Skip to Content

Proposed Rule

Operating Permit Programs and Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NSR); Flexible Air Permitting Rule

Document Details

Information about this document as published in the Federal Register.

Published Document

This document has been published in the Federal Register. Use the PDF linked in the document sidebar for the official electronic format.

Start Preamble Start Printed Page 52206

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

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 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 www.regulations.gov or e-mail. The 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 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 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 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.

Start Further Info

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-Start Printed Page 522075515, 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.

End Further Info End Preamble Start Supplemental Information

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 groupSIC aNAICS b
Aerospace Manufacturing372336411, 336412, 332912, 336411, 335413.
Automobile Manufacturing371336111, 336112, 336712, 336211, 336992, 336322, 336312, 33633, 33634, 33635, 336399, 336212, 336213.
Industrial Organic Chemicals286325191, 32511, 325132, 325192, 225188, 325193, 32512, 325199.
Chemical Processes281325181, 325182, 325188, 32512, 325131, 325998, 331311.
Converted Paper and Paperboard Products267322221, 322222, 322223, 322224, 322226, 322231, 326111, 326112, 322299, 322291, 322232, 322233, 322211.
Magnetic Tape Manufacturing369334613.
Petroleum Refining29132411.
Other Coating Operations226, 229, 251, 252, 253, 254, 267, 358, 363313311, 313312, 314992, 33132, 337122, 337121, 337124, 337215, 337129, 37125, 337211, 337214, 337127, 322221, 322222, 322226, 335221, 335222, 335224, 335228, 333312, 333415, 333319.
Paper Mills262322121, 322122.
Pharmaceutical Manufacturing283325411, 325412, 325413, 325414.
Printing and Publishing275323114, 323110, 323111, 323113, 323112, 323115, 323119.
Pulp and Paper Mills26232211, 322121, 322122, 32213.
Semi-conductors367334413.
Specialty Chemical Batch Processes282, 283, 284, 285, 286, 287, 289, 3863251, 3252, 3253, 3254, 3255, 3256, 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 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 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. Start Printed 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).

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).

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). Start Printed 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]

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.

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]

Start Printed 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]

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]

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 Start Printed Page 52211existing 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]

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.

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 Start Printed Page 52212applicable 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.

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.

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]

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.

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 Start Printed Page 52213determine 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]

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]

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 Start Printed Page 52214these 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]
  • 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 Start Printed Page 52215changes 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]

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]

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 Start Printed Page 52216AOSs. 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.

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 Start Printed Page 52217primarily 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.

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.

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 Start Printed Page 52218anticipated 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.

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.

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.

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 Start Printed 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 Start Printed Page 52220approach might be to avoid triggering applicable requirements that require additional authorizations, such as by adopting a PAL or accepting a PTE limit.)

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.

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 Start Printed Page 52221applicable 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.

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.

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). Start Printed 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]

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]

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 Start Printed Page 52223instance, 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.

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.

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.

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.

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 Start Printed Page 52224incorrectly 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 Start Printed Page 52225implicate 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.

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]

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 (m3)) 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

Tank size, V (m3)Stored liquid maximum true vapor pressure, VP (kPa)Emissions limitation from 40 CFR part 60, subpart KbMRRT citations from 40 CFR part 60, subpart Kb
V < 75AnyNot applicableNot applicable.
75 ≤ V ≤ 114VP < 15.0Not applicableNot applicable.
75 ≤ V ≤ 11415.0 ≤ VP < 27.6None§§ 60.116b(a)-(e).
§ 60.112b(a)(1) Fixed roof w/internal floating roof; or§ 60.113b(a), § 60.115b(a), §§ 60.116b(a)-(c), (e).
75 ≤ V ≤ 11427.6 ≤ VP < 76.6§ 60.112b(a)(2) External floating roof; or§ 60.113b(b), § 60.115b(b), §§ 60.116b(a)-(c), (e).
§ 60.112b(a)(3) Closed vent system and control device ≥ 95% efficient§ 60.113b(c) or (d), § 60.115b(c) or (d), §§ 60.116b(a), (b), (e).
75 ≤ V ≤ 11476.6 ≤ VP§ 60.112b(b) Closed vent system and control device ≥ 95% efficient§ 60.113b(c) or (d), § 60.115b(c) or (d), §§ 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 Start Printed Page 52226of 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.

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).

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 m3); 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.

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 m3 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 m3 and 38 m3 because only the SIP requirements apply to these tanks regardless of the liquid that is stored. A tank that is between 38 m3 and 75 m3 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 m3 and 114 m3. 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 m3 and 114 m3

Operating scenario No.Tank size, V (m3)Are materials with HAPs stored?VP or VPH, as applicable (kPa) aMost stringent applicable control requirements
175 ≤ V ≤ 114NoVP < 15.0SIP.
275 ≤ V ≤ 114No15.0 ≤ VP < 27.6SIP.
375 ≤ V ≤ 114No27.6 ≤ VP < 76.6NSPS.
475 ≤ V ≤ 114No76.6 ≤ VPNSPS.
575 ≤ V ≤ 114YesVPH < 13.1SIP.
675 ≤ V ≤ 114Yes13.1 ≤ VPH < 76.6HON.
775 ≤ V ≤ 114Yes76.6 ≤ VPHHON.
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 Start Printed Page 52227existing 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 Start Printed Page 52228sources.[45] We also take comment on whether instead the Green Groups should be a voluntary rather than a mandatory program element for States.

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.

Start Printed 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.

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 Start Printed Page 52230activities 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).

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 Start Printed Page 52231spray 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.

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.

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.

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.

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.

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 Start Printed Page 52232new 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]

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.

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, Start Printed Page 52233including 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.

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.

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.

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 Start Printed Page 52234meet 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]

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]

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 Start Printed Page 52235stringent 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]

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 Start Printed Page 52236determination 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.

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 Start Printed Page 52237considered 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 Start Printed Page 52238Green 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 Start Printed Page 52239particular, 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).

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 Start Printed Page 52240authority 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 Start Printed Page 52241control 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 Start Printed Page 52242promote 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.

Start List of Subjects

List of Subjects

End List of Subjects Start Signature

Dated: August 28, 2007.

Stephen L. Johnson,

Administrator.

End Signature

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.

Start Part

PART 51—[AMENDED]

1. The authority citation for part 51 continues to read as follows:

Start Authority

Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q.

End Authority

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:

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 Start Printed Page 52243procedures 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 Start Printed Page 52244control 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. Start Printed 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 Start Printed Page 52246comes 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. Start Printed 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 Start Printed Page 52248program) 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 § 70.6(a)(3)(iii)(B) of this chapter shall satisfy this reporting requirement. The deviation reports shall be submitted within the time limits prescribed by the applicable program implementing § 70.6(a)(3)(iii)(B) of this chapter. The reports shall contain the following information:

(A) The identification of owner and operator and the permit number;

(B) The 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:

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 Start Printed Page 52249requirements, 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 Start Printed 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 § 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. Start Printed 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 § 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. Start Printed 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 Start Printed Page 52253emissions 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 § 70.6(a)(3)(iii)(B) of this chapter shall satisfy this reporting requirement. The deviation reports shall be submitted within the time limits prescribed by the applicable program implementing § 70.6(a)(3)(iii)(B) of this chapter. The reports shall contain the following information:

(a) The identification of owner and operator and the permit number;

(b) The 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.

End Part Start Part

PART 52—[AMENDED]

4. The authority citation for part 52 continues to read as follows:

Start Authority

Authority: 42 U.S.C. 7401 et seq.

End Authority

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:

Prevention of significant deterioration of air quality.

(a) * * *

(2) * * *Start Printed 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 Start Printed Page 52255of 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 § 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 Start Printed 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. Start Printed 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 Start Printed Page 52258emissions 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 Start Printed Page 52259anticipated 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 § 70.6(a)(3)(iii)(B) of this chapter shall satisfy this reporting requirement. The deviation reports shall be submitted within the time limits prescribed by the applicable program implementing § 70.6(a)(3)(iii)(B) of this chapter. The reports shall contain the following information:

(a) The identification of owner and operator and the permit number;

(b) The 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.

End Part Start Part

PART 70—[AMENDED]

6. The authority citation for part 70 continues to read as follows:

Start Authority

Authority: 42 U.S.C. 7401, et seq.

End Authority

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:

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:

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 § 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:

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 § 70.6(a)(9) of this part or to define permit terms and conditions implementing any AOS under § 70.6(a)(9) or implementing § 70.4(b)(12) or § 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 Start Printed Page 52260text, (a)(3)(iii)(A), and (a)(9) to read as follows:

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 § 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.

* * * * *
End Part Start Part

PART 71—[AMENDED]

11. The authority citation for part 71 continues to read as follows:

Start Authority

Authority: 42 U.S.C. 7401, et seq.

End Authority

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:

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:

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 § 71.6(a)(9) or to define permit terms and conditions implementing any AOS under § 71.6(a)(9) or implementing § 71.6(a)(10) or § 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:

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.

* * * * *
Start Printed 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 § 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.

* * * * *
End Part End Supplemental Information

Footnotes

1.  We first addressed the concept of a flexibile air permit in May 1991. See 56 FR 21712, 21748 (May 10, 1991).

Back to Citation

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.

Back to Citation

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).

Back to Citation

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).

Back to Citation

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.”

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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).

Back to Citation

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.

Back to Citation

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).

Back to Citation

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.

Back to Citation

16.  See the pilot permit report, “Evaluation of the Implementation Experience with Innovative Air Permits,” page 22.

Back to Citation

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.

Back to Citation

18.  Findings are discussed in more detail in the “Evaluation of Implementation Experiences with Innovative Air Permits” report, under Finding 8.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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)).

Back to Citation

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.

Back to Citation

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.

Back to Citation

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

Back to Citation

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.

Back to Citation

29.  As needed, additional terms would be added to assure compliance with applicable requirements beyond NSR that are implicated by the advance approved changes.

Back to Citation

30.  See footnote 22.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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).

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

42.  See section VI.A of this preamble and footnote 26 for more on the streamlining of applicable requirements in a title V permit.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.”

Back to Citation

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.

Back to Citation

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).

Back to Citation

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.

Back to Citation

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.

Back to Citation

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 § 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.

Back to Citation

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.

Back to Citation

54.  Parallel requirements are found at 40 CFR 51.165(a)(5)(ii) and 51.166(r)(2).

Back to Citation

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.

Back to Citation

56.  Such credits in order to be used as an emissions offset must also be federally enforceable.

Back to Citation

57.  See 67 FR 80221 for a discussion of the MRRT requirements promulgated for PALs by the Agency in December of 2002.

Back to Citation

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.

Back to Citation

59.  See 40 CFR part 124 for permits issued under § 52.21. See § 51.161 for permits issued under State programs approved pursuant to §§ 51.165 and 51.166.

Back to Citation

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.

Back to Citation

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 § 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.

Back to Citation

62.  Vatavuk, William, “Part II, Factors for Estimating Capital and Operating Costs,” Chemical Engineering, Nov. 3, 1980.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.

Back to Citation

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.”

Back to Citation

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.

Back to Citation

[FR Doc. E7-17418 Filed 9-11-07; 8:45 am]

BILLING CODE 6560-50-P