 are currently
controlled with a large, very efficient (96-percent control) carbon
adsorption system which the source installed at the time it became
subject to MACT subpart EE. This resulted in voluntary over-control of
the two lines subject only to the SIP limitation. The source adopted
this control approach so as to retire the old control devices that
previously served these two lines and to allow for flexibility in
future operations. With the voluntary over-control of these two lines,
current total annual VOC emissions from Building 1 are 500 tpy. The
amount of this over-control would be approximately 572 tpy, assuming
that the seven lines are equal in their contributions to the total VOC
emissions of Building 1.
The source would like the flexibility to make a range of changes
within Building 1, but the exact changes within this range will depend
upon business conditions during the permit term and, therefore, are not
yet known. Overall, the source seeks the flexibility to make the
following changes:
Use new raw materials in coating solutions or use an
entirely new coating solution;
Modify the existing process equipment; and/or
Add new process equipment of a similar nature to existing
equipment (including new coating lines) within this building. This new
equipment would be limited to equipment included in the definition of
``magnetic tape manufacturing operation'' in MACT subpart EE (40 CFR
63.702).
The source may pursue a two-part approach to obtain the desired
flexibility to make changes within Building 1: (1) Obtain a PSD permit
that designates Building 1 as a Green Group and advance approves the
future changes; and (2) revise the existing title V permit under the
significant modification process to incorporate all applicable
requirements, as required by part 70, for the changes that are advance
approved in Building 1 under PSD.
Assuming the source follows this approach, the source submits a PSD
permit application requesting a Green Group designation for Building 1.
This permit application must include descriptions of the types of
changes the source intends to make there over the next 10 years (as
noted above), along with emissions information associated with both the
changes, especially regarding any requested increases in emissions, and
the existing operations of Building 1.
The PSD application must demonstrate how those changes and the
associated emissions increases in combination with existing emissions
will comply with PSD requirements for
[[Page 52238]]
Green Groups. In order to meet BACT, the source in its PSD application
proposes to control emissions from Building 1, including emissions from
anticipated changes, by (1) Using permanent total enclosures to capture
all VOC emissions from the building (including coating lines and
associated mixing vessels, solvent recovery equipment, and waste
handling devices), and (2) venting these enclosures and the storage
tanks to the highly efficient (96-percent efficient) carbon adsorption
system currently used to control emissions from all the equipment in
Building 1. The PSD application includes the following BACT-related
demonstrations:
A demonstration that the resultant 96-percent control of
VOCs qualifies as BACT; and
A demonstration that the existing carbon adsorption system
has the capacity to maintain 96-percent control in the face of the
increased solvent loading associated with the anticipated changes.
In addition, the application contains a proposed Green Group
emissions limit of 600 tpy VOC and all emissions information relied
upon to calculate this limit. The proposed limit, in this case, is the
sum of the current baseline actual emissions for each existing
emissions activity comprising the group (since that baseline already
reflects application of the proposed BACT), which the source has
calculated to be 500 tpy, plus a 100 tpy emissions increase increment
to accommodate the calculated, maximum emissions from any future
changes for which the source is seeking approval. In other cases where
current controls do not reflect application of the proposed BACT,
sources also would be required to submit actual emissions information
for included activities relative to their operation before BACT would
be applied. In this example, by subjecting the coating lines and all of
the other emissions activities in the Green Group to the BACT level of
control, the source has imposed additional control, not otherwise
required, on the two lines otherwise subject only to SIP requirements.
While the overall actual emissions from this group may increase by 100
tpy upon approval of the Green Group, the proposed increase would be
subjected to BACT, and overall VOC emissions would be less by 472 tpy
than the actual emissions level that would occur for the source were
the Green Group level of control not in effect for the two lines
previously subject to only to SIP requirements (i.e., 572 tpy over-
control minus the 100 tpy increase).
The PSD application also includes a demonstration that a VOC
emissions increase of 100 tpy from Building 1 will be consistent with
the PSD requirements applicable to the area. It shows that the
increase, among other things, will not cause or contribute to ambient
ozone in excess of the ozone NAAQS or have an adverse impact on the air
quality related values associated with any Class I area.
The application also describes, as normally required under PSD
permitting, how the source will demonstrate initial and ongoing
compliance with the BACT emissions limits. In doing so, the source
bears in mind the requirements of the other applicable requirements
(NSPS subpart SSS, MACT subpart EE, and the SIP) with an eye toward
streamlining these requirements, as discussed further below. For the
initial VOC BACT compliance test, the source proposes to measure the
control efficiency of the carbon adsorption system by testing at the
inlet and outlet of the system using EPA Reference Method 25A and to
verify the permanent total enclosures using EPA Reference Method 204.
To assure ongoing compliance with the proposed BACT for VOC emissions,
the source proposes to monitor continuously the Green Group's single
emissions outlet (the carbon adsorption system stack) with a CEMS
calibrated on the predominant VOC. (The same CEMS currently used for
compliance purposes under the existing emissions limits.) The operating
limit for this parameter (outlet concentration) will be established
during the initial performance test. This monitoring system will also
serve to assure that the emissions vented to the carbon adsorber do not
exceed the capacity of the system (a Green Group requirement), which
would result in an elevated outlet concentration. In addition, the
source proposes to continuously monitor its permanent total enclosures
using differential pressure gauges to demonstrate that these enclosures
are at the prescribed negative pressure relative to their surroundings.
The doors into the enclosures also are equipped with contact switches
and electronic interlocks that automatically close the door after 15
seconds; the actual open time for each door is monitored and tracked.
An operator alarm sounds if a door is open longer than 3 minutes. These
types of testing and monitoring procedures are allowed under NSPS
subpart SSS, MACT subpart EE, and the SIP as well.
To demonstrate compliance with the annual VOC emissions limit
required for a Green Group (set, in this case, at the level of baseline
actual emissions at BACT plus 100 tpy (i.e., 600 tpy VOC) as projected
in the application), the source proposes to meet the MRRT requirements
for Green Groups (discussed previously) by using the concentration data
from the VOC CERMS on the Building 1 carbon adsorber outlet coupled
with data from a volumetric flow rate CEMS. Together these CEMS
constitute a continuous emissions rate monitoring system (CERMS), which
will allow a direct determination of mass emissions from this building.
Total VOC emissions will be determined for each month, and the source
will calculate the rolling 12-month total for comparison to the annual
VOC emissions limit.
The source also proposes comprehensive recordkeeping and reporting
in its PSD application. The proposed recordkeeping includes use of an
automated data acquisition and handling system (DAHS) to record CEMS
and CERMS readings at least once every 15 minutes and to make the
necessary calculations.
After review and public comment, the permitting authority approves
the proposed BACT determination, ambient air quality analysis, and
compliance assurance measures. The permitting authority then issues a
PSD permit to the source designating Building 1 as a Green Group.
This PSD permit provides advance approval under major NSR for the
described changes within the Green Group. However, this major NSR
approval does not address the requirements of the title V permitting
program. Therefore, another step is needed to enable the source to
proceed with these changes without any further review or approval by
the permitting authority.
Under the second part of the process and (in this example)
concurrent with the PSD permit application, the source submits an
application for a significant permit modification of its part 70
permit. Therein the source proposes to include the advance approvals
under major NSR in the title V permit so as to assure compliance with
all applicable requirements relevant to the anticipated changes. To do
so, this application proposes streamlined requirements to address the
spectrum of changes that could occur within Building 1 and includes a
streamlining demonstration and associated documentation.\68\ In
[[Page 52239]]
particular, the application proposes a streamlined emissions limit of
96-percent control of VOC and organic HAP emissions, to be achieved
using the same control strategy proposed as BACT. The streamlining
demonstration and documentation show that this 96-percent reduction
level will assure compliance with all the emissions limits that could
apply to any of the existing, modified, or new equipment in Building 1
(i.e., MACT subpart EE, NSPS subpart SSS, the SIP, and BACT). This
demonstration accounts for the level and format of the emissions limits
(all in terms of percent reduction), the associated test methods (all
are consistent), the averaging time (all are consistent), and the
collection of equipment across which compliance is demonstrated (all
require compliance for each individual piece of equipment).
---------------------------------------------------------------------------
\68\ As explained above in section VI.A of this preamble and
footnote 26, in White Paper Number 2 we interpreted our part 70
rules to allow sources to streamline multiple applicable
requirements that apply to the same emissions unit(s) into a single
set of requirements that assure compliance with all the subsumed
applicable requirements. Sources that seek to streamline applicable
requirements should submit their request as part of their title V
permit application, identifying the proposed streamlined
requirements and providing a demonstration that the streamlined
requirements assure compliance with all the underlying, subsumed
applicable requirements. Where the source wishes to streamline the
advance approval under NSR with all other relevant applicable
requirements, the same title V permit application can address both
actions.
---------------------------------------------------------------------------
The streamlining proposal also includes streamlined monitoring,
recordkeeping, and reporting requirements that assure compliance with
the streamlined emissions limit at least as well as the requirements of
the subsumed applicable requirements. In this case, the monitoring
requirements associated with the BACT emissions limit are shown to
assure compliance with the streamlined emissions limit as least as well
as the monitoring applicable to each less-stringent emissions limit.
Similarly, the recordkeeping and reporting associated with the BACT
monitoring approach are appropriate for use with the streamlined limit
and provide no less compliance assurance than would the recordkeeping
and reporting required for any of the subsumed monitoring approaches.
In this case, where the PSD application and streamlining proposal
are being prepared simultaneously, the source appropriately considered
the other, non-NSR applicable requirements in its permit application
for the BACT emissions limit and associated MRRT requirements so that
as the BACT limit (i.e., 96 percent reduction) meshed with the
streamlined requirements in the part 70 permit application. This
approach simplified the streamlining proposal.
The part 70 application essentially incorporates the description
contained in the PSD permit which established the Green Group. That is,
it describes the baseline configuration in Building 1, as well as the
types of changes that are anticipated (mirroring the changes approved
in the Green Group PSD permit). The part 70 application also identifies
the streamlined requirements and all the subsumed applicable
requirements implicated by the potential changes (PSD, NSPS subpart
SSS, MACT subpart EE, and the SIP), and indicates that PSD
authorization has been received (or is being concurrently processed).
Any physical or operational changes that implicate different sets of
applicable requirements would be identified as AOSs, as discussed
previously in Example 2. The application proposes terms and conditions
to assure compliance with the streamlined requirements. Focusing these
terms and conditions on the streamlined requirements simplifies both
the application and the resulting permit.
The magnitude of the authorized emissions increase under the
proposed scenario(s) is bounded by the annual VOC emissions limitation
for the Green Group established at the level of baseline actual
emissions under BACT plus the 100 tpy VOC emissions increase approved
under PSD. Thus, the permit application proposes an aggregate total of
600 tpy VOC. Note that any VOC emissions within Building 1 will count
against this limitation. For purposes of this example, we have assumed
that no debottlenecking effect occurs from emissions units that are not
changed themselves. Traditional NSR (i.e., minor or major NSR, as
applicable) continues to apply outside the Green Group.
For purposes of the Green Group (which is a single emissions unit
under the PSD regulations proposed), the aggregate total emissions
figure (600 tpy) included in the part 70 application fulfills the part
70 requirement that annual emissions be provided in the application for
each emissions unit. However, because some of the emissions activities
that are included in the Green Group are also subject to other
applicable requirements (i.e., the SIP, NSPS subpart SSS, and/or MACT
subpart EE), they may be considered emissions units for purposes of
these requirements. As a result, the source potentially could be
required to provide the annual emissions in tpy for each of these
smaller emissions units in the part 70 permit. Under the part 70 rule
revisions proposed (see proposed 40 CFR 70.5(c)(3)(iii)), for emissions
units that are under an emissions cap, ``tpy can be reported as part of
the aggregate emissions associated with the cap, except where more
specific information is needed to determine an applicable
requirement.'' Thus, because the application already stipulates that
the emissions activities are subject to these other applicable
requirements, there is no need for the source to include annual
emissions for each of the subject emissions activities.
The source and the permitting authority then proceed through the
process for a significant permit modification that involves
streamlining and the incorporation of the Green Group permit (i.e., the
advance approval issued under major NSR). After review and public
participation, and after addressing the comments received, the
permitting authority issues a revised title V permit which includes the
streamlined requirements, the Green Group permit terms, and a permit
shield.
The source subsequently is able to make the authorized changes in
the Green Group/Building 1 without additional review or approval or
permit revisions. Log entries are required if the source makes changes
that cause a shift to a different AOS. Note that the notification
requirements of the NSPS and MACT General Provisions continue to apply
if the source adds a new line or modifies an affected source or
facility within the Green Group.
VIII. What is the effect of these proposed revisions?
A. If these proposed revisions are finalized, what are the implications
for approved part 70 programs?
The part 70 regulations provide, in pertinent part, that--
If part 70 is subsequently revised such that the Administrator
determines that it is necessary to require a change to an approved
State program, the required revisions to the program shall be
submitted within 12 months of the final changes to part 70 or within
such other period as authorized by the Administrator.
See 40 CFR 70.4(a); see also 40 CFR 70.4(i).
The revisions to the part 70 program proposed build upon the
existing regulatory structure, as promulgated in 1992. For the reasons
discussed above, we believe that these proposed revisions clarify the
existing part 70 regulations. Our pilot experience--where we worked
closely with several different States--strongly suggests that these
revisions, if finalized, would likely not necessitate revisions to many
approved State programs. Based on our pilot experience, however, we
recognize that State programs differ, and we believe that at least some
States would likely revise their current part 70 program to add
sufficient authority to implement the final rule or to make current
[[Page 52240]]
authority on flexible permits more explicit. We solicit comment on our
initial position that at least some State programs would require
program revisions in response to the final rule.
We intend to work closely with States and review expeditiously any
documentation submitted regarding the adequacy of current part 70
programs and any proposed program revisions. Nothing precludes State
and local permitting authorities from issuing flexible permits, as they
may have done in the past, but they must determine if sufficient
authority exists under their current operating permit program to do so.
For those States that believe they lack authority under their current
part 70 programs to implement the final rule, such States should submit
proposed revisions to their title V operating permits program to their
EPA Regional Offices within 12 months of the date of publication of the
final rule in the Federal Register. See 40 CFR 70.4(a). For other
States if, based on their subsequent efforts to implement the final
rule, we determine in writing that a particular part 70 program does
not provide sufficient authority to implement the final rule or is
inconsistent with the final rule, then the relevant State will have 12
months from the date of our written determination to submit a proposed
operating permit program consistent with the final rule to us for
review and approval.
B. What are the implications for NSR programs?
We believe that Green Groups will have environmental and
administrative benefits like those of PALs. Accordingly, we propose
that the Green Groups, like PALs, should be a mandatory program
element. When the Green Group provisions are finalized, this will
require revisions to SIPs or a demonstration that adequate authority
already exists.
By ``mandatory program element,'' we mean that SIPs must include
provisions providing for the issuance of major NSR permits with Green
Group designations. However, a Green Group would be an option that a
source may, or may not, choose to seek. In addition, a permitting
authority would have discretion as to whether or not to issue a Green
Group permit based on the particulars of each individual case.
Where States and local agencies would need implementation plan
revisions to be able to issue permits establishing Green Groups, they
must adopt and submit revisions to their part 51 permitting programs
implementing these minimum program elements no later than 3 years from
the date of publication in the Federal Register of the final Green
Group regulations in 40 CFR 51.165 and 51.166. In any area for which we
are the reviewing authority, or for which we have delegated our
authority to issue permits to State or local permitting authorities,
the changes would take effect 60 days from the date of publication in
the Federal Register of the final Green Group regulations in 40 CFR
52.21.
As we noted in the NSR improvements adopted in 2002, State and
local jurisdictions have significant freedom to customize their NSR
programs (67 FR 80241). 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.''
See 45 FR 52676.
During the interim period between this proposal and finalization of
the proposed rules, we believe that certain major NSR permits with
features similar to a Green Group designation could be approved under
our existing federal PSD regulations at 40 CFR 52.21. Such permits
would have to abide by the existing regulations, including the
restrictions at 40 CFR 52.21(r)(2) and (j)(4), which would differ from
this proposal for Green Groups. Because of the benefits we believe
Green Groups bring, we invite States to whom we have delegated the
federal PSD program, as well as States implementing their own EPA-
approved major NSR programs, to work with us on a case-by-case basis
within the constraints of existing regulations to determine whether and
to what extent Green Group-like permits may be available in this
interim period.
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993),
this action is a ``significant regulatory action'' because it is likely
to result in a rule that may raise novel legal or policy issues arising
out of legal mandates, the President's priorities, or the principles
set forth in the Executive Order. Accordingly, EPA submitted this
action to the Office of Management and Budget (OMB) for review under EO
12866 and any changes made in response to OMB recommendations have been
documented in the docket for this action.
B. Paperwork Reduction Act
This proposed rule would revise several existing rules. The current
information collection requirements of those rules are contained in
three different Information Collection Requests (ICRs). The Office of
Management and Budget (OMB) has approved the information collection
requirements for parts 70 and 71 under the provisions of the Paperwork
Reduction Act, 44 U.S.C. 3501 et seq. The currently approved ICR for
part 70 is assigned ICR number 1587.06 and OMB number 2060-0243; for
part 71, the ICR number is 1713.05 and the OMB number is 2060-0336.
Similarly, OMB has approved information collection requirements for
parts 51 and 52 that govern the State and Federal programs for
preconstruction review and permitting of major new and modified sources
pursuant to part C (PSD) and part D (nonattainment major NSR) of title
I of the CAA. The currently approved ICR for parts 51 and 52 is
assigned ICR number 1230.17 and OMB number 2060-0003.
The information collection requirements in this proposed rule have
been submitted for approval to OMB under the Paperwork Reduction Act,
44 U.S.C. 3501 et seq. The ICR documents prepared by EPA have been
assigned EPA ICR numbers 1587.08, 1713.07, and 1230.20.
The total economic impact of the proposed Flexible Air Permitting
Rule over the three-year term of the ICR is estimated to be $36 million
in cost savings for sources with a burden reduction of approximately
943,000 labor hours; $19 million in cost savings for permitting
authorities with a burden reduction of approximately 514,000 labor
hours; and costs of $1.4 million with an increase in burden of
approximately 37,000 labor hours for EPA.
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: (1) Review instructions; (2) develop, acquire, install, and
utilize technology and systems for the purposes of collecting,
validating, and verifying information, processing and maintaining
information, and disclosing and providing information; (3) adjust the
existing ways to comply with any previously applicable instructions and
requirements; (4) train personnel to be able to respond to a collection
of information; (5) search data sources; (6) complete and review the
collection of information; and (7) 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
[[Page 52241]]
control number. The OMB control numbers for EPA's regulations are
listed in 40 CFR part 9 and 48 CFR Chapter 15.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, including the use of automated collection
techniques, EPA has established a public docket for this rule, which
includes this ICR, under Docket ID number EPA-HQ-OAR-2004-0087. Submit
any comments related to the ICR for this proposed rule to EPA and OMB.
See the ADDRESSES section at the beginning of this notice for where to
submit comments to EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW., Washington, DC 20503, Attention: Desk Office for
EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after September 12, 2007, a comment to OMB is
best assured of having its full effect if OMB receives it by October
12, 2007. The final rule will respond to any OMB or public comments on
the information collection requirements contained in this proposal.
C. Regulatory Flexibility Act (RFA)
The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the Agency certifies that the rule will not have
``a significant economic impact on a substantial number of small
entities.'' Small entities include small businesses, small
organizations, and small government jurisdictions.
For purposes of assessing the impacts of this proposal on small
entities, a small entity is defined as: (1) A small business as defined
by the Small Business Administration's regulations at 13 CFR 121.201;
(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; and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not
dominant in its field.
This proposed rule would merely clarify existing requirements and
allow regulated entities to seek additional flexibility for their Clean
Air Act permits, and would not create a new burden for regulated
entities. We have determined there will be cost savings for small
entities associated with these proposed revisions. After considering
the economic impact of this proposed rule on small entities, I certify
that this action will not have a significant economic impact on a
substantial number of small entities. Therefore, a regulatory
flexibility analysis is not required.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 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, 2
U.S.C. 1532, we generally must prepare a written statement, including a
cost-benefit analysis, for any proposed or final rule that ``includes
any Federal mandate that may result in the expenditure by State, local,
and tribal governments, in the aggregate, or by the private sector, of
$100 million or more * * * in any one year.'' A ``Federal mandate'' is
defined to include a ``Federal intergovernmental mandate'' and a
``Federal private sector mandate.'' 2 U.S.C. 658(6). A ``Federal
intergovernmental mandate,'' in turn, is defined to include a
regulation that ``would impose an enforceable duty upon State, local,
or tribal governments,'' 2 U.S.C. 658(5)(A)(i), except for, among other
things, a duty that is ``a condition of Federal assistance.'' 2 U.S.C.
658(5)(A)(i)(I). A ``Federal private sector mandate'' includes a
regulation that ``would impose an enforceable duty upon the private
sector,'' with certain exceptions [2 U.S.C. 658(7)(A)].
Before promulgating a rule for which a written statement is needed,
section 205 of the UMRA generally requires us 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 where they are inconsistent with applicable law. Moreover,
section 205 allows us 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 why that
alternative was not adopted. Before we establish any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, we 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 our regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
We have determined under the regulatory provisions of title II of
the UMRA that this proposed rule does not include a Federal mandate
that may result in estimated costs of $100 million or more to either
State, local, or tribal governments in the aggregate, or to the private
sector. This proposed rule is estimated to save State, local, and
tribal permitting authorities over $5 million and to result in an
administrative burden reduction of 135,000 hours. Thus, this proposed
rule is not subject to the requirements of sections 202 or 205 of the
UMRA.
In addition, we have determined that this proposed rule contains no
regulatory requirements that might significantly or uniquely affect
small governments. We expect any impact will act to lower overall
administrative burden to these entities. Therefore, this proposed rule
is not subject to the requirements of section 203 of the UMRA.
E. Executive Order 13132: Federalism
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires us 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, or on the distribution of power and
responsibilities among the various levels of government.''
This proposal 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. This proposal should result in
cost savings and administrative burden reductions for States and will
not alter the overall relationship or distribution of powers between
governments for the part 70 and part 71 operating permits programs or
for the part 51 and part 51 NSR programs. Thus, Executive Order 13132
does not apply to this proposed rule.
In the spirit of Executive Order 13132, and consistent with our
policy to
[[Page 52242]]
promote communication between us and State and local governments, we
specifically solicit comment on this proposed rule from State and local
officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, ``Consultation and Coordination with Indian
Tribal Governments'' (65 FR 67249, November 6, 2000), requires us to
develop an accountable process to ensure ``meaningful and timely input
by tribal officials in the development of regulatory policies that have
tribal implications.'' ``Policies that have tribal implications'' is
defined in the Executive Order to include regulations that have
``substantial direct effects on one or more Indian tribes, on the
relationship between the Federal government and the Indian tribes, or
on the distribution of power and responsibilities between the Federal
government and Indian tribes.''
These proposed rule revisions do not have tribal implications
because they will not have a substantial direct effect on one or more
Indian tribes, on the relationship between the Federal government and
Indian tribes, or on the distribution of power and responsibilities
between the Federal government and Indian tribes, as specified in
Executive Order 13175. This action does not significantly or uniquely
affect the communities of Indian tribal governments. Accordingly, the
requirements of Executive Order 13175 do not apply to these proposed
rule revisions. We solicit comments from Indian tribal governments on
the proposed rule.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
This proposed 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 it does not establish an
environmental standard intended to mitigate health or safety risks.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This rule is not subject to Executive Order 13211, ``Actions
Concerning Regulations That Significantly Affect Energy Supply,
Distribution, or Use'' (66 FR 28355, May 22, 2001) because it is not a
significant regulatory action under Executive Order 12866.
This proposed rule is not a ``significant energy action,'' as
defined in Executive Order 13211, because it is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy. As noted earlier, this action would simply clarify existing
requirements and would not impose any new requirements, and thus would
not affect the supply, distribution, or use of energy.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 104-113, directs us 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 (e.g., materials
specifications, test methods, sampling procedures, and business
practices) that are developed or adopted by voluntary consensus bodies.
The NTTAA directs us to provide Congress, through OMB, explanations
when the Agency decides not to use available and applicable voluntary
consensus standards.
The NTTAA does not apply to this proposed rule because it does not
involve technical standards. Therefore, we did not consider the use of
any voluntary consensus standards.
List of Subjects
40 CFR Part 51
Environmental protection, Administrative practice and procedures,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
40 CFR Part 52
Environmental protection, Administrative practice and procedures,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
40 CFR Part 70
Environmental protection, Administrative practice and procedures,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
40 CFR Part 71
Environmental protection, Administrative practice and procedures,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
Dated: August 28, 2007.
Stephen L. Johnson,
Administrator.
For the reasons set out in the preamble, title 40, chapter I of the
Code of Federal Regulations is proposed to be amended as set forth
below.
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. 7401-7671q.
Subpart I--[Amended]
2. Section 51.165 is amended as follows:
a. By adding paragraph (a)(1)(v)(G);
b. By revising paragraph (a)(1)(xii)(A);
c. By revising paragraph (a)(1)(xxxv)(D);
d. By revising paragraph (a)(2)(ii)(A);
e. By adding paragraph (a)(2)(v);
f. By revising paragraph (a)(6) introductory text; and
g. By adding paragraph (i).
The additions and revisions read as follows:
Sec. 51.165 Permit requirements.
(a) * * *
(1) * * *
(v) * * *
(G) This definition shall not apply to approved physical changes or
changes in the method of operation within a Green Group with respect to
any Green Group pollutant when the major stationary source is complying
with the requirements under paragraph (i) of this section for a Green
Group for that pollutant.
* * * * *
(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 or a Green Group under paragraph
(i) of this section. Instead, paragraphs (a)(1)(xxviii) and (xxxv) of
this section shall apply for those purposes.
* * * * *
(xxxv) * * *
(D) For a PAL or Green Group 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
[[Page 52243]]
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.
* * * * *
(2) * * *
(ii) * * *
(A) Except as otherwise provided in paragraphs (a)(2)(iii) through
(v) 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.
* * * * *
(v) The plan shall require that for any major stationary source
with a Green Group for a regulated NSR pollutant, the owner or operator
shall comply with the requirements in paragraph (i) of this section for
those emissions activities included within the Green Group.
* * * * *
(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 Green Group 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) Green Groups. The plan shall provide for Green Groups according
to the provisions in paragraphs (i)(1) through (17) of this section.
(1) Applicability. The reviewing authority may issue a permit under
regulations approved pursuant to this section designating a Green Group
at any existing major stationary source if the permit contains terms
and conditions assuring that the Green Group meets the requirements in
paragraphs (i)(1) through (17) of this section.
(i) Changes at a Green Group. Any physical change in or change in
the method of operation authorized for a Green Group pursuant to the
requirements in paragraphs (i)(1) through (17) of this section that
maintains the Green Group's total emissions at or below the Green Group
emissions limit and maintains the Green Group's compliance with its
LAER limit(s):
(A) Is not a major modification for the Green Group pollutant; and
(B) Does not have to be approved through the plan's nonattainment
major NSR program.
(ii) Prior requirements. A major stationary source shall continue
to comply with all remaining applicable Federal or State requirements,
emissions limitations, and work practice requirements that were
established prior to the effective date of the Green Group.
(2) Definitions. The plan shall use the definitions in paragraphs
(i)(2)(i) through (iv) of this section for the purpose of developing
and implementing regulations that authorize the use of Green Groups
consistent with paragraphs (i)(1) through (17) of this section. When a
term is not defined in these paragraphs, it shall have the meaning
given in paragraph (a)(1) or (f) of this section or in the Act.
(i) Green Group means a group of new and/or existing emissions
activities that is characterized by use of a common, dedicated air
pollution control device and that has been designated as a Green Group
by the reviewing authority in a permit issued under regulations
approved pursuant to this section. A Green Group is a single emissions
unit for purposes of this section.
(ii) Green Group pollutant means a pollutant emitted from the
emissions activities that comprise the Green Group and for which a
Green Group is designated at a major stationary source.
(iii) Green Group permit means the major NSR permit issued by the
reviewing authority that establishes a Green Group for a major
stationary source.
(iv) Green Group emissions limit means an emissions limitation for
the Green Group pollutant, expressed in tons per year, that is
enforceable as a practical matter and established for a Green Group at
a major stationary source in accordance with paragraphs (i)(1) through
(17) of this section.
(3) Permit application requirements. The owner or operator of a
major stationary source must request approval for a Green Group in an
application for a major NSR permit that meets the requirements of this
section, as applicable, and of sections 172(c)(5) and 173 of the Act.
As part of a permit application requesting a Green Group, the owner or
operator of a major stationary source shall submit the following
information to the reviewing authority for approval:
(i) List of designated emissions activities. A list of the
emissions activities proposed for inclusion in the Green Group. In
addition, the owner or operator of the source shall indicate which, if
any, Federal or State applicable requirements, emissions limitations,
or work practices apply to each activity.
(ii) Baseline actual emissions. Calculations of the baseline actual
emissions from included emissions activities (with supporting
documentation). Baseline actual emissions are to include emissions
associated not only with operation of the activity, but also emissions
associated with startup, shutdown, and malfunction.
(iii) Monitoring data conversion procedures. 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 (i)(15)(i) of this section.
(iv) Description. A description of the equipment that comprises the
Green Group, including a description of existing emissions activities,
proposed physical changes or changes in method of operation (which may
include the addition of new emissions activities), and the common air
pollution control device. The description must provide information
about maximum total emissions that will be generated by the Green
Group's emissions activities and the associated characteristics of the
combined emissions streams (including the worst-case emissions stream)
that will be ducted to the common air pollution control device. The
description must be sufficient:
(A) To allow the reviewing authority to distinguish changes
proposed to be authorized in the Green Group from unauthorized changes;
and
(B) To enable the reviewing authority to determine LAER for the
Green Group consistent with paragraphs (i)(4)(ii) and (i)(7)(v) of this
section.
(v) Control technology demonstration. A demonstration that the
proposed
[[Page 52244]]
control technology represents LAER. Such a demonstration shall confirm
that the emissions reduction capacity of the proposed common control
device is sufficient to meet the relevant emissions reduction
requirement, considering the maximum total emissions from the Green
Group and the associated characteristics of the combined emissions
streams that will be ducted to the common air pollution control device.
The LAER demonstration shall be based on worst-case emissions from the
new and existing emissions activities authorized for the Green Group.
(vi) Monitoring system. A proposed monitoring system sufficient to
meet the requirements of paragraph (i)(13) of this section with respect
to Green Group emissions limit(s) and the requirements of paragraph
(i)(14) of this section with respect to LAER-related limitations.
(vii) Proposed Green Group emissions limit. The proposed Green
Group emissions limit, in tons per year, with supporting documentation
including, but not limited to, the following:
(A) Baseline actual emissions of existing emissions activities
proposed to be included in the Green Group, adjusted to reflect the
application of LAER; and
(B) The amount of emissions growth proposed for the Green Group as
the result of the proposed physical, operational, and other changes.
(4) General requirements for designating a Green Group. The plan
shall provide that the reviewing authority may designate a Green Group
at an existing major stationary source through issuance of a
nonattainment major NSR permit under regulations approved pursuant to
this section, provided that in addition the requirements in paragraphs
(i)(4)(i) through (vii) of this section are met.
(i) Green Group emissions limit. The reviewing authority,
consistent with regulations approved pursuant to paragraph (i)(6) of
this section, shall establish a Green Group emissions limit in tons per
year for those emissions activities included under the Green Group
(including any new emissions activities added within the Green Group).
For each month during the Green Group effective period after the first
12 months of establishing the Green Group, the major stationary source
owner or operator shall show that the sum of the monthly emissions from
each included emissions activity for the previous 12 consecutive months
is less than or equal to the Green Group emissions limit (i.e., a 12-
month total, rolled monthly). For each month during the first 11 months
from the Green Group effective date, the major stationary source owner
or operator shall show that the sum of the preceding monthly emissions
from the Green Group effective date for each emissions activity under
the Green Group is less than or equal to the Green Group emissions
limit.
(ii) LAER emissions limit. The reviewing authority shall determine
LAER for the emissions of the Green Group pollutant from the group of
emissions activities designated as a Green Group. The LAER emissions
limit shall ensure that the emissions of the emissions activities
included in the Green Group are ducted to a common, dedicated air
pollution control device. The control device, in combination with any
additional control measures consistent with paragraphs (i)(4)(ii)(A)
and (B) of this section, must achieve the LAER level of emissions
reductions for the Green Group pollutant.
(A) In addition to the requirement to duct emissions from the Green
Group to a common air pollution control device, additional control
measures such as pollution prevention (as defined under paragraph
(a)(1)(xxvi) of this section), work practices, and/or operational
standards may be defined as part of the approved control measures.
(B) Pollution prevention measures that have been determined to
represent LAER may be approved to apply during certain periods of
operation. The included emissions activities must have ductwork
extending to the common air pollution control device, but the owner or
operator would be allowed to bypass the control device during periods
when the pollution prevention alternative is in use, consistent with
the LAER determination. Emissions activities that exclusively use the
pollution prevention alternative and never use the common air pollution
control device may not be included in the Green Group.
(iii) Permit content. The Green Group permit shall contain all the
requirements of paragraph (i)(7) of this section.
(iv) Included emissions. The Green Group emissions limit shall
include fugitive emissions of the Green Group pollutant, to the extent
quantifiable, from all emissions activities included under the Green
Group.
(v) Regulated pollutant. Each Green Group shall regulate emissions
of only one pollutant. However, the same collection of emissions
activities may be designated separately as a Green Group for another
pollutant.
(vi) Effective period. Each Green Group designation shall have an
effective period of 10 years.
(vii) Monitoring, recordkeeping, and reporting. The Green Group
permit shall require the owner or operator to comply with the
monitoring, recordkeeping, and reporting requirements in paragraphs
(i)(13) through (16) of this section for each included emissions
activity.
(5) General provisions for Green Groups. The plan shall require
that the provisions set out in paragraphs (i)(5)(i) through (iv) of
this section apply to Green Groups:
(i) Any project for which the owner or operator begins actual
construction after the effective date of a Green Group designation and
before its expiration date will be considered to have occurred while
the emissions unit was a Green Group.
(ii) At no time (during or after the Green Group effective period)
are emissions reductions of a Green Group pollutant that occur during
the Green Group effective period creditable as decreases for purposes
of offsets under paragraph (a)(3)(ii) of this section unless the Green
Group emissions limit is reduced by the amount of such emissions
reductions and such reductions would be creditable in the absence of
the Green Group designation. No emissions reduction credit can be
generated for emissions growth that was authorized under the Green
Group permit, but never realized.
(iii) At no time (during or after the Green Group effective period)
are emissions increases or reductions of a Green Group pollutant that
occur during the Green Group effective period creditable for purposes
of calculating a net emissions increase under paragraph (a)(1)(vi) of
this section (that is, must not be used in a ``netting analysis''),
unless the Green Group emissions limit is reduced by the amount of such
emissions reductions and such reductions would be creditable in the
absence of the Green Group designation. No emissions reduction credit
can be generated for emissions growth that was authorized under the
Green Group permit, but never realized.
(iv) The Green Group 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 Green Group is located in an attainment
area and the area is redesignated to nonattainment, its Green Group
designation is not affected. Similarly, redesignation from
nonattainment to attainment does not affect the Green Group
designation. However, if an existing Green Group designation expires,
it must re-qualify under the requirements that are currently applicable
in the area.
[[Page 52245]]
(6) Setting the 10-year Green Group emissions limit. The plan shall
provide that the Green Group emissions limit is to be established as
follows:
(i) Except as provided in paragraphs (i)(6)(ii) through (iv) of
this section, the Green Group emissions limit shall be established as
the sum of the baseline actual emissions (as defined in paragraph
(a)(1)(xxxv) of this section) of the Green Group pollutant for each
emissions activity included in the Green Group. When establishing the
Green Group emissions limit, for a Green Group pollutant, a single
period of 24 consecutive months must be used to determine the baseline
actual emissions for all existing emissions activities. However, a
different period of 24 consecutive months may be used for each
different Green Group pollutant. Emissions associated with activities
that were permanently shut down after this 24-month period must be
subtracted from the Green Group emissions limit. The reviewing
authority shall specify a reduced Green Group emissions limit(s) (in
tons/yr) in the Green Group 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 Green Group permit.
(ii) For activities (which do not include modifications to existing
units) on which actual construction began after the 24-month period, in
lieu of adding the baseline actual emissions as specified in paragraph
(i)(6)(i) of this section, the emissions must be added to the Green
Group emissions limit in an amount equal to the potential to emit of
the activities.
(iii) The reviewing authority shall establish the Green Group
emissions level by adjusting the total derived according to paragraphs
(i)(6)(i) and (ii) of this section to reflect:
(A) The application of LAER; and
(B) An additional amount of actual emissions consistent with the
growth approved for the Green Group.
(7) Content of the Green Group permit. The plan shall require that
the Green Group permit contain the elements listed in paragraphs
(i)(7)(i) through (xiii) of this section and any other provisions that
the reviewing authority deems necessary to implement the Green Group.
(i) The Green Group pollutant.
(ii) A description of the equipment that comprises the Green Group,
including a description of existing emissions activities, any
authorized physical changes or changes in method of operation, and the
common air pollution control device. The description must provide
information about the maximum total emissions that will be generated by
the Green Group's emissions activities and the associated
characteristics of the combined emissions streams that will be ducted
to the common air pollution control device. The description must be
sufficient to distinguish, when a change is subsequently made in the
Green Group, whether that change was authorized under the Green Group
permit.
(iii) A statement designating the described equipment as a Green
Group.
(iv) The Green Group emissions limit (in terms of a 12-month total,
rolled monthly) for the group of emissions activities included under
the Green Group.
(v) All emissions limitations and work practice requirements
established to ensure that LAER is met.
(vi) The Green Group effective date and the expiration date of the
Green Group (i.e., the Green Group effective period). If the source
owner or operator must construct a new air pollution control device or
modify an existing device as a result of the LAER determination for the
Green Group, the permit may provide that the existing emissions
activities within the Green Group are not required to meet the LAER
emissions limitation(s) or the Green Group emissions limit until the
new or modified air pollution control device is in operation. (That is,
such emissions activities may continue to meet pre-existing emissions
limitations until that time.) However, new and modified emissions
activities within the Green Group must be subject to LAER upon startup.
In addition, the Green Group must be subject to the Green Group
emissions limit (and associated monitoring, recordkeeping, and
reporting requirements) beginning at the time that the new or modified
air pollution control device is placed in operation.
(vii) Specification in the Green Group permit that if a major
stationary source owner or operator applies to renew a Green Group in
accordance with paragraph (i)(11) of this section before the end of the
effective period, then the Green Group shall not expire at the end of
the effective period. It shall remain in effect until a new Green Group
permit is issued by the reviewing authority.
(viii) A requirement that emissions calculations for compliance
purposes must include emissions from startups, shutdowns, and
malfunctions.
(ix) A requirement that, once the Green Group expires, the major
stationary source is subject to the requirements of paragraph (i)(10)
of this section.
(x) 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 (i)(15)(i) of this section.
(xi) A requirement that the major stationary source owner or
operator meet all applicable requirements for monitoring, testing, and
operation in accordance with the provisions of paragraphs (i)(13) and
(14) of this section.
(xii) A requirement to retain the records required under paragraph
(i)(15) of this section on site. Such records may be retained in an
electronic format.
(xiii) A requirement to submit the reports required under paragraph
(i)(16) of this section by the required deadlines.
(8) Green Group effective period. The plan shall require that the
reviewing authority specify an effective period of 10 years. The
effective period begins upon the Green Group effective date, which is
the date that the Green Group permit becomes effective.
(9) Reopening of the Green Group permit. The plan shall provide
that the requirements in paragraphs (i)(9)(i) through (iii) of this
section apply to reopening Green Group permits.
(i) Mandatory reopenings. During the Green Group effective period,
the reviewing authority must reopen the Green Group permit to:
(A) Correct typographical/calculation errors made in setting the
Green Group emissions limit or reflect a more accurate determination of
emissions used to establish this limit;
(B) Reduce the Green Group emissions limit 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; and
(C) Reduce the Green Group emissions limit if the owner or operator
of the major stationary source creates creditable emissions reductions
for use in a netting analysis under paragraph (a)(1)(vi) of this
section.
(ii) Discretionary reopenings. The reviewing authority shall have
discretion to reopen the Green Group permit for the purposes listed in
paragraphs (i)(9)(ii)(A) through (C) of this section. If the reviewing
authority declines to reopen the Green Group permit for any of these
purposes, the Green Group emissions limit must be adjusted upon
expiration of the Green Group designation or upon renewal of the
source's title V permit, whichever
[[Page 52246]]
comes first. The major stationary source owner or operator is
responsible for compliance with any new applicable requirements,
regardless of when the permit is reopened and adjusted.
(A) To reduce the Green Group emissions limit to reflect newly
applicable Federal requirements (for example, NSPS) with compliance
dates after the Green Group effective date;
(B) To reduce the emissions limit 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
(C) To reduce the emissions limit 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.
(iii) Required process. Except for the permit reopening in
paragraph (i)(9)(i)(A) of this section for the correction of
typographical/calculation errors that do not increase the Green Group
emissions limit, all other reopenings shall be carried out in
accordance with the full public participation requirements for major
NSR permitting under the regulations approved pursuant to this section.
(10) Expiration of a Green Group. The plan shall require that any
Green Group designation that is not renewed in accordance with the
procedures in paragraph (i)(11) of this section shall expire at the end
of its effective period. After expiration of the Green Group
designation, the following provisions apply:
(i) The emissions unit defined by the Green Group remains an
emissions unit for purposes of major NSR and remains subject to the
LAER control requirements; Green Group emissions limit; any shorter-
term emissions limits; and monitoring, recordkeeping, reporting, and
testing requirements imposed by the Green Group permit.
(ii) The major stationary source owner or operator shall continue
to comply with any State or Federal applicable requirements (LAER,
RACT, NSPS, etc.) that may have applied either during or prior to the
Green Group effective period.
(iii) Any subsequent physical change or change in the method of
operation at the emissions unit defined by the Green Group will be
subject to nonattainment major NSR requirements if such change meets
the definition of major modification in paragraph (a)(1)(v) of this
section.
(11) Renewal of a Green Group. The plan shall require that the
following provisions apply to renewal of a Green Group:
(i) Required procedures. A Green Group may be renewed through
issuance of a new major NSR permit according to all the requirements of
this paragraph (i) for the initial Green Group designation.
(ii) Application deadline. A major stationary source owner or
operator shall submit a timely application to the reviewing authority
to request renewal of a Green Group. A timely application is one that
is submitted at least 6 months prior to, but not earlier than 18 months
from, the date that the Green Group designation would otherwise expire.
This deadline for application submittal is to ensure that the Green
Group designation will not expire before the Green Group is renewed. If
the owner or operator of a major stationary source submits a complete
application to renew the Green Group within this time period, then the
Green Group shall continue to be effective until the new nonattainment
major NSR permit with the renewed Green Group is issued.
(12) Increasing a Green Group emissions limit during its effective
period. The plan shall provide that the reviewing authority may
increase a Green Group emissions limit during its effective period only
if the increase is contained in a new permit incorporating the increase
into a new Green Group consistent with the requirements of the
regulations approved pursuant to this section.
(13) Monitoring requirements for Green Group emissions limitations.
The plan shall provide that the following monitoring requirements apply
to Green Groups.
(i) General requirements.
(A) Each Green Group permit must contain enforceable requirements
for the monitoring system that accurately determines, in terms of mass
per unit of time, emissions of the Green Group pollutant from the
emissions activities under the Green Group. Any monitoring system
authorized for use in the Green Group 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 Green Group permit.
(B) The Green Group monitoring system must employ one or more of
the four general monitoring approaches meeting the minimum requirements
set forth in paragraphs (i)(13)(ii)(A) through (D) of this section and
must be approved by the reviewing authority.
(C) Notwithstanding paragraph (i)(13)(i)(B) of this section, you
may also employ an alternative monitoring approach that meets paragraph
(i)(13)(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 Green Group 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 (i)(13)(iii) through (ix) of this section:
(A) Mass balance calculations for activities using coatings or
solvents;
(B) CEMS;
(C) CPMS or PEMS; and
(D) Emissions factors.
(iii) Mass balance calculations. An owner or operator using mass
balance calculations to monitor the Green Group 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 Green Group pollutant that is contained in or created by
all materials used in or at the emissions activity;
(B) Assume that the emissions activity emits all of the Green Group
pollutant that is contained in or created by any raw material or fuel
used in or at the emissions activity, 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 activity, publishes a range of pollutant content from
such material, the owner or operator must use the highest value of the
range to calculate the Green Group 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 Green Group
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 activity is operating.
[[Page 52247]]
(v) CPMS or PEMS. An owner or operator using CPMS or PEMS to
monitor Green Group 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 Green Group pollutant emissions across the range of operation of
the emissions activity; 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 activity is operating.
(vi) Emissions factors. An owner or operator using emissions
factors to monitor Green Group pollutant emissions shall meet the
following requirements:
(A) All emissions factors shall be adjusted, if appropriate, to
account for the degree of uncertainty or limitations in the factors'
development;
(B) The emissions activity shall operate within the designated
range of use for the emissions factor, if applicable; and
(C) If technically practicable, the owner or operator of a
significant or major emissions activity that relies on an emissions
factor to calculate Green Group pollutant emissions shall conduct
validation through performance testing or other scientifically valid
means approved by the reviewing authority to determine a site-specific
emissions factor. Such testing or other means shall occur within 6
months of Green Group permit issuance.
(vii) Missing data procedures. A source owner or operator must
record and report maximum potential emissions without considering
enforceable emissions limitations or operational restrictions for an
emissions activity during any period of time that there is no
monitoring data, unless another method for determining emissions during
such periods is specified in the Green Group permit.
(viii) Alternative requirements. Notwithstanding the requirements
in paragraphs (i)(13)(iii) through (vii) of this section, where an
owner or operator of an emissions activity cannot demonstrate a
correlation between the monitored parameter(s) and the Green Group
pollutant emissions rate at all operating points of the emissions
activity, the reviewing authority shall, at the time of permit
issuance:
(A) Establish default value(s) for determining compliance with the
Green Group emissions limit based on the highest potential emissions
reasonably estimated at such operating point(s); or
(B) Determine that operation of the emissions activity during
operating conditions when there is no correlation between monitored
parameter(s) and the Green Group pollutant emissions is a violation of
the Green Group emissions limit.
(ix) Re-validation. All data used to establish the Green Group
pollutant emissions must be re-validated 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 Green Group.
(14) Additional monitoring requirements for LAER. The plan shall
provide that the permit must also require the owner or operator with a
Green Group to monitor, measure, and record data sufficient to
determine whether:
(i) The emissions reduction measures (including the Green Group air
pollution control device) meet the emissions limitations and/or work
practice requirements adopted in conjunction with LAER; and
(ii) The demonstrated capacity of the Green Group air pollution
control device was exceeded by the emissions stream(s) directed to it
at any time during the reporting period. The capacity of the control
device is considered exceeded if the characteristics of the emissions
stream entering the device are outside the range for which it has been
demonstrated that the device can achieve LAER, absent valid monitoring
data (from a continuous monitoring system or other monitoring approach
approved for such use by the reviewing authority) showing compliance
with LAER at the new operating level. A period of exceedance is
considered a deviation for purposes of recordkeeping and reporting.
(15) Recordkeeping requirements. The plan shall require that the
following recordkeeping requirements apply to Green Groups:
(i) Records to determine compliance. The Green Group permit shall
require an owner or operator to retain a copy of all records necessary
to determine compliance with any requirement of paragraph (i) of this
section and of the Green Group permit, including a determination of
each emissions activity's 12-month rolling total emissions, for 5 years
from the date of such record.
(ii) Other records. The Green Group permit shall require an owner
or operator to retain a copy of the following records for the duration
of the Green Group effective period plus 5 years:
(A) A copy of the Green Group permit application and any
applications for revisions to the Green Group permit; and
(B) Each annual certification of compliance pursuant to title V and
the data relied on in certifying the compliance.
(16) Reporting and notification requirements. The plan shall
require the owner or operator to 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 (i)(16)(i) through (iii) of this
section.
(i) Semi-annual report. The semi-annual 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 (i)(16)(i)(A) through (G) of this section.
(A) The identification of owner and operator and the permit number.
(B) Total annual emissions (tons per year) from the emissions
activities included under the Green Group, based on a 12-month rolling
total for each month in the reporting period recorded pursuant to
paragraph (i)(15)(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 Green Group pollutant emissions.
(D) A list of any emissions activities included under the Green
Group that were added 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 activity monitored by the monitoring system continued to
operate, and the calculation of the emissions of the pollutant or the
number determined by the method included in the permit, as provided by
paragraph (i)(13)(vii) of this section.
(G) A signed statement by the responsible official (as defined by
the applicable title V operating permit
[[Page 52248]]
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 Green Group emissions limit or emissions reduction requirement
(e.g., LAER limit), including periods where no monitoring is available.
A report submitted pursuant to Sec. 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 Sec. 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 Green Group 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.
(17) Transition requirements. The plan shall provide that the
reviewing authority may not issue a Green Group permit that does not
comply with the requirements in paragraphs (i)(1) through (17) of this
section or their equivalent after the Administrator has approved
regulations incorporating these requirements into the plan. The plan
shall provide that the reviewing authority may supersede any Green
Group permit that was established prior to the date of approval of the
plan by the Administrator with a Green Group permit that complies with
the requirements of paragraphs (i)(1) through (17) of this section.
3. Section 51.166 is amended as follows:
a. By revising paragraph (a)(7)(iv)(a);
b. By adding paragraph (a)(7)(vii);
c. By adding paragraph (b)(2)(v);
d. By revising paragraph (b)(21)(i);
e. By revising paragraph (b)(47)(iv);
f. By revising paragraph (r)(6) introductory text; and
g. By adding paragraph (z).
The additions and revisions read as follows:
Sec. 51.166 Prevention of significant deterioration of air quality.
(a) * * *
(7) * * *
(iv) * * *
(a) Except as otherwise provided in paragraphs (a)(7)(v) through
(vii) 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.
* * * * *
(vii) The plan shall require that for any major stationary source
with a Green Group for a regulated NSR pollutant, the owner or operator
shall comply with the requirements in paragraph (z) of this section for
those emissions activities included within the Green Group.
* * * * *
(b) * * *
(2) * * *
(v) This definition shall not apply to approved physical changes or
changes in the method of operation within a Green Group with respect to
any Green Group pollutant when the major stationary source is complying
with the requirements under paragraph (z) of this section for a Green
Group for that pollutant.
* * * * *
(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 or a Green Group under paragraph
(z) of this section. Instead, paragraphs (b)(40) and (b)(47) of this
section shall apply for those purposes.
* * * * *
(47) * * *
(iv) For a PAL or Green Group 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 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.
* * * * *
(r) * * *
(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 Green Group 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.
* * * * *
(z) Green Groups. The plan shall provide for Green Groups according
to the provisions in paragraphs (z)(1) through (17) of this section.
(1) Applicability. The reviewing authority may issue a permit under
regulations approved pursuant to this section designating a Green Group
at any existing major stationary source if the permit contains terms
and conditions assuring that the Green Group meets the requirements in
paragraphs (z)(1) through (17) of this section.
(i) Changes at a Green Group. Any physical change in or change in
the method of operation authorized for a Green Group pursuant to the
requirements in paragraphs (z)(1) through (17) of this section that
maintains the Green Group's total emissions at or below the Green Group
emissions limit and maintains the Green Group's compliance with its
best available control technology (BACT) limit(s):
(a) Is not a major modification for the Green Group pollutant;
(b) Does not have to be approved through the plan's PSD program;
and
(c) Is not subject to the provisions of paragraph (j)(4) of this
section.
(ii) Prior requirements. Except as provided under paragraph
(z)(1)(i)(c) of this section, a major stationary source shall continue
to comply with all remaining applicable Federal or State
[[Page 52249]]
requirements, emissions limitations, and work practice requirements
that were established prior to the effective date of the Green Group.
(2) Definitions. The plan shall use the definitions in paragraphs
(z)(2)(i) through (iv) of this section for the purpose of developing
and implementing regulations that authorize the use of Green Groups
consistent with paragraphs (z)(1) through (17) of this section. When a
term is not defined in these paragraphs, it shall have the meaning
given in paragraph (b) or (aa) of this section or in the Act.
(i) Green Group means a group of new and/or existing emissions
activities that is characterized by use of a common, dedicated air
pollution control device and that has been designated as a Green Group
by the reviewing authority in a permit issued under regulations
approved pursuant to this section. A Green Group is a single emissions
unit for purposes of this section.
(ii) Green Group pollutant means a pollutant emitted from the
emissions activities that comprise the Green Group and for which a
Green Group is designated at a major stationary source.
(iii) Green Group permit means the major NSR permit issued by the
reviewing authority that establishes a Green Group for a major
stationary source.
(iv) Green Group emissions limit means an emissions limitation for
the Green Group pollutant, expressed in tons per year, that is
enforceable as a practical matter and established for a Green Group at
a major stationary source in accordance with paragraphs (z)(1) through
(17) of this section.
(3) Permit application requirements. The owner or operator of a
major stationary source must request approval for a Green Group in an
application for a major NSR permit that meets the requirements of
paragraphs (j) through (r)(5) of this section, as applicable. As part
of a permit application requesting a Green Group, the owner or operator
of a major stationary source shall submit the following information to
the reviewing authority for approval:
(i) List of designated emissions activities. A list of the
emissions activities proposed for inclusion in the Green Group. In
addition, the owner or operator of the source shall indicate which, if
any, Federal or State applicable requirements, emissions limitations,
or work practices apply to each activity.
(ii) Baseline actual emissions. Calculations of the baseline actual
emissions from included emissions activities (with supporting
documentation). Baseline actual emissions are to include emissions
associated not only with operation of the activity, but also emissions
associated with startup, shutdown, and malfunction.
(iii) Monitoring data conversion procedures. 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 (z)(15)(i) of this section.
(iv) Description. A description of the equipment that comprises the
Green Group, including a description of existing emissions activities,
proposed physical changes or changes in method of operation (which may
include the addition of new emissions activities), and the common air
pollution control device. The description must provide information
about maximum total emissions that will be generated by the Green
Group's emissions activities and the associated characteristics of the
combined emissions streams (including the worst-case emissions stream)
that will be ducted to the common air pollution control device. The
description must be sufficient:
(a) To allow the reviewing authority to distinguish changes
proposed to be authorized in the Green Group from unauthorized changes;
and
(b) To enable the reviewing authority to determine BACT for the
Green Group consistent with paragraphs (z)(4)(ii) and (z)(7)(vi) of
this section.
(v) Control technology demonstration. A demonstration that the
proposed control technology represents BACT. Such a demonstration shall
confirm that the emissions reduction capacity of the proposed common
control device is sufficient to meet the relevant emissions reduction
requirement, considering the maximum total emissions from the Green
Group and the associated characteristics of the combined emissions
streams that will be ducted to the common air pollution control device.
The BACT demonstration shall be based on worst-case emissions from the
new and existing emissions activities authorized for the Green Group.
(vi) Monitoring system. A proposed monitoring system sufficient to
meet the requirements of paragraph (z)(13) of this section with respect
to Green Group emissions limit(s) and the requirements of paragraph
(z)(14) of this section with respect to BACT-related limitations.
(vii) Proposed Green Group emissions limit. The proposed Green
Group emissions limit, in tons per year, with supporting documentation
including, but not limited to, the following:
(a) Baseline actual emissions of existing emissions activities
proposed to be included in the Green Group, adjusted to reflect the
application of BACT; and
(b) The amount of emissions growth proposed for the Green Group as
the result of the proposed physical, operational, and other changes.
(4) General requirements for designating a Green Group. The plan
shall provide that the reviewing authority may designate a Green Group
at an existing major stationary source through issuance of a PSD permit
under regulations approved pursuant to this section, provided that in
addition, at a minimum, the requirements in paragraphs (z)(4)(i)
through (vii) of this section are met.
(i) Green Group emissions limit. The reviewing authority,
consistent with regulations approved pursuant to paragraph (z)(6) of
this section, shall establish a Green Group emissions limit in tons per
year for those emissions activities included under the Green Group
(including any new emissions activities added within the Green Group).
For each month during the Green Group effective period after the first
12 months of establishing the Green Group, the major stationary source
owner or operator shall show that the sum of the monthly emissions from
each included emissions activity for the previous 12 consecutive months
is less than or equal to the Green Group emissions limit (i.e. a 12-
month total, rolled monthly). For each month during the first 11 months
from the Green Group effective date, the major stationary source owner
or operator shall show that the sum of the preceding monthly emissions
from the Green Group effective date for each emissions activity under
the Green Group is less than or equal to the Green Group emissions
limit.
(ii) BACT emissions limit. The reviewing authority shall determine
BACT for the emissions of the Green Group pollutant from the group of
emissions activities designated as a Green Group. The BACT emissions
limit shall ensure that the emissions of the emissions activities
included in the Green Group are ducted to a common, dedicated air
pollution control device and ensure compliance with any applicable
emissions limitation under the State Implementation Plan and each
applicable emission standard and standard of performance under 40 CFR
parts 60 and 61. The control device, in combination with any additional
control measures consistent with paragraphs
[[Page 52250]]
(z)(4)(ii)(a) and (b) of this section, must achieve the BACT level of
emissions reductions for the Green Group pollutant.
(a) In addition to the requirement to duct emissions from the Green
Group to a common air pollution control device, additional control
measures such as pollution prevention (as defined under paragraph
(b)(38) of this section), work practices, and/or operational standards
may be defined as part of the approved control measures.
(b) Pollution prevention measures that have been determined to
represent BACT may be approved to apply during certain periods of
operation. The included emissions activities must have ductwork
extending to the common air pollution control device, but the owner or
operator would be allowed to bypass the control device during periods
when the pollution prevention alternative is in use, consistent with
the BACT determination. Emissions activities that exclusively use the
pollution prevention alternative and never use the common air pollution
control device may not be included in the Green Group.
(iii) Permit content. The Green Group permit shall contain all the
requirements of paragraph (z)(7) of this section.
(iv) Included emissions. The Green Group emissions limit shall
include fugitive emissions of the Green Group pollutant, to the extent
quantifiable, from all emissions activities included under the Green
Group.
(v) Regulated pollutant. Each Green Group shall regulate emissions
of only one pollutant. However, the same collection of emissions
activities may be designated separately as a Green Group for another
pollutant.
(vi) Effective period. Each Green Group designation shall have an
effective period of 10 years.
(vii) Monitoring, recordkeeping, and reporting. The Green Group
permit shall require the owner or operator to comply with the
monitoring, recordkeeping, and reporting requirements in paragraphs
(z)(13) through (16) of this section for each included emissions
activity.
(5) General provisions for Green Groups. The plan shall require
that the provisions set out in paragraphs (z)(5)(i) through (iv) apply
to Green Groups:
(i) Any project for which the owner or operator begins actual
construction after the effective date of a Green Group designation and
before its expiration date will be considered to have occurred while
the emissions unit was a Green Group.
(ii) At no time (during or after the Green Group effective period)
are emissions reductions of a Green Group pollutant that occur during
the Green Group effective period creditable as decreases for purposes
of offsets under Sec. 51.165(a)(3)(ii) unless the Green Group
emissions limit is reduced by the amount of such emissions reductions
and such reductions would be creditable in the absence of the Green
Group designation. No emissions reduction credit can be generated for
emissions growth that was authorized under the Green Group permit, but
never realized.
(iii) At no time (during or after the Green Group effective period)
are emissions increases or reductions of a Green Group pollutant that
occur during the Green Group effective period creditable for purposes
of calculating a net emissions increase under paragraph (b)(3) of this
section (that is, must not be used in a ``netting analysis''), unless
the Green Group emissions limit is reduced by the amount of such
emissions reductions and such reductions would be creditable in the
absence of the Green Group designation. No emissions reduction credit
can be generated for emissions growth that was authorized under the
Green Group permit, but never realized.
(iv) The Green Group 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 Green Group is located in an attainment
area and the area is redesignated to nonattainment, its Green Group
designation is not affected. Similarly, redesignation from
nonattainment to attainment does not affect the Green Group
designation. However, if an existing Green Group designation expires,
it must re-qualify under the requirements that are currently applicable
in the area.
(6) Setting the 10-year Green Group emissions limit. The plan shall
provide that the Green Group emissions limit is to be established as
follows:
(i) Except as provided in paragraphs (z)(6)(ii) through (iv) of
this section, the Green Group emissions limit shall be established as
the sum of the baseline actual emissions (as defined in paragraph
(b)(47) of this section) of the Green Group pollutant for each
emissions activity included in the Green Group. When establishing the
Green Group emissions limit, for a Green Group pollutant, a single
period of 24 consecutive months must be used to determine the baseline
actual emissions for all existing emissions activities. However, a
different period of 24 consecutive months may be used for each
different Green Group pollutant. Emissions associated with activities
that were permanently shut down after this 24-month period must be
subtracted from the Green Group emissions limit. The reviewing
authority shall specify a reduced Green Group emissions limit(s) (in
tons/yr) in the Green Group 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 Green Group permit.
(ii) For activities (which do not include modifications to existing
units) on which actual construction began after the 24-month period, in
lieu of adding the baseline actual emissions as specified in paragraph
(z)(6)(i) of this section, the emissions must be added to the Green
Group emissions limit in an amount equal to the potential to emit of
the activities.
(iii) The reviewing authority shall establish the Green Group
emissions level by adjusting the total derived according to paragraphs
(z)(6)(i) and (ii) of this section to reflect:
(a) The application of BACT; and
(b) An additional amount of actual emissions consistent with the
growth approved for the Green Group.
(iv) Notwithstanding the methodology set out above in paragraphs
(z)(6)(i) through (iii) of this section, the reviewing authority shall
reduce the Green Group emissions limit and/or establish short-term
emissions limits as necessary to meet other applicable requirements of
this section, including the requirements of paragraphs (k) and (p).
(7) Content of the Green Group permit. The plan shall require that
the Green Group permit contain the elements listed in paragraphs
(z)(7)(i) through (xiv) of this section and any other provisions that
the reviewing authority deems necessary to implement the Green Group.
(i) The Green Group pollutant.
(ii) A description of the equipment that comprises the Green Group,
including a description of existing emissions activities, any
authorized physical changes or changes in method of operation, and the
common air pollution control device. The description must provide
information about the maximum total emissions that will be generated by
the Green Group's emissions activities and the associated
characteristics of the combined emissions streams that will be ducted
to the common air pollution control device. The description must be
sufficient to distinguish, when a change is subsequently made in the
Green Group, whether that change was authorized under the Green Group
permit.
[[Page 52251]]
(iii) A statement designating the described equipment as a Green
Group.
(iv) The Green Group emissions limit (in terms of a 12-month total,
rolled monthly) for the group of emissions activities included under
the Green Group.
(v) Any shorter-term emissions limits that are necessary to
safeguard ambient air quality, as determined according to the
requirements of the regulations approved pursuant to this section.
(vi) All emissions limitations and work practice requirements
established to ensure that BACT is met.
(vii) The Green Group effective date and the expiration date of the
Green Group (i.e., the Green Group effective period). If the source
owner or operator must construct a new air pollution control device or
modify an existing device as a result of the BACT determination for the
Green Group, the permit may provide that the existing emissions
activities within the Green Group are not required to meet the BACT
emissions limitation(s) or the Green Group emissions limit until the
new or modified air pollution control device is in operation. (That is,
such emissions activities may continue to meet pre-existing emissions
limitations until that time.) However, new and modified emissions
activities within the Green Group must be subject to BACT upon startup.
In addition, the Green Group must be subject to the Green Group
emissions limit (and associated monitoring, recordkeeping, and
reporting requirements) beginning at the time that the new or modified
air pollution control device is placed in operation.
(viii) Specification in the Green Group permit that if a major
stationary source owner or operator applies to renew a Green Group in
accordance with paragraph (z)(11) of this section before the end of the
effective period, then the Green Group shall not expire at the end of
the effective period. It shall remain in effect until a new Green Group
permit is issued by the reviewing authority.
(ix) A requirement that emissions calculations for compliance
purposes must include emissions from startups, shutdowns, and
malfunctions.
(x) A requirement that, once the Green Group expires, the major
stationary source is subject to the requirements of paragraph (z)(10)
of this section.
(xi) 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 (z)(15)(i) of this section.
(xii) A requirement that the major stationary source owner or
operator meet all applicable requirements for monitoring, testing, and
operation in accordance with the provisions of paragraphs (z)(13) and
(14) of this section.
(xiii) A requirement to retain the records required under paragraph
(z)(15) of this section on site. Such records may be retained in an
electronic format.
(xiv) A requirement to submit the reports required under paragraph
(z)(16) of this section by the required deadlines.
(8) Green Group effective period. The plan shall require that the
reviewing authority specify an effective period of 10 years. The
effective period begins upon the Green Group effective date, which is
the date that the Green Group permit becomes effective.
(9) Reopening of the Green Group permit. The plan shall provide
that the requirements in paragraphs (z)(9)(i) through (iii) of this
section apply to reopening Green Group permits.
(i) Mandatory reopenings. During the Green Group effective period,
the reviewing authority must reopen the Green Group permit to:
(a) Correct typographical/calculation errors made in setting the
Green Group emissions limit or reflect a more accurate determination of
emissions used to establish this limit;
(b) Reduce the Green Group emissions limit if the owner or operator
of the major stationary source creates creditable emissions reductions
for use as offsets under Sec. 51.165(a)(3)(ii); and
(c) Reduce the Green Group emissions limit if the owner or operator
of the major stationary source creates creditable emissions reductions
for use in a netting analysis under paragraph (b)(3) of this section.
(ii) Discretionary reopenings. The reviewing authority shall have
discretion to reopen the Green Group permit for the purposes listed in
paragraphs (z)(9)(ii)(a) through (c) of this section. If the reviewing
authority declines to reopen the Green Group permit for any of these
purposes, the Green Group emissions limit must be adjusted upon
expiration of the Green Group designation or upon renewal of the
source's title V permit, whichever comes first. The major stationary
source owner or operator is responsible for compliance with any new
applicable requirements, regardless of when the permit is reopened and
adjusted.
(a) To reduce the Green Group emissions limit to reflect newly
applicable Federal requirements (for example, NSPS) with compliance
dates after the Green Group effective date;
(b) To reduce the emissions limit 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
(c) To reduce the emissions limit 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.
(iii) Required process. Except for the permit reopening in
paragraph (z)(9)(i)(a) of this section for the correction of
typographical/calculation errors that do not increase the Green Group
emissions limit, all other reopenings shall be carried out in
accordance with the public participation requirements of paragraph (q)
of this section.
(10) Expiration of a Green Group. The plan shall require that any
Green Group designation that is not renewed in accordance with the
procedures in paragraph (z)(11) of this section shall expire at the end
of its effective period. After expiration of the Green Group
designation, the following provisions apply:
(i) The emissions unit defined by the Green Group remains an
emissions unit for purposes of major NSR and remains subject to the
BACT control requirements; Green Group emissions limit; any shorter-
term emissions limits; and monitoring, recordkeeping, reporting, and
testing requirements imposed by the Green Group permit.
(ii) 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 or prior to the
Green Group effective period.
(iii) Any subsequent physical change or change in the method of
operation at the emissions unit defined by the Green Group will be
subject to PSD requirements if such change meets the definition of
major modification in paragraph (b)(2) of this section.
(11) Renewal of a Green Group. The plan shall require that the
following provisions apply to renewal of a Green Group:
(i) Required procedures. A Green Group may be renewed through
issuance of a new major NSR permit according to all the requirements of
this paragraph (z) for the initial Green Group designation.
[[Page 52252]]
(ii) Application deadline. A major stationary source owner or
operator shall submit a timely application to the reviewing authority
to request renewal of a Green Group. A timely application is one that
is submitted at least 6 months prior to, but not earlier than 18 months
from, the date that the Green Group designation would otherwise expire.
This deadline for application submittal is to ensure that the Green
Group designation will not expire before the Green Group is renewed. If
the owner or operator of a major stationary source submits a complete
application to renew the Green Group within this time period, then the
Green Group shall continue to be effective until the new PSD permit
with the renewed Green Group is issued.
(12) Increasing a Green Group emissions limit during its effective
period. The plan shall provide that the reviewing authority may
increase a Green Group emissions limit during its effective period only
if the increase is contained in a new permit incorporating the increase
into a new Green Group consistent with the requirements of the
regulations approved pursuant to this section.
(13) Monitoring requirements for Green Group emissions limitations.
The plan shall provide that the following monitoring requirements apply
to Green Groups.
(i) General requirements.
(a) Each Green Group permit must contain enforceable requirements
for the monitoring system that accurately determines, in terms of mass
per unit of time, emissions of the Green Group pollutant from the
emissions activities under the Green Group. Any monitoring system
authorized for use in the Green Group 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 Green Group permit.
(b) The Green Group monitoring system must employ one or more of
the four general monitoring approaches meeting the minimum requirements
set forth in paragraphs (z)(13)(ii)(a) through (d) of this section and
must be approved by the reviewing authority.
(c) Notwithstanding paragraph (z)(13)(i)(b) of this section, you
may also employ an alternative monitoring approach that meets paragraph
(z)(13)(i)(a) of this section if approved by the reviewing authority.
(b) Failure to use a monitoring system that meets the requirements
of this section renders the Green Group 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 (z)(13)(iii) through (ix) of this section:
(a) Mass balance calculations for activities using coatings or
solvents;
(b) CEMS;
(c) CPMS or PEMS; and
(d) Emissions factors.
(iii) Mass balance calculations. An owner or operator using mass
balance calculations to monitor the Green Group 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 Green Group pollutant that is contained in or created by
all materials used in or at the emissions activity;
(b) Assume that the emissions activity emits all of the Green Group
pollutant that is contained in or created by any raw material or fuel
used in or at the emissions activity, 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 activity, publishes a range of pollutant content from
such material, the owner or operator must use the highest value of the
range to calculate the Green Group 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 Green Group
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 activity is operating.
(v) CPMS or PEMS. An owner or operator using CPMS or PEMS to
monitor Green Group 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 Green Group pollutant emissions across the range of operation of
the emissions activity; 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 activity is operating.
(vi) Emissions factors. An owner or operator using emissions
factors to monitor Green Group pollutant emissions shall meet the
following requirements:
(a) All emissions factors shall be adjusted, if appropriate, to
account for the degree of uncertainty or limitations in the factors'
development;
(b) The emissions activity shall operate within the designated
range of use for the emissions factor, if applicable; and
(c) If technically practicable, the owner or operator of a
significant or major emissions activity that relies on an emissions
factor to calculate Green Group pollutant emissions shall conduct
validation through performance testing or other scientifically valid
means approved by the reviewing authority to determine a site-specific
emissions factor. Such testing or other means shall occur within 6
months of Green Group permit issuance, unless the reviewing authority
determines that testing is not required.
(vii) Missing data procedures. A source owner or operator must
record and report maximum potential emissions without considering
enforceable emissions limitations or operational restrictions for an
emissions activity during any period of time that there is no
monitoring data, unless another method for determining emissions during
such periods is specified in the Green Group permit.
(viii) Alternative requirements. Notwithstanding the requirements
in paragraphs (z)(13)(iii) through (vii) of this section, where an
owner or operator of an emissions activity cannot demonstrate a
correlation between the monitored parameter(s) and the Green Group
pollutant emissions rate at all operating points of the emissions
activity, the reviewing authority shall, at the time of permit
issuance:
(a) Establish default value(s) for determining compliance with the
Green Group emissions limit based on the highest potential emissions
reasonably estimated at such operating point(s); or
(b) Determine that operation of the emissions activity during
operating conditions when there is no correlation between monitored
parameter(s) and the Green Group pollutant emissions is a violation of
the Green Group emissions limit.
(ix) Re-validation. All data used to establish the Green Group
pollutant
[[Page 52253]]
emissions must be re-validated 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
Green Group.
(14) Additional monitoring requirements for BACT. The plan shall
provide that the permit must also require the owner or operator with a
Green Group to monitor, measure, and record data sufficient to
determine whether:
(i) The emissions reduction measures (including the Green Group air
pollution control device) meet the emissions limitations and/or work
practice requirements adopted in conjunction with BACT; and
(ii) The demonstrated capacity of the Green Group air pollution
control device was exceeded by the emissions stream(s) directed to it
at any time during the reporting period. The capacity of the control
device is considered exceeded if the characteristics of the emissions
stream entering the device are outside the range for which it has been
demonstrated that the device can achieve BACT, absent valid monitoring
data (from a continuous monitoring system or other monitoring approach
approved for such use by the reviewing authority) showing compliance
with BACT at the new operating level. A period of exceedance is
considered a deviation for purposes of recordkeeping and reporting.
(15) Recordkeeping requirements. The plan shall require that the
following recordkeeping requirements apply to Green Groups:
(i) Records to determine compliance. The Green Group permit shall
require an owner or operator to retain a copy of all records necessary
to determine compliance with any requirement of paragraph (z) of this
section and of the Green Group permit, including a determination of
each emissions activity's 12-month rolling total emissions, for 5 years
from the date of such record.
(ii) Other records. The Green Group permit shall require an owner
or operator to retain a copy of the following records for the duration
of the Green Group effective period plus 5 years:
(a) A copy of the Green Group permit application and any
applications for revisions to the Green Group permit; and
(b) Each annual certification of compliance pursuant to title V and
the data relied on in certifying the compliance.
(16) Reporting and notification requirements. The plan shall
require the owner or operator to 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 (z)(16)(i) through (iii) of this
section.
(i) Semi-annual report. The semi-annual 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 (z)(16)(i)(a) through (g) of this section.
(a) The identification of owner and operator and the permit number.
(b) Total annual emissions (tons per year) from the emissions
activities included under the Green Group, based on a 12-month rolling
total for each month in the reporting period recorded pursuant to
paragraph (z)(15)(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 Green Group pollutant emissions.
(d) A list of any emissions activities included under the Green
Group that were added 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 activity monitored by the monitoring system continued to
operate, and the calculation of the emissions of the pollutant or the
number determined by the method included in the permit, as provided by
paragraph (z)(13)(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 Green Group emissions limit or emissions reduction requirement
(e.g., BACT limit), including periods where no monitoring is available.
A report submitted pursuant to Sec. 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 Sec. 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 Green Group 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.
(17) Transition requirements. The plan shall provide that the
reviewing authority may not issue a Green Group permit that does not
comply with the requirements in paragraphs (z)(1) through (17) of this
section or their equivalent after the Administrator has approved
regulations incorporating these requirements into the plan. The plan
shall provide that the reviewing authority may supersede any Green
Group permit that was established prior to the date of approval of the
plan by the Administrator with a Green Group permit that complies with
the requirements of paragraphs (z)(1) through (17) of this section.
PART 52--[AMENDED]
4. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart A--[Amended]
5. Section 52.21 is amended as follows:
a. By revising paragraph (a)(2)(iv)(a);
b. By adding paragraph (a)(2)(vii);
c. By adding paragraph (b)(2)(v);
d. By revising paragraph (b)(21)(i);
e. By revising paragraph (b)(48)(iv);
f. By revising paragraph (r)(6) introductory text; and
g. By adding paragraph (dd).
The additions and revisions read as follows:
Sec. 52.21 Prevention of significant deterioration of air quality.
(a) * * *
(2) * * *
[[Page 52254]]
(iv) * * *
(a) Except as otherwise provided in paragraphs (a)(2)(v) through
(vii) 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.
* * * * *
(vii) For any major stationary source with a Green Group for a
regulated NSR pollutant, the owner or operator shall comply with the
requirements in paragraph (dd) of this section for those emissions
activities included within the Green Group.
* * * * *
(b) * * *
(2) * * *
(v) This definition shall not apply to approved physical changes or
changes in the method of operation within a Green Group with respect to
any Green Group pollutant when the major stationary source is complying
with the requirements under paragraph (dd) of this section for a Green
Group for that pollutant.
* * * * *
(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 or a Green Group under paragraph
(dd) of this section. Instead, paragraphs (b)(41) and (b)(48) of this
section shall apply for those purposes.
* * * * *
(48) * * *
(iv) For a PAL or Green Group 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.
* * * * *
(r) * * *
(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 Green Group 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.
* * * * *
(dd) Green Groups. The provisions in paragraphs (dd)(1) through
(17) of this section govern Green Groups.
(1) Applicability. The Administrator may issue a permit pursuant to
this section designating a Green Group at any existing major stationary
source if the permit contains terms and conditions assuring that the
Green Group meets the requirements in paragraphs (dd)(1) through (17)
of this section.
(i) Changes at a Green Group. Any physical change in or change in
the method of operation authorized for a Green Group pursuant to the
requirements in paragraphs (dd)(1) through (17) of this section that
maintains the Green Group's total emissions at or below the Green Group
emissions limit and maintains the Green Group's compliance with its
best available control technology (BACT) limit(s):
(a) Is not a major modification for the Green Group pollutant;
(b) Does not have to be approved through the PSD program; and
(c) Is not subject to the provisions of paragraphs (j)(4) and
(r)(2) of this section.
(ii) Prior requirements. Except as provided under paragraph
(dd)(1)(i)(c) of this section, a major stationary source shall continue
to comply with all remaining applicable Federal or State requirements,
emissions limitations, and work practice requirements that were
established prior to the effective date of the Green Group.
(2) Definitions. For the purposes of this paragraph (dd), the
definitions in paragraphs (dd)(2)(i) through (iv) of this section
apply. When a term is not defined in these paragraphs, it shall have
the meaning given in paragraph (b) or (aa) of this section or in the
Act.
(i) Green Group means a group of new and/or existing emissions
activities that is characterized by use of a common, dedicated air
pollution control device and that has been designated as a Green Group
by the Administrator in a permit issued pursuant to this section. A
Green Group is a single emissions unit for purposes of this section.
(ii) Green Group pollutant means a pollutant emitted from the
emissions activities that comprise the Green Group and for which a
Green Group is designated at a major stationary source.
(iii) Green Group permit means the major NSR permit issued by the
Administrator that establishes a Green Group for a major stationary
source.
(iv) Green Group emissions limit means an emissions limitation for
the Green Group pollutant, expressed in tons per year, that is
enforceable as a practical matter and established for a Green Group at
a major stationary source in accordance with paragraphs (dd)(1) through
(17) of this section.
(3) Permit application requirements. The owner or operator of a
major stationary source must request approval for a Green Group in an
application for a major NSR permit that meets the requirements of
paragraphs (j) through (r)(5) of this section, as applicable. As part
of a permit application requesting a Green Group, the owner or operator
of a major stationary source shall submit the following information to
the Administrator for approval:
(i) List of designated emissions activities. A list of the
emissions activities proposed for inclusion in the Green Group. In
addition, the owner or operator of the source shall indicate which, if
any, Federal or State applicable requirements, emissions limitations,
or work practices apply to each activity.
(ii) Baseline actual emissions. Calculations of the baseline actual
emissions from included emissions activities (with supporting
documentation). Baseline actual emissions are to include emissions
associated not only with operation of the activity, but also emissions
associated with startup, shutdown, and malfunction.
(iii) Monitoring data conversion procedures. 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 (dd)(15)(i) of this section.
(iv) Description. A description of the equipment that comprises the
Green Group, including a description of existing emissions activities,
proposed physical changes or changes in method
[[Page 52255]]
of operation (which may include the addition of new emissions
activities), and the common air pollution control device. The
description must provide information about maximum total emissions that
will be generated by the Green Group's emissions activities and the
associated characteristics of the combined emissions streams (including
the worst-case emissions stream) that will be ducted to the common air
pollution control device. The description must be sufficient:
(a) To allow the Administrator to distinguish changes proposed to
be authorized in the Green Group from unauthorized changes; and
(b) To enable the Administrator to determine BACT for the Green
Group consistent with paragraphs (dd)(4)(ii) and (dd)(7)(vi) of this
section.
(v) Control technology demonstration. A demonstration that the
proposed control technology represents BACT. Such a demonstration shall
confirm that the emissions reduction capacity of the proposed common
control device is sufficient to meet the relevant emissions reduction
requirement, considering the maximum total emissions from the Green
Group and the associated characteristics of the combined emissions
streams that will be ducted to the common air pollution control device.
The BACT demonstration shall be based on worst-case emissions from the
new and existing emissions activities authorized for the Green Group.
(vi) Monitoring system. A proposed monitoring system sufficient to
meet the requirements of paragraph (dd)(13) of this section with
respect to Green Group emissions limit(s) and the requirements of
paragraph (dd)(14) of this section with respect to BACT-related
limitations.
(vii) Proposed Green Group emissions limit. The proposed Green
Group emissions limit, in tons per year, with supporting documentation
including, but not limited to, the following:
(a) Baseline actual emissions of existing emissions activities
proposed to be included in the Green Group, adjusted to reflect the
application of BACT; and
(b) The amount of emissions growth proposed for the Green Group as
the result of the proposed physical, operational, and other changes.
(4) General requirements for designating a Green Group. The
Administrator may designate a Green Group at an existing major
stationary source through issuance of a PSD permit according to the
requirements of this section, provided that in addition the
requirements in paragraphs (dd)(4)(i) through (vii) of this section are
met.
(i) Green Group emissions limit. The Administrator, consistent with
paragraph (dd)(6) of this section, shall establish a Green Group
emissions limit in tons per year for those emissions activities
included under the Green Group (including any new emissions activities
added within the Green Group). For each month during the Green Group
effective period after the first 12 months of establishing the Green
Group, the major stationary source owner or operator shall show that
the sum of the monthly emissions from each included emissions activity
for the previous 12 consecutive months is less than or equal to the
Green Group emissions limit (i.e. a 12-month total, rolled monthly).
For each month during the first 11 months from the Green Group
effective date, the major stationary source owner or operator shall
show that the sum of the preceding monthly emissions from the Green
Group effective date for each emissions activity under the Green Group
is less than or equal to the Green Group emissions limit.
(ii) BACT emissions limit. The Administrator shall determine BACT
for the emissions of the Green Group pollutant from the group of
emissions activities designated as a Green Group. The BACT emissions
limit shall ensure that the emissions of the emissions activities
included in the Green Group are ducted to a common, dedicated air
pollution control device and ensure compliance with any applicable
emissions limitation under the State Implementation Plan and each
applicable emission standard and standard of performance under 40 CFR
parts 60 and 61. The control device, in combination with any additional
control measures consistent with paragraphs (dd)(4)(ii)(a) and (b) of
this section, must achieve the BACT level of emissions reductions for
the Green Group pollutant.
(a) In addition to the requirement to duct emissions from the Green
Group to a common air pollution control device, additional control
measures such as pollution prevention (as defined under paragraph
(b)(39) of this section), work practices, and/or operational standards
may be defined as part of the approved control measures.
(b) Pollution prevention measures that have been determined to
represent BACT may be approved to apply during certain periods of
operation. The included emissions activities must have ductwork
extending to the common air pollution control device, but the owner or
operator would be allowed to bypass the control device during periods
when the pollution prevention alternative is in use, consistent with
the BACT determination. Emissions activities that exclusively use the
pollution prevention alternative and never use the common air pollution
control device may not be included in the Green Group.
(iii) Permit content. The Green Group permit shall contain all the
requirements of paragraph (dd)(7) of this section.
(iv) Included emissions. The Green Group emissions limit shall
include fugitive emissions of the Green Group pollutant, to the extent
quantifiable, from all emissions activities included under the Green
Group.
(v) Regulated pollutant. Each Green Group shall regulate emissions
of only one pollutant. However, the same collection of emissions
activities may be designated separately as a Green Group for another
pollutant.
(vi) Effective period. Each Green Group designation shall have an
effective period of 10 years.
(vii) Monitoring, recordkeeping, and reporting. The Green Group
permit shall require the owner or operator to comply with the
monitoring, recordkeeping, and reporting requirements provided in
paragraphs (dd)(13) through (16) of this section for each included
emissions activity.
(5) General provisions for Green Groups. The provisions set out in
paragraphs (dd)(5)(i) through (iv) apply to Green Groups:
(i) Any project for which the owner or operator begins actual
construction after the effective date of a Green Group designation and
before its expiration date will be considered to have occurred while
the emissions unit was a Green Group.
(ii) At no time (during or after the Green Group effective period)
are emissions reductions of a Green Group pollutant that occur during
the Green Group effective period creditable as decreases for purposes
of offsets under Sec. 51.165(a)(3)(ii) of this chapter unless the
Green Group emissions limit is reduced by the amount of such emissions
reductions and such reductions would be creditable in the absence of
the Green Group designation. No emissions reduction credit can be
generated for emissions growth that was authorized under the Green
Group permit, but never realized.
(iii) At no time (during or after the Green Group effective period)
are emissions increases or reductions of a Green Group pollutant that
occur during the Green Group effective period creditable for purposes
of calculating a net emissions increase under paragraph
[[Page 52256]]
(b)(3) of this section (that is, must not be used in a ``netting
analysis''), unless the Green Group emissions limit is reduced by the
amount of such emissions reductions and such reductions would be
creditable in the absence of the Green Group designation. No emissions
reduction credit can be generated for emissions growth that was
authorized under the Green Group permit, but never realized.
(iv) The Green Group 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 Green Group is located in an attainment
area and the area is redesignated to nonattainment, its Green Group
designation is not affected. Similarly, redesignation from
nonattainment to attainment does not affect the Green Group
designation. However, if an existing Green Group designation expires,
it must re-qualify under the requirements that are currently applicable
in the area.
(6) Setting the 10-year Green Group emissions limit. (i) Except as
provided in paragraphs (dd)(6)(ii) through (iv) of this section, the
Green Group emissions limit shall be established as the sum of the
baseline actual emissions (as defined in paragraph (b)(48) of this
section) of the Green Group pollutant for each emissions activity
included in the Green Group. When establishing the Green Group
emissions limit, for a Green Group pollutant, a single period of 24
consecutive months must be used to determine the baseline actual
emissions for all existing emissions activities. However, a different
period of 24 consecutive months may be used for each different Green
Group pollutant. Emissions associated with activities that were
permanently shut down after this 24-month period must be subtracted
from the Green Group emissions limit. The Administrator shall specify a
reduced Green Group emissions limit(s) (in tons/yr) in the Green Group
permit to become effective on the future compliance date(s) of any
applicable Federal or State regulatory requirement(s) that the
Administrator is aware of prior to issuance of the Green Group permit.
(ii) For activities (which do not include modifications to existing
units) on which actual construction began after the 24-month period, in
lieu of adding the baseline actual emissions as specified in paragraph
(dd)(6)(i) of this section, the emissions must be added to the Green
Group emissions limit in an amount equal to the potential to emit of
the activities.
(iii) The Administrator shall establish the Green Group emissions
level by adjusting the total derived according to paragraphs (dd)(6)(i)
and (ii) of this section to reflect:
(a) The application of BACT; and
(b) An additional amount of actual emissions consistent with the
growth approved for the Green Group.
(iv) Notwithstanding the methodology set out above in paragraphs
(dd)(6)(i) through (iii) of this section, the Administrator shall
reduce the Green Group emissions limit and/or establish short-term
emissions limits as necessary to meet other applicable requirements of
this section, including the requirements of paragraphs (k) and (p).
(7) Content of the Green Group permit. The Green Group permit must
contain the elements listed in paragraphs (dd)(7)(i) through (xiv) of
this section and any other provisions that the Administrator deems
necessary to implement the Green Group.
(i) The Green Group pollutant.
(ii) A description of the equipment that comprises the Green Group,
including a description of existing emissions activities, any
authorized physical changes or changes in method of operation, and the
common air pollution control device. The description must provide
information about the maximum total emissions that will be generated by
the Green Group's emissions activities and the associated
characteristics of the combined emissions streams that will be ducted
to the common air pollution control device. The description must be
sufficient to distinguish, when a change is subsequently made in the
Green Group, whether that change was authorized under the Green Group
permit.
(iii) A statement designating the described equipment as a Green
Group.
(iv) The Green Group emissions limit (in terms of a 12-month total,
rolled monthly) for the group of emissions activities included under
the Green Group.
(v) Any shorter-term emissions limits that are necessary to
safeguard ambient air quality, as determined according to the
requirements of this section.
(vi) All emissions limitations and work practice requirements
established to ensure that BACT is met.
(vii) The Green Group effective date and the expiration date of the
Green Group (i.e., the Green Group effective period). If the source
owner or operator must construct a new air pollution control device or
modify an existing device as a result of the BACT determination for the
Green Group, the permit may provide that the existing emissions
activities within the Green Group are not required to meet the BACT
emissions limitation(s) or the Green Group emissions limit until the
new or modified air pollution control device is in operation. (That is,
such emissions activities may continue to meet pre-existing emissions
limitations until that time.) However, new and modified emissions
activities within the Green Group must be subject to BACT upon startup.
In addition, the Green Group must be subject to the Green Group
emissions limit (and associated monitoring, recordkeeping, and
reporting requirements) beginning at the time that the new or modified
air pollution control device is placed in operation.
(viii) Specification in the Green Group permit that if a major
stationary source owner or operator applies to renew a Green Group in
accordance with paragraph (dd)(11) of this section before the end of
the effective period, then the Green Group shall not expire at the end
of the effective period. It shall remain in effect until a new Green
Group permit is issued by the Administrator.
(ix) A requirement that emissions calculations for compliance
purposes must include emissions from startups, shutdowns, and
malfunctions.
(x) A requirement that, once the Green Group expires, the major
stationary source is subject to the requirements of paragraph (dd)(10)
of this section.
(xi) 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 (dd)(15)(i) of this section.
(xii) A requirement that the major stationary source owner or
operator meet all applicable requirements for monitoring, testing, and
operation in accordance with the provisions under paragraphs (dd)(13)
and (14) of this section.
(xiii) A requirement to retain the records required under paragraph
(dd)(15) of this section on site. Such records may be retained in an
electronic format.
(xiv) A requirement to submit the reports required under paragraph
(dd)(16) of this section by the required deadlines.
(8) Green Group effective period. The Administrator shall specify
an effective period of 10 years. The effective period begins upon the
Green Group effective date, which is the date that the Green Group
permit becomes effective.
(9) Reopening of the Green Group permit. The requirements in
paragraphs (dd)(9)(i) through (iii) of this section apply to reopening
Green Group permits.
[[Page 52257]]
(i) Mandatory reopenings. During the Green Group effective period,
the Administrator must reopen the Green Group permit to:
(a) Correct typographical/calculation errors made in setting the
Green Group emissions limit or reflect a more accurate determination of
emissions used to establish this limit;
(b) Reduce the Green Group emissions limit 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
(c) Reduce the Green Group emissions limit if the owner or operator
of the major stationary source creates creditable emissions reductions
for use in a netting analysis under paragraph (b)(3) of this section.
(ii) Discretionary reopenings. The Administrator shall have
discretion to reopen the Green Group permit for the purposes listed in
paragraphs (dd)(9)(ii)(a) through (c) of this section. If the
Administrator declines to reopen the Green Group permit for any of
these purposes, the Green Group emissions limit must be adjusted upon
expiration of the Green Group designation or upon renewal of the
source's title V permit, whichever comes first. The major stationary
source owner or operator is responsible for compliance with any new
applicable requirements, regardless of when the permit is reopened and
adjusted.
(a) To reduce the Green Group emissions limit to reflect newly
applicable Federal requirements (for example, NSPS) with compliance
dates after the Green Group effective date;
(b) To reduce the emissions limit 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
(c) To reduce the emissions limit if the Administrator 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.
(iii) Required process. Except for the permit reopening in
paragraph (dd)(9)(i)(a) of this section for the correction of
typographical/calculation errors that do not increase the Green Group
emissions limit, all other reopenings shall be carried out in
accordance with the public participation requirements of paragraph (q)
of this section.
(10) Expiration of a Green Group. Any Green Group designation that
is not renewed in accordance with the procedures in paragraph (dd)(11)
of this section shall expire at the end of its effective period. After
expiration of the Green Group designation, the following provisions
apply:
(i) The emissions unit defined by the Green Group remains an
emissions unit for purposes of major NSR and remains subject to the
BACT control requirements; Green Group emissions limit; any shorter-
term emissions limits; and monitoring recordkeeping, reporting, and
testing requirements imposed by the Green Group permit.
(ii) 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 or prior to the
Green Group effective period.
(iii) Any subsequent physical change or change in the method of
operation at the emissions unit defined by the Green Group will be
subject to PSD requirements if such change meets the definition of
major modification in paragraph (b)(2) of this section.
(11) Renewal of a Green Group. The following provisions apply to
renewal of a Green Group:
(i) Required procedures. A Green Group may be renewed through
issuance of a new major NSR permit according to all the requirements of
this paragraph (dd) for the initial Green Group designation.
(ii) Application deadline. A major stationary source owner or
operator shall submit a timely application to the Administrator to
request renewal of a Green Group. A timely application is one that is
submitted at least 6 months prior to, but not earlier than 18 months
from, the date that the Green Group designation would otherwise expire.
This deadline for application submittal is to ensure that the Green
Group designation will not expire before the Green Group is renewed. If
the owner or operator of a major stationary source submits a complete
application to renew the Green Group within this time period, then the
Green Group shall continue to be effective until the new PSD permit
with the renewed Green Group is issued.
(12) Increasing a Green Group emissions limit during its effective
period. The Administrator may increase a Green Group emissions limit
during its effective period only if the increase is contained in a new
permit incorporating the increase into a new Green Group consistent
with the requirements of this section.
(13) Monitoring requirements for Green Group emissions limitations.
(i) General requirements.
(a) Each Green Group permit must contain enforceable requirements
for the monitoring system that accurately determines, in terms of mass
per unit of time, emissions of the Green Group pollutant from the
emissions activities under the Green Group. Any monitoring system
authorized for use in the Green Group 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 Green Group permit.
(b) The Green Group monitoring system must employ one or more of
the four general monitoring approaches meeting the minimum requirements
set forth in paragraphs (dd)(13)(ii)(a) through (d) of this section and
must be approved by the Administrator.
(c) Notwithstanding paragraph (dd)(13)(i)(b) of this section, you
may also employ an alternative monitoring approach that meets paragraph
(dd)(13)(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 Green Group 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 (dd)(13)(iii) through (ix) of this section:
(a) Mass balance calculations for activities using coatings or
solvents;
(b) CEMS;
(c) CPMS or PEMS; and
(d) Emissions factors.
(iii) Mass balance calculations. An owner or operator using mass
balance calculations to monitor the Green Group 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 Green Group pollutant that is contained in or created by
all materials used in or at the emissions activity;
(b) Assume that the emissions activity emits all of the Green Group
pollutant that is contained in or created by any raw material or fuel
used in or at the emissions activity, 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
[[Page 52258]]
emissions activity, publishes a range of pollutant content from such
material, the owner or operator must use the highest value of the range
to calculate the Green Group pollutant emissions unless the
Administrator 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 Green Group
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 activity is operating.
(v) CPMS or PEMS. An owner or operator using CPMS or PEMS to
monitor Green Group 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 Green Group pollutant emissions across the range of operation of
the emissions activity; 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 activity is operating.
(vi) Emissions factors. An owner or operator using emissions
factors to monitor Green Group pollutant emissions shall meet the
following requirements:
(a) All emissions factors shall be adjusted, if appropriate, to
account for the degree of uncertainty or limitations in the factors'
development;
(b) The emissions activity shall operate within the designated
range of use for the emissions factor, if applicable; and
(c) If technically practicable, the owner or operator of a
significant or major emissions activity that relies on an emissions
factor to calculate Green Group pollutant emissions shall conduct
validation through performance testing or other scientifically valid
means approved by the Administrator to determine a site-specific
emissions factor. Such testing or other means shall occur within 6
months of Green Group permit issuance.
(vii) Missing data procedures. A source owner or operator must
record and report maximum potential emissions without considering
enforceable emissions limitations or operational restrictions for an
emissions activity during any period of time that there is no
monitoring data, unless another method for determining emissions during
such periods is specified in the Green Group permit.
(viii) Alternative requirements. Notwithstanding the requirements
in paragraphs (dd)(13)(iii) through (vii) of this section, where an
owner or operator of an emissions activity cannot demonstrate a
correlation between the monitored parameter(s) and the Green Group
pollutant emissions rate at all operating points of the emissions
activity, the Administrator shall, at the time of permit issuance:
(a) Establish default value(s) for determining compliance with the
Green Group emissions limit based on the highest potential emissions
reasonably estimated at such operating point(s); or
(b) Determine that operation of the emissions activity during
operating conditions when there is no correlation between monitored
parameter(s) and the Green Group pollutant emissions is a violation of
the Green Group emissions limit.
(ix) Re-validation. All data used to establish the Green Group
pollutant emissions must be re-validated 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
Green Group.
(14) Additional monitoring requirements for BACT. The permit shall
also require the owner or operator with a Green Group to monitor,
measure, and record data sufficient to determine whether:
(i) The emissions reduction measures (including the Green Group air
pollution control device) meet the emissions limitations and/or work
practice requirements adopted in conjunction with BACT; and
(ii) The demonstrated capacity of the Green Group air pollution
control device was exceeded by the emissions stream(s) directed to it
at any time during the reporting period. The capacity of the control
device is considered exceeded if the characteristics of the emissions
stream entering the device are outside the range for which it has been
demonstrated that the device can achieve BACT, absent valid monitoring
data (from a continuous monitoring system or other monitoring approach
approved for such use by the Administrator) showing compliance with
BACT at the new operating level. A period of exceedance is considered a
deviation for purposes of recordkeeping and reporting.
(15) Recordkeeping requirements.
(i) Records to determine compliance. The Green Group permit shall
require an owner or operator to retain a copy of all records necessary
to determine compliance with any requirement of paragraph (dd) of this
section and of the Green Group permit, including a determination of
each emissions activity's 12-month rolling total emissions, for 5 years
from the date of such record.
(ii) Other records. The Green Group permit shall require an owner
or operator to retain a copy of the following records for the duration
of the Green Group effective period plus 5 years:
(a) A copy of the Green Group permit application and any
applications for revisions to the Green Group permit; and
(b) Each annual certification of compliance pursuant to title V and
the data relied on in certifying the compliance.
(16) 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 (dd)(16)(i) through (iii) of this section.
(i) Semi-annual report. The semi-annual 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 (dd)(16)(i)(a) through (g) of this section.
(a) The identification of owner and operator and the permit number.
(b) Total annual emissions (tons per year) from the emissions
activities included under the Green Group, based on a 12-month rolling
total for each month in the reporting period recorded pursuant to
paragraph (dd)(15)(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 Green Group pollutant emissions.
(d) A list of any emissions activities included under the Green
Group that were added 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
[[Page 52259]]
anticipated date that the monitoring system will be fully operational
or replaced with another monitoring system, and whether the emissions
activity monitored by the monitoring system continued to operate, and
the calculation of the emissions of the pollutant or the number
determined by the method included in the permit, as provided by
paragraph (dd)(13)(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 Green Group emissions limit or emissions reduction requirement
(e.g., BACT limit), including periods where no monitoring is available.
A report submitted pursuant to Sec. 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 Sec. 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 Green Group 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 re-validation test or method
within 3 months after completion of such test or method.
(17) Transition requirements. The Administrator may not issue a
Green Group permit that does not comply with the requirements in
paragraphs (dd)(1) through (17) of this section or their equivalent
after [EFFECTIVE DATE OF FINAL RULE]. The Administrator may supersede
any Green Group permit that was established prior to [EFFECTIVE DATE OF
FINAL RULE] with a Green Group permit that complies with the
requirements of paragraphs (dd)(1) through (17) of this section.
PART 70--[AMENDED]
6. The authority citation for part 70 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
7. Section 70.2 is amended by adding definitions of ``Alternative
operating scenario (AOS)'' and ``Approved replicable methodology
(ARM)'' in alphabetical order, to read as follows:
Sec. 70.2 Definitions.
* * * * *
Alternative operating scenario (AOS) means a scenario authorized in
a part 70 permit that involves a physical or operational change at the
part 70 source for a particular emissions unit, and that subjects the
unit to one or more applicable requirements that differ from those
applicable to the emissions unit prior to implementation of the change
or renders inapplicable one or more requirements previously applicable
to the emissions unit prior to implementation of the change.
* * * * *
Approved replicable methodology (ARM) means part 70 permit terms
that:
(1) Specify a protocol which is consistent with and implements an
applicable requirement, or requirement of this part, such that the
protocol is based on sound scientific/mathematical principles and
provides reproducible results using the same inputs; and
(2) Require the results of that protocol to be used for assuring
compliance with such applicable requirement or requirement of this
part, including where an ARM is used for determining applicability of a
specific requirement to a particular change.
* * * * *
8. Section 70.4 is amended by revising paragraph (d)(3)(xi) to read
as follows:
Sec. 70.4 State program submittals and transition.
* * * * *
(d) * * *
(3) * * *
(xi) Approval of AOSs. The program submittal must include
provisions to insure that AOSs requested by the source and approved by
the permitting authority are included in the part 70 permit pursuant to
Sec. 70.6(a)(9).
* * * * *
9. Section 70.5 is amended as follows:
a. By revising paragraph (c)(2);
b. By revising paragraph (c)(3)(iii);
c. By revising paragraph (c)(7);
d. By adding paragraph (c)(8)(ii)(D); and
e. By adding paragraph (c)(8)(iii)(D).
The additions and revisions read as follows:
Sec. 70.5 Permit applications.
* * * * *
(c) * * *
(2) A description of the source's processes and products (by
Standard Industrial Classification Code) including those associated
with any AOS identified by the source.
(3) * * *
(iii) Emissions rate in tpy and in such terms as are necessary to
establish compliance consistent with the applicable standard reference
test method. For emissions units subject to an emissions cap, tpy can
be reported as part of the aggregate emissions associated with the cap,
except where more specific information is needed to determine an
applicable requirement.
* * * * *
(7) Additional information as determined to be necessary by the
permitting authority to define AOSs identified by the source pursuant
to Sec. 70.6(a)(9) of this part or to define permit terms and
conditions implementing any AOS under Sec. 70.6(a)(9) or implementing
Sec. 70.4(b)(12) or Sec. 70.6(a)(10) of this part. The permit
application shall include documentation demonstrating that the source
has obtained all authorization(s) required under the applicable
requirements relevant to any proposed AOSs, or a certification that the
source has submitted all relevant materials, including permit
application(s) to the appropriate permitting authority, for obtaining
such authorization(s).
(8) * * *
(ii) * * *
(D) For applicable requirements associated with an AOS, a statement
that the source will meet such requirements upon implementation of the
AOS. If an AOS implicates an applicable requirement that will become
effective during the permit term, a statement that the source will meet
such requirements on a timely basis.
(iii) * * *
(D) For applicable requirements associated with an AOS, a statement
that the source will meet such requirements upon implementation of the
AOS. If an AOS involves an applicable requirement that will become
effective during the permit term, a statement that the source will meet
such requirements on a timely basis. A statement that the source will
meet in a timely manner applicable requirements that become effective
during the permit term will satisfy this provision, unless a more
detailed schedule is expressly required by the applicable requirement.
* * * * *
10. Section 70.6 is amended by revising paragraphs (a)(1)
introductory
[[Page 52260]]
text, (a)(3)(iii)(A), and (a)(9) to read as follows:
Sec. 70.6 Permit content.
(a) * * *
(1) Emissions limitations and standards, including those
operational requirements and limitations that assure compliance with
all applicable requirements at the time of permit issuance, such as
ARMs.
* * * * *
(3) * * *
(iii) * * *
(A) Submittal of reports of any required monitoring at least every
6 months. All instances of deviations from permit requirements must be
clearly identified in such reports, and the reports must identify the
AOSs and relevant ARMs implemented during the reporting period. All
required reports must be certified by a responsible official consistent
with Sec. 70.5(d) of this part.
* * * * *
(9) Terms and conditions for reasonably anticipated alternative
operating scenarios (AOSs) identified by the source in its application
as approved by the permitting authority. Such terms and conditions:
(i) Shall require the source, contemporaneously with making a
change from one operating scenario to another, to record in a log at
the permitted facility a record of the AOS under which it is operating.
The log shall include a description of the change that triggered the
AOS; the emissions unit(s) included in the AOS; the applicable
requirements and other permit terms and conditions that apply to the
AOS; and the date the source began to operate the AOS;
(ii) May extend the permit shield described in paragraph (f) of
this section to all terms and conditions under each such AOS; and
(iii) Must ensure that the terms and conditions of each AOS meet
all applicable requirements and the requirements of this part. The
permit terms must include a description of the emissions units, the
anticipated changes, and the applicable requirements included in the
AOS, and must describe how the source will comply with such
requirements. The permitting authority shall not approve an AOS into
the part 70 permit until the source has obtained all authorizations
required under any applicable requirement relevant to that AOS.
* * * * *
PART 71--[AMENDED]
11. The authority citation for part 71 continues to read as
follows:
Authority: 42 U.S.C. 7401, et seq.
12. Section 71.2 is amended by adding definitions of ``Alternative
operating scenario (AOS)'' and ``Approved replicable methodology
(ARM)'' in alphabetical order, to read as follows:
Sec. 71.2 Definitions.
* * * * *
Alternative operating scenario (AOS) means a scenario authorized in
a part 71 permit that involves a physical or operational change at the
part 71 source for a particular emissions unit, and that subjects the
unit to one or more applicable requirements that differ from those
applicable to the emissions unit prior to implementation of the change
or renders inapplicable one or more requirements previously applicable
to the emissions unit prior to implementation of the change.
* * * * *
Approved replicable methodology (ARM) means part 71 permit terms
that:
(1) Specify a protocol which is consistent with and implements an
applicable requirement, or requirement of this part, such that the
protocol is based on sound scientific/mathematical principles and
provides reproducible results using the same inputs; and
(2) Require the results of that protocol to be used for assuring
compliance with such applicable requirement or requirement of this
part, including where an ARM is used for determining applicability of a
specific requirement to a particular change.
* * * * *
13. Section 71.5 is amended as follows:
a. By revising paragraph (c)(2);
b. By revising paragraph (c)(3)(iii);
c. By revising paragraph (c)(7);
d. By adding paragraph (c)(8)(ii)(D); and
e. By adding paragraph (c)(8)(iii)(D).
The additions and revisions read as follows:
Sec. 71.5 Permit applications.
* * * * *
(c) * * *
(2) A description of the source's processes and products (by
Standard Industrial Classification Code) including those associated
with any AOS identified by the source.
(3) * * *
(iii) Emissions rates in tpy and in such terms as are necessary to
establish compliance consistent with the applicable standard reference
test method. For emissions units subject to an emissions cap, tpy can
be reported as part of the aggregate emissions associated with the cap,
except where more specific information is needed to determine an
applicable requirement.
* * * * *
(7) Additional information as determined to be necessary by the
permitting authority to define AOSs identified by the source pursuant
to Sec. 71.6(a)(9) or to define permit terms and conditions
implementing any AOS under Sec. 71.6(a)(9) or implementing Sec.
71.6(a)(10) or Sec. 71.6(a)(13). The permit application shall include
documentation demonstrating that the source has obtained all
authorization(s) required under the applicable requirements relevant to
any proposed AOSs, or a certification that the source has submitted all
relevant materials, including permit application(s) to the appropriate
permitting authority, for obtaining such authorization(s).
(8) * * *
(ii) * * *
(D) For applicable requirements associated with an AOS, a statement
that the source will meet such requirements upon implementation of the
AOS. If an AOS implicates an applicable requirement that will become
effective during the permit term, a statement that the source will meet
such requirements on a timely basis.
(iii) * * *
(D) For applicable requirements associated with an AOS, a statement
that the source will meet such requirements upon implementation of the
AOS. If an AOS includes an applicable requirement that will become
effective during the permit term, a statement that the source will meet
such requirements on a timely basis. A statement that the source will
meet in a timely manner applicable requirements that become effective
during the permit term will satisfy this provision, unless a more
detailed schedule is expressly required by the applicable requirement.
* * * * *
14. Section 71.6 is amended by revising paragraphs (a)(1)
introductory text, (a)(3)(iii)(A), and (a)(9) to read as follows:
Sec. 71.6 Permit content.
(a) * * *
(1) Emissions limitations and standards, including those
operational requirements and limitations that assure compliance with
all applicable requirements at the time of permit issuance, such as
ARMs.
* * * * *
[[Page 52261]]
(3) * * *
(iii) * * *
(A) Submittal of reports of any required monitoring at least every
6 months. All instances of deviations from permit requirements must be
clearly identified in such reports, and the reports must identify the
AOSs and relevant ARMs implemented during the reporting period. All
required reports must be certified by a responsible official consistent
with Sec. 71.5(d).
* * * * *
(9) Terms and conditions for reasonably anticipated alternative
operating scenarios (AOSs) identified by the source in its application
as approved by the permitting authority. Such terms and conditions:
(i) Shall require the source, contemporaneously with making a
change from one operating scenario to another, to record in a log at
the permitted facility a record of the AOS under which it is operating.
The log shall include a description of the change that triggered the
AOS; the emissions unit(s) included in the AOS; the applicable
requirements and other permit terms and conditions that apply to the
AOS; and the date the source began to operate the AOS;
(ii) May extend the permit shield described in paragraph (f) of
this section to all terms and conditions under each such AOS; and
(iii) Must ensure that the terms and conditions of each AOS meet
all applicable requirements and the requirements of this part. The
permit terms must include a description of the emissions units, the
anticipated changes, and the applicable requirements included in the
AOS, and must describe how the source will comply with such
requirements. The permitting authority shall not approve an AOS into
the part 71 permit until the source has obtained all authorizations
required under any applicable requirement relevant to that AOS.
* * * * *
[FR Doc. E7-17418 Filed 9-11-07; 8:45 am]
BILLING CODE 6560-50-P