Document ID: EPA-HQ-OAR-2004-0087-0001
Agency: epa
Document Type: Proposed Rule
Title: Operating Permit Programs and Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NSR); Flexible Air Permitting Rule
Posted Date: 2007-09-12T04:00Z

[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:

------------------------------------------------------------------------
        Industry group                SIC a               NAICS b
------------------------------------------------------------------------
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.
------------------------------------------------------------------------
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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.

---------------------------------------------------------------------------

[[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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \16\ See the pilot permit report, ``Evaluation of the 
Implementation Experience with Innovative Air Permits,'' page 22.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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
.

---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \18\ Findings are discussed in more detail in the ``Evaluation 
of Implementation Experiences with Innovative Air Permits'' report, 
under Finding 8.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

     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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \27\ For the complete text of the elements that must be included 
in a title V application, see 40 CFR 70.5(c).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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
.

---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.''
---------------------------------------------------------------------------

    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