We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the ADDRESSES section. Include “Docket No. FAA-2012-0722; Directorate Identifier 2011-NM-188-AD” at the beginning of your comments. We specifically invite comments on the overall regulatory, economic, environmental, and energy aspects of this proposed AD. We will consider all comments received by the closing date and may amend this proposed AD based on those comments.

We will post all comments we receive, without change, to http://www.regulations.gov, including any personal information you provide. We will also post a report summarizing each substantive verbal contact we receive about this proposed AD.

Transport Canada Civil Aviation (TCCA), which is the aviation authority for Canada, has issued Canadian Airworthiness Directive CF-2011-22, dated July 13, 2011 (referred to after this as “the MCAI”), to correct an unsafe condition for the specified products. The MCAI states:

The required action is replacing the AC generator with a modified or new AC generator. You may obtain further information by examining the MCAI in the AD docket.

Bombardier has issued Service Bulletin 84-24-45, dated January 13, 2011. The actions described in this service information are intended to correct the unsafe condition identified in the MCAI.

This product has been approved by the aviation authority of another country, and is approved for operation in the United States. Pursuant to our bilateral agreement with the State of Design Authority, we have been notified of the unsafe condition described in the MCAI and service information referenced above. We are proposing this AD because we evaluated all pertinent information and determined an unsafe condition exists and is likely to exist or develop on other products of the same type design.

TCCA AD CF-2011-22, dated July 13, 2011, prohibits installation of certain part numbers following the accomplishment of the replacement required by paragraph (g) of this AD. This AD prohibits installation of those part numbers as of the effective date of this AD.

Based on the service information, we estimate that this proposed AD would affect about 83 products of U.S. registry. We also estimate that it would take about 2 work-hours per product to comply with the basic requirements of this proposed AD. The average labor rate is $85 per work-hour. Required parts would cost about $0 per product. Where the service information lists required parts costs that are covered under warranty, we have assumed that there will be no charge for these parts. As we do not control warranty coverage for affected parties, some parties may incur costs higher than estimated here. Based on these figures, we estimate the cost of the proposed AD on U.S. operators to be $14,110, or $170 per product.

Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.

We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect 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.

For the reasons discussed above, I certify this proposed regulation:

1. Is not a “significant regulatory action” under Executive Order 12866;

2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);

3. Will not affect intrastate aviation in Alaska; and

4. Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

We prepared a regulatory evaluation of the estimated costs to comply with this proposed AD and placed it in the AD docket.

Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the ADDRESSES section. Include “Docket No. FAA-2011-0652; Directorate Identifier 2010-NM-045-AD” at the beginning of your comments. We specifically invite comments on the overall regulatory, economic, environmental, and energy aspects of this proposed AD. We will consider all comments received by the closing date and may amend this proposed AD because of those comments.

We will post all comments we receive, without change, to http://www.regulations.gov, including any personal information you provide. We will also post a report summarizing each substantive verbal contact we receive about this proposed AD.

We issued an NPRM to amend 14 CFR part 39 to include an AD that would apply to all The Boeing Company Model MD-90-30 airplanes. That NPRM published in the Federal Register on July 8, 2011 (76 FR 40288). That NPRM proposed to require repetitive eddy current high frequency (ETHF) inspections for cracking on the aft side of the left and right wing rear spar lower caps at station Xrs=164.000, further ETHF inspections if cracks are found, and repair if necessary. The NPRM also proposed repetitive post-repair inspections, and repair if necessary.

Since we issued the previous NPRM (76 FR 40288, July 8, 2011), we have determined that it is necessary to add repetitive inspections for cracking on the wing rear spar lower caps at station Xrs=164.000 after the splice repair is done. The replacement spar cap is susceptible to fatigue cracking because its design is the same as that of the original spar cap.

We gave the public the opportunity to comment on the previous NPRM (76 FR 40288, July 8, 2011). The following presents the comments received on the NPRM and the FAA's response to each comment.

Boeing requested that we revise the original NPRM (76 FR 40288, July 8, 2011) to require an ETHF inspection on any splice repair within 30,000 flight cycles after the repair. Boeing explained that neither Boeing Alert Service Bulletin MD90-57A026, Revision 1, dated February 23, 2011 (which was cited as the appropriate source of service information for the original NPRM), nor the original NPRM itself addresses inspection of the replaced spar cap segment for fatigue cracking at flap hinge station Xrs=164.000. Boeing noted that the design of the original and replacement spar caps is the same, so the replacement spar cap is also susceptible to the same fatigue cracking issue. Boeing suggested that this change would affect paragraphs (h)(1)(ii), (h)(2)(ii), (h)(3)(ii), (i)(1), (i)(2)(i)(C), (i)(2)(ii), and (i)(3) of the original NPRM.

Boeing also explained that they will revise Boeing Alert Service Bulletin MD90-57A026, Revision 1, dated February 23, 2011, as soon as possible.

We agree with the request, for the reasons provided by the commenter. We have added this post-repair inspection in new paragraph (j) of this AD, and re-identified subsequent paragraphs accordingly.

We are proposing this supplemental NPRM because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of the same type design. Certain changes described above expand the scope of the original NPRM (76 FR 40288, July 8, 2011). As a result, we have determined that it is necessary to reopen the comment period to provide additional opportunity for the public to comment on this supplemental NPRM.

This supplemental NPRM would require accomplishing the actions specified in the service information described previously, except as discussed under “Differences Between the Supplemental NPRM and the Service Information.”

Boeing Alert Service Bulletin MD90-57A026, Revision 1, dated February 23, 2011, does not specify corrective actions if cracking is found during any inspection of repaired areas, but this proposed AD would require repairing those conditions in one of the following ways:

• In accordance with a method that we approve; or

• Using data that meet the certification basis of the airplane, and that have been approved by the Boeing Commercial Airplanes Organization Designation Authorization (ODA) whom we have authorized to make those findings.

We estimate that this proposed AD affects 51 airplanes of U.S. registry. We estimate the following costs to comply with this proposed AD:

We have received no definitive data that would enable us to provide cost estimates for the on-condition actions specified in this AD.

Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs” describes in more detail the scope of the Agency's authority.

We are issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: “General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect 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.

For the reasons discussed above, I certify this proposed regulation:

(1) Is not a “significant regulatory action” under Executive Order 12866,

(2) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),

(3) Will not affect intrastate aviation in Alaska, and

(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal.

Communications should identify both docket numbers (FAA Docket No. FAA 2012-0705 and Airspace Docket No. 12-AWP-4) and be submitted in triplicate to the Docket Management System (see ADDRESSES section for address and phone number). You may also submit comments through the Internet at http://www.regulations.gov.

Commenters wishing the FAA to acknowledge receipt of their comments on this action must submit with those comments a self-addressed stamped postcard on which the following statement is made: “Comments to FAA Docket No. FAA-2012-0705 and Airspace Docket No. 12-AWP-4.” The postcard will be date/time stamped and returned to the commenter.

All communications received on or before the specified closing date for comments will be considered before taking action on the proposed rule. The proposal contained in this action may be changed in light of comments received. All comments submitted will be available for examination in the public docket both before and after the closing date for comments. A report summarizing each substantive public contact with FAA personnel concerned with this rulemaking will be filed in the docket.

An electronic copy of this document may be downloaded through the Internet at http://www.regulations.gov. Recently published rulemaking documents can also be accessed through the FAA's Web page at http://www.faa.gov/airports_airtraffic/air_traffic/publications/airspace_amendments/.

You may review the public docket containing the proposal, any comments received, and any final disposition in person in the Dockets Office (see the ADDRESSES section for the address and phone number) between 9:00 a.m. and 5:00 p.m., Monday through Friday, except federal holidays. An informal docket may also be examined during normal business hours at the Northwest Mountain Regional Office of the Federal Aviation Administration, Air Traffic Organization, Western Service Center, Operations Support Group, 1601 Lind Avenue SW., Renton, WA 98057.

Persons interested in being placed on a mailing list for future NPRMs should contact the FAA's Office of Rulemaking, (202) 267-9677, for a copy of Advisory Circular No. 11-2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.

The FAA is proposing an amendment to Title 14 Code of Federal Regulations (14 CFR) Part 71 by establishing Class E en route domestic airspace extending upward from 1,200 feet above the surface at Coaldale VORTAC, Coaldale, NV. This action would contain aircraft while in IFR conditions under control of the Oakland ARTCC by vectoring aircraft from en route airspace to terminal areas.

Class E airspace designations are published in paragraph 6006, of FAA Order 7400.9V, dated August 9, 2011, and effective September 15, 2011, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document will be published subsequently in this Order.

The FAA has determined this proposed regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. Therefore, this proposed regulation; (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified this proposed rule, when promulgated, would not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the U.S. Code. Subtitle 1, Section 106, describes the authority for the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of the airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it would establish controlled airspace at the Coaldale VORTAC, Coaldale, NV.

This proposal will be subject to an environmental analysis in accordance with FAA Order 1050.1E, “Environmental Impacts: Policies and Procedures” prior to any FAA final regulatory action.

Accordingly, pursuant to the authority delegated to me, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:

Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal.

Communications should identify both docket numbers (FAA Docket No. FAA 2012-0569 and Airspace Docket No. 12-ANM-17) and be submitted in triplicate to the Docket Management System (see “ ADDRESSES ” section for address and phone number). You may also submit comments through the Internet at http://www.regulations.gov.

Commenters wishing the FAA to acknowledge receipt of their comments on this action must submit with those comments a self-addressed stamped postcard on which the following statement is made: “Comments to FAA Docket No. FAA-2012-0569 and Airspace Docket No. 12-ANM-17”. The postcard will be date/time stamped and returned to the commenter.

All communications received on or before the specified closing date for comments will be considered before taking action on the proposed rule. The proposal contained in this action may be changed in light of comments received. All comments submitted will be available for examination in the public docket both before and after the closing date for comments. A report summarizing each substantive public contact with FAA personnel concerned with this rulemaking will be filed in the docket.

An electronic copy of this document may be downloaded through the Internet at http://www.regulations.gov. Recently published rulemaking documents can also be accessed through the FAA's web page at http://www.faa.gov/airports_airtraffic/air_traffic/publications/airspace_amendments/.

You may review the public docket containing the proposal, any comments received, and any final disposition in person in the Dockets Office (see the “ ADDRESSES ” section for the address and phone number) between 9:00 a.m. and 5:00 p.m., Monday through Friday, except federal holidays. An informal docket may also be examined during normal business hours at the Northwest Mountain Regional Office of the Federal Aviation Administration, Air Traffic Organization, Western Service Center, Operations Support Group, 1601 Lind Avenue SW., Renton, WA 98057.

Persons interested in being placed on a mailing list for future NPRM's should contact the FAA's Office of Rulemaking, (202) 267-9677, for a copy of Advisory Circular No. 11-2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.

The FAA is proposing an amendment to Title 14 Code of Federal Regulations (14 CFR) Part 71 by modifying Class E airspace at L M Clayton Airport, Wolf Point, MT. Controlled airspace is necessary to accommodate aircraft using the NDB standard instrument approach procedures at L M Clayton Airport, and would enhance the safety and management of aircraft operations.

Class E airspace designations are published in paragraph 6005, of FAA Order 7400.9V, dated August 9, 2011, and effective September 15, 2011, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document will be published subsequently in this Order.

The FAA has determined this proposed regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. Therefore, this proposed regulation; (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified this proposed rule, when promulgated, would not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the U.S. Code. Subtitle 1, Section 106, describes the authority for the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of the airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it would modify controlled airspace at Wolf Point, L M Clayton Airport, Wolf Point, MT.

This proposal will be subject to an environmental analysis in accordance with FAA Order 1050.1E, “Environmental Impacts: Policies and Procedures” prior to any FAA final regulatory action.

Accordingly, pursuant to the authority delegated to me, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:

Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller, John R. Norris, Cheryl A. LaFleur, and Tony T. Clark.

1. The Commission seeks comment on this proposed policy statement, which clarifies and refines current policies governing the allocation of capacity for new merchant transmission projects and new nonincumbent, cost-based, participant-funded transmission projects. In recent years, a number of merchant and nontraditional transmission developers have sought guidance from the Commission regarding application of open access principles to new transmission facilities through petitions for declaratory orders. As the Commission addressed these requests, its policies have evolved over time to provide potential customers adequate opportunities to obtain service while also providing transmission developers adequate certainty to assist with financing transmission projects. As a result of these evolving policies, different rules have been adopted regarding capacity allocation for merchant transmission projects and nonincumbent, cost-based, participant-funded transmission projects.

2. With the benefit of experience regarding the unique characteristics of merchant and other nontraditional transmission project proposals, and in consideration of industry input on Commission policies regarding the allocation of capacity on such projects, the Commission proposes to streamline its capacity allocation policies by establishing consistent policies regarding capacity allocation for both merchant transmission projects and nonincumbent, cost-based, participant-funded transmission projects. Specifically, the Commission proposes to allow developers of such projects to select a subset of customers, based on not unduly discriminatory or preferential criteria, and negotiate directly with those customers to reach agreement on the key terms and conditions for procuring capacity, when they (1) broadly solicit interest in the project from potential customers, and (2) submit a report to the Commission describing the solicitation, selection and negotiation process. The Commission proposes these policy reforms to ensure transparency in the capacity allocation process while providing developers the ability to negotiate bilaterally with potential customers the rates, terms, and conditions for the full amount of transmission capacity. These policy reforms would be implemented within the existing four factor analysis used to evaluate requests for negotiated rate authority. 1 The Commission seeks comment regarding this proposed change in policy, as discussed below.

3. The Commission first granted negotiated rate authority to a merchant transmission project developer over a decade ago, finding that merchant transmission can play a useful role in expanding competitive generation alternatives for customers. 2 Unlike traditional utilities recovering their costs-of-service from captive and wholesale customers, investors in merchant transmission projects assume the full market risk of development. 3 Over the course of a number of early proceedings, the Commission developed ten criteria to guide its analysis in making a determination as to whether negotiated rate authority would be just and reasonable for a given merchant transmission project. 4 Two of these criteria were that (1) an open season process should be employed to initially allocate all transmission capacity and (2) the results of the open season should be posted on an Open Access Same-Time Information System (OASIS) and filed in a report with the Commission. 5

4. In Chinook, the Commission refined its approach to evaluating merchant transmission by adopting a four-factor analysis. 6 Under this analysis, the Commission continues to rely upon an open season and a post-open season report as a means to provide transparency in the allocation of initial transmission capacity and ensure against undue discrimination among potential customers in the award of transmission capacity. Specifically, the Commission evaluates the terms and conditions of the open season as part of ensuring no undue discrimination (second factor), 7 and uses the open season as an added protection in overseeing any affiliate participation, to ensure no undue preference or affiliate concerns (third factor).

5. The Chinook order also marked a change in Commission policy on capacity allocation, as in that order the Commission for the first time authorized developers to allocate some portion of capacity through anchor customer presubscriptions, while requiring that the remaining portion be allocated in a subsequent open season. The Commission implemented this policy to achieve the dual goals of requiring an open season process that ensures capacity on a merchant transmission project is allocated transparently in an open, fair, and not unduly discriminatory manner, while permitting an anchor customer model that enables developers of merchant transmission projects to meet the financial challenges unique to merchant transmission development. 8 Since the Chinook order, the Commission has issued orders on several new merchant and other nontraditional transmission development proposals, including granting requests to allocate up to 75 percent of a transmission project's capacity to anchor customers. 9

6. The Commission also has received proposals from transmission developers regarding the allocation of capacity on cost-based, participant-funded transmission projects. These proceedings involved incumbent transmission developers, 10 while one involved a nonincumbent transmission developer. 11 In NU/NSTAR, the Commission approved the structure of a transaction whereby a customer was granted usage rights to transmission capacity in exchange for funding the transmission expansion, under the reasoning that any potential transmission customer has the right to request transmission service expansion from a transmission owning utility, and that utility is obligated to make any necessary system expansions and offer service at the higher of an incremental cost or an embedded cost rate to the transmission customer. More recently, in National Grid, the Commission found again that participant funding of transmission projects by incumbent transmission providers is not inconsistent with the Commission's open access requirements. 12 Cost-based participant-funded projects are similar to merchant projects in that both involve willing customers assuming part of the risk of a transmission project in return for defined capacity rights; i.e., there is no direct assignment of costs to captive customers. Cost-based participant-funded projects differ between incumbents and nonincumbents, in that incumbent transmission providers have a clearly defined set of existing obligations under their tariffs for the expansion of their existing transmission facilities, whereas nonincumbents have no existing obligation to build any transmission facilities.

7. To gain feedback regarding the Commission's capacity allocation policies, the Commission held a technical conference in March 2011 to discuss the extent to which nonincumbent developers of transmission should be provided flexibility in the allocation of rights to use transmission facilities developed on a cost-of-service or negotiated rate basis. 13 Participants at that conference and subsequent commenters acknowledged the value in widely soliciting new customers, but they also expressed the desire to be able to allocate 100 percent of their projects' capacity through bilateral negotiations with identified customers. 14 Based on these comments, the Commission held a follow up workshop in February 2012 to obtain input on potential reforms to the Commission's capacity allocation policies. 15 Many participants at the 2012 workshop suggested that the need for flexibility required something less structured than the traditional open season process. Specifically, some commenters, including transmission developers, emphasized the inherent incentive transmission developers have to solicit interest widely and attract potential customers to their project, so that they can identify customers that are most likely to be successful in their own generation projects and therefore provide the greatest certainty that they will be successful in becoming transmission customers. 16 In this respect, these commenters argued that their incentives harmonize with the Commission's goals of open access. Further, they argue that their class of transmission developers does not raise the same concerns that motivated the Commission in Order No. 888, 17 where vertically-integrated utilities had an economic incentive to favor their own generation and discriminate against competitors when providing transmission service. 18

8. However, commenters also focused on the need for negotiation flexibility during the capacity allocation process, 19 pointing out that the transmission developer and customer need to address a variety of issues, including points of delivery and receipt, project timing and what happens if schedules change, termination rights of parties at various development stages, development cost-sharing, length and payments of the initial term of service, extensions of the term and associated payments. 20 These commenters argued that a rigid open season process that requires developers to offer all customers the same terms and conditions does not allow for the bilateral exchange of information to address the unique needs of developers and their potential customers. Moreover, these commenters pointed out that there have been no claims of undue discrimination resulting from any of the anchor customer proposals the Commission has approved, to date, 21 and that parties who feel they were unduly discriminated against have had, as an added protection, the right to file a section 206 complaint. 22

9. However, other commenters at the 2012 workshop voiced concerns with the merchant transmission model in general, and the opportunity for potentially unduly discriminatory deals. 23 They argued that allowing more flexibility for merchant transmission developers is tantamount to reverting to the pre-open access Order No. 888 days of transmission regulation, and discouraged the Commission from pursuing policies that enable anchor customers to exclude or burden generation competitors or engage in other abusive practices the Commission sought to eradicate in Order No. 888. Such commenters favor requiring merchant transmission developer participation in the regional planning process. 24 The staff of the Federal Trade Commission similarly questions how the Commission will restrain merchant transmission developers from exercising market power. 25

10. The Commission believes that there is a role within its transmission development policies for both bilateral negotiations for transmission service and uniform rules and processes through the pro forma OATT for all customers at all times. The policy of open access and comparable treatment is the underpinning of the Commission's approach to ensuring against undue discrimination and permeates many, if not all, of the Commission's programs. However, this does not mean that the Commission cannot be flexible in how it accomplishes open access and comparable treatment. As Order No. 1000  26 is implemented around the country, the Commission expects that more transmission needs will be identified and addressed through the open and transparent regional transmission planning process. Nonetheless, bilateral negotiation between transmission developers and potential customers may be another appropriate vehicle for new merchant transmission projects and new nonincumbent, cost-based, participant-funded transmission projects to move forward. In fact, Order No. 1000 allowed for such a vehicle, noting that some projects may not seek to pursue regional or interregional cost allocation. 27 In addition, there may be projects that are considered in the regional planning process that, although not ultimately selected in a regional plan for purposes of cost allocation, have sufficient value for individual potential customers such that they wish to pursue them through bilateral negotiations with a potential developer. This proposed policy statement is intended to provide a “roadmap” for entities to pursue those projects, while also serving to ensure transparency in the allocations of capacity resulting from such bilateral negotiation and, in turn, to ensure that transmission service is provided at rates, terms and conditions that are just and reasonable and not unduly discriminatory.

11. Accordingly, the Commission proposes to clarify and refine its policies governing the allocation capacity for new merchant transmission projects and new nonincumbent, cost-based, participant-funded transmission projects to ensure that it is done in an open and transparent manner, giving all interested parties a chance to participate. The Commission believes that the proposed capacity allocation process outlined here satisfies our statutory responsibilities, provides sufficient transparency and protections to market participants, and is responsive to the industry concerns.

12. The Commission proposes to revise its merchant transmission policy to streamline the process by which capacity may be allocated on new merchant transmission projects and to expect more detail and transparency in the report describing the developer's capacity allocation approach. While the Commission's fundamental concerns continue to be that new transmission capacity be allocated in a not unduly discriminatory or preferential manner, the Commission's experience with new merchant transmission projects and comments received during the technical conference and workshop suggest that we can provide more flexibility while addressing these concerns. The Commission proposes to allow merchant transmission developers to allocate up to 100 percent of their projects' capacity through bilateral negotiations. 28 With the transparency protections discussed below, the Commission also proposes to allow capacity allocation to affiliates, when done in a transparent manner, so that other interested parties can voice concern if they believe the affiliate was treated preferentially at the expense of another party. 29

13. The flexibility we propose to afford under the policy outlined below is complemented by the emphasis on additional detail in reports describing the developer's capacity allocation approach. The Commission agrees with commenters that each merchant transmission project has unique characteristics that require the ability to negotiate risk-sharing and other details. The Commission also acknowledges that merchant transmission developers have inherent incentives to solicit interest widely in a potential project. However, other commenters point out that counter-incentives may exist that motivate a developer to unduly prefer one or more customers. To protect against undue discrimination, the Commission proposes to allow merchant transmission developers to engage in an open solicitation to identify potential transmission customers, but with the expectation that they will submit to the Commission reports regarding the processes that led to the identification of customers and execution of relevant capacity arrangements. The Commission believes that this approach, when coupled with the existing opportunity to file complaints under FPA section 206, serves the interest of customers and developers alike. 30

14. In the past, the Commission has required an open season for the allocation of capacity on new merchant transmission projects. The open season requirement was to ensure open access to transmission capacity and prevent the withholding of transmission capacity from interested transmission customers, and also to enable the developer to assess the size of the market. However, beginning with the Chinook order, the Commission also began to allow the allocation of a portion of transmission capacity through bilateral negotiations prior to an open season. Thus, current Commission policy allows a merchant transmission developer to solicit interest through bilateral negotiations for a portion of its capacity so long as it makes the remainder available through an open season.

15. Based on the Commission's experience with prior cases and information received from the technical conference and workshop, the Commission believes that bilateral negotiations, if conducted in a transparent manner, may serve the same purpose as an open season process by ensuring against undue discrimination or preference in the provision of transmission service. Hence, the Commission proposes that, in seeking negotiated rate authority, merchant transmission developers should also engage in an open solicitation of interest in their projects from potential transmission customers (without the previous requirement of an open season). Such open solicitation should include a broad notice issued in a manner that ensures that all potential and interested customers are informed of the proposed project. For example, such notice may be placed in trade magazines, regional energy publications, communications with regional transmission planning groups, and email distribution lists addressing transmission-related matters. Such notice should include transmission developer points of contact and pertinent project dates, as well as sufficient technical specifications and contract information to inform interested customers of the nature of the project, including:

16. The developer should also specify in the notice the criteria it plans to use to select transmission customers, such as credit rating; “first mover” status, i.e., customers who respond early and take on greater project risk; and customers' willingness to incorporate project risk-sharing into their contracts. This will contribute to the transparency of the process, and help interested entities know at the outset the features of the project and how the bids to the merchant transmission developer will be considered.

17. Finally, the merchant transmission developer would be expected to update its posting if there are any material changes to the nature of the project or the status of capacity allocation.

18. Under this proposed process, once a subset of customers has been identified by the developer through the open solicitation process, the Commission would allow developers to engage in bilateral negotiations with each potential customer on the specific terms and conditions for procuring transmission capacity, as the Commission recognizes that developers and potential customers may need to negotiate individualized terms that meet their unique needs. 31 In these negotiations, the Commission proposes to allow for distinctions among prospective customers based on transparent and not unduly discriminatory or preferential criteria—so long as the differences in negotiated terms recognize material differences and do not result in undue discrimination or preference —with the potential result that a single customer may be awarded up to 100 percent of capacity. For instance, developers might offer “first mover” customers more favorable terms and conditions than later customers.

19. In the past, the Commission required that developers file a report, shortly after the close of the open season, on the results of the open season and any anchor customer presubscription, including information on the notice of the open season, the method used for evaluating bids, the identity of the parties that purchased capacity, and the amount, term, and price of that capacity. 32 The Commission required this report to provide transparency to the allocation of initial transmission rights, and to enable unsuccessful bidders to determine if they were treated in an unduly discriminatory manner so that they may file a complaint if they believe they were. 33

20. The Commission now proposes to place more emphasis on reporting, as the success of the capacity allocation approach proposed here and its ability to prevent undue discrimination relies, to a noticeable degree, on the transparency this report provides. Open access requires not only that everyone is given an opportunity to seek access, but also that entities know how their bids were evaluated and, if they were not selected in the initial allocation of transmission rights, on what basis that decision was made. If a party feels it was treated in an unduly discriminatory way, it may file a complaint under section 206 of the FPA; however, parties must have access to the relevant information on the outcomes of the capacity allocation process to evaluate whether or not they were treated fairly.

21. To prevent against undue discrimination by merchant transmission developers, a report should be submitted shortly after the completion of the open solicitation process and the resulting negotiations describing the processes that led to the identification of transmission customers and the execution of the relevant contractual arrangements. The merchant transmission developer should describe the criteria used to select customers, any price terms, and any risk-sharing terms and conditions that served as the basis for identifying transmission customers selected versus those that were not. The Commission proposes that the developer should include, at a minimum, the following information in the report to provide sufficient transparency to the Commission and interested parties:

(6) Criteria used for distinguishing customers and the method used for evaluating bids. This should include specific details on how each potential transmission customer (including both those who were and those who were not allocated capacity) was evaluated and compared to other potential transmission customers, both at the early stage when the developer chooses with whom to enter into bilateral negotiations and subsequently when the developer chooses in the negotiation phase to whom to award transmission capacity;

(7) Explanation of decisions used to select and reject specific customers. In particular, the report should identify the facts, including any terms and conditions of agreements unique to individual customers that led to their selection, and relevant information about others that led to their rejection. If a selected customer is an affiliate, the Commission will look more carefully at the basis for reaching that determination.

22. The Commission anticipates that, under this proposed policy, those developers requesting negotiated rate authority will file this report either in conjunction with their request for negotiated rate authority or as a compliance filing to a Commission order approving a request for negotiated rate authority. 34 This will allow interested entities to submit comments on the report, or otherwise protest the contents or insufficiency of the report, to ensure that there is sufficient transparency, as well as to provide Commission oversight in the capacity allocation process. 35

23. Beyond the reporting process described above, the Commission does not propose to change its existing requirement that developers seek Commission approval, either when the developer requests negotiated rate authority or files its report describing its capacity allocation approach, if an affiliate is expected to participate as a customer on the proposed merchant transmission project. Further, consistent with Commission precedent, in order to allow affiliate participation, the Commission will expect an affirmative showing that the affiliate is not afforded an undue preference. 36

24. The Commission proposes to apply the policy reforms above to nonincumbent, cost-based, participant-funded transmission developers. The Commission has similar concerns regarding the capacity allocation process regardless of whether the project is a nonincumbent, cost-based, participant-funded transmission project or a merchant transmission project. That is, the Commission is concerned that access is not unduly discriminatory or preferential. We believe that the process outlined herein will address our concerns regardless of the manner by which transmission rates are determined. Commenters and workshop participants support the Commission's application of these policy reforms to both merchant transmission developers and nonincumbent, cost-based, participant-funded transmission developers. 37

25. However, use of this common process does not eliminate the distinction between these types of projects. In particular, although the negotiations between developers and potential customers could address a transmission rate, among other issues, the Commission's approach to reviewing such a rate would be different for a new merchant transmission project than for a new nonincumbent, cost-based, participant-funded transmission project. For a merchant transmission project, the Commission relies on the processes it sets forth to ensure against undue discrimination in the award of capacity and the willingness of the transmission developer and customers to negotiate a transmission rate and terms and conditions, understanding that the customers are not captive customers. 38 For a nonincumbent, cost-based, participant-funded transmission project, the Commission would review the transmission rate, including any agreed upon return on equity, in greater detail to ensure that it satisfies Commission precedent regarding cost-based transmission service.

26. While we are proposing that this capacity allocation process apply equally to nonincumbent, cost-based, participant-funded projects, we are not proposing to evaluate such projects based on the other aspects of the four factor analysis set forth in Chinook. 39 To the extent nonincumbent, cost-based, participant-funded transmission projects wish to use an anchor customer-type model, the effect of the proposed policy would be that the Commission will deem any capacity allocation process that follows the guidelines of this proposed policy statement to satisfy its concerns regarding undue discrimination and undue preference.

27. The Commission does not propose to change its case-by-case evaluation of requests for cost-based participant-funded transmission projects by incumbent transmission providers. 40 As noted above, incumbents differ from nonincumbents in that the former have a clearly defined set of existing obligations under their OATTs with regard to new transmission development, including participation in regional planning processes and the processing of transmission service request queues. Nonincumbent transmission developers do not yet own or operate transmission facilities in the region that they propose to develop transmission and, therefore, are not yet subject to an OATT in that region. The proposed policy laid out above identifies the Commission's policies regarding the allocation of capacity for merchant transmission developers and nonincumbent, cost-based, participant-funded projects during the development of a new transmission facility. In most instances, we would expect that an incumbent transmission provider will be able to use existing processes set forth in its OATT to allocate capacity on a new transmission facility. These existing OATT processes do not prohibit incumbent transmission owners from identifying projects that could be constructed on a participant-funded basis in conjunction with processing of transmission service requests or in addition to meeting transmission needs through participation in a regional transmission planning process. 41 Furthermore, the Commission will continue to entertain on a case-by-case basis requests for waiver of any OATT requirements that may be needed for the incumbent transmission owner to pursue innovative transmission development that is just, reasonable, and not unduly discriminatory. For example, an incumbent may seek waiver of serial queue processing requirements so that they may cluster transmission service requests, 42 or they may seek to “ring fence” a transmission project in order to ensure that new transmission facilities developed for a particular customer or set of customers do not adversely impact existing customers, including native load. 43 Incumbent developers should address the capacity allocation issues in a manner that does not constitute undue discrimination or preference and is consistent with the applicable Commission-accepted tariffs. 44

28. The Commission invites comments on this proposed policy statement September 24, 2012.

29. In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page ( http://www.ferc.gov ) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426.

30. From FERC's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

31. User assistance is available for eLibrary and the FERC's Web site during normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-8371, TTY (202)502-8659. Email the Public Reference Room at public.referenceroom@ferc.gov.

1. Under section 215 of the Federal Power Act (FPA), the Federal Energy Regulatory Commission (Commission) proposes to approve regional Reliability Standard PRC-006-SERC-01 (Automatic Underfrequency Load Shedding (UFLS) Requirements) in the SERC Reliability Corporation (SERC)  1 Region. The Commission also proposes to approve the related violation risk factors (VRFs), with one modification, and violation severity levels (VSLs), implementation plan, and effective date proposed by the North American Electric Reliability Corporation (NERC). Regional Reliability Standard PRC-006-SERC-01 was submitted to the Commission for approval by NERC and is designed to ensure that automatic UFLS protection schemes designed by planning coordinators and implemented by applicable distribution providers and transmission owners in the SERC Region are coordinated to effectively mitigate the consequences of an underfrequency event.

2. Section 215 of the FPA requires a Commission-certified Electric Reliability Organization (ERO) to develop mandatory and enforceable Reliability Standards, which are subject to Commission review and approval. Once approved, the Reliability Standards may be enforced by NERC, subject to Commission oversight, or by the Commission independently. 2

3. Reliability Standards that NERC proposes to the Commission may include Reliability Standards that are proposed by a Regional Entity to be effective in that region. 3 In Order No. 672, the Commission noted that:

4. On April 19, 2007, the Commission accepted delegation agreements between NERC and each of the eight Regional Entities. 6 In the order, the Commission accepted SERC as a Regional Entity organized on less than an interconnection-wide basis. As a Regional Entity, SERC oversees Bulk-Power System reliability within the SERC Region, which covers a geographic area of approximately 560,000 square miles in a sixteen-state area in the southeastern and central United States (all of Missouri, Alabama, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, and portions of Iowa, Illinois, Kentucky, Virginia, Oklahoma, Arkansas, Louisiana, Texas and Florida). The SERC Region is currently geographically divided into five subregions that are identified as Southeastern, Central, VACAR, Delta, and Gateway.

5. On February 1, 2012, NERC submitted a petition to the Commission seeking approval of regional Reliability Standard PRC-006-SERC-01. 7 NERC requests approval of the regional Reliability Standard, associated VRFs and VSLs, and the implementation plan for PRC-006-SERC-01. NERC requests the standard become effective over a 30-month window following the effective date of a final rule in this docket, as provided in NERC's implementation plan, to allow entities to respond to any changes in UFLS settings. NERC states that this is the first request for Commission approval of this proposed regional Reliability Standard and that it will only apply to applicable registered entities within the SERC Region. NERC also states that the NERC continent-wide Reliability Standards do not presently address the issues covered in regional Reliability Standard PRC-006-SERC-01.

6. NERC states that regional Reliability Standard PRC-006-SERC-01 was developed to be consistent with the NERC UFLS Reliability Standard PRC-006-1. 8 Regional Reliability Standard PRC-006-SERC-01 is designed to ensure that automatic UFLS protection schemes designed by planning coordinators and implemented by applicable distribution providers and transmission owners in the SERC Region are coordinated to effectively mitigate the consequences of an underfrequency event. 9

7. NERC states that the proposed regional Reliability Standard satisfies the factors set forth in Order No. 672 that the Commission considers when determining whether a proposed Reliability Standard is just, reasonable, not unduly discriminatory or preferential and in the public interest. 10 NERC states that regional Reliability Standard PRC-006-SERC-01 adds specificity not contained in the NERC UFLS Reliability Standard for UFLS schemes in the SERC Region. 11 NERC states that regional Reliability Standard PRC-006-SERC-01 effectively mitigates, in conjunction with Reliability Standard PRC-006-1, the consequences of an underfrequency event while accommodating differences in system transmission and distribution topology among SERC planning coordinators resulting from historical design criteria, makeup of load demands, and generation resources. 12

8. According to NERC, regional Reliability Standard PRC-006-SERC-01 is clear and unambiguous regarding what is required and who is required to comply. The proposed regional Reliability Standard is applicable to generator owners, planning coordinators, and UFLS entities in the SERC Region. The term “UFLS entities” (as noted in Reliability Standard PRC-006-1) means all entities that are responsible for the ownership, operation, or control of automatic UFLS equipment as required by the UFLS program established by the Planning Coordinators. 13 NERC states that such entities may include distribution providers and transmission owners. NERC also states that each requirement of PRC-006-SERC-01 has an associated measure of compliance that will assist those enforcing the standard to enforce it in a consistent and non-preferential manner.Proposed regional Reliability Standard PRC-006-SERC-01 contains eight requirements, summarized as follows:

Requirement R1 requires each planning coordinator to include its SERC subregion as an identified island when developing criteria for selecting portions of the Bulk-Power System that may form islands;

Requirement R2 requires each planning coordinator to select or develop an automatic UFLS scheme (percent of load to be shed, frequency set points, and time delays) for implementation by UFLS entities within its area that meets the specified minimum requirements;

Requirement R3 requires each planning coordinator to conduct simulations of its UFLS scheme for an imbalance between load and generation of 13 percent, 22 percent, and 25 percent for all identified islands;

Requirement R4 requires each UFLS entity that has a total load of 100 MW or greater in a planning coordinator area in the SERC Region to implement the UFLS scheme developed by their planning coordinator within specified tolerances;

Requirement R5 requires each UFLS entity that has a total load less than 100 MW in a planning coordinator area in the SERC Region to implement the UFLS scheme developed by their planning coordinator within specified tolerances, but specifies that those entities shall not be required to have more than one UFLS step;

Requirement R6 requires each UFLS entity in the SERC Region to implement changes to the UFLS scheme which involve frequency settings, relay time delays, or changes to the percentage of load in the scheme within 18 months of notification by the planning coordinator;

Requirement R7 requires each planning coordinator to provide specified information concerning their UFLS scheme to SERC according to the schedule specified by SERC; and

Requirement R8 requires each generator owner to provide specified generator underfrequency and overfrequency protection information within 30 days of a request by SERC to facilitate post-event analysis of frequency disturbances.

9. NERC also explains that the proposed regional Reliability Standard sets minimum automatic UFLS design requirements, which are equivalent to the design requirements in the SERC UFLS program that has been in effect since September 3, 1999. 14 NERC states that the one change relative to the existing SERC UFLS program is the addition of a minimum time delay requirement. The addition allows planning coordinators to use current UFLS schemes if those schemes meet the performance requirements specified in the NERC UFLS standard. Therefore, NERC concludes that the distribution providers and transmission owners subject to the proposed regional Reliability Standard will have to make minimal changes to implement their portions of the UFLS schemes.

10. NERC also proposes VRFs and VSLs for the regional Reliability Standard, an implementation plan, and an effective date. NERC states that these aspects were developed and reviewed for consistency with NERC and Commission guidelines.

11. NERC proposes specific implementation plans for each requirement in the regional Reliability Standard, as identified below, with the regional Reliability Standard becoming fully effective thirty months after the first day of the first quarter following regulatory approval. NERC states that the implementation time is reasonable, as it balances the need for reliability with the practicability of implementation.

12. NERC proposes that Requirement R1 of PRC-006-SERC-01 become effective twelve months after the first day of the first quarter following regulatory approval, but no sooner than twelve months following regulatory approval of Reliability Standard PRC-006-1. NERC states that this twelve-month period is consistent with the effective date of Requirement R2 of Reliability Standard PRC-006-1. Requirement R2 of PRC-006-SERC-01 would become effective twelve months after the first day of the first quarter following regulatory approval. NERC states that this twelve-month period is needed to allow time for entities to ensure a minimum time delay of six cycles on existing automatic UFLS relays as specified in Sub-requirement R2.6. Requirement R3 would become effective eighteen months after the first day of the first quarter following regulatory approval. NERC explains that this additional six-month period is needed to allow time to perform and coordinate studies necessary to assess the overall effectiveness of the UFLS schemes in the SERC Region. Requirements R4, R5, and R6 would become effective thirty months after the first day of the first quarter following regulatory approval. NERC states that this additional eighteen months is needed to allow time for any necessary changes to be made to the existing UFLS schemes in the SERC Region. Requirement R7 would become effective six months following the effective date of Requirement R8 of Reliability Standard PRC-006-1, but no sooner than one year following the first day of the first calendar quarter after applicable regulatory approval of PRC-006-SERC-01. Finally, Requirement R8 of PRC-006-SERC-01 would become effective twelve months after the first day of the first quarter following regulatory approval. NERC states that this twelve-month period is needed to allow time for generator owners to collect and make an initial data filing.

13. Pursuant to FPA section 215(d)(2), we propose to approve regional Reliability Standard PRC-006-SERC-01 as just, reasonable, not unduly discriminatory or preferential, and in the public interest. PRC-006-SERC-01 is designed to work in conjunction with NERC Standard PRC-006-1 to effectively mitigate the consequences of an underfrequency event while accommodating differences in system transmission and distribution topology among SERC Planning Coordinators due to historical design criteria, makeup of load demands, and generation resources. 15 As indicated above, PRC-006-SERC-01 covers topics not covered by the corresponding NERC Reliability Standard PRC-006-1 because it adds specificity for UFLS schemes in the SERC Region. For example, Requirement R1 of the proposed regional Reliability Standard PRC-006-SERC-01 requires all planning coordinators in the SERC Region to include their respective “SERC subregion as an identified island when developing criteria for selecting portions of the [Bulk-Power System] that may form islands.”  16 This requirement goes beyond the corresponding requirement in Reliability Standard PRC-006-1 that a planning coordinator study the entire region as an island.

14. While we propose to approve regional Reliability Standard PRC-006-SERC-01, we identify a possible inconsistency between Requirement R6 of the proposed regional Reliability Standard and PRC-006-1, which the Commission addressed in Order No. 763. Reliability Standard PRC-SERC-006-01, Requirement R6 states:

15. The Commission reads the requirement that UFLS entities implement a change “within 18-months” to establish a “maximum” timeframe to comply with a planning coordinator's schedule to implement changes to UFLS schemes, but also to recognize that the planning coordinator could establish a schedule for the changes to be implemented in less time. 18 The inclusion of a maximum timeframe would be more stringent than Reliability Standard PRC-006-1, Requirement R9, which does not contain a maximum timeframe to implement changes to a UFLS scheme.

16. We are concerned, however, that the italicized language in the rationale NERC provides for Requirement R6 may be incompatible with Order No. 763. As explained above, we interpret Requirement R6 to mean that planning coordinators can establish schedules for requiring changes to UFLS schemes by applicable entities within an 18-month time frame from the time the entities are notified. Yet, the rationale for Requirement R6 could result in Requirement R6 being read to allow applicable entities not to adopt the planning coordinator's schedule if it is less than 18 months. The Commission is concerned that leaving it up to applicable entities to determine their schedules for changes under certain circumstances will cause confusion and result in a lack of consistency in the application of the regional Reliability Standard. Allowing each UFLS entity to choose its own timing could harm reliability or at least defeat the purpose of the planning coordinator's role.

17. Our concern is rooted in the Commission's directive in Order No. 763 concerning PRC-006-1, which held that planning coordinators should be responsible for establishing schedules for the completion of corrective actions in response to UFLS events. 19 In the Notice of Proposed Rulemaking for PRC-006-1, the Commission stated that Reliability Standard PRC-006-1 does not specify how soon after an event an entity would need to implement corrections in response to any deficiencies identified in an event assessment. 20 NERC responded that the time that a UFLS entity has to implement corrections will be established by the planning coordinator, as specified in Requirement R9 of PRC-006-1. 21 In Order No. 763, the Commission accepted NERC's comments that Requirement R9 requires compliance with a schedule established by the planning coordinator, but the Commission stated that NERC's reading of Requirement R9 should be made clear in the Requirement itself and directed NERC to make that requirement explicit in future versions of the Reliability Standard. 22

18. NERC states that PRC-006-SERC-01 is designed to work in conjunction with Reliability Standard PRC-006-1. 23 NERC also maintains that the regional Reliability Standard is more stringent than PRC-006-1. 24 Construing Requirement R6 as imposing a maximum time to comply with a planning coordinator's schedule, but leaving it up to the applicable entity to decide whether to take more time (up to 18 months) than the planning coordinator schedule allows, would be inconsistent with and, in certain cases, be less stringent than PRC-006-1. First, we are concerned that allowing applicable entities the flexibility to determine their own implementation schedule (up to 18 months) for changes rather than follow the schedule established by the planning coordinator is inconsistent with the policy underlying Order No. 763 that planning coordinators establish schedules for completing changes to UFLS programs. If a planning coordinator believes that a change made pursuant to Requirement R6 should be completed in less than 18 months, the planning coordinator's schedule should be mandatory. Second, in certain circumstances, such an interpretation would be expressly prohibited by the Commission's directive in Order No. 763 concerning Requirement R9, which gives the planning coordinator the responsibility of setting a schedule for completing corrective actions to UFLS programs following event assessments pursuant to Requirement R11 and R12 of PRC-006-1. Although we acknowledge that changes made pursuant to Requirement R6 of the regional Reliability Standard will not always be corrective changes made in response to event assessments pursuant to the Requirements of PRC-006-1, Requirement R6 is broad enough to encompass corrective changes, thus creating a conflict between the regional Reliability Standard and PRC-006-1 under the proscribed interpretation. Thus, the Commission will not read Requirement R6 as providing a UFLS entity with the discretion not to follow the schedule set by the planning coordinator when the schedule is less than 18 months. 25

19. NERC states that the VRFs and VSLs for the proposed regional Reliability Standard were developed and reviewed for consistency with NERC and Commission guidelines. After reviewing the assigned VRFs and VSLs for PRC-006-SERC-01 in Exhibit E, the Commission agrees, with one modification, that the proposed VRF and VSL assignments appear consistent with Commission guidelines. Therefore, the Commission proposes to approve, with one modification, the VRFs and VSLs assigned to the main Requirements in regional Reliability Standard PRC-006-SERC-01.

20. We propose to direct NERC to modify the VRF assigned to Requirement R6 from “medium” to “high.” In the petition, NERC states that Requirement R9 of PRC-006-1 and Requirement R6 address “a similar reliability goal.”  26 However, NERC states that while Requirement R9 of PRC-006-1 addresses UFLS scheme implementation and has a VRF of “high,” Requirement R6 only addresses the timing of implementation and is, therefore, appropriately assigned a “medium” VRF. 27 Guideline 3 of the Commission's VRF Guidelines states that “[a]bsent justification to the contrary, the Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability goals in different Reliability Standards would be treated comparably.”  28 As NERC notes, Requirement R6 and Requirement R9 of proposed PRC-006-1 address “a similar reliability goal.” While NERC explains in its filing that the specific topics addressed by each Requirement are different, the fact that they address a similar reliability goal suggests that they should be treated comparably and each given a “high” VRF, consistent with Guideline 3.

21. In addition, in Guideline 5 of the VRF Guidelines, the Commission indicated that, for Requirements with co-mingled reliability objectives, “the Violation Risk Factor assignment for such Requirements is not watered down to reflect the lower risk level associated with the less important objective of the Reliability Standard.”  29 NERC states in the petition that Requirement R6 combines the lesser risk reliability objective of establishing a maximum time frame for implementing changes to UFLS schemes with the higher risk reliability objective of actually implementing changes to UFLS schemes. 30 As a result, consistent with Guideline 5, the Commission believes that proposed Requirement R6 should be assigned a “high” VRF. We seek comment on this proposed directive.

22. NERC states that the implementation time for the proposed regional Reliability Standard is reasonable, as it balances the need for reliability with the practicability of implementation. The Commission proposes to accept the implementation plan and effective date proposed by NERC.

23. The Office of Management and Budget (OMB) regulations require that OMB approve certain reporting and recordkeeping (collections of information) imposed by an agency. 31 Upon approval of a collection(s) of information, OMB will assign an OMB control number and expiration date. Respondents subject to the filing requirements of this rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number.

24. The Commission is submitting these reporting and recordkeeping requirements to OMB for its review and approval under section 3507(d) of the PRA. Comments are solicited on the Commission's need for this information, whether the information will have practical utility, the accuracy of provided burden estimate, ways to enhance the quality, utility, and clarity of the information to be collected, and any suggested methods for minimizing the respondent's burden, including the use of automated information techniques.

25. This Notice of Proposed Rulemaking proposes to approve regional Reliability Standard PRC-006-SERC-01. This is the first time NERC has requested Commission approval of this proposed regional Reliability Standard. NERC states in its petition that UFLS requirements had been in place at a continent-wide level and within SERC for many years prior to implementation of the Commission-approved Reliability Standards in 2007. Because the UFLS requirements have been in place prior to the development of PRC-006-SERC-01, the proposed regional Reliability Standard is largely associated with requirements the applicable entities are already following. 32 The proposed regional Reliability Standard, PRC-006-SERC-01, is designed to ensure that automatic UFLS protection schemes designed by planning coordinators and implemented by applicable distribution providers and transmission owners in the SERC Region are coordinated so they may effectively mitigate the consequences of an underfrequency event. The proposed regional Reliability Standard is only applicable to generator owners, planning coordinators, and UFLS entities in the SERC Region. The term “UFLS entities” means all entities that are responsible for the ownership, operation, or control of automatic UFLS equipment as required by the UFLS program established by the planning coordinators. Such entities may include distribution providers and transmission owners. The reporting requirements in proposed regional Reliability Standard PRC-006-SERC-01 only pertain to entities within the SERC Region.

26. Public Reporting Burden: Our estimate below regarding the number of respondents is based on the NERC compliance registry as of May 29, 2012. According to the NERC compliance registry, there are 21 planning coordinators and 104 generator owners within the SERC Region. The individual burden estimates are based on the time needed for planning coordinators to incrementally gather data, run studies, and analyze study results to design or update the UFLS programs that are required in the regional Reliability Standard in addition to the requirements of the NERC Reliability Standard PRC-006-1. 33 Additionally, generator owners must provide a detailed set of data and documentation to SERC within 30 days of a request to facilitate post event analysis of frequency disturbances. These burden estimates are consistent with estimates for similar tasks in other Commission-approved Reliability Standards.

Total Annual Hours for Collection: (Compliance/Documentation) = 2,584 hours.

Total Reporting Cost for planning coordinators: = 504 hours @ $120/hour = $60,480.

Total Reporting Cost for generator owners: = 1,664 hours @ $120/hour = $199,680.

Total Record Retention Cost for generator owners: 416 hours @ $28/hour = $11,647.

Total Annual Cost (Reporting + Record Retention)  35 : = $60,480 + $199,680 +$11,648 = $271,808.

Title: Mandatory Reliability Standards for the SERC Region.

Action: Proposed Collection FERC-725K.

OMB Control No.: To be determined.

Respondents: Businesses or other for-profit institutions; not-for-profit institutions.

Frequency of Responses: On Occasion.

Necessity of the Information: This proposed rule proposes to approve the regional Reliability Standard pertaining to automatic underfrequency load shedding. The proposed regional Reliability Standard helps ensure the reliable operation of the Bulk-Power System by arresting declining frequency and assisting recovery of frequency following system events leading to frequency degradation.

Internal Review: The Commission has reviewed the proposed regional Reliability Standard and made a determination that its action is necessary to implement section 215 of the FPA. These requirements, if accepted, should conform to the Commission's expectation for UFLS programs as well as procedures within the SERC Region.

27. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873].

28. For submitting comments concerning the collection(s) of information and the associated burden estimate(s), please send your comments to the Commission and to the Office of Management and Budget, Office of Information and Regulatory Affairs, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-4638, fax: (202) 395-7285]. For security reasons, comments to OMB should be submitted by email to: oira_submission@omb.eop.gov . Comments submitted to OMB should include Docket Number RM12-09 and an OMB Control Number to be determined.

29. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment. 36 The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. Included in the exclusion are rules that are clarifying, corrective, or procedural or that do not substantially change the effect of the regulations being amended. 37 The actions proposed here fall within this categorical exclusion in the Commission's regulations.

30. The Regulatory Flexibility Act of 1980 (RFA)  38 generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. The RFA mandates consideration of regulatory alternatives that accomplish the stated objectives of a proposed rule and that minimize any significant economic impact on a substantial number of small entities. The Small Business Administration's (SBA) Office of Size Standards develops the numerical definition of a small business. 39 The SBA has established a size standard for electric utilities, stating that a firm is small if, including its affiliates, it is primarily engaged in the transmission, generation and/or distribution of electric energy for sale and its total electric output for the preceding twelve months did not exceed four million megawatt hours. 40

31. Proposed regional Reliability Standard PRC-006-SERC-01 proposes to establish consistent and coordinated requirements for the design, implementation, and analysis of automatic UFLS schemes among all applicable entities within the SERC Region. It will be applicable to planning coordinators, generator owners and entities that are responsible for the ownership, operation, or control of UFLS equipment. Comparison of the NERC Compliance Registry with data submitted to the Energy Information Administration on Form EIA-861 indicates that perhaps as many as 1 small entity is registered as a planning coordinator and 5 small entities are registered as generator owners in the SERC Region. The Commission estimates that the small planning coordinator to whom the proposed regional Reliability Standard will apply will incur compliance costs of $2,880 ($2,880 per planning coordinator) associated with the proposed regional Reliability Standard's requirements. The small generator owners will incur compliance and record keeping costs of $10,160 ($2,032 per generator owner). Accordingly, proposed regional Reliability Standard PRC-006-SERC-01 should not impose a significant operating cost increase or decrease on the affected small entities.

32. Further, NERC explains that the cost for smaller entities to implement regional Reliability Standard PRC-006-SERC-01 was considered during the development process. The Reliability Standard PRC-006-1 requires a planning coordinator to identify which entities will participate in its UFLS scheme, including the number of steps and percent load that UFLS entities will shed. The standard drafting team recognized that UFLS entities with a load of less than 100 MW may have difficulty in implementing more than one UFLS step and in meeting a tight tolerance. Therefore, the standard drafting team included Requirement R5, which states that such small entities shall not be required to have more than one UFLS step, and sets their implementation tolerance to a wider level. Requirement R5 limits additional compliance costs for smaller entities to comply with the regional Reliability Standard.

33. Based on this understanding, the Commission certifies that the regional Reliability Standard will not have a significant economic impact on a substantial number of small entities. Accordingly, no regulatory flexibility analysis is required.

34. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due September 24, 2012. Comments must refer to Docket No. RM12-9-000, and must include the commenter's name, the organization they represent, if applicable, and their address in their comments.

35. The Commission encourages comments to be filed electronically via the eFiling link on the Commission's Web site at http://www.ferc.gov . The Commission accepts most standard word processing formats. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing.

36. Commenters that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426.

37. All comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters.

38. In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through the Commission's Home Page ( http://www.ferc.gov ) and in the Commission's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426.

39. From the Commission's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

40. User assistance is available for eLibrary and the Commission's Web site during normal business hours from the Commission's Online Support at 202-502-6652 (toll free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov , or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. Email the Public Reference Room at public.referenceroom@ferc.gov .

Part 543 addresses minimum internal control standards (MICS) for Class II gaming operations. The regulations require tribes to establish controls and implement procedures at least as stringent as those described in this Part to maintain the integrity of the gaming operation and minimize the risk of theft.

The MICS were last amended in 2009 in the first phase of what was intended to be a multi-phase process of revising the MICS and separating Class II and III controls. This proposed rule furthers that multi-phase process and includes amendments to update the MICS to reflect widespread technological advances in the industry.

Table of Contents I. Background II. What elements are required under sections 110(a)(1) and (2)? III. Scope of Infrastructure SIPs IV. What is EPA's analysis of how North Carolina addressed the elements of sections 110(a)(1) and (2) “Infrastructure” provisions? V. Proposed Action VI. Statutory and Executive Order Reviews I. Background

On July 18, 1997 (62 FR 38652), EPA established an annual PM 2.5 NAAQS at 15.0 micrograms per cubic meter (μg/m 3 ) based on a 3-year average of annual mean PM 2.5 concentrations. At that time, EPA also established a 24-hour NAAQS of 65 μg/m 3 . See 40 CFR 50.7. On October 17, 2006 (71 FR 61144), EPA retained the 1997 annual PM 2.5 NAAQS at 15.0 μg/m 3 based on a 3-year average of annual mean PM 2.5 concentrations, and promulgated a new 24-hour NAAQS of 35 μg/m 3 based on a 3-year average of the 98th percentile of 24-hour concentrations. By statute, SIPs meeting the requirements of sections 110(a)(1) and (2) are to be submitted by states within three years after promulgation of a new or revised NAAQS. Sections 110(a)(1) and (2) require states to address basic SIP requirements, including emissions inventories, monitoring, and modeling to assure attainment and maintenance of the NAAQS. States were required to submit such SIPs to EPA no later than July 2000 for the 1997 annual PM 2.5 NAAQS, no later than October 2009 for the 2006 24-hour PM 2.5 NAAQS.

On March 4, 2004, Earthjustice submitted a notice of intent to sue related to EPA's failure to issue findings of failure to submit related to the “infrastructure” requirements for the 1997 annual PM 2.5 NAAQS. On March 10, 2005, EPA entered into a consent decree with Earthjustice which required EPA, among other things, to complete a Federal Register notice announcing EPA's determinations pursuant to section 110(k)(1)(B) as to whether each state had made complete submissions to meet the requirements of section 110(a)(2) for the 1997 PM 2.5 NAAQS by October 5, 2008. In accordance with the consent decree, EPA made completeness findings for each state based upon what the Agency received from each state for the 1997 PM 2.5 NAAQS as of October 3, 2008.

On October 22, 2008, EPA published a final rulemaking entitled “Completeness Findings for Section 110(a) State Implementation Plans Pertaining to the Fine Particulate Matter (PM 2.5 ) NAAQS,” making a finding that each state had submitted or failed to submit a complete SIP that provided the basic program elements of section 110(a)(2) necessary to implement the 1997 PM 2.5 NAAQS ( see 73 FR 62902). For those states that did receive findings, the findings of failure to submit for all or a portion of a state's implementation plan established a 24-month deadline for EPA to promulgate a Federal Implementation Plan to address the outstanding SIP elements unless, prior to that time, the affected states submitted, and EPA approved, the required SIPs.

The findings that all or portions of a state's submission are complete established a 12-month deadline for EPA to take action upon the complete SIP elements in accordance with section 110(k). North Carolina's infrastructure submissions were received by EPA on April 1, 2008, for the 1997 annual PM 2.5 NAAQS, and on September 21, 2009, for the 2006 24-hour PM 2.5 NAAQS. The submissions were determined to be complete on October 1, 2008, and March 21, 2010, respectively. North Carolina was among other states that did not receive findings of failure to submit because it had provided a complete submission to EPA to address the infrastructure elements for the 1997 PM 2.5 NAAQS by October 3, 2008.

On July 6, 2011, WildEarth Guardians and Sierra Club filed an amended complaint related to EPA's failure to take action on the SIP submittal related to the “infrastructure” requirements for the 2006 24-hour PM 2.5 NAAQS. On October 20, 2011, EPA entered into a consent decree with WildEarth Guardians and Sierra Club which required EPA, among other things, to complete a Federal Register notice of the Agency's final action either approving, disapproving, or approving in part and disapproving in part the North Carolina 2006 24-hour PM 2.5 NAAQS Infrastructure SIP submittal addressing the applicable requirements of sections 110(a)(2)(A)-(H), (J)-(M), except for section 110(a)(2)(C) the nonattainment area requirements and section 110(a)(2)(D)(i)(II) visibility requirements, by September 30, 2012. On July 20, 2011, EPA published a final rulemaking disapproving the interstate transport requirements for section 110(a)(2)(D)(i) for the 2006 24-hour PM 2.5 NAAQS for North Carolina. See 76 FR 43167.

Today's action is proposing to approve in part, and to conditionally approve in part North Carolina's infrastructure submissions for both the 1997 annual and 2006 24-hour PM 2.5 NAAQS for sections 110(a)(2)(A)-(H), (M), with the exception of sections 110(a)(2)(C) related to PSD requirements, section 110(a)(2)(D)(i) interstate transport requirements, 110(a)(2)(E)(ii) and 110(a)(2)(J) related to PSD requirements. With respect to sections 110(a)(2)(E)(ii), and sections 110(a)(2)(C) and 110(a)(2)(J) as they relate to PSD requirements, EPA is proposing to conditionally approve North Carolina's infrastructure SIP as it relates to these requirements. Today's action is not approving any specific rule, but rather proposing that North Carolina's already approved SIP meets—or in the case of the elements proposed for conditional approval will meet—, with changes, certain CAA requirements.

Section 110(a) of the CAA requires states to submit SIPs to provide for the implementation, maintenance, and enforcement of a new or revised NAAQS within three years following the promulgation of such NAAQS, or within such shorter period as EPA may prescribe. Section 110(a) imposes the obligation upon states to make a SIP submission to EPA for a new or revised NAAQS, but the contents of that submission may vary depending upon the facts and circumstances. In particular, the data and analytical tools available at the time the state develops and submits the SIP for a new or revised NAAQS affects the content of the submission. The contents of such SIP submissions may also vary depending upon what provisions the state's existing SIP already contains. In the case of the 1997 annual and 2006 24-hour PM 2.5 NAAQS, some states may need to adopt language specific to the PM 2.5 NAAQS to ensure that they have adequate SIP provisions to implement the PM 2.5 NAAQS.

Section 110(a)(1) provides the procedural and timing requirements for SIPs. Section 110(a)(2) lists specific elements that states must meet for “infrastructure” SIP requirements related to a newly established or revised NAAQS. As mentioned above, these requirements include SIP infrastructure elements such as modeling, monitoring, and emissions inventories that are designed to assure attainment and maintenance of the NAAQS. The requirements that are the subject of this proposed rulemaking are listed below  1 and in EPA's October 2, 2007, memorandum entitled “Guidance on SIP Elements Required Under Section 110(a)(1) and (2) for the 1997 8-Hour Ozone and PM 2.5 National Ambient Air Quality Standards” and September 25, 2009, memorandum entitled “Guidance on SIP Elements Required Under Section 110(a)(1) and (2) for the 2006 24-Hour Fine Particle (PM 2.5 ) National Ambient Air Quality Standards.”

• 110(a)(2)(A): Emission limits and other control measures.

• 110(a)(2)(B): Ambient air quality monitoring/data system.

• 110(a)(2)(C): Program for enforcement of control measures. 2

• 110(a)(2)(D): Interstate transport. 3

• 110(a)(2)(E): Adequate resources.

• 110(a)(2)(F): Stationary source monitoring system.

• 110(a)(2)(G): Emergency power.

• 110(a)(2)(H): Future SIP revisions.

• 110(a)(2)(I): Areas designated nonattainment and meet the applicable requirements of part D. 4

• 110(a)(2)(J): Consultation with government officials; public notification; and PSD and visibility protection.

• 110(a)(2)(K): Air quality modeling/data.

• 110(a)(2)(L): Permitting fees.

• 110(a)(2)(M): Consultation/participation by affected local entities.

EPA is currently acting upon SIPs that address the infrastructure requirements of CAA section 110(a)(1) and (2) for ozone and PM 2.5 NAAQS for various states across the country. Commenters on EPA's recent proposals for some states raised concerns about EPA statements that it was not addressing certain substantive issues in the context of acting on those infrastructure SIP submissions. 5 Those Commenters specifically raised concerns involving provisions in existing SIPs and with EPA's statements in other proposals that it would address two issues separately and not as part of actions on the infrastructure SIP submissions: (i) Existing provisions related to excess emissions during periods of start-up, shutdown, or malfunction (SSM) at sources, that may be contrary to the CAA and EPA's policies addressing such excess emissions; and (ii) existing provisions related to “director's variance” or “director's discretion” that purport to permit revisions to SIP approved emissions limits with limited public process or without requiring further approval by EPA, that may be contrary to the CAA (director's discretion). EPA notes that there are two other substantive issues for which EPA likewise stated in other proposals that it would address separately: (i) Existing provisions for minor source new source review (NSR) programs that may be inconsistent with the requirements of the CAA and EPA's regulations that pertain to such programs (minor source NSR); and (ii) existing provisions for Prevention of Significant Deterioration (PSD) programs that may be inconsistent with current requirements of EPA's “Final NSR Improvement Rule,” 67 FR 80186 (December 31, 2002), as amended by 72 FR 32526 (June 13, 2007) (NSR Reform). In light of the comments, EPA believes that its statements in various proposed actions on infrastructure SIPs with respect to these four individual issues should be explained in greater depth. It is important to emphasize that EPA is taking the same position with respect to these four substantive issues in this action on the infrastructure SIPs for the 1997 and 2006 PM 2.5 NAAQS from North Carolina.

EPA intended the statements in the other proposals concerning these four issues merely to be informational and to provide general notice of the potential existence of provisions within the existing SIPs of some states that might require future corrective action. EPA did not want states, regulated entities, or members of the public to be under the misconception that the Agency's approval of the infrastructure SIP submission of a given state should be interpreted as a re-approval of certain types of provisions that might exist buried in the larger existing SIP for such state. Thus, for example, EPA explicitly noted that the Agency believes that some states may have existing SIP approved SSM provisions that are contrary to the CAA and EPA policy, but that “in this rulemaking, EPA is not proposing to approve or disapprove any existing state provisions with regard to excess emissions during SSM of operations at facilities.” EPA further explained, for informational purposes, that “EPA plans to address such State regulations in the future.” EPA made similar statements, for similar reasons, with respect to the director's discretion, minor source NSR, and NSR Reform issues. EPA's objective was to make clear that approval of an infrastructure SIP for these ozone and PM 2.5 NAAQS should not be construed as explicit or implicit re-approval of any existing provisions that relate to these four substantive issues. EPA is reiterating that position in this action on the infrastructure SIP for North Carolina.

Unfortunately, the Commenters and others evidently interpreted these statements to mean that EPA considered action upon the SSM provisions and the other three substantive issues to be integral parts of acting on an infrastructure SIP submission, and therefore that EPA was merely postponing taking final action on the issues in the context of the infrastructure SIPs. This was not EPA's intention. To the contrary, EPA only meant to convey its awareness of the potential for certain types of deficiencies in existing SIPs and to prevent any misunderstanding that it was reapproving any such existing provisions. EPA's intention was to convey its position that the statute does not require that infrastructure SIPs address these specific substantive issues in existing SIPs and that these issues may be dealt with separately, outside the context of acting on the infrastructure SIP submission of a state. To be clear, EPA did not mean to imply that it was not taking a full final agency action on the infrastructure SIP submission with respect to any substantive issue that EPA considers to be a required part of acting on such submissions under section 110(k) or under section 110(c). Given the confusion evidently resulting from EPA's statements in those other proposals, however, we want to explain more fully the Agency's reasons for concluding that these four potential substantive issues in existing SIPs may be addressed separately from actions on infrastructure SIP submissions.

The requirement for the SIP submissions at issue arises out of CAA section 110(a)(1). That provision requires that states must make a SIP submission “within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national primary ambient air quality standard (or any revision thereof)” and that these SIPs are to provide for the “implementation, maintenance, and enforcement” of such NAAQS. Section 110(a)(2) includes a list of specific elements that “[e]ach such plan” submission must meet. EPA has historically referred to these particular submissions that states must make after the promulgation of a new or revised NAAQS as “infrastructure SIPs.” This specific term does not appear in the statute, but EPA uses the term to distinguish this particular type of SIP submission designed to address basic structural requirements of a SIP from other types of SIP submissions designed to address other different requirements, such as “nonattainment SIP” submissions required to address the nonattainment planning requirements of part D, “regional haze SIP” submissions required to address the visibility protection requirements of CAA section 169A, NSR permitting program submissions required to address the requirements of part D, and a host of other specific types of SIP submissions that address other specific matters.

Although section 110(a)(1) addresses the timing and general requirements for these infrastructure SIPs, and section 110(a)(2) provides more details concerning the required contents of these infrastructure SIPs, EPA believes that many of the specific statutory provisions are facially ambiguous. In particular, the list of required elements provided in section 110(a)(2) contains a wide variety of disparate provisions, some of which pertain to required legal authority, some of which pertain to required substantive provisions, and some of which pertain to requirements for both authority and substantive provisions. 6 Some of the elements of section 110(a)(2) are relatively straightforward, but others clearly require interpretation by EPA through rulemaking, or recommendations through guidance, in order to give specific meaning for a particular NAAQS. 7

Notwithstanding that section 110(a)(2) provides that “each” SIP submission must meet the list of requirements therein, EPA has long noted that this literal reading of the statute is internally inconsistent, insofar as section 110(a)(2)(I) pertains to nonattainment SIP requirements that could not be met on the schedule provided for these SIP submissions in section 110(a)(1). 8 This illustrates that EPA must determine which provisions of section 110(a)(2) may be applicable for a given infrastructure SIP submission. Similarly, EPA has previously decided that it could take action on different parts of the larger, general “infrastructure SIP” for a given NAAQS without concurrent action on all subsections, such as section 110(a)(2)(D)(i), because the Agency bifurcated the action on these latter “interstate transport” provisions within section 110(a)(2) and worked with states to address each of the four prongs of section 110(a)(2)(D)(i) with substantive administrative actions proceeding on different tracks with different schedules. 9 This illustrates that EPA may conclude that subdividing the applicable requirements of section 110(a)(2) into separate SIP actions may sometimes be appropriate for a given NAAQS where a specific substantive action is necessitated, beyond a mere submission addressing basic structural aspects of the state's implementation plans. Finally, EPA notes that not every element of section 110(a)(2) would be relevant, or as relevant, or relevant in the same way, for each new or revised NAAQS and the attendant infrastructure SIP submission for that NAAQS. For example, the monitoring requirements that might be necessary for purposes of section 110(a)(2)(B) for one NAAQS could be very different than what might be necessary for a different pollutant. Thus, the content of an infrastructure SIP submission to meet this element from a state might be very different for an entirely new NAAQS, versus a minor revision to an existing NAAQS. 10

Similarly, EPA notes that other types of SIP submissions required under the statute also must meet the requirements of section 110(a)(2), and this also demonstrates the need to identify the applicable elements for other SIP submissions. For example, nonattainment SIPs required by part D likewise have to meet the relevant subsections of section 110(a)(2) such as section 110(a)(2)(A) or (E). By contrast, it is clear that nonattainment SIPs would not need to meet the portion of section 110(a)(2)(C) that pertains to part C, i.e., the PSD requirements applicable in attainment areas. Nonattainment SIPs required by part D also would not need to address the requirements of section 110(a)(2)(G) with respect to emergency episodes, as such requirements would not be limited to nonattainment areas. As this example illustrates, each type of SIP submission may implicate some subsections of section 110(a)(2) and not others.

Given the potential for ambiguity of the statutory language of section 110(a)(1) and (2), EPA believes that it is appropriate for EPA to interpret that language in the context of acting on the infrastructure SIPs for a given NAAQS. Because of the inherent ambiguity of the list of requirements in section 110(a)(2), EPA has adopted an approach in which it reviews infrastructure SIPs against this list of elements “as applicable.” In other words, EPA assumes that Congress could not have intended that each and every SIP submission, regardless of the purpose of the submission or the NAAQS in question, would meet each of the requirements, or meet each of them in the same way. EPA elected to use guidance to make recommendations for infrastructure SIPs for these ozone and PM 2.5 NAAQS.

On October 2, 2007, EPA issued guidance making recommendations for the infrastructure SIP submissions for both the 1997 8-hour ozone NAAQS and the 1997 PM 2.5 NAAQS. 11 Within this guidance document, EPA described the duty of states to make these submissions to meet what the Agency characterized as the “infrastructure” elements for SIPs, which it further described as the “basic SIP requirements, including emissions inventories, monitoring, and modeling to assure attainment and maintenance of the standards.”  12 As further identification of these basic structural SIP requirements, “attachment A” to the guidance document included a short description of the various elements of section 110(a)(2) and additional information about the types of issues that EPA considered germane in the context of such infrastructure SIPs. EPA emphasized that the description of the basic requirements listed on attachment A was not intended “to constitute an interpretation of” the requirements, and was merely a “brief description of the required elements.”  13 EPA also stated its belief that with one exception, these requirements were “relatively self explanatory, and past experience with SIPs for other NAAQS should enable States to meet these requirements with assistance from EPA Regions.”  14 However, for the one exception to that general assumption ( i.e., how states should proceed with respect to the requirements of section 110(a)(2)(G) for the 1997 PM 2.5 NAAQS), EPA gave much more specific recommendations. But for other infrastructure SIP submittals, and for certain elements of the submittals for the 1997 PM 2.5 NAAQS, EPA assumed that each state would work with its corresponding EPA regional office to refine the scope of a state's submittal based on an assessment of how the requirements of section 110(a)(2) should reasonably apply to the basic structure of the state's implementation plans for the NAAQS in question.

On September 25, 2009, EPA issued guidance to make recommendations to states with respect to the infrastructure SIPs for the 2006 PM 2.5 NAAQS. 15 In the 2009 Guidance, EPA addressed a number of additional issues that were not germane to the infrastructure SIPs for the 1997 8-hour ozone and 1997 PM 2.5 NAAQS, but were germane to these SIP submissions for the 2006 PM 2.5 NAAQS (e.g., the requirements of section 110(a)(2)(D)(i) that EPA had bifurcated from the other infrastructure elements for those specific 1997 ozone and PM 2.5 NAAQS). Significantly, neither the 2007 Guidance nor the 2009 Guidance explicitly referred to the SSM, director's discretion, minor source NSR, or NSR Reform issues as among specific substantive issues EPA expected states to address in the context of the infrastructure SIPs, nor did EPA give any more specific recommendations with respect to how states might address such issues even if they elected to do so. The SSM and director's discretion issues implicate section 110(a)(2)(A), and the minor source NSR and NSR Reform issues implicate section 110(a)(2)(C). In the 2007 Guidance and the 2009 Guidance, however, EPA did not indicate to states that it intended to interpret these provisions as requiring a substantive submission to address these specific issues in existing SIP provisions in the context of the infrastructure SIPs for these NAAQS. Instead, EPA's 2007 Guidance merely indicated its belief that the states should make submissions in which they established that they have the basic SIP structure necessary to implement, maintain, and enforce the NAAQS. EPA believes that states can establish that they have the basic SIP structure, notwithstanding that there may be potential deficiencies within the existing SIP. Thus, EPA's proposals for other states mentioned these issues not because the Agency considers them issues that must be addressed in the context of an infrastructure SIP as required by section 110(a)(1) and (2), but rather because EPA wanted to be clear that it considers these potential existing SIP problems as separate from the pending infrastructure SIP actions. The same holds true for this action on the infrastructure SIPs for North Carolina.

EPA believes that this approach to the infrastructure SIP requirement is reasonable because it would not be feasible to read section 110(a)(1) and (2) to require a top to bottom, stem to stern, review of each and every provision of an existing SIP merely for purposes of assuring that the state in question has the basic structural elements for a functioning SIP for a new or revised NAAQS. Because SIPs have grown by accretion over the decades as statutory and regulatory requirements under the CAA have evolved, they may include some outmoded provisions and historical artifacts that, while not fully up to date, nevertheless may not pose a significant problem for the purposes of “implementation, maintenance, and enforcement” of a new or revised NAAQS when EPA considers the overall effectiveness of the SIP. To the contrary, EPA believes that a better approach is for EPA to determine which specific SIP elements from section 110(a)(2) are applicable to an infrastructure SIP for a given NAAQS, and to focus attention on those elements that are most likely to need a specific SIP revision in light of the new or revised NAAQS. Thus, for example, EPA's 2007 Guidance specifically directed states to focus on the requirements of section 110(a)(2)(G) for the 1997 PM 2.5 NAAQS because of the absence of underlying EPA regulations for emergency episodes for this NAAQS and an anticipated absence of relevant provisions in existing SIPs.

Finally, EPA believes that its approach is a reasonable reading of section 110(a)(1) and (2) because the statute provides other avenues and mechanisms to address specific substantive deficiencies in existing SIPs. These other statutory tools allow the Agency to take appropriate tailored action, depending upon the nature and severity of the alleged SIP deficiency. Section 110(k)(5) authorizes EPA to issue a “SIP call” whenever the Agency determines that a state's SIP is substantially inadequate to attain or maintain the NAAQS, to mitigate interstate transport, or otherwise to comply with the CAA. 16 Section 110(k)(6) authorizes EPA to correct errors in past actions, such as past approvals of SIP submissions. 17 Significantly, EPA's determination that an action on the infrastructure SIP is not the appropriate time and place to address all potential existing SIP problems does not preclude the Agency's subsequent reliance on provisions in section 110(a)(2) as part of the basis for action at a later time. For example, although it may not be appropriate to require a state to eliminate all existing inappropriate director's discretion provisions in the course of acting on the infrastructure SIP, EPA believes that section 110(a)(2)(A) may be among the statutory bases that the Agency cites in the course of addressing the issue in a subsequent action. 18

North Carolina's infrastructure submission addresses the provisions of sections 110(a)(1) and (2) as described below.

1. 110(a)(2)(A) Emission limits and other control measures: North Carolina's SIP provides an overview of the provisions of the North Carolina Air Pollution Control Regulations relevant to air quality control regulations. The regulations described below have been federally approved in the North Carolina SIP and include enforceable emission limitations and other control measures. NCAC 2D.0400, Ambient Air Quality Standards, and 2D.0500, Emissions Control Standards, establish emission limits for PM 2.5 and address the required control measures, means and techniques for compliance with the PM 2.5 NAAQS. EPA has made the preliminary determination that the provisions contained in these regulations and North Carolina's practices are adequate to protect the PM 2.5 annual and 24-hour NAAQS in the State.

In this action, EPA is not proposing to approve or disapprove any existing state provisions with regard to excess emissions during SSM of operations at a facility. EPA believes that a number of states have SSM provisions which are contrary to the CAA and existing EPA guidance, “State Implementation Plans: Policy Regarding Excess Emissions During Malfunctions, Startup, and Shutdown” (September 20, 1999), and the Agency plans to address such state regulations in the future. In the meantime, EPA encourages any state having deficient SSM provisions to take steps to correct it as soon as possible.

Additionally, in this action, EPA is not proposing to approve or disapprove any existing state rules with regard to director's discretion or variance provisions. EPA believes that a number of states have such provisions which are contrary to the CAA and existing EPA guidance (52 FR 45109 (November 24, 1987)), and the Agency plans to take action in the future to address such state regulations. In the meantime, EPA encourages any state having a director's discretion or variance provision which is contrary to the CAA and EPA guidance to take steps to correct the deficiency as soon as possible.

2. 110(a)(2)(B) Ambient air quality monitoring/data system: NCAC 2D.0600, Monitoring, and 2D.0806, Ambient Monitoring and Modeling Analysis, along with the North Carolina Network Description and Ambient Air Monitoring Network Plan, provide for an ambient air quality monitoring system in the State. Annually, EPA approves the ambient air monitoring network plan for the state agencies. On July 1, 2011, North Carolina submitted its plan to EPA, and on October 20, 2011, EPA approved this plan. North Carolina's approved monitoring network plan can be accessed at www.regulations.gov using Docket ID No. EPA-R04-OAR-2010-1015. EPA has made the preliminary determination that North Carolina's SIP and practices are adequate for the ambient air quality monitoring and data systems related to the 1997 annual and 2006 24-hour PM 2.5 NAAQS.

3. 110(a)(2)(C) Program for enforcement of control measures including review of proposed new sources: Regulation NCAC 2D.0530, Prevention of Significant Deterioration, and 2D.0531, Sources in a Nonattainment Area, pertain to the construction or modification of any major stationary source in areas designated as attainment, nonattainment or unclassifiable under section 107(d)(1)(A)(ii) or (iii) of the CAA. These provisions are designed to ensure that sources in areas attaining the NAAQS at the time of designations prevent any significant deterioration in air quality. NCAC 2D.0531 also sets the permitting requirements for areas in or around nonattainment areas. On July 10, 2012, North Carolina submitted a letter to EPA to provide the schedule to address outstanding requirements related to the PM 2.5 standard for its PSD program and committing to providing the necessary SIP revision to address its SIP deficiencies related to the NSR PM 2.5 Rule requirements. Based on North Carolina's commitment, EPA is proposing to conditionally approve North Carolina's 110(a)(2)(C) infrastructure SIP consistent with section 110(k)(4) of the Act. EPA intends to move forward with finalizing the conditional approval consistent with section 110(k)(4) of the Act.

In this action, EPA is also proposing to conditionally approve North Carolina's infrastructure SIP for the 1997 annual and 2006 24-hour PM 2.5 NAAQS with respect to the general requirement in section 110(a)(2)(C) to include a program in the SIP that regulates the modification and construction of any stationary source as necessary to assure that the NAAQS are achieved. EPA is not proposing to approve or disapprove the State's existing minor NSR program itself to the extent that it is inconsistent with EPA's regulations governing this program. EPA believes that a number of states may have minor NSR provisions that are contrary to the existing EPA regulations for this program. EPA intends to work with states to reconcile state minor NSR programs with EPA's regulatory provisions for the program. The statutory requirements of section 110(a)(2)(C) provide for considerable flexibility in designing minor NSR programs, and EPA believes it may be time to revisit the regulatory requirements for this program to give the states an appropriate level of flexibility to design a program that meets their particular air quality concerns, while assuring reasonable consistency across the country in protecting the NAAQS with respect to new and modified minor sources.

4. 110(a)(2)(D)(ii) Interstate and International transport provisions: NCAC 2D.0530, Prevention of Significant Deterioration, 2D.0531, Sources in a Nonattainment Area, and 2D.0532, Sources Contributing to an Ambient Violation, describe how the State will notify neighboring states of potential impacts from new or modified sources. North Carolina does not have any pending obligation under sections 115 and 126 of the CAA. EPA has made the preliminary determination that North Carolina's SIP and practices are adequate for insuring compliance with the applicable requirements relating to interstate and international pollution abatement for the 1997 annual and 2006 24-hour PM 2.5 NAAQS.

5. 110(a)(2)(E) Adequate resources: EPA is proposing two separate actions with respect to the sub-elements required pursuant to section 110(a)(2)(E). Section 110(a)(2)(E) requires that each implementation plan provide (i) necessary assurances that the State will have adequate personnel, funding, and authority under state law to carry out its implementation plan, (ii) that the State comply with the requirements respecting State Boards pursuant to section 128 of the Act, and (iii) necessary assurances that, where the State has relied on a local or regional government, agency, or instrumentality for the implementation of any plan provision, the State has responsibility for ensuring adequate implementation of such plan provisions. EPA is proposing to approve North Carolina's SIP as meeting the requirements of sub-elements 110(a)(2)(E)(i) and (iii). With respect to 110(a)(2)(E)(ii) (regarding state boards), EPA is proposing to conditionally approve this sub-element. EPA's rationale for today's proposals respecting each sub-element is described in turn below.

In support of EPA's proposal to approve sub-elements 110(a)(2)(E)(i) and (iii), EPA notes that DAQ is responsible for adopting air quality rules, revising SIPs, developing and tracking the budget, establishing the title V fees, and other planning needs. DAQ also coordinates agreements with local air pollution control programs. Additionally, the SIP submittal cover letter provided by North Carolina certifies the sufficiency of the state program with 110(a)(2)(E)(i) and (iii) requirements. As evidence of the adequacy of DAQ's resources with respect to sub-elements (i) and (iii), EPA submitted a letter to North Carolina on March 17, 2011, outlining 105 grant commitments and the current status of these commitments for fiscal year 2010. The letter EPA submitted to North Carolina can be accessed at www.regulations.gov using Docket ID No. EPA-R04-OAR-2011-0352. Annually, states update these grant commitments based on current SIP requirements, air quality planning, and applicable requirements related to the NAAQS. There were no outstanding issues for fiscal year 2010, therefore, North Carolina's grants were finalized and closed out. EPA has made the preliminary determination that North Carolina has adequate resources for implementation of the 1997 annual and 2006 24-hour PM 2.5 NAAQS. In addition, the requirements of 110(a)(2)(E)(i) and (iii) are met when EPA performs a completeness determination for each SIP submittal. This determination ensures that each submittal provides evidence that adequate personnel, funding, and legal authority under State Law has been used to carry out the state's implementation plan and related issues. North Carolina's authority is included in all prehearings and final SIP submittal packages submitted for approval by EPA. EPA has made the preliminary determination that North Carolina has adequate resources for implementation of the 1997 annual and 2006 24-hour PM 2.5 NAAQS.

As discussed above, with respect to sub-element 110(a)(2)(E)(ii), EPA is proposing to conditionally approve North Carolina's infrastructure SIP as to this requirement. North Carolina's April 1, 2008, and September 21, 2009, infrastructure certification letters did not certify the adequacy of the State's implementation plan to meet the requirements of section 110(a)(2)(E)(ii) (requiring state compliance with section 128 of the CAA), and presently North Carolina's SIP does not include provisions to meet section 128 requirements.

The section 128 State Board requirements—as applicable to the infrastructure SIP pursuant to section 110(a)(2)(E)(ii)—provide at subsection (a)(1) that each SIP shall contain requirements that any board or body which approves permits or enforcement orders be subject to the described public interest and income restrictions. It further requires at subsection (a)(2) that any board or body, or the head of an executive agency with similar power to approve permits or enforcement orders under the CAA, shall also be subject to conflict of interest disclosure requirements. EPA's proposed conditional approval of North Carolina's 110(a)(2)(E)(ii) infrastructure SIP is based upon the State's commitment to adopt specific enforceable measures related to both 128(a)(1) and 128(a)(2) to address current deficiencies in the North Carolina SIP.

For purposes of section 128(a)(1), initial permit approvals and enforcement orders are issued by delegated officials within NC DENR. Pursuant to N.C.G.S. § 143-215.114A, the Secretary NC DENR is authorized to assess civil penalties for violations of the State's Air Pollution Control laws. NC DENR is also authorized pursuant to N.C.G.S. § 143-215.114C to request the Attorney General of the State to institute a civil action seeking injunctive relief to restrain the violation or threatened violation of the State's Air Pollution Control laws. The North Carolina Environmental Management Commission is authorized pursuant to N.C.G.S. § 143-215.108, to approve Air Pollution Control permits in the State, however, the Commission has delegated by regulation this authority to the Secretary of the Department of Environment, Health, and Natural Resources. See 15A N.C. Admin. Code 02A.0105(a)(2). 19 As such, EPA is proposing to conditionally approve element 110(a)(2)(E)(ii) with respect to 128(a)(1) based upon a commitment by the State to timely submit any SIP revisions necessary to remove the Environmental Management Commission's authority to approve permits or enforcement orders under the State's Air Pollution Act. 20

Regarding section 128(a)(2) (also made applicable to the infrastructure SIP pursuant to section 110(a)(2)(E)(ii)), North Carolina has committed to EPA to submit for incorporation into the SIP relevant provisions of N.C.G.S. § 138A, Article 3: Public Disclosure of Economic Interests, sufficient to satisfy the conflict of interest provisions applicable to the head of NC DENR and those officials within the Department delegated his authority.

As a result, EPA is proposing to conditionally approve North Carolina's infrastructure SIP with respect to element 110(a)(2)(E)(ii) consistent with section 110(k)(4) of the CAA. North Carolina's above-described commitments are contained in the State's January 11, 2012, letter of commitment submitted to EPA in connection with North Carolina's infrastructure submittal for purposes of the 1997 Ozone NAAQS. The letter North Carolina submitted can be accessed at www.regulations.gov using Docket ID No. EPA-R04-OAR-2011-0352. In the letter of commitment, North Carolina committed to adopt specific enforceable measures related to both CAA sections 128(a)(1) and 128(a)(2) to address deficiencies in the North Carolina SIP related to CAA section 110(a)(2)(E)(ii). Notably, changes to North Carolina rules regarding the 1997 Ozone NAAQS are the same types of changes that would be required as part of today's proposed conditional approval for the 1997 annual and 2006 24-hour PM 2.5 NAAQS. EPA previously finalized a conditional approval regarding sub-element 110(a)(2)(E)(ii) for the 1997 Ozone NAAQS. 77 FR 5703 (February 6, 2012).

Consistent with the State's January 11, 2012, commitment, North Carolina must submit to EPA by February 6, 2013, SIP revisions adopting specific enforceable measures related to both CAA sections 128(a)(1) and 128(a)(2). If the State fails to submit these revisions by February 6, 2013, a final conditional approval would then automatically become a disapproval on that date and EPA will issue a finding of disapproval. EPA is not required to propose the finding of disapproval. If the conditional approval is converted to a disapproval, the final disapproval triggers the Federal Implementation Plan requirement under section 110(c). However, if the State meets its commitment within the applicable timeframe, the conditionally approved submission will remain a part of the SIP until EPA takes final action approving or disapproving the new submittal. If EPA disapproves the new submittal, today's conditionally approved submittal will also be disapproved at that time. If EPA approves the new submittal, North Carolina's infrastructure SIP will be fully approved in its entirety and replace the conditionally approved element in the SIP.

6. 110(a)(2)(F) Stationary source monitoring system: North Carolina's infrastructure submission describes how the State establishes requirements for emissions compliance testing and utilizes emissions sampling and analysis. It further describes how the State ensures the quality of its data through observing emissions and monitoring operations. North Carolina DAQ uses these data to track progress towards maintaining the NAAQS, develop control and maintenance strategies, identify sources and general emission levels, and determine compliance with emission regulations and additional EPA requirements. These requirements are provided in NCAC 2D.0605, General Recordkeeping and Reporting Requirements, 2D.0613, Quality Assurance Program, and 2D.0614, Compliance Assurance Monitoring. Additionally, North Carolina is required to submit emissions data to EPA for purposes of the National Emissions Inventory (NEI). The NEI is EPA's central repository for air emissions data. EPA published the Air Emissions Reporting Rule (AERR) on December 5, 2008, which modified the requirements for collecting and reporting air emissions data (73 FR 76539). The AERR shortened the time states had to report emissions data from 17 to 12 months, giving states one calendar year to submit emissions data. All states are required to submit a comprehensive emissions inventory every three years and report emissions for certain larger sources annually through EPA's online Emissions Inventory System. States report emissions data for the six criteria pollutants and the precursors that form them—nitrogen oxides, sulfur dioxide, ammonia, lead, carbon monoxide, particulate matter, and volatile organic compounds. Many states also voluntarily report emissions of hazardous air pollutants. North Carolina made its latest update to the NEI on December 19, 2011. EPA compiles the emissions data, supplementing it where necessary, and releases it to the general public through the Web site http://www.epa.gov/ttn/chief/eiinformation.html. EPA has made the preliminary determination that North Carolina's SIP and practices are adequate for the stationary source monitoring systems related to the 1997 annual and 2006 24-hour PM 2.5 NAAQS.

7. 110(a)(2)(G) Emergency power: NCAC 2D.0300, Air Pollution Emergencies, authorizes the North Carolina DAQ Director to determine the existence of an air pollution emergency and it describes the preplanned abatement strategies triggered by the occurrence of such an emergency. These criteria have previously been approved by EPA. On September 25, 2009, EPA released the guidance entitled “Guidance on SIP Elements Required Under Sections 110(a)(1) and (2) for the 2006 24-Hour Fine Particulate (PM 2.5 ) National Ambient Air Quality Standards (NAAQS).” This guidance clarified that “to address the section 110(a)(2)(G) element, states with air quality control regions identified as either Priority I, IA, or Priority II by the `Prevention of Air Pollution Emergency Episodes' rule at 40 CFR 51.150, must develop emergency episode contingency plans.” EPA's September 25, 2009, guidance also states that “until the Agency finalized changes to the emergency episode regulation to establish for PM 2.5 specific levels for classifying areas as Priority I, IA, or II for PM 2.5 , and to establish a significant harm level (SHL) * * *,” it recommends that states with a 24-Hour PM 2.5 concentration above 140 µg/m 3 (using the most recent three years of data) develop an emergency episode plan. For states where this level has not been exceeded, the state can certify that it has appropriate general emergency powers to address PM 2.5 related episodes, and that no specific emergency episode plans are needed at this time. On September 19, 2008, DAQ submitted a letter to EPA verifying that it is a Class III Priority Area and is exempt from adopting emergency episode plan for PM 2.5 NAAQS. EPA has made the preliminary determination that North Carolina's SIP and practices are adequate for emergency powers related to the 1997 annual and 2006 24-hour PM 2.5 NAAQS.

8. 110(a)(2)(H) Future SIP revisions: As previously discussed, DAQ is responsible for adopting air quality rules and revising SIPs as needed to attain or maintain the NAAQS. North Carolina has the ability and authority to respond to calls for SIP revisions, and has provided a number of SIP revisions over the years for implementation of the PM NAAQS. Specific to the 1997 annual and 2006 24-hour PM 2.5 NAAQS, North Carolina's submissions have included:

• August 21, 2009, Hickory PM 2.5 Attainment Demonstration;

• August 21, 2009, Triad PM 2.5 Attainment Demonstration;

• December 18, 2009, Triad PM 2.5 Redesignation Request and Maintenance Plan; and,

• December 18, 2009, Hickory PM 2.5 Redesignation Request and Maintenance Plan.

EPA has made the preliminary determination that North Carolina's SIP and practices adequately demonstrate a commitment to provide future SIP revisions related to the 1997 annual and 2006 24-hour PM 2.5 NAAQS when necessary.

9. 110(a)(2)(J) (121 consultation) Consultation with government officials: NCAC 2D.0530, Prevention of Significant Deterioration, and 2D.0531, Sources in a Nonattainment Area, as well as North Carolina's Regional Haze Implementation Plan (which allows for consultation between appropriate state, local, and tribal air pollution control agencies as well as the corresponding Federal Land Managers), provide for consultation with government officials whose jurisdictions might be affected by SIP development activities. North Carolina adopted state-wide consultation procedures for the implementation of transportation conformity. These consultation procedures include considerations associated with the development of mobile inventories for SIPs. Implementation of transportation conformity as outlined in the consultation procedures requires DAQ to consult with federal, state and local transportation and air quality agency officials on the development of motor vehicle emissions budgets. EPA approved North Carolina's consultation procedures on December 27, 2002 (See 67 FR 78983). Additionally, DAQ submitted a regional haze plan which outlines its consultation practices with Federal Land Managers. EPA has made the preliminary determination that North Carolina's SIP and practices adequately demonstrate consultation with government officials related to the 1997 annual and 2006 24-hour PM 2.5 NAAQS when necessary.

10. 110(a)(2)(J) (127 public notification) Public notification: DAQ has public notice mechanisms in place to notify the public of PM 2.5 and other pollutant forecasting, including an air quality monitoring Web site providing PM 2.5 alerts, http://xapps.enr.state.nc.us/aq/ForecastCenter. North Carolina also has an outreach program to educate the public and promote voluntary emissions reduction measures including the “Turn Off Your Engine” idling reduction program. NCAC 2D.0300, Air Pollution Emergencies, requires that DAQ notify the public of any air pollution episode or NAAQS violation. EPA has made the preliminary determination that North Carolina's SIP and practices adequately demonstrate the State's ability to provide public notification related to the 1997 annual and 2006 24-hour PM 2.5 NAAQS when necessary.

11. 110(a)(2)(J) (PSD) PSD and visibility protection: North Carolina demonstrates its authority to regulate new and modified sources of PM to assist in the protection of air quality in NCAC 2D.0530, Prevention of Significant Deterioration, and 2D.0531, Sources in a Nonattainment Area, which describe the permit requirements for new major sources or major modifications of existing sources in areas classified as attainment or unclassifiable under section 107(d)(1)(A)(ii) or (iii) of the CAA. This ensures that sources in areas attaining the NAAQS at the time of designations prevent any significant deterioration in air quality. NCAC 2D.0531 also sets the permitting requirements for areas in or around nonattainment areas. As with infrastructure element 110(a)(2)(C), infrastructure element 110(a)(2)(J) of North Carolina's SIP does not include provisions to meet all the requirements for NSR/PSD related to the PM 2.5 standard. As noted above, on July 10, 2012, North Carolina submitted a letter to EPA to provide the schedule to address outstanding requirements related to the PM 2.5 standard for its PSD program and committing to providing the necessary SIP revision to address the PM 2.5 NSR/PSD requirements for which the SIP is currently deficient. As a result, EPA is proposing to conditionally approve North Carolina's infrastructure SIP with respect to element 110(a)(2)(J) in accordance with section 110(k)(4) of the Act. EPA intends to move forward with finalizing the conditional approval consistent with section 110(k)(4) of the Act.

With regard to the applicable requirements for visibility protection, EPA recognizes that states are subject to visibility and regional haze program requirements under part C of the Act (which includes sections 169A and 169B). In the event of the establishment of a new NAAQS, however, the visibility and regional haze program requirements under part C do not change. Thus, EPA finds that there is no new visibility obligation “triggered” under section 110(a)(2)(J) when a new NAAQS becomes effective. This would be the case even in the event a secondary PM 2.5 NAAQS for visibility is established, because this NAAQS would not affect visibility requirements under part C.

12. 110(a)(2)(K) Air quality and modeling/data: NCAC 2D.0300, Air Pollution Emergencies, and NCAC 2D.0806, Ambient Monitoring and Modeling Analysis, require that air modeling be conducted to determine permit applicability. These regulations demonstrate that North Carolina has the authority to provide relevant data for the purpose of predicting the effect on ambient air quality of the 1997 annual and 2006 24-hour PM 2.5 NAAQS. EPA has made the preliminary determination that North Carolina's SIP and practices adequately demonstrate the State's ability to provide for air quality and modeling, along with analysis of the associated data, related to the 1997 annual and 2006 24-hour PM 2.5 NAAQS when necessary.

13. 110(a)(2)(L) Permitting fees: North Carolina addresses the review of construction permits as previously discussed in 110(a)(2)(C) above. Permitting fees in North Carolina are collected through the State's federally-approved title V fees program, according to State's federally-approved title V fees program according to State Regulation NCAC 2Q.0200, Permit Fees. EPA has made the preliminary determination that North Carolina's SIP and practices adequately provide for permitting fees related to the 1997 annual and 2006 24-hour PM 2.5 NAAQS when necessary.

14. 110(a)(2)(M) Consultation/participation by affected local entities: NCAC 2Q.0307, Public Participation Procedures requires that DAQ notify the public of an application, a preliminary determination, the activity or activities involved in a permit action, any emissions associated with a permit modification, and the opportunity for comment prior to making a final permitting decision. Furthermore, DAQ has demonstrated consultation with, and participation by, affected local entities through its work with local political subdivisions during the developing of its Transportation Conformity SIP and Regional Haze Implementation Plan. EPA has made the preliminary determination that North Carolina's SIP and practices adequately demonstrate consultation with affected local entities related to the 1997 annual and 2006 24-hour PM 2.5 NAAQS when necessary.

EPA is now proposing two related types of actions. First, EPA is proposing to determine that the North Carolina SIP is currently adequate, as explained in North Carolina's April 1, 2008, and September 21, 2009, submittals, to meet the requirements of CAA 110(a)(1) and (2)(A)-(B), (D)-(H), (K)-(M), pursuant to EPA's October 2, 2007, and September 25, 2009, guidance to ensure that the 1997 annual and 2006 24-hour PM 2.5 NAAQS are implemented, enforced, and maintained in North Carolina. Second, EPA is proposing to conditionally approve North Carolina's infrastructure submissions for both the 1997 annual and 2006 24-hour PM 2.5 NAAQS with regard to CAA sections 110(a)(2)(C), 110(a)(2)(E)(ii) and 110(a)(2)(J).

Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable federal regulations. See 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this proposed action merely approves state law as meeting federal requirements and does not impose additional requirements beyond those imposed by State law. For that reason, this proposed action:

• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Order 12866 (58 FR 51735, October 4, 1993);

• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq. );

• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. );

• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);

• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);

• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);

• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);

• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and

• Does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).

In addition, this proposed rule does not have tribal implications as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), because the SIP is not approved to apply in Indian country located in the state, and EPA notes that it will not impose substantial direct costs on tribal governments or preempt tribal law.

I. General Information A. What should I consider as I prepare my comments for EPA?

1. Submitting CBI. Do not submit CBI to EPA through http://www.regulations.gov or email. 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. Tips for Preparing Your Comments. When submitting comments, remember to:

a. Identify the rulemaking by docket number and other identifying information (subject heading, Federal Register date and page number).

b. 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.

c. Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.

d. Describe any assumptions and provide any technical information and/or data that you used.

e. If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.

f. Provide specific examples to illustrate your concerns, and suggest alternatives.

g. Explain your views as clearly as possible, avoiding the use of profanity or personal threats.

h. Make sure to submit your comments by the comment period deadline identified.

Detailed background information describing the proposed rulemaking may be found in a previously published document: Approval, Disapproval and Promulgation of Implementation Plans; State of Wyoming; Regional Haze State Implementation Plan; Federal Implementation Plan for Regional Haze; Proposed Rule (77 FR 33022, June 4, 2012).

EPA requests comment on the information described below that has been added to docket EPA-R08-OAR-2012-0026.

• A July 12, 2012 letter from Micheal Dunn, PacifiCorp, to Carl Daly, EPA Region 8. The information provided in the letter is to support EPA's third proposal in the alternative for Jim Bridger Unit 1 and Unit 2 as described in the proposed rulemaking.

Throughout this document, the terms “we,” “us,” and “our” refer to EPA.

On February 11, 2010, September 1, 2010, and May 22, 2012, the Clark County Department of Air Quality (Clark or DAQ) submitted new and amended regulations to EPA for approval as revisions to the Clark County portion of the Nevada SIP under the Clean Air Act (CAA or Act). Collectively, the submitted regulations (referred to as “Sections”) comprise DAQ's current program for preconstruction review and permitting of new or modified stationary sources under DAQ jurisdiction in Clark County, including related definitions. 1 These SIP revision submittals, referred to herein as the “NSR SIP submittal” or “submitted NSR rules,” represent a comprehensive revision to Clark County's preconstruction review and permitting program and are intended to satisfy the requirements under both part C (prevention of significant deterioration) (PSD) and part D (nonattainment new source review) of title I of the Act as well as the general preconstruction review requirements for minor sources under section 110(a)(2)(C) of the Act. These preconstruction review and permitting programs are often collectively referred to as “New Source Review” (NSR).

It should be noted that pursuant to State law, the State of Nevada, not a local air district, has jurisdiction over plants which generate electricity by using steam produced by the burning of fossil fuel within the State of Nevada. The applicable State law, now codified in Nevada Revised Statutes (NRS) 445B.500, was approved by EPA in 1980 as NRS 445.546(4). See 45 FR 46384 (July 10, 1980) (now codified at 40 CFR 52.1470(e)). Thus, the State, not DAQ, has jurisdiction over such plants that are located or that will be constructed within Clark County. The submitted NSR rules therefore apply to stationary sources located in Clark County, except for plants which generate electricity by using steam produced by the burning of fossil fuel, which are subject to the Nevada Division of Environmental Protection's (NDEP) jurisdiction.

Table 1 lists the rules addressed by this proposal with the dates that they were adopted by DAQ and submitted to EPA by NDEP, which is the governor's designee for Nevada SIP submittals.

On August 11, 2010 and March 1, 2011, DAQ's February 11, 2010 and September 1, 2010 submittals were deemed by operation of law to meet the completeness criteria in 40 CFR part 51, appendix V, which must be met before formal EPA review. We find that DAQ's May 22, 2012 submittal also meets the appendix V completeness criteria. Each of these submittals includes evidence of public notice and adoption of the regulation. While we can act only on the most recently submitted version of each regulation (which supersedes earlier submitted versions), we have reviewed materials provided with previous submittals. Our technical support document (TSD) provides additional background information on each of the submitted rules.

The existing SIP-approved NSR program for new or modified stationary sources in Clark County consists of one State regulation and seven Clark County regulations (“Sections”), or portions thereof, which EPA approved on April 14, 1981, June 18, 1982, June 21, 1981, and September 7, 2004. See 46 FR 21758 (April 14, 1981) (final rule approving DAQ Section 1); 47 FR 26620 (June 21, 1982) (final rule approving revisions to DAQ Section 1); 47 FR 26386 (June 18, 1982) (final rule approving DAQ Section 16); and 69 FR 54006 (September 7, 2004) (final rule approving, in whole or in part, DAQ Sections 0, 11, 12, 58, and 59, and Nevada Administrative Code (NAC) 445B.22083). Collectively, these regulations established the NSR requirements for both major and minor stationary sources under DAQ jurisdiction in Clark County, including requirements for the generation and use of emission reduction credits in nonattainment areas.

Consistent with Clark's stated intent to have the submitted NSR rules replace the existing SIP NSR program in its entirety, EPA's approval of the regulations identified above in table 1 would have the effect of entirely superseding, or rescinding our prior approval of, all but two of the rules in the current SIP-approved program. Table 2 lists the existing rules in the Nevada SIP governing NSR for stationary sources under DAQ jurisdiction. All of these rules except for Section 11 and NAC section 445B.22083 would be replaced in, or otherwise deleted from, the SIP by the submitted set of rules listed in table 1 if EPA were to take final action as proposed herein. Section 11 is a rule that defines DAQ's “ambient air quality standards.” NAC 445B.22083 is a regulation adopted by the Nevada State Environmental Commission (SEC) that prohibits the construction of new power plants or major modifications to existing power plants under State jurisdiction within specified areas designated nonattainment for certain NAAQS within Clark County. 4 Our proposed action would have no effect on Section 11 or NAC 445B.22083, both of which remain part of the applicable Nevada SIP.

The purpose of this proposed rule is to present our evaluation under the CAA and EPA's regulations of the new and amended NSR rules submitted by DAQ on February 11, 2010, September 1, 2010, and May 22, 2012, as identified in table 1. We provide our reasoning in general terms below but provide more detailed analysis in our technical support document (TSD), which is available in the docket for this proposed rulemaking.

EPA has reviewed the rules submitted by DAQ governing NSR for stationary sources under DAQ jurisdiction for compliance with the CAA's general requirements for SIPs in CAA section 110(a)(2), EPA's regulations for stationary source permitting programs in 40 CFR part 51, sections 51.160 through 51.164, and the CAA requirements for SIP revisions in CAA section 110(l). 5 As described below, EPA is proposing a limited approval and limited disapproval of the submitted NSR rules.

With respect to procedures, CAA sections 110(a) and 110(l) require that revisions to a SIP be adopted by the State after reasonable notice and public hearing. EPA has promulgated specific procedural requirements for SIP revisions in 40 CFR part 51, subpart F. These requirements include publication of notices, by prominent advertisement in the relevant geographic area, of a public hearing on the proposed revisions, a public comment period of at least 30 days, and an opportunity for a public hearing.

Based on our review of the public process documentation included in the February 11, 2010, September 1, 2010, and May 22, 2012 submittals, we find that DAQ has provided sufficient evidence of public notice and opportunity for comment and public hearings prior to adoption and submittal of these rules to EPA.

With respect to substantive requirements, we have evaluated each “Section” of DAQ's submitted NSR rules in accordance with the CAA and regulatory requirements that apply to: (1) General preconstruction review programs for minor sources under section 110(a)(2)(C) of the Act, (2) PSD permit programs under part C of title I of the Act, and (3) Nonattainment NSR permit programs under part D of title I of the Act. For the most part, the submitted NSR rules satisfy the applicable requirements for these three permit programs and would strengthen the applicable SIP by updating the regulations and adding requirements to address new or revised NSR permitting requirements promulgated by EPA in the last several years, but the submitted NSR rules also contain specific deficiencies which prevent full approval. Below, we discuss generally our evaluation of DAQ's submitted NSR rules and the deficiencies that are the basis for our proposed limited disapproval of these rules. Our TSD contains a more detailed evaluation and recommendations for program improvements.

Section 110(a)(2)(C) of the Act requires that each SIP include a program to provide for “regulation of the modification and construction of any stationary source within the areas covered by the plan as necessary to assure that national ambient air quality standards are achieved, including a permit program as required in parts C and D” of title I of the Act. Thus, in addition to the permit programs required in parts C and D of title I of the Act, which apply to new or modified “major” stationary sources of pollutants, each SIP must include a program to provide for the regulation of the construction and modification of any stationary source within the areas covered by the plan as necessary to assure that the NAAQS are achieved. These general pre-construction requirements are commonly referred to as “minor NSR” and are subject to EPA's implementing regulations in 40 CFR 51.160-51.164.

Section 12.1 contains the requirements for review and permitting of individual minor stationary sources under DAQ jurisdiction in Clark County, and Section 12.4 contains the requirements for review and permitting of modifications at major stationary sources that are not “major modifications” and therefore not subject to PSD or Nonattainment NSR. These regulations satisfy most of the statutory and regulatory requirements for minor NSR programs, but Section 12.1 also contains several deficiencies that form the basis for our proposed limited disapproval, as discussed below.

First, one of the key control requirements in Section 12.1 appears to depend upon a definition of “ambient air quality standards” that is not consistent with the NAAQS. Specifically, subsection 12.1.4.1(c) requires that each minor source permit issued by Clark include emission limitations that ensure that “[t]he ambient air quality standards will be attained or maintained” (12.1.4.1(c)) and appears to depend upon DAQ's definition of “ambient air quality standards” in Section 11, which does not include the 2006 24-hour PM 2.5 NAAQS of 35 ug/m3 or the 2008 Lead (Pb) NAAQS of 15 ug/m3 (rolling 3-month average). See 40 CFR 50.13 and 50.16. EPA approved Section 11 into the Clark County portion of the Nevada SIP on September 7, 2004 (69 FR 54006), and at the time this definition was consistent with the Federal NAAQS, but given EPA's promulgation of revised NAAQS for PM 2.5 and Lead (Pb) in 2006 and 2008, respectively, Section 11 is no longer consistent with the NAAQS. As such, with respect to the 2006 24-hour PM 2.5 NAAQS and the 2008 Lead NAAQS, Section 12.1 does not provide a means for determining whether the construction or modification of a stationary source will result in a violation of applicable portions of the control strategy or interference with attainment or maintenance of the NAAQS, as required by 40 CFR 51.160.

Second, subsection 12.1.3.6(a)(5) provides that an applicant may identify specific portions of a permit that it wants to be Federally enforceable. This is not consistent with CAA requirements, as all conditions of a permit issued pursuant to a SIP-approved permit program are Federally enforceable. See CAA 113, 304; see also 40 CFR 52.23. As a general matter, we note that any statement contained in a permit application regarding Federal enforceability has no effect on EPA's or citizens' enforcement authorities under sections 113 and 304 of the Act.

Third, neither Section 12.1 nor Section 12.4 contain a provision addressing, for minor stationary sources, the requirement in 40 CFR 51.160(d) to “provide that approval of any construction or modification must not affect the responsibility on the owner or operator to comply with applicable portions of the control strategy.”

Fourth, Section 12.1 provides (in subsection 12.1.2(a)) an exemption from permitting requirements for “[c]onstruction and operation of any emission units or performance of any of the activities listed in” a separate rule called Section 12.5, which addresses the operating permit requirements of title V of the CAA. Because Section 12.5 is neither approved into the SIP nor included in the NSR SIP submittal, we cannot conclude that this exemption is appropriate for minor NSR purposes.

Fifth, the applicability provisions in Section 12.1 (in particular the definition of “minor source” in subsection 12.1.1(c)) are deficient as they do not address sources of PM 2.5 or PM 2.5 precursor emissions. Pursuant to CAA section 110(a)(2)(C), States were required to amend their minor source programs to include direct PM 2.5 emissions and precursor emissions in the same manner as included for purposes of PM 2.5 major NSR. See 73 FR 28321, 28344 (May 16, 2008). In the absence of applicability provisions that appropriately capture minor sources of PM 2.5 or their precursors, Section 12.1 does not provide for protection of the PM 2.5 NAAQS in the issuance of permits for new or modified minor sources as required by 40 CFR 51.160-51.164.

Finally, Section 12.1 does not contain any provisions designed to ensure that the air quality impacts of stationary sources are not underestimated due to stack heights that exceed good engineering practice or air dispersion modeling techniques that do not satisfy the criteria in 40 CFR 51.118(b), as required by 40 CFR 51.164.

Compared to the existing SIP minor NSR program in Section 12 (as adopted October 7, 2003), however, submitted Section 12.1 and Section 12.4 represent an overall strengthening of DAQ's minor NSR program. For example, the new rules establish more detailed monitoring, recordkeeping, and reporting requirements, more specific criteria for permit applications and conditions for permit issuance, and well-defined criteria for the determination of emission limits and standards that represent “reasonably available control technology,” which we expect will allow for more effective implementation and enforcement of the requirements applicable to minor stationary sources in Clark County. See, e.g., Section 12.1, subsections 12.1.4.1. and 12.1.5.1, compared with SIP Section 12 (as adopted October 7, 2003), subsections 12.1.1. and 12.8.2.

Part C of title I of the Act contains the provisions for the prevention of significant deterioration (PSD) of air quality in areas designated “attainment” or “unclassifiable” for the NAAQS, including preconstruction permit requirements for new major sources or major modifications proposing to construct in such areas. EPA's regulations for PSD permit programs are found in 40 CFR 51.166 and 40 CFR 52.21. Clark County is currently designated as “attainment” or “unclassifiable/attainment” for all NAAQS pollutants, except for the PM 10 standard in Las Vegas Valley (hydrographic area #212) and for the 1997 8-hour ozone standard in Las Vegas Valley and additional portions of the county. See 40 CFR 81.329.

Section 12.2 and Section 12.4 contain the requirements for review and permitting of PSD sources under DAQ jurisdiction in Clark County. These regulations satisfy most of the statutory and regulatory requirements for PSD permit programs, but Section 12.2 also contains several deficiencies that form the basis for our proposed limited disapproval, as discussed below.

First, the definition of “allowable emissions” in subsection 12.2.2(b) provides for calculation of emissions rates based on “practically enforceable” permit limits, in lieu of federally enforceable limits, but it does not provide criteria by which a limit will be judged to be “practically enforceable” by DAQ. This definition also allows for permit conditions with “future compliance dates” to be used to determine allowable emissions, which is not consistent with EPA's definition of the term in 40 CFR 51.166(b)(16).

Second, the definition of “baseline actual emissions” (BAE) in subsection 12.2.2(c), paragraph (1)(B)(i), includes a requirement to adjust the BAE downward to “exclude any emissions that would have exceeded an emission limitation with which the major stationary source must comply as of the particular date, had such major stationary source been required to comply with such limitations during the consecutive 24-month period” (emphasis added). EPA's definition of BAE in 40 CFR 51.166(b)(47)(ii)( c ) includes a similar provision but requires a downward adjustment in BAE “to exclude any emissions that would have exceeded an emission limitation with which the major stationary source must currently comply. * * *” The reference in subsection 12.2.2(c) to an emission limitation that applied “as of the particular date” instead of an emission limitation with which the source must “currently comply” is problematic, as it is not clear which “particular date” the definition refers to.

Third, the definition of “net emissions increase” (NEI) in subsection 12.2.2(ii) contains several provisions in subparagraph (1)(C) for calculating “actual emissions after the contemporaneous project” which are not consistent with EPA's definition of NEI in 40 CFR 51.166(b)(3). EPA's definition of NEI allows for consideration of those emission increases and decreases that are “contemporaneous” with the project under review but does not call for any assessment of actual emissions after a contemporaneous project. 40 CFR 51.166(b)(3). Additionally, subparagraph (1)(C)(ii) allows for the calculation of NEI to be based on “projected actual emissions” in certain cases, which is not allowed under EPA's definition of NEI in 40 CFR 51.166(b)(3).

Fourth, the definition of “major modification” in subsection 12.2.2(dd) is not consistent with EPA's current approach to the treatment of fugitive emissions in applicability determinations for major modifications. Specifically, subsection 12.2.2(dd) requires, in subparagraph (4), that fugitive emissions be excluded from the determination of whether a particular physical or operational change is a major modification “unless the major stationary source is a categorical stationary source or belongs to any other stationary source category which, as of August 7, 1980, is being regulated under Section 111 or 112 of the Act.” Although this language is consistent with the text of 40 CFR 51.166(b)(2)(v) as of July 1, 2010, EPA has administratively stayed this paragraph indefinitely, effective March 30, 2011. See 76 FR 17548 (final rule effectuating and extending stay of the final rule entitled “Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NSR): Reconsideration of Inclusion of Fugitive Emissions” (“Fugitive Emissions Rule”) published December 19, 2008). The effect of this administrative stay was to revert the treatment of fugitive emissions in applicability determinations to the approach that applied prior to the Fugitive Emissions Rule, thus requiring that fugitive emissions be included in “major modification” applicability determinations for all source categories. 76 FR at 17550, 17551.

Fifth, the definition of “regulated NSR pollutant” in subsection 12.2.2(pp) does not satisfy current requirements regarding identification of precursors and treatment of “condensable particular matter” in PSD applicability determinations. EPA's definition of “regulated NSR pollutant” in 40 CFR 51.166(b)(49)(i) requires identification of specific precursors for ozone and PM 2.5 purposes. Additionally, EPA's definition of “regulated NSR pollutant” in 40 CFR 51.166(b)(49) includes a paragraph (vi) stating that on or after January 1, 2011, “gaseous emissions from a source or activity which condense to form particulate matter at ambient temperatures” ( i.e., condensable particular matter) must be accounted for in applicability determinations and in establishing emissions limitations for particulate matter (PM), PM 2.5 and PM 10 in PSD permits. See 73 FR 28321 (May 16, 2008) (final rule to implement NSR and PSD requirements for PM 2.5 ).

Sixth, one provision governing “Plantwide Applicability Limits” (PALs) in subsection 12.2.19 is not entirely consistent with EPA's requirement regarding the timeframe for adjustment of a PAL to address compliance dates that occur during the PAL effective period. Specifically, where the compliance date for a State or Federal requirement that applies to the PAL source occurs during the PAL effective period, subsection 12.2.9 allows for a PAL to be adjusted “at the time the affected Part 70 Operating Permit is renewed,” rather than “at the time of PAL permit renewal or title V permit renewal, whichever occurs first,” as required by 40 CFR 51.166(w)(10)(v) (emphases added). This is a deficiency because, although Part 70 permits are renewed more frequently than PAL permits, at any given time it is possible that the expiration date for a PAL permit will occur before the expiration date for a Part 70 permit.

Finally, neither Section 12.2 nor Section 12.4 contains a provision addressing, for new or modified major stationary sources, the requirement in 40 CFR 51.160(d) to “provide that approval of any construction or modification must not affect the responsibility on the owner or operator to comply with applicable portions of the control strategy.”

Compared to the existing SIP PSD program in Section 12 (as adopted October 7, 2003), however, submitted Section 12.2 and Section 12.4 represent an overall strengthening of DAQ's PSD program, in large part because Section 12.2 includes updated PSD provisions to regulate new or modified major stationary sources of greenhouse gases (GHGs) and PM 2.5 , both of which are unregulated under the existing SIP PSD program. Section 12.2 also satisfies the requirements of EPA's 2002 regulations to revise the NSR programs (67 FR 80186, December 31, 2002) (“NSR Reform” rules), with limited exceptions.

Part D of title I of the Act contains the general requirements for areas designated “nonattainment” for the NAAQS, including preconstruction permit requirements for new major sources or major modifications proposing to construct in such nonattainment areas, commonly referred to as “Nonattainment New Source Review” or “NSR.” EPA's regulations for NSR permit programs are found in 40 CFR 51.165. Clark County is currently designated as “attainment” or “unclassifiable/attainment” for all NAAQS pollutants, with two exceptions: certain portions of Clark County are designated and classified as “marginal” nonattainment for the 1997 8-hour ozone NAAQS, and the Las Vegas planning area within Clark County is designated and classified as “serious” nonattainment for the PM 10 NAAQS. 40 CFR 81.329.

Section 12.3 and Section 12.4 contain the NSR requirements for review and permitting of major sources and major modifications under DAQ jurisdiction in Clark County. These regulations satisfy most of the statutory and regulatory requirements for NSR permit programs, but Section 12.3 also contains several deficiencies that form the basis for our proposed limited disapproval, as discussed below.

First, the requirements for offsets in Section 12.3, subsection 12.3.6 do not contain adequate provisions to assure that emission offset calculations are based on the same emissions baseline used in the demonstration of reasonable further progress for the relevant NAAQS pollutant (where applicable) and to satisfy EPA's NSR criteria for offset calculations, as required by CAA section 173(a)(1)(A) and 40 CFR 51.165(a)(3).

Second, Section 12.3 does not contain provisions to assure that emissions increases from new or modified major stationary sources are offset by real reductions in “actual emissions” as required by CAA 173(c)(1) because it does not contain adequate criteria for determining whether certain emission reductions may qualify for use as offsets. Subsection 12.3.6 references a separate rule (Section 12.7) for important criteria related to this determination, but Section 12.7 is neither approved into the SIP nor included in the NSR SIP submittal and therefore cannot provide an appropriate basis for evaluating emission reductions for purposes of satisfying the requirements in CAA section 173(c)(1).

Third, Section 12.3 does not adequately address the requirement in CAA section 173(c)(2) to prevent emissions reductions “otherwise required by [the Act]” from being credited for purposes of satisfying the part D offset requirements. Specifically, although subsection 12.3.6.6(a) states that “[e]mission reductions used to satisfy offset requirements must be real, surplus, permanent, quantifiable, and federally enforceable” (emphasis added), the definition of the term “surplus” in subsection 12.3.2 is not adequate to ensure that emission reductions required by standards promulgated under CAA section 111 (New Source Performance Standards) or under CAA section 112 (National Emission Standards for Hazardous Air Pollutants) are not credited for purposes of satisfying part D offset requirements.

Fourth, the definition of “baseline actual emissions” (BAE) in subsection 12.3.2(c), paragraph (1)(C), includes a requirement to adjust the BAE downward to “exclude any emissions that would have exceeded an emission limitation with which the major stationary source must comply as of the particular date, had such major stationary source been required to comply with such limitations during the consecutive 24-month period” (emphasis added). EPA's definition of BAE in 40 CFR 51.165(a)(1)(xxxv)(B)( 3 ) includes a similar provision but requires a downward adjustment in BAE “to exclude any emissions that would have exceeded an emission limitation with which the major stationary source must currently comply. * * *” The reference in subsection 12.3.2(c) to an emission limitation that applied “as of the particular date” instead of an emission limitation with which the source must “currently comply” is problematic, as it is not clear which “particular date” the definition refers to.

Fifth, the definition of “major modification” in subsection 12.3.2(x) requires exclusion of two specific types of physical or operational changes that EPA's definition of “major modification” in 40 CFR 51.165(a)(1)(v) does not exclude: (1) the installation or operation of a permanent Clean Coal Technology Demonstration Project that constitutes repowering; and (2) the reactivation of a very clean coal-fired electric utility steam generating unit. Although such exemptions are acceptable for purposes of PSD review ( see 40 CFR 51.166(b)(2)(iii) and (b)(36)), such exemptions are not permissible for Nonattainment NSR purposes. See CAA 415.

Additionally, the definition of “major modification” in subsection 12.3.2(x) is not consistent with EPA's current approach to the treatment of fugitive emissions in applicability determinations for major modifications. As discussed above with respect to the definition of this same term in Section 12.2, EPA has administratively stayed 40 CFR 51.165(a)(1)(v)(G), effective March 30, 2011 ( see 76 FR 17548), which had the effect of reverting the treatment of fugitive emissions in applicability determinations to the approach that applied prior to the Fugitive Emissions Rule, thus requiring that fugitive emissions be included in “major modification” applicability determinations for all source categories. 76 FR at 17550, 17551.

Sixth, the definition of “regulated NSR pollutant” in subsection 12.3.2(ii) does not satisfy current requirements regarding “condensable particular matter” in NSR applicability determinations. EPA's definition of “regulated NSR pollutant” in 40 CFR 51.165(a)(xxxvii) includes a paragraph stating that on or after January 1, 2011, “gaseous emissions from a source or activity which condense to form particulate matter at ambient temperatures” ( i.e., condensable particular matter) must be accounted for in applicability determinations and in establishing emissions limitations for particulate matter (PM), PM 2.5 and PM 10 in NSR permits. See 73 FR 28321.

Seventh, Section 12.3 allows for interpollutant trades between VOC and NO X emission reductions for purposes of satisfying offset requirements for ozone, and interpollutant trades among PM 2.5, SO 2 and NO X emission reductions for purpose of satisfying offset requirements for PM 2.5 . These provisions do not satisfy EPA's regulatory and policy criteria for approval of such interpollutant trades or interprecursor trading hierarchies. See 40 CFR 51.165(a)(11) and “Improving Air Quality with Economic Incentive Programs,” U.S. EPA Office of Air and Radiation, January 2001. Although Section 12.3 does not currently apply to PM 2.5 sources because Clark County is designated attainment/unclassifiable for the 1997 and 2006 p.m. 2.5 NAAQS, we propose to disapprove this provision because it is contrary to applicable EPA regulations and policy for both ozone and PM 2.5 purposes.

Eighth, Section 12.3 does not contain any provisions designed to ensure that the air quality impacts of stationary sources are not underestimated due to stack heights that exceed good engineering practice or air dispersion modeling techniques that do not satisfy the criteria in 40 CFR 51.118(b), as required by 40 CFR 51.164.

Finally, neither Section 12.3 nor Section 12.4 contain a provision addressing, for new or modified major stationary sources, the requirement in 40 CFR 51.160(d) to “provide that approval of any construction or modification must not affect the responsibility on the owner or operator to comply with applicable portions of the control strategy.”

Compared to the existing SIP NSR program in Section 12 (as adopted October 7, 2003), however, submitted Section 12.3 and Section 12.4 represent an overall strengthening of DAQ's NSR program, in large part because Section 12.3 contains definitions of important NSR terms, such as “potential to emit,” that are more consistent with EPA's definitions in 40 CFR 51.165(a) than the definitions used in the SIP NSR program ( see, e.g., definition of “total potential to emit” in SIP Section 12, subsection 12.1.6.1). Section 12.3 also satisfies the requirements of EPA's 2002 NSR Reform rules, with limited exceptions.

Section 110(l) prohibits EPA from approving a revision of a plan if the revision would “interfere with any applicable requirement concerning attainment and reasonable further progress * * * or any other applicable requirement of [the Act].”

Our approval of the Clark County NSR SIP submittal (and replacement or supersession of the existing SIP NSR rules) would strengthen the applicable SIP in some specific respects and would relax the SIP in other specific respects. Taken in its entirety, we find that the SIP revision represents a strengthening of Clark County's minor NSR, PSD, and Nonattainment NSR programs compared to the existing SIP programs that we approved in 1982 and 2004, and that our approval of the NSR SIP submittal would not interfere with any applicable requirement concerning attainment and reasonable further progress (RFP) or any other applicable requirement of the Act.

The most significant deficiencies that we have identified in the submitted NSR rules, as discussed in detail earlier in this TSD, are generally as follows: (1) The absence of minor NSR provisions that ensure protection of the 2006 PM 2.5 NAAQS and 2008 Lead (Pb) NAAQS; (2) minor NSR applicability provisions that do not cover stationary sources of PM 2.5 ; (3) deficiencies in the definitions of certain terms used in PSD and Nonattainment NSR (NNSR) applicability determinations; (4) definition of “regulated NSR pollutant” that does not adequately address PSD and NNSR requirements for regulation of condensable particulate matter; (5) deficiencies in the criteria for assessing the quality (or “integrity”) of emission reduction credits used to satisfy NNSR offset requirements; and (6) the absence of minor NSR or NNSR provisions to ensure that the air quality impacts of stationary sources are not underestimated due to stack heights that exceed good engineering practice or unacceptable air dispersion modeling techniques. We identify these as the “most significant” deficiencies because these are the most likely to affect pollutant emissions within Clark County, compared to other deficiencies that we do not expect would significantly affect emissions levels ( e.g., administrative requirements for permit issuance).

Many of these deficiencies are related to requirements that came into effect after we last approved Clark County's NSR programs in 1982 and 2004. For example, minor NSR SIP revisions to implement the 2006 PM 2.5 NAAQS and 2008 Lead (Pb) NAAQS were due in 2009 and 2011, respectively. See CAA 110(a). Similarly, SIP revisions to implement EPA's PSD and NNSR requirements for condensable particular matter were due in 2011. See 73 FR 28321 (May 16, 2008). With respect to all of these post-2005 requirements, which the existing SIP NSR program does not address, we believe it is reasonable to conclude that our approval of the NSR SIP submittal as a revision to the Nevada SIP would not interfere with any applicable requirement concerning attainment and RFP or any other applicable requirement of the Act, because there is no applicable requirement in the existing SIP program that would be affected by the deficiencies in the submitted NSR rules.

As to the remaining deficiencies, we have evaluated these together with the most significant differences between the two NSR programs (SIP-approved versus the NSR SIP submittal) to evaluate the overall effect that our approval of the NSR SIP submittal might have on the stringency of DAQ's permit programs and the potential air quality impacts of these program revisions. First, certain PSD and NNSR definitions governing applicability determinations in Section 12.2 and Section 12.3 are not as stringent as the corresponding Federal definitions in 40 CFR 51.166 and 51.165, respectively. Second, the offset ratio in Section 12.3 is 1:1, compared to a more stringent ratio of 2:1 in the existing SIP NSR program, and the criteria in Section 12.3 for evaluating the integrity of emissions reduction credits used to satisfy NNSR offset requirements are not adequate to assure actual emission reductions. Third, the minor NSR program and NNSR program (Sections 12.1, 12.3, and 12.4 to some extent) both lack provisions to ensure that the air quality impacts of stationary sources are not underestimated due to stack heights that exceed good engineering practice or unacceptable air dispersion modeling techniques. Fourth, DAQ has established public notice thresholds for minor NSR (Section 12.1) that exclude from public review the following types of less-environmentally significant minor sources: (1) New minor sources with potential emissions of NAAQS pollutants below 50 tons per year (tpy) for CO; 40 tpy for VOCs, SO 2 , or NO X ; 15 tpy for PM 10 ; and 0.6 tpy for Lead (Pb) ( see subsection 12.1.5.3), and (2) modifications at existing minor sources that result in PTE increases less than 40 tpy for SO 2 ; 35 tpy for CO; 20 tpy for VOC or NO X ; and 7.5 tpy for PM 10 ( see subsection 12.1.6(a)(7)). Compare with SIP Section 12, subsection 12.1.1.1 (requiring preconstruction review for “any new stationary source” or “modification” without emissions-based applicability thresholds). Finally, the control standard for minor sources has been changed from “Best Available Control Technology” under the SIP minor NSR program to “Reasonably Available Control Technology” under submitted Section 12.1 ( see subsection 12.1.3.6(b), (c)).

With respect to the scope of the NSR program, the deficiencies in the applicability-related definitions in Sections 12.2 and 12.3 and the new de minimis thresholds established in Section 12.1 could potentially reduce the number of new or modified stationary sources that are subject to preconstruction review under these programs and thereby relax the NSR program for new and modified sources compared to the SIP-approved program. As to the minor NSR control standard, the NNSR offset requirements, and the absence of provisions related to stack heights, the submitted NSR rules may result in application of less-stringent control technologies on minor sources (from BACT to RACT), potential under estimations of the air quality impacts of stationary source operations and, with respect to ozone precursor and PM 10 emissions, offset transactions that may not achieve adequate emission reductions.

Several significant improvements in the submitted NSR rules should be considered in assessing the overall impact of these potential program relaxations. First, the potential for reduced numbers of regulated sources is offset to at least some extent by new provisions in Section 12.1 that establish a five-year permit term, thereby mandating a regular review of all minor source permit conditions and source operations, and provisions providing that DAQ may re-open a minor NSR permit at any time for cause. See “Proposed Revision to the Clark County Part of the Nevada State Implementation Plan: Minor Source New Source Review Program Rule Adoptions and Revisions,” January 29, 2009 (hereinafter “Minor NSR SIP Submittal”), Appendix B: “Technical Requirements.”

Second, Section 12.1 requires that each minor NSR permit contain a number of important types of permit terms and conditions which are more specific than required under the SIP NSR program and that strengthen the enforceability of the program—for example, physical descriptions of each emission unit, emission limitations that ensure protection of ambient air quality standards, and more clearly defined monitoring, recordkeeping, and reporting requirements modeled on the CAA's title V operating permit program. Compare Section 12.1, subsection 12.1.4.1 (Term and Conditions) with SIP Section 12, subsection 12.8.1.1 (conditions of ATC).

Third, Section 12.1 contains important new conditions for issuance of minor NSR permits, such as the requirement to assure compliance with all applicable SIP requirements. See Section 12.1, subsection 12.1.5.1 (Action on Application) compared to SIP Section 12 (as adopted October 7, 2003), subsection 12.8.2 (ATC issuance requirements).

Fourth, both the minor source program in Section 12.1 and the major source programs in Sections 12.2 and 12.3 rely on several new or revised definitions of key terms that are more consistent with Federal definitions (in CAA 302 and 40 CFR part 51, subpart I) than corresponding definitions in the SIP NSR program. See, e.g., definition of “potential to emit” in Section 0  6 compared to definition of “total potential to emit” in SIP Section 12 (as adopted October 7, 2003), subsection 12.1.6.1; new definition of “emission limit” or “emission limitation” in Section 0.

Finally, with respect to the difference between BACT and LAER for minor stationary sources in Clark County, supporting information submitted by DAQ indicates that the shift away from the existing BACT standard in the SIP is not likely to affect emissions to any significant degree given the ambiguities in the SIP rule which undermined the practical enforceability of this standard, and that the RACT standard in submitted Section 12.1 is expected to be equally effective in controlling emissions at minor sources, if not more so given the enhanced compliance provisions. See Minor NSR SIP Submittal, Chapter 3: “Technical Support Document for Sections 0, 12.0, 12.1, and 12.11” at 3-20 to 3-28 and Appendix B: “Technical Requirements.”

With respect to offset requirements, we note that the SIP NSR program did not require offsets for VOC or NO X because Clark County was not designated nonattainment for any ozone NAAQS at the time when we approved the SIP program in 2004. See Section 59 (Emission Offsets), as adopted October 7, 2003 at Table 59.1.2. The NSR control (LAER) and offset requirements in submitted Section 12.3 therefore ensure greater reductions of ozone precursor emissions compared to the SIP program, which required neither LAER nor offsets for NO X or VOC.

For PM 10 purposes, the SIP NSR program required that major stationary sources ( i.e., sources with PTE of 70 tpy or more) obtain PM 10 offsets at a ratio of 2:1, whereas the submitted Section 12.3 requires those same sources to obtain PM 10 offsets at a ratio of 1:1. See Section 59 (Emission Offsets) (as adopted October 7, 2003) at Table 59.1.2 and Section 12.3 (Permit Requirements for Major Sources in Nonattainment Areas) (as adopted May 18, 2010) at Table 12.3-1. This relaxation in the offset ratio for PM 10 sources applies only to stationary sources locating within the boundaries of the PM 10 nonattainment area in the Las Vegas planning area (hydrographic area #212), and appears to be counterbalanced by the overall strengthening in the NSR program, as discussed above with respect to both major and minor sources throughout Clark County.

Significantly, the submitted Section 12.2 includes new PSD provisions to regulate new or modified major stationary sources of greenhouse gases (GHGs) and PM 2.5 , both of which are unregulated under the existing SIP PSD program. In addition, both Section 12.2 and Section 12.3 satisfy the requirements of EPA's 2002 NSR Reform rules, with limited exceptions.

In sum, the new and revised provisions in the submitted NSR rules enable DAQ to review source operations on a more regular basis; require DAQ to make specific determinations related to air quality impacts and applicable SIP requirements as part of permit issuance; improve the enforceability of the NSR program through the establishment of more detailed compliance requirements and improved definitions of important terms; establish NNSR requirements for ozone precursor emissions that were not required under the existing SIP program; and establish new PSD provisions for the regulation of GHG and PM 2.5 emission sources. We find that, on balance, these NSR program improvements outweigh the potential relaxations discussed above compared to the existing SIP program.

In addition, Clark County is currently designated attainment or unclassifiable/attainment for all but two NAAQS pollutants (PM 10 and 1997 8-hour ozone), and with respect to these two remaining pollutants, EPA has determined based on ambient air monitoring data that the nonattainment areas within Clark County are attaining both of these standards. See 75 FR 45485 (August 3, 2010) (Determination of Attainment for PM 10 for the Las Vegas Valley Nonattainment Area) and 76 FR 17343 (March 29, 2011) (Determination of Attainment for the Clark County 1997 8-Hour Ozone Nonattainment Area). We are unaware of any reliance by DAQ on the continuation of any aspect of the permit-related rules in the Clark County portion of the Nevada SIP for the purpose of continued attainment or maintenance of the NAAQS. Given all these considerations and in light of the air quality improvements in Clark County, we propose to conclude that our approval of these updated NSR regulations into the Nevada SIP would not interfere with any applicable requirement concerning attainment and RFP or any other applicable requirement of the Act.

For the reasons stated above and explained further in our TSD, we find that the submitted NSR rules satisfy most of the applicable CAA and regulatory requirements for minor NSR, PSD, and Nonattainment NSR permit programs under CAA section 110(a)(2)(C) and parts C and D of title I of the Act but also contain certain deficiencies that prevent us from proposing a full approval of the rules. Therefore, we are proposing a limited approval and limited disapproval of the submitted NSR rules. We do so based also on our finding that, while the rules do not meet all of the applicable requirements, the rules would represent an overall strengthening of the SIP by clarifying and enhancing the NSR permitting requirements for major and minor stationary sources under DAQ jurisdiction in Clark County.

We note that, pursuant to EPA's recent classification of the Clark County ozone nonattainment area as “marginal” nonattainment for the 1997 8-hour ozone standard effective June 13, 2012 (77 FR 28424, May 14, 2012), DAQ is now obligated to submit NSR SIP revisions meeting the applicable requirements of subpart 2 of part D, title I of the Act, including an offset ratio of 1.1 to 1 for NO X and VOC ( see CAA 182(a)(4)) no later than June 13, 2013. Likewise, with respect to stationary sources under NDEP jurisdiction ( i.e., major new or modified plants which generate electricity by using steam produced by the burning of fossil fuel) within portions of Clark County that are designated nonattainment for the 1997 8-hour ozone standard, NDEP is obligated to submit, no later than June 13, 2013, NSR SIP revisions meeting the applicable requirements of subpart 2 of part D, title I of the Act. Although EPA is not requiring NDEP to submit Nonattainment NSR rules for the Las Vegas PM 10 nonattainment area ( i.e., hydrographic area 212) in light of the construction prohibition in NAC section 445B.22083, 7 for the 1997 8-hour ozone NAAQS the geographic boundaries of the nonattainment area within Clark County extend beyond the areas subject to the construction prohibition in NAC 445B.22083. See 40 CFR 81.329. NDEP is therefore obligated to address this regulatory gap in Nonattainment NSR permit requirements for new or modified major sources in these areas. In lieu of adopting and submitting a Nonattainment NSR program, NDEP may revise NAC section 445B.22083 to extend its construction prohibitions to the entire ozone nonattainment area within Clark County (as defined in 40 CFR 81.329) and submit this revised rule to EPA for approval into the SIP. These are not current program deficiencies but upcoming obligations on both NDEP's and DAQ's part that we encourage the State to address at its earliest opportunity.

Pursuant to section 110(k) of the CAA and for the reasons provided above, EPA is proposing a limited approval and limited disapproval of revisions to the Clark County portion of the Nevada SIP that govern the issuance of permits for stationary sources under the jurisdiction of the Clark County Department of Air Quality, including review and permitting of major sources and major modifications under parts C and D of title I of the CAA. Specifically, EPA is proposing a limited approval and limited disapproval of the new and amended Clark County regulations listed in table 1, above, as a revision to the Clark County portion of the Nevada SIP.

EPA is proposing this action because, although we find that the new and amended rules meet most of the applicable requirements for such permit programs and that the SIP revisions improve the existing SIP, we have found certain deficiencies that prevent full approval, as explained further in this preamble and in the TSD for this rulemaking. The intended effect of this proposed limited approval and limited disapproval action is to update the applicable SIP with current Clark County permitting regulations  8 and to set the stage for remedying deficiencies in these regulations.

If finalized as proposed, this limited approval action would trigger an obligation on EPA to promulgate a Federal Implementation Plan unless the State of Nevada corrects the deficiencies, and EPA approves the related plan revisions, within two years of the final action. Additionally, for those deficiencies that relate to the Nonattainment NSR requirements under part D of title I of the Act, the offset sanction in CAA section 179(b)(2) would apply in the Clark County nonattainment areas 18 months after the effective date of a final limited disapproval, and the highway funding sanctions in CAA section 179(b)(1) would apply in these areas six months after the offset sanction is imposed. Neither sanction will be imposed under the CAA if Nevada submits and we approve prior to the implementation of the sanctions, SIP revisions that correct the deficiencies that we identify in our final action.

We will accept comments from the public on this proposed limited approval and limited disapproval for the next 30 days.

This proposed action is not a “significant regulatory action” under the terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under the EO.

This proposed action does not impose an information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq, because this proposed limited approval/disapproval under section 110 and subchapter I, part D of the Clean Air Act will not in-and-of itself create any new information collection burdens but simply disapproves certain State requirements for inclusion into the SIP. Burden is defined at 5 CFR 1320.3(b).

The Regulatory Flexibility Act (RFA) generally requires an agency to conduct a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements 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 not-for-profit enterprises, and small governmental jurisdictions. For purposes of assessing the impacts of today's proposed rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration's (SBA) 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.

After considering the economic impacts of today's proposed rule on small entities, I certify that this action will not have a significant impact on a substantial number of small entities. This rule does not impose any requirements or create impacts on small entities. This proposed limited approval/disapproval under section 110 and subchapter I, part D of the Clean Air Act will not in-and-of itself create any new requirements but simply disapproves certain State requirements for inclusion into the SIP. Accordingly, it affords no opportunity for EPA to fashion for small entities less burdensome compliance or reporting requirements or timetables or exemptions from all or part of the rule. The fact that the Clean Air Act prescribes that various consequences ( e.g., higher offset requirements) may or will flow from this proposed limited disapproval does not mean that EPA either can or must conduct a regulatory flexibility analysis for this action. Therefore, this action will not have a significant economic impact on a substantial number of small entities.

We continue to be interested in the potential impacts of this proposed rule on small entities and welcome comments on issues related to such impacts.

This action contains no Federal mandates under the provisions of Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538 for State, local, or tribal governments or the private sector. EPA has determined that the proposed limited disapproval action 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 action proposes to disapprove pre-existing requirements under State or local law, and imposes no new requirements. Accordingly, no additional costs to State, local, or tribal governments, or to the private sector, result from this action.

Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.”

This proposed action 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, because it merely disapproves certain State requirements for inclusion into the SIP and does not alter the relationship or the distribution of power and responsibilities established in the Clean Air Act. Thus, Executive Order 13132 does not apply to this proposed action.

This proposed action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000), because the SIP EPA is proposing to disapprove would not apply in Indian country located in the state, and EPA notes that it will not impose substantial direct costs on tribal governments or preempt tribal law. Thus, Executive Order 13175 does not apply to this proposed action.

EPA interprets E.O. 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the E.O. has the potential to influence the regulation. This proposed action is not subject to EO 13045 because it is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997). This proposed limited approval and disapproval under section 110 and subchapter I, part D of the Clean Air Act will not in-and-of itself create any new regulations but simply disapproves certain State requirements for inclusion into the SIP.

This proposed rule is not subject to Executive Order 13211 (66 FR 28355, May 22, 2001) because it is not a significant regulatory action under Executive Order 12866.

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards ( e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards.

The EPA believes that this action is not subject to requirements of Section 12(d) of NTTAA because application of those requirements would be inconsistent with the Clean Air Act.

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States.

EPA lacks the discretionary authority to address environmental justice in this rulemaking.

This is a synopsis of the Commission's Notice of Proposed Rule Making, MB Docket No. 12-177, adopted June 28, 2012, and released June 29, 2012. The full text of this Commission decision is available for inspection and copying during normal business hours in the FCC's Reference Information Center at Portals II, CY-A257, 445 12th Street SW., Washington, DC 20554. This document may also be purchased from the Commission's duplicating contractors, Best Copy and Printing, Inc., 445 12th Street SW., Room CY-B402, Washington, DC 20554, telephone 1-800-378-3160 or via email www.BCPIWEB.com. This document does not contain proposed information collection requirements subject to the Paperwork Reduction Act of 1995, Public Law 104-13. In addition, therefore, it does not contain any proposed information collection burden “for small business concerns with fewer than 25 employees,” pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107-198, see 44 U.S.C. 3506(c)(4).

Provisions of the Regulatory Flexibility Act of l980 do not apply to this proceeding.

Members of the public should note that from the time a Notice of Proposed Rule Making is issued until the matter is no longer subject to Commission consideration or court review, all ex parte contacts are prohibited in Commission proceedings, such as this one, which involve channel allotments. See 47 CFR 1.1204(b) for rules governing permissible ex parte contacts.

For information regarding proper filing procedures for comments, see 47 CFR 1.415 and 1.420.

For the reasons discussed in the preamble, the Federal Communications Commission proposes to amend 47 CFR part 73 as follows:

I. Background

The Center for Auto Safety, in letters dated July 8, 2012 and July 13, 2012, petitioned for a Defect Order under 49 CFR Part 552 and for a Hearing on Notification and Remedy of Defects under 49 CFR Part 577. The petitions relate to Ford's recall of MY 2002-2004 Ford Escape vehicles (Recall 04V-574) and Mazda's recall of MY 2002-2004 Mazda Tribute vehicles (Recall 04V-583).

In 49 CFR Part 573 Defect and Information Reports (Part 573 Report) filed in December 2004, Ford and Mazda both informed NHTSA that the inner liner of the accelerator cable in certain Ford Escape and Mazda Tribute vehicles could migrate out of place during vehicle operation, and prevent the throttle body from returning to the idle position. Ford and Mazda said that the safety consequence of a throttle body not returning to the idle position was a progressive, and in some cases sudden increase in speed. Ford and Mazda notified vehicle owners of the recalls (Recall 04V-574 and 04V-583) in January 2005. Thereafter, on October 6, 2005, Ford released a recall update to dealers. In that update, Ford provided supplemental instructions on how to remove the accelerator cable. The instructions indicate that damage to the speed (or cruise) control cable can result if the accelerator cable is not properly removed. Mazda, however, did not issue a recall update.

The Center for Auto Safety (CAS) asserts that Ford and Mazda failed to notify about 319,500 Ford Escape owners and 84,700 Mazda Tribute owners that their vehicles' speed (or cruise) control cables may have been damaged during the accelerator cable replacements conducted in Recall 04V-574 and Recall 04V-583. According to CAS, these vehicles were repaired prior to September 30, 2005. Related to this potential damage, CAS states that Ford and Mazda did not file Part 573 Reports with NHTSA which would have initiated a second recall. CAS adds that Ford and Mazda did not file Part 573 Reports and recall the cruise control cables. CAS claims that the cruise control cable can fail independently of being damaged in the course of repairs conducted pursuant to Recall 04V-574 and Recall 04V-583.

In its July 8 petition, CAS refers to a crash involving a MY 2002 Ford Escape which occurred in January 2012 in Payson, Arizona. The driver of the Ford Escape was killed in the crash. CAS states that the driver's vehicle had been repaired in January 2005, after Recall 04V-574 was announced but before the October 2005 recall update was released.

NHTSA has been gathering information on the Arizona crash since early 2012 when it first learned of it. NHTSA obtained the police report when it became available. In June 2012, NHTSA contacted counsel representing the driver's family to obtain more information on the crash. Independent of CAS's petition, NHTSA opened a preliminary investigation (PE 12-019) on July 17, 2012 that among other things will encompass issues raised by the Center for Auto Safety's petition.

CAS requests that NHTSA open a defect investigation into MY 2002-2004 Ford Escapes and MY 2001-2004 Mazda Tributes with cruise control cables of the same design as in Recall 04V-574, Recall 04V-583, and in the Arizona vehicle. Pursuant to 49 CFR 552.3, any interested person may file a petition requesting that the Administrator commence a proceeding to decide whether to issue an order concerning the notification and remedy of a failure of a motor vehicle or item of replacement equipment to comply with an applicable motor vehicle safety standard or a defect in such vehicle or equipment that relates to motor vehicle safety. If NHTSA grants the petition, NHTSA opens an investigation.

Based on the information obtained by NHTSA prior to the filing of the CAS petition, NHTSA opened an investigation on July 17, 2012 that will, among other issues, assess the scope and remedy of Recall 04V-574 (involving certain model year 2002-2004 Ford Escape vehicles) and Recall 04V-583 (involving certain model year 2002-2004 Mazda Tribute vehicles). In view of the fact that NHTSA has opened an investigation that will examine the issues on the Ford Escape and Mazda Tribute speed control cables, including claims raised by CAS, the agency denies this portion of CAS's petition as moot.

CAS's petition for a hearing on notification and remedy of defects pursuant to 49 CFR Part 557 requests that NHTSA hold a hearing to determine whether Ford and Mazda reasonably met their obligations to notify owners and correct the defects at issue in Recall 04V-574 and Recall 04V-583. In determining whether to hold a hearing, the agency considers (1) The nature of the complaint; (2) the seriousness of the alleged breach of obligation to remedy; (3) the existence of similar complaints; (4) the ability of the NHTSA to resolve the problem without holding a hearing; and (5) other pertinent matters. 49 CFR 557.6.

We first consider the nature of the complaint. CAS claims that Ford did not notify owners of about 319,500 vehicles of potential damage to speed control cables caused by a faulty recall repair in Recall 04V-574. CAS claims that Mazda did not notify owners of about 84,700 vehicles of potential damage to speed control cables caused by a faulty recall repair in Recall 04V-583. CAS also claims that Ford and Mazda did not file Reports pursuant to 49 CFR Part 573 with NHTSA which would have initiated a second recall. Finally, CAS claims that Ford and Mazda did not file Part 573 Reports and recall the cruise control cable. Federal regulations require vehicle manufacturers to submit reports to NHTSA for each defect that the manufacturer or the Administrator of NHTSA determines to be related to motor vehicle safety. 49 CFR 573.6. Issues of the nature raised by CAS will be addressed in PE 12-019.

Second, we consider the seriousness of the alleged breach of obligation to remedy. If CAS's claims are true, they are serious. NHTSA will consider them in PE 12-019.

Third, we consider the existence of similar complaints. NHTSA received complaints from consumers by way of Vehicle Owner Questionnaires (VOQ's) regarding accelerator cable failure, cruise control cable failure, and/or stuck throttles. These are identified in the PE 12-019 Opening Resume in certain MY 2002-2004 Ford Escape and Mazda Tribute vehicles. NHTSA takes these complaints seriously. Considering the VOQ complaints in the context of the 2012 crash in Arizona, NHTSA opened a preliminary evaluation to investigate the safety consequence broadly including the scope and adequacy of Recall 04V-574 and Recall 04V-583. However, aside from the petition from CAS, NHTSA has not received any other complaints that Ford and Mazda failed to notify owners of vehicles that had been repaired pursuant to Recall 04V-574 or Recall 04V-583 of a faulty recall repair, file a Part 573 Report with NHTSA and initiate a second Ford Escape or Mazda Tribute recall, or file a Part 573 Report reporting the cruise control cable defect and recalling the Ford Escape and Mazda Tribute cruise control cables. Nor has NHTSA received any other requests that the Agency conduct a hearing to assess whether Ford and Mazda have met their statutory and regulatory obligations to notify owners and correct the defects at issue in Recall 04V-574 and Recall 04V-583.

Fourth, we consider the likelihood that NHTSA can resolve this alleged problem without a hearing. NHTSA believes that it can obtain the information it needs to resolve this matter by directly using its information gathering authorities with respect to Ford and Mazda, contacting Ford Escape and Mazda Tribute owners and otherwise conducting an agency investigation. We do not believe that there would be benefits to holding a hearing. In fact, the time taken to plan for and hold a hearing would detract from the investigation.

Finally, the Agency will consider other pertinent factors. The Agency has opened PE 12-019 to assess the Ford Escape and Mazda Tribute recalls and broader issues that may not be related to those recalls. We believe that an investigation is a more efficient way of obtaining the information necessary to evaluate the issues presented in CAS's petition than holding a hearing.

CAS's petition for a hearing is denied.

Request for Information

When we make a finding that a petition presents substantial information indicating that listing a species may be warranted, we are required to promptly review the status of the species (status review). For the status review to be complete and based on the best available scientific and commercial information, we request information on the Sonoran talussnail from governmental agencies, Native American tribes, the scientific community, industry, and any other interested parties. We seek information on:

(1) The species' biology, range, and population trends, including:

(a) Habitat requirements for feeding, breeding, and sheltering;

(b) Genetics and taxonomy;

(c) Historical and current range, including distribution patterns;

(d) Historical and current population levels, and current and projected trends; and

(e) Past and ongoing threats and conservation measures for the species, its habitat or both.

(2) The factors that are the basis for making a listing determination for a species under section 4(a) of the Act (16 U.S.C. 1531 et seq. ), which are:

(a) The present or threatened destruction, modification, or curtailment of its habitat or range;

(b) Overutilization for commercial, recreational, scientific, or educational purposes;

(c) Disease or predation;

(d) The inadequacy of existing regulatory mechanisms; or

(e) Other natural or manmade factors affecting its continued existence.

If, after the status review, we determine that listing the Sonoran talussnail is warranted, we will propose critical habitat (see definition in section 3(5)(A) of the Act) under section 4 of the Act, to the maximum extent prudent and determinable at the time we propose to list the species. Therefore, we also request data and information on:

(1) What may constitute “physical or biological features essential to the conservation of the species,” within the geographical range currently occupied by the species;

(2) Where these features are currently found;

(3) Whether any of these features may require special management considerations or protection;

(4) Specific areas outside the geographical area occupied by the species that are “essential for the conservation of the species”; and

(5) What, if any, critical habitat you think we should propose for designation if the species is proposed for listing, and why such habitat meets the requirements of section 4 of the Act.

Please include sufficient information with your submission (such as scientific journal articles or other publications) to allow us to verify any scientific or commercial information you include.

Submissions merely stating support for, or opposition to, the action under consideration without providing supporting information, although noted, will not be considered in making a determination. Section 4(b)(1)(A) of the Act directs that determinations as to whether any species is an endangered or threatened species must be made “solely on the basis of the best scientific and commercial data available.”

You may submit your information concerning this status review by one of the methods listed in the ADDRESSES section. If you submit information via http://www.regulations.gov, your entire submission—including any personal identifying information—will be posted on the Web site. If your submission is made via a hardcopy that includes personal identifying information, you may request at the top of your document that we withhold this personal identifying information from public review. However, we cannot guarantee that we will be able to do so. We will post all hardcopy submissions on http://www.regulations.gov.

Information and supporting documentation that we received and used in preparing this finding is available for you to review at http://www.regulations.gov, or by appointment, during normal business hours, at the U.S. Fish and Wildlife Service, Arizona Ecological Services Office (see FOR FURTHER INFORMATION CONTACT ).

Section 4(b)(3)(A) of the Act requires that we make a finding on whether a petition to list, delist, or reclassify a species presents substantial scientific or commercial information indicating that the petitioned action may be warranted. We are to base this finding on information provided in the petition, supporting information submitted with the petition, and information otherwise available in our files. To the maximum extent practicable, we are to make this finding within 90 days of our receipt of the petition and publish our notice of the finding promptly in the Federal Register .

Our standard for substantial scientific or commercial information within the Code of Federal Regulations (CFR) with regard to a 90-day petition finding is “that amount of information that would lead a reasonable person to believe that the measure proposed in the petition may be warranted” (50 CFR 424.14(b)). If we find that substantial scientific or commercial information was presented, we are required to promptly conduct a species status review, which we subsequently summarize in our 12-month finding.

The “substantial information” standard for a 90-day finding differs from the Act's “best scientific and commercial data” standard that applies to a status review to determine whether a petitioned action is warranted. A 90-day finding does not constitute a status review under the Act. In a 12-month finding, we will announce our determination as to whether a petitioned action is warranted after we have completed a thorough status review of the species, which is conducted following a substantial 90-day finding. Because the Act's standards for 90-day and status review conducted for a 12-month finding on a petition are different, as described above, a substantial 90-day finding does not mean that our status review and resulting determination will result in a warranted finding.

On June 24, 2010, we received a petition dated June 24, 2010, from the Center for Biological Diversity, requesting that we list the Rosemont talussnail ( Sonorella rosemontensis ) and Sonoran talussnail ( Sonorella magdalenensis ) as endangered or threatened and that we designate critical habitat under the Act. The petition clearly identified itself as such and included the requisite identification information for the petitioner, required by 50 CFR 424.14(a). In a December 1, 2011, letter to the petitioner, we responded that we reviewed the information presented in the petition and determined that issuing an emergency regulation temporarily listing the Sonoran talussnail under section 4(b)(7) of the Act was not warranted. According to the Multi-district Litigation Stipulated Settlement Agreement ( WildEarth Guardians v. Salazar, No. 1:10-mc-00377-EGS (D. D.C.); Center for Biological Diversity v. Salazar, No. 1:10-mc-00377-EGS (D.D.C.)), we are required to complete an initial finding for the Sonoran talussnail in Fiscal Year 2012, which ends September 30, 2012, as to whether the petition contains substantial information indicating that the action may be warranted. This finding addresses the petition to list the Sonoran talussnail and fulfills the requirement of the Multi-district Litigation Stipulated Settlement Agreement. The petition for the Rosemont talussnail will be addressed in a separate finding. There are no previous federal actions concerning to the Sonoran talussnail under the Act.

The Sonoran talussnail is a relatively large pulmonate (with functional lungs), terrestrial snail with an average shell diameter of 0.74 inches (in) (19 millimeters (mm)) (Miller 1978, p. 111). The petitioner provided no further physical description of the species, nor do we have any additional species-specific information in our files. In general, snails of the Sonorella genus have a depressed spherical spiraling shell that is 0.47 to 1.30 in (12 to 33 mm) in diameter and lightly colored, normally containing a dark peripheral band (Bequaert and Miller 1973, p. 110). Because shells of Sonorella are weakly differentiated and Sonorella is hermaphroditic (meaning an individual has both male and female sex organs), species are primarily separated by geographic location and anatomy of male genitalia (Bequaert and Miller 1973, p. 110).

According to information in our files, the genus Sonorella includes 79 species (McCord 1995, p. 317). The Sonoran talussnail is in the order Stylommatophora and the family Helminthoglyptidae first described in 1890 by R.E.C. Stearns as Helix from specimens collected near Magdalena, Sonora, in Mexico (Bequaert and Miller 1973, pp. 121-122). Between 1915 and 1923, Pilsbry and Ferriss described seven other species and subspecies of Sonorella that are currently recognized as the Sonoran talussnail: S. hinckleyi, S. h. fraternal, S. tumacacori, S. cayetanensis, S. sitiens arida, S. tumamocensis, and S. linearis (Bequaert and Miller 1973, p. 122). Pilsbry (1939, p. 341) later synonymized the first four of these species with S. s. arida, which he raised to a species, S. arida. Following additional research, the three remaining species recognized by Pilsbry were synonymized with S. magdalenensis as a single species (Bequaert and Miller 1973, p. 122). Although a thorough systematic and phylogenetic review of the genus Sonorella has not been published in the literature, the Sonoran talussnail is recognized as a valid species by the scientific community (Bequaert and Miller 1973, pp. 121-123; McCord 1995, p. 320). We consider the petitioned species, Sonorella magdalenensis, to be a valid species based on the information in the petition and available in our files, and, therefore a listable entity under the Act.

There is little other information available specific to the biology of the Sonoran talussnail; however, it is reasonable to conclude that the Sonoran talussnail is likely to be similar to other closely related talussnails in terms of its habitat needs and life-history traits. Sonorella species are generally considered rock snails, occupying rockslides and talus slopes (slopes composed of volcanic rock and limestone) (Pilsbry 1939, p. 268; Naranjo-Garcia 1988, p. 84; Pearce and Orstan 2006, p. 265). The petitioner notes that the Sonoran talussnail is found in talus or coarse broken rock slides at elevations ranging from 2,750 to 6,000 feet (839 to1830 meters) (Bequaert and Miller 1973, p. 122). Most Sonorella species prefer steep rock slides with sufficient interstitial space (space between rocks) that allow crawling to the proper depth for protection from summer heat (Bequaert and Miller 1973, p. 27; Hoffman 1990, p. 7; Hoffman 1995, p. 5). Occupied sites can usually be identified by the presence of dead and bleached shells, which are typically abundant because they disintegrate slowly in arid environs (Pilsbry 1939, p. 269).

Talussnails spend considerable time in estivation (dormancy), perhaps up to 3 years at a time (Hoffman 1990, p. 7). To prepare for estivation, talussnails use mucus and calcium to attach the opening of the shell to the face of a rock to make a waterproof seal. During estivation, talussnails survive by extracting calcium carbonate from their shells, which is re-deposited when active feeding resumes (Hoffman 1990, p. 7). Weather conditions are the most important factor affecting activity of living Sonorella, with talussnails only active above ground during or following summer monsoon rains (Jontz et al. 2002a, p. 3; Weaver et al. 2010, p. 3). Talussnails feed primarily on fungus and decaying plant matter (Hoffman 1990, p. 7; Hoffman 1995, p. 6; AGFD 2008, p. 2). Sonorella species in the Santa Rita Mountains have been reported foraging on Xanthoparmelia, a leaf-like lichen, during and after rains (WestLand Resources 2010, pp. 26, 31).

Sonorella species mate face-to-face, and insemination is simultaneous reciprocal, meaning when two talussnails meet both are usually inseminated (Hoffman 1995, p. 6; Davison and Mordan 2007, p. 175). During or after rain events, talussnails lay a clutch of 30 to 40 eggs once or twice during summer. Fluctuations in humidity may cause large variations in rates of maturation and the life span of talussnails. The life span of land snails is dependent on their cycle of activity, although talussnails are believed to live 8 to 9 years (Hoffman 1995, p. 6). Many mountain ranges in southeastern Arizona where Sonorella species live are also inhabited by a snail-eating beetle ( Scaphinotus petersi ), which presumably preys upon talussnails (McCord 1995, p. 321). Talussnails are also believed to be eaten by rodents and birds, but this is probably a sporadic random occurrence (Hoffman 1990, p. 10).

Species in the Sonorella genus are found throughout most of Arizona, portions of western New Mexico and Texas, and in Sonora, Mexico, and are typically distributed across the landscape as geographically isolated populations exhibiting a high degree of endemism (organisms having narrowly distributed isolated populations) (Bequaert and Miller 1973, p. 22; McCord 1995, p. 321). The distribution and diversity of Sonorella species across the arid Southwest has likely been promoted by cycles of fragmentation and connection between the mountains they inhabit. It is thought that a protracted series of substantial migrations occurred during wetter periods throughout the Pleistocene Epoch (i.e., 2.5 million to 10,000 years ago), when topography also may have been more suitable for colonization by snails crawling across the landscape (Bequaert and Miller 1973, p. 22; McCord 1995, p. 321). In contrast, the drier climate and geography of the present-day Southwest does not favor dispersal of Sonorella species into new territories (Bequaert and Miller 1973, p. 22).

The Sonoran talussnail is one of six Sonorella species that has a large range relative to other members of the genus, and the Sonoran talussnail inhabits the most widely separated localities of all Sonorella (Bequaert and Miller 1973, p. 25). In addition to the type locality in the Sierra Magdalena in Sonora, Mexico, the petitioner notes that, in Arizona, the Sonoran talussnail has been documented in seven mountain ranges within a 200- by 30-mile (mi) (124- by 19-kilometer (km)) area primarily along the edges of the Santa Cruz Valley in Pima and Santa Cruz Counties (Bequaert and Miller 1973, p. 25). In Pima County, the species is known from the Roskruge Mountains, southern end of Tucson Mountains, northern end of Santa Rita Mountains, Cerro Colorado Mountains, and Tumamoc Hill (Bequaert and Miller 1973, p. 122). In Santa Cruz County, it is known from the San Cayetano and Tumacacori mountains (Bequaert and Miller 1973, p. 122). Bequaert and Miller (1973, p. 122) also note that the Sonoran talussnail has been found in other locations in Sonora, Mexico, as far south as the Sierra Pajaritos located 24 mi (39 km) east of the town of Ures, Sonora.

To our knowledge, there are no population numbers or trends known for the Sonoran talussnail. There are no recent survey data for all of the known range, and we have no information in our files to indicate that anyone has looked for this species throughout its range for almost 40 years. As noted by the petitioner, WestLand Resources (2010, pp. 28-29) found Sonorella species in 26 localities in the Santa Rita Mountains along slopes, ridge lines, and canyon bottoms in 2008 and 2009. Some of these talussnails were likely Sonoran talussnails, although this has not been verified. We have no additional information readily available in our files regarding the species' current distribution. Furthermore, the petitioner does not present, nor do we have in our files, information related to population numbers, size, or trends for the Sonoran talussnail.

Section 4 of the Act (16 U.S.C. 1533) and its implementing regulations at 50 CFR part 424 set forth the procedures for adding a species to, or removing a species from, the Federal Lists of Endangered and Threatened Wildlife and Plants. A species may be determined to be an endangered or threatened species due to one or more of the five factors described in section 4(a)(1) of the Act:

(A) The present or threatened destruction, modification, or curtailment of its habitat or range;

(B) Overutilization for commercial, recreational, scientific, or educational purposes;

(C) Disease or predation;

(D) The inadequacy of existing regulatory mechanisms; or

(E) Other natural or manmade factors affecting its continued existence.

In considering what factors might constitute threats, we must look beyond the mere exposure of the species to the factor to determine whether the species responds to the factor in a way that causes actual impacts to the species. If there is exposure to a factor, but no response, or only a positive response, that factor is not a threat. If there is exposure and the species responds negatively, the factor may be a threat and we then attempt to determine how significant a threat it is. If the threat is significant, it may drive or contribute to the risk of extinction of the species such that the species may warrant listing as endangered or threatened as those terms are defined by the Act. This does not necessarily require empirical proof of a threat. The combination of exposure and some corroborating evidence of how the species is likely impacted could suffice. The mere identification of factors that could impact a species negatively may not be sufficient to compel a finding that listing may be warranted. The information must contain evidence sufficient to suggest that these factors may be operative threats that act on the species to the point that the species may meet the definition of endangered or threatened under the Act.

In making this 90-day finding, we evaluated whether information regarding threats to the Sonoran talussnail, as presented in the petition and other information available in our files, is substantial, thereby indicating that the petitioned action may be warranted. Our evaluation of this information is presented below.

The petitioner asserts that the Sonoran talussnail is threatened by habitat loss and degradation due to mining; exotic plant invasion and control; real estate development; livestock grazing; recreation and vandalism; and illegal immigration, smuggling, and enforcement activities along the international border. Other threats asserted by the petitioner include over-collection; inadequate regulatory mechanisms; and small, isolated populations at risk of loss due to chance events and ongoing climate change.

In support of the assertion that mining activity is a threat to the Sonoran talussnail throughout its range, the petitioner explains that mining, in general, and the proposed Rosemont Copper Mine in the Santa Rita Mountains (Augusta Resource Corporation 2010, p. 10), specifically, may directly remove talussnails, degrade habitat and water quality and quantity, alter microhabitat conditions, and increase access roads and collection pressure (Center for Biological Diversity 2010, pp. 15-17). The petitioner referenced WestLand Resources (2009, p. 2 and 2010, pp. 23-32), Jones (2008, p. 1), and Bequaert and Miller (1973, p. 25) to illustrate that the Sonoran talussnail may occur in talus slopes as well as the waste rock footprint of the proposed Rosemont Copper Mine. The petitioner indicated that dust, sediment, herbicides, and windblown pollutants from mining activities, and mining-related road construction, use, and maintenance, may cause increased interstitial sedimentation and contamination of Sonoran talussnail habitat in the Santa Rita Mountains within and adjacent to the proposed Rosemont Copper Mine footprint (Service 1998, p. 5; AGFD 2003, p. 3; Fonseca 2009, p. 3; SWCA Environmental Consultants 2009, pp. 3-7).

In reference to the petitioner's claim that mining is a threat to the Sonoran talussnail, some of the information presented by the petitioner appears to be reliable. Review of the information provided by the petitioner supports that the Sonoran talussnail likely occurs in the waste rock footprint and talus slopes of the proposed Rosemont Copper Mine; however, the petitioner did not provide substantial information to illustrate that mining and mineral exploration is occurring in other parts of the species' range. However, according to U.S. Geological Survey 7.5-minute topographic maps readily available in our files, there are numerous mines and mining prospects within 2 miles of five of the known locations of Sonoran talussnail in Arizona: the Cerro Colorado Mountains, San Cayetano Mountains, Santa Rita Mountains, Tucson Mountains, and Tumacacori Mountains. These mines and mining claims are on privately owned lands or lands managed by U.S. Forest Service or Arizona State Land Department. Although we do not have information on the status of these mines, we believe their existence reveals that there is mining potential and a history of interest in areas adjacent to known locations of the Sonoran talussnail. Hard rock mining typically involves the blasting of hillsides and the crushing of rock. Threats posed to the Sonoran talussnail from such mining are supported by the information provided by the petitioner as well as other information readily available in our files (Hoffman 1990, p. 7; Jontz et al. 2002b, p. 1) that indicates Sonoran talussnails could be killed or their habitat rendered unsuitable from hard rock mining activities that remove talus, increase sedimentation in spaces between talus, and otherwise alter moisture conditions. These additional mines in locations that could impact more populations of the Sonoran talussnail would put the species at a high risk of extinction. Therefore, we conclude that the petition, as well as information readily available in our files, presents substantial information that this species may warrant listing due to habitat destruction from mining activities throughout most of its range.

In support of its assertion that the Sonoran talussnail is threatened by exotic plant invasion and control, the petitioner stated that Pennisetum cilare (buffelgrass) invades both lower slopes and steep rocky hillsides and is expanding very rapidly in areas inhabited by the species in the Roskruge Mountains, Tumamoc Hill, and Mexico (Arizona-Sonora Desert Museum 2010, p. 1). The petitioner further explained that fire carried by bufflegrass, as well as rock disturbance and herbicide application to remove bufflegrass, may degrade habitat of talussnails (Fonseca 2009, p. 3). The petitioner further referenced Garcia and Conway (2007, entire) and U.S. Forest Service (2003, entire) to illustrate that herbicides used in control of exotic plants such as buffelgrass threaten non-target species. Finally, the petitioner stated that P. setaceum (fountain grass) may also threaten Sonoran talussnail in the Tucson Mountains.

In reference to the petitioner's claim that exotic plant invasion and control is a threat to Sonoran talussnail, some of the information presented by the petitioner appears to be reliable. Review of this and other information readily available in our files confirms that the perennial African buffelgrass is prevalent throughout four of the seven mountain ranges in Arizona and one in Mexico with known locations of Sonoran talussnails: Cerro Colorado Mountains, Roskruge Mountains, Tucson Mountains, Tumamoc Hill, and Sierra Magdalena (Van Devender and Dimmitt 2006, pp. 5-6; Burquez-Montijo et al. 2002, p. 137). However, the petitioner provided no information concerning how fire carried by buffelgrass may be acting on the species. Information readily available in our files supports that fire has become an increasingly significant threat in the Sonoran Desert within the range of the Sonoran talussnail due to the widespread invasion of nonnative annual and perennial grasses (Burquez and Qunitana 1994, p. 23).

The Sonoran Desert is not adapted to high-intensity fire, yet buffelgrass is not only fire-tolerant but also fire-promoting (Halverson and Guertin 2003, p. 13). On slopes where Sonoran talussnails may be present, buffelgrass establishment is higher in the vicinity of rocks and in disturbed soils (Burquez-Montijo 2002, p. 134). The fire cycle created by conversion of slopes to buffelgrass can alter the microclimate and nutrient availability in the soil and litter layer that Sonoran talussnails rely on for food (Burquez-Montijo 2002, p. 135; Esque and Schwalbe 2002, p. 181; Williams and Baruch 2000, pp. 128-130). A study by Nekola (2002, pp. 64-65) found that increased fire cycles caused by fire management in central North American grasslands reduced the abundance and diversity of land snails and altered the microclimate and nutrient availability to snails by burning the duff or litter layer where snails feed. Even though they live in talus and not grasslands, Sonoran talussnails also rely on a litter layer to feed. In addition, surveys of a canyon occupied by Sonorella species in the Pinaleno Mountains of Arizona following the Nuttall complex fires in 2004 revealed hundreds of scorched talussnail shells along the canyon where burnout operations apparently reached high temperatures (Jones 2004, pers. comm.).

Information in our files regarding the ability of buffelgrass to carry fire into habitats of the Sonoran talussnail, combined with evidence that fire has killed other Sonorella species and resulted in decreased abundance and diversity and altered habitat of other land snails, supports that similar negative impacts may occur, or may be occurring, to Sonoran talussnail. Therefore, information provided by the petitioner and readily available in our files presents substantial evidence that this species may warrant listing due to habitat destruction from exotic plant invasion throughout most of its range. The petitioner did not provide substantial information, nor do we have information in our files, supporting that mechanical or chemical removal of invasive plant species is a threat to the Sonoran talussnail.

The petitioner also states that real estate development, livestock grazing, recreation, vandalism, and activities along the international border are threats to Sonoran talussnail, but provides no substantial information to evaluate. The petitioner also states that collection is known to threaten talussnails. The petition also explains that inadequate existing regulatory mechanisms are a threat to the Sonoran talussnail based on a lack of regulation from collection laws, U.S. Forest Service regulations, and a general lack of other regulations to protect the species or its habitat in the United States or Mexico. The petitioner also asserts that Sonorella species are highly vulnerable to extinction due to chance events because they are found in isolated populations in small patches, and from historic range contraction that is likely to continue due to climate warming. We will further evaluate these factors, along with any other potential factors, during our status review and will report our findings in the subsequent 12-month finding.

On the basis of our determination under section 4(b)(3)(A) of the Act, we determine that the petition presents substantial scientific or commercial information indicating that listing the Sonoran talussnail may be warranted. This finding is based on substantial information provided in the petition, in addition to information readily available in our files, related to possible impacts originating from mining and the invasion of exotic plants.

Because we have found that the petition presents substantial information indicating that listing the Sonoran talussnail may be warranted, we are initiating a status review to determine whether listing the Sonoran talussnail under the Act is warranted. We will evaluate all information under the five factors during the status review under section 4(b)(3)(B) of the Act. We will fully evaluate these potential threats during our status review, under the Act's requirement to review the best available scientific information when making that finding. Accordingly, we encourage the public to consider and submit information related to these and any other threats that may be operating on the Sonoran talussnail (see Request for Information).

A complete list of references cited is available on the Internet at http://www.regulations.gov and upon request from the Arizona Ecological Services Office (see FOR FURTHER INFORMATION CONTACT ).

The primary authors of this notice are the staff members of the Arizona Ecological Services Office.

The authority for this action is the Endangered Species Act of 1973, as amended (16 U.S.C. 1531 et seq. ).

We will accept written comments and information during this reopened comment period on our proposed revised designation of critical habitat for the tidewater goby that was published in the Federal Register on October 19, 2011 (76 FR 64996), our DEA of the proposed revised designation, and the amended required determinations provided in this document. We will consider information and recommendations from all interested parties. We are particularly interested in comments concerning:

(1) The reasons why we should or should not designate habitat as “critical habitat” under section 4 of the Act (16 U.S.C. 1531 et seq. ), including whether there are threats to the species from human activity, the degree of which can be expected to increase due to the designation, and whether that increase in threat outweighs the benefit of designation such that the designation of critical habitat is not prudent.

(2) Specific information on:

(a) The distribution of the tidewater goby;

(b) The amount and distribution of tidewater goby habitat;

(c) What areas within the geographical area occupied by the species at the time of listing that contain physical or biological features essential to the conservation of the species we should include in the designation and why; and

(d) What areas outside the geographical area occupied at the time of listing are essential for the conservation of the species and why.

(3) Land-use designations and current or planned activities in the subject areas and their possible effects on proposed revised critical habitat for tidewater goby.

(4) Any foreseeable economic, national security, or other relevant impacts that may result from designating any area that may be included in the final designation. We are particularly interested in any impacts on small entities, and the benefits of including or excluding areas from the proposed designation that are subject to these impacts.

(5) Whether our approach to designating critical habitat could be improved or modified in any way to provide for greater public participation and understanding, or to assist us in accommodating public concerns and comments.

(6) Information on the extent to which the description of economic impacts in the DEA is complete and accurate.

(7) The likelihood of adverse social reactions to the designation of critical habitat, as discussed in the DEA, and how the consequences of such reactions, if likely to occur, would relate to the conservation and regulatory benefits of the proposed critical habitat designation.

If you submitted comments or information on the proposed revised rule (76 FR 64996) during the initial comment period from October 19, 2011, to December 19, 2011, please do not resubmit them. We will incorporate them into the public record as part of this comment period, and we will fully consider them in the preparation of our final determination. Our final determination concerning revised critical habitat will take into consideration all written comments and any additional information we receive during both comment periods. On the basis of public comments, we may, during the development of our final determination, find that areas proposed do not meet the definition of critical habitat, are appropriate for exclusion under section 4(b)(2) of the Act, or are not appropriate for exclusion.

You may submit your comments and materials concerning the proposed rule or DEA by one of the methods listed in the ADDRESSES section. We request that you send comments only by the methods described in the ADDRESSES section.

If you submit a comment via http://www.regulations.gov, your entire comment—including any personal identifying information—will be posted on the Web site. We will post all hardcopy comments on http://www.regulations.gov as well. If you submit a hardcopy comment that includes personal identifying information, you may request at the top of your document that we withhold this information from public review. However, we cannot guarantee that we will be able to do so.

Comments and materials we receive, as well as supporting documentation we used in preparing the proposed rule and DEA, will be available for public inspection on http://www.regulations.gov at Docket No. FWS-R8-ES-2011-0085, or by appointment, during normal business hours, at the U.S. Fish and Wildlife Service, Ventura Fish and Wildlife Office (see FOR FURTHER INFORMATION CONTACT ). You may obtain copies of the proposed revised rule and the DEA on the Internet at http://www.regulations.gov at Docket Number FWS-R8-ES-2011-0085, or by mail from the Ventura Fish and Wildlife Office (see FOR FURTHER INFORMATION CONTACT ).

It is our intent to discuss only those topics directly relevant to the designation of critical habitat for tidewater goby in this document. For more information on previous Federal actions concerning the tidewater goby, refer to the proposed revised designation of critical habitat published in the Federal Register on October 19, 2011 (76 FR 64996). For more information on the tidewater goby or its habitat, refer to the final listing rule published in the Federal Register on February 4, 1994 (59 FR 5494); the first and second rules proposing critical habitat published in the Federal Register on August 3, 1999 (64 FR 42250) and November 28, 2006 (71 FR 68914), respectively; and the subsequent final critical habitat designations published in the Federal Register on November 20, 2000 (65 FR 69693) and January 31, 2008 (73 FR 5920), which are available at http://www.fws.gov/ventura or from the Ventura Fish and Wildlife Office (see FOR FURTHER INFORMATION CONTACT ). Additionally, more species information can be found in the Recovery Plan for the Tidewater Goby (Recovery Plan) (Service 2005), and in the Tidewater Goby 5-year review (Service 2007), which are available at http://www.fws.gov/endangered .

On April 15, 2009, Natural Resources Defense Council (NRDC) filed a lawsuit in the U.S. District Court for the Northern District of California challenging a portion of the January 31, 2008, final rule that designated 44 critical habitat units in Del Norte, Humboldt, Mendocino, Sonoma, Marin, San Mateo, Santa Cruz, Monterey, San Luis Obispo, Santa Barbara, Ventura, and Los Angeles Counties, California (73 FR 5920, January 31, 2008). In a consent decree dated December 11, 2009, the U.S. District Court: (1) Stated that the 44 critical habitat units should remain in effect, (2) stated that the final rule designating critical habitat was remanded in its entirety for reconsideration, and (3) directed the Service to promulgate a revised critical habitat rule that considers the entire geographic range of the tidewater goby and any currently unoccupied tidewater goby habitat. The consent decree requires that the Service submit a final revised rule to the Federal Register no later than November 27, 2012.

Section 3 of the Act defines critical habitat as the specific areas within the geographical area occupied by a species, at the time it is listed in accordance with the Act, on which are found those physical or biological features essential to the conservation of the species and that may require special management considerations or protection, and specific areas outside the geographical area occupied by a species at the time it is listed, upon a determination that such areas are essential for the conservation of the species. If the proposed rule is made final, section 7 of the Act will prohibit destruction or adverse modification (collectively referred to as “adverse modification”) of the designated critical habitat by any activity funded, authorized, or carried out by any Federal agency. Federal agencies proposing actions that may affect critical habitat must consult with us on the effects of their proposed actions, under section 7(a)(2) of the Act.

Section 4(b)(2) of the Act requires that we designate or revise critical habitat based upon the best scientific data available, after taking into consideration the economic impact, impact on national security, or any other relevant impact of specifying any particular area as critical habitat. We may exclude an area from critical habitat if we determine that the benefits of excluding the area outweigh the benefits of including the area as critical habitat, provided such exclusion will not result in the extinction of the species.

When considering the benefits of inclusion for an area, we consider the additional regulatory benefits that area would receive from the protection from adverse modification as a result of actions with a Federal nexus (activities conducted, funded, permitted, or authorized by Federal agencies), the educational benefits of mapping areas containing essential features that aid in the recovery of the listed species, and any benefits that may result from designation due to State or Federal laws that may apply to critical habitat. In the case of tidewater goby, the benefits of critical habitat include public awareness of the presence of tidewater goby and the importance of habitat protection, and, where a Federal nexus exists, increased habitat protection for tidewater goby due to protection from adverse modification of critical habitat. In practice, situations with a Federal nexus exist primarily on Federal lands or for projects undertaken by Federal agencies.

When considering the benefits of exclusion, we consider, among other things, whether exclusion of a specific area is likely to result in conservation; the continuation, strengthening, or encouragement of partnerships; or implementation of a management plan.

We are not currently considering any areas for exclusion from critical habitat. However, the final decision on whether to exclude any areas will be based on the best scientific data available at the time of the final designation, including information obtained during the comment period and information about the economic impact of designation. Accordingly, we have prepared a draft economic analysis concerning the proposed critical habitat designation (DEA), which is available for review and comment (see ADDRESSES ).

The purpose of the DEA is to identify and analyze the potential economic impacts associated with the proposed critical habitat designation for the tidewater goby. The DEA separates conservation measures into two distinct categories according to “without critical habitat” and “with critical habitat” scenarios. The “without critical habitat” scenario represents the baseline for the analysis, considering protections otherwise afforded to the tidewater goby (e.g., under the Federal listing and other Federal, State, and local regulations). The “with critical habitat” scenario describes the incremental impacts specifically due to designation of critical habitat for the species. In other words, these incremental conservation measures and associated economic impacts would not occur but for the designation. Conservation measures implemented under the baseline (without critical habitat) scenario are described qualitatively within the DEA, but economic impacts associated with these measures are not quantified. Economic impacts are only quantified for conservation measures implemented specifically due to the designation of critical habitat (i.e., incremental impacts). For a further description of the methodology of the analysis, see Chapter 2, “Framework for the Analysis,” of the DEA (Industrial Economics Incorporated (IEc) 2012).

The DEA provides estimated costs of the foreseeable potential economic impacts of the proposed critical habitat designation for the tidewater goby over the next 20 years, which was determined to be the appropriate period for analysis because limited planning information is available for most activities to forecast activity levels for projects beyond a 20-year timeframe. It identifies potential incremental costs as a result of the proposed revised critical habitat designation; these are those costs attributed to critical habitat over and above those baseline costs attributed to listing. The DEA quantifies economic impacts of tidewater goby conservation efforts associated with the following categories of activity: (1) Water management; (2) cattle grazing; (3) transportation (roads, highways, bridges); (4) utilities (oil and gas pipelines); (5) residential, commercial, and industrial development; and (6) natural resource management.

Baseline protections for the tidewater goby address a broad range of habitat threats within a significant portion of the proposed critical habitat area. A key consideration in the incremental analysis is that, where tidewater goby critical habitat overlaps with steelhead ( Oncorhynchus mykiss ) critical habitat, steelhead conservation measures would be sufficiently protective for tidewater goby critical habitat as well. As a result, few incremental project modification costs are anticipated in these areas. Across the designation, incremental costs primarily include costs of administrative efforts associated with new and reinitiated consultations to consider adverse modification of critical habitat for tidewater goby. In addition, some minor incremental project modification costs are forecast to result from critical habitat. This result is attributed to the following key findings: (1) Baseline protections exist for tidewater goby; (2) steelhead critical habitat overlaps with a large portion of the unoccupied units; and (3) minimal economic activity occurs on private lands in the study area.

In total, the incremental impacts to all economic activities are estimated to be $558,000 over the 20-year timeframe, or $49,300 on an annualized basis (assuming a 7 percent discount rate). Approximately 98 percent of these incremental costs result from administrative costs of considering adverse modification in section 7 consultations.

Incremental conservation efforts are estimated to be $11,500 over the 20-year timeframe or $1,090 on an annualized basis (both assuming a 7 percent discount rate). These include the costs of adding the tidewater goby to the environmental impact reports (EIR) required for projects that are being proposed in critical habitat unit MAR-5 Bolinas Lagoon and SLO-12 Oso Flaco Lake, as well as additional surveying for tidewater goby in Oso Flaco Lake.

As we stated earlier, we are soliciting data and comments from the public on the DEA, as well as all aspects of the proposed rule and our amended required determinations. We may revise the proposed rule to incorporate or address information we receive during the public comment period. In particular, we may exclude an area from critical habitat if we determine that the benefits of excluding the area outweigh the benefits of including the area, provided the exclusion will not result in the extinction of this species.

In this document, we are making a revision to the proposed revised critical habitat as identified and described in the proposed rule that we published in the Federal Register on October 19, 2011 (76 FR 64996). In the proposed rule we stated that, “We also are proposing to designate specific areas outside the geographical area occupied by the species at the time of listing that were historically occupied, but are presently unoccupied, because such areas are essential for the conservation of the species” (76 FR 65004). However, we did not intend to limit the proposal to only specific areas outside the geographical area occupied by the species at the time of listing that were historically occupied. Our intent was to consider all areas that are essential for the conservation of the species and not only those that were known to be historically occupied, and we were in error when we included “that were historically occupied, but are presently unoccupied” in the proposed revised rule. In the proposed revised rule, we proposed to designate 6 units that are outside the geographical area occupied by the species at the time of listing where tidewater gobies have not been detected. These units are: SM-2 Pomponio Creek, MAR-5 Bolinas Lagoon, SLO-1 Arroyo de la Cruz, SLO-12 Oso Flaco Lake, LA-1 Arroyo Sequit, and LA-2 Zuma Canyon. These units are essential for the conservation of the tidewater goby because translocation to new locations within developing metapopulations is anticipated to enhance or accelerate the rangewide recovery effort as described in the recovery plan (Service 2005). Moreover, the recovery strategy in the recovery plan states that as subpopulations of tidewater gobies become isolated, recolonization rates decrease, local extirpations become permanent, and entire metapopulations can move incrementally toward extinction. Thus, these units are essential for the conservation of the species because they could be used to minimize the chance of local extirpations resulting in extinction of the broader metapopulations and resultant loss of their unique genetic traits either by introducing tidewater goby in these units or by the natural colonization of these units.

In our October 19, 2011, proposed revised rule (76 FR 64996), we indicated that we would defer our determination of compliance with several statutes and executive orders until the information concerning potential economic impacts of the designation and potential effects on landowners and stakeholders became available in the DEA. We have now made use of the DEA data to make these determinations. In this document, we affirm the information in our proposed revised rule concerning Executive Order (E.O.) 12866 (Regulatory Planning and Review), E.O. 12630 (Takings), E.O. 13132 (Federalism), E.O. 12988 (Civil Justice Reform), E.O. 13211 (Energy, Supply, Distribution, and Use), the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq. ), the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ), the National Environmental Policy Act (42 U.S.C. 4321 et seq. ), and the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951). However, based on the DEA data, we are amending our required determination concerning the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ).

Under the Regulatory Flexibility Act (RFA; 5 U.S.C. 601 et seq. ), as amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA; 5 U.S.C. 801 et seq. ), whenever an agency is required to publish a notice of rulemaking for any proposed or final rule, it must prepare and make available for public comment a regulatory flexibility analysis that describes the effects of the rule on small entities (i.e., small businesses, small organizations, and small government jurisdictions). However, no regulatory flexibility analysis is required if the head of the agency certifies the rule will not have a significant economic impact on a substantial number of small entities. The SBREFA amended the RFA to require Federal agencies to provide a certification statement of the factual basis for certifying that the rule will not have a significant economic impact on a substantial number of small entities. Based on our DEA of the proposed designation, we provide our analysis for determining whether the proposed rule would result in a significant economic impact on a substantial number of small entities. Based on comments we receive, we may revise this determination as part of our final rulemaking.

According to the Small Business Administration, small entities include small organizations such as independent nonprofit organizations; small governmental jurisdictions, including school boards and city and town governments that serve fewer than 50,000 residents; and small businesses (13 CFR 121.201). Small businesses include manufacturing and mining concerns with fewer than 500 employees, wholesale trade entities with fewer than 100 employees, retail and service businesses with less than $5 million in annual sales, general and heavy construction businesses with less than $27.5 million in annual business, special trade contractors doing less than $11.5 million in annual business, and agricultural businesses with annual sales less than $750,000. To determine if potential economic impacts to these small entities are significant, we considered the types of activities that might trigger regulatory impacts under this designation as well as types of project modifications that may result. In general, the term “significant economic impact” is meant to apply to a typical small business firm's business operations.

To determine if the proposed designation of critical habitat for the tidewater goby would affect a substantial number of small entities, we considered the number of small entities affected within particular types of economic activities, such as: (1) Water management; (2) cattle grazing; (3) transportation (roads, highways, bridges); (4) utilities (oil and gas pipelines); (5) residential, commercial, and industrial development; and (6) natural resource management. In order to determine whether it is appropriate for us to certify that this proposed rule would not have a significant economic impact on a substantial number of small entities, we considered each industry or category individually. In estimating the numbers of small entities potentially affected, we also considered whether their activities have any Federal involvement. Critical habitat designation will not affect activities that do not have any Federal involvement; designation of critical habitat only affects activities conducted, funded, permitted, or authorized by Federal agencies. In areas where the tidewater goby is present, Federal agencies already are required to consult with us under section 7 of the Act on activities they fund, permit, or implement that may affect the species. If we finalize the proposed critical habitat designation, consultations to avoid the adverse modification of critical habitat would be incorporated into the existing consultation process.

In the DEA, we evaluated the potential economic effects on small entities resulting from implementation of conservation actions related to the proposed designation of critical habitat for the tidewater goby. The analysis is based on estimated impacts associated with the proposed rulemaking as described in Chapters 4 and 5, and Appendix A, of the DEA, and evaluates the potential for economic impacts related to activity categories including development, natural resource management, transportation, utilities, water management, and recreation.

As described in Chapters 4 and 5 of the DEA, estimated incremental impacts consist primarily of administrative costs and time delays associated with section 7 consultation. The Service and the action agency are the only entities with direct compliance costs associated with this proposed critical habitat designation, although small entities may participate in section 7 consultation as a third party. It is therefore possible that the small entities may spend additional time considering critical habitat during section 7 consultation for the tidewater goby. The DEA indicates that the incremental impacts potentially incurred by small entities are limited to development, natural resource management, transportation, utilities, and water management activities.

Chapter 5 of the DEA discusses the potential for proposed revised critical habitat to affect development through additional costs of section 7 consultation. These costs are borne by developers and existing landowners, depending on whether developers are able to pass all or a portion of their costs back to landowners in the form of lower prices paid for undeveloped land. Of the total number of entities engaged in land subdivision and residential, commercial, industrial and institutional construction, nearly 99 percent are small entities.

Whether individual developers are affected depends on the specific characteristics of a particular land parcel as well as the availability of land within the affected region. If land is not scarce, the price of a specific parcel will likely incorporate any regulatory restrictions on that parcel. Therefore, any costs associated with conservation efforts for tidewater goby will likely be reflected in the price paid for the parcel. In this case, the costs of conservation efforts are ultimately borne by the current landowner in the form of reduced land values. Many of these landowners may be individuals or families that are not legally considered to be businesses.

If, however, land in the affected region is scarce, or the characteristics of the specific parcel are unique, the price of a parcel may not incorporate regulatory restrictions associated with that parcel. In this case, the project developer may be required to incur the additional costs associated with the section 7 consultation process. To understand the potential impacts on small entities, we conservatively assume that all of the private owners of developable lands affected by proposed revised critical habitat designation are developers.

In Chapter 5 of the DEA, we estimate that a total of 20 formal, informal, and technical assistance consultations, plus one re-initiation, may require additional effort to consider adverse modification of revised critical habitat. Assuming that each consultation is undertaken by a separate entity, we estimate that 21 developers may be affected by the designation. For purposes of this analysis, and because nearly 99 percent of developers in the study area are small, we assume that all 21 are small entities. These developers represent less than 0.1 percent of small developers in the study area.

Excluding costs borne by Federal agencies, costs per consultation range from $260 for technical assistance to $1,800 for re-initiation of a formal consultation. Because we are unable to identify the specific entities affected, the impact relative to those entities' annual revenues or profits is unknown. However, assuming the average small entity has annual revenues of approximately $5.1 million, this maximum annualized impact of $1,800 represents less than 0.1 percent of annual revenues.

The consultation history for natural resource management projects suggests that these projects are generally undertaken by Federal and State agencies, or County departments. The DEA estimates incremental administrative costs for section 7 consultation on natural resource management in every County except Orange County. Only one of these entities, Del Norte County, meets the threshold for small governmental jurisdiction. Del Norte County is anticipated to incur administrative costs associated with addressing adverse modification in approximately three consultations, including one re-initiation. Even if all consultations occur in the same year, total impacts to Del Norte County will be less than 1 percent of the County's annual revenue.

The consultation history for tidewater goby includes several consultations regarding utilities and oil and gas development. In Chapter 5 of the DEA, we estimate that 24 consultations involving utility activities will occur during the 20-year period. Based on the overall percentage of all small entities in the study area (56 percent), we estimate that 14 of the 24 total entities that will be affected over the 20-year period are small entities. Excluding costs to Federal agencies, the cost per entity of addressing adverse modification in a section 7 consultation ranges from $260 for technical assistance to $880 for a formal consultation (no re-initiations are predicted for utility activities). Because we are unable to identify the specific entities affected, the impact relative to those entities' annual revenues or profits is unknown. However, assuming the average small entity in this industry has annual revenues of approximately $9.3 million, this maximum annualized impact of $880 represents less than 0.01 percent of annual revenues.

Chapter 5 of the DEA also discusses the potential for water management activities to be affected by the designation. Over the 20-year period, we estimate that 125 consultations involving water management activities, including re-initiations, will occur. Based on the overall percentage of all small entities in the study area (83 percent), we estimate that 104 of the 125 total entities that will be affected over the 20-year period are small entities. Excluding costs to Federal agencies, the cost per entity of addressing adverse modification in a section 7 consultation ranges from $260 for technical assistance to $1,800 for re-initiation of a formal consultation. Because we are unable to identify the specific entities affected, the impact relative to those entities' annual revenues or profits is unknown. However, assuming the average small entity in this industry has annual revenues of approximately $5.0 million, this maximum annualized impact of $1,800 represents less than 0.1 percent of annual revenues.

The DEA also concludes that none of the government entities with which we might consult on tidewater goby for transportation or recreation meet the definitions of small as defined by the Small Business Act (SBE) (IEC 2012, p. A-6); therefore, impacts to small government entities due to transportation and recreation are not anticipated. A review of the consultation history for tidewater goby suggests future section 7 consultations on livestock grazing (for example, ranching operations) are unlikely, and as a result are not anticipated to be affected by the proposed rule (IEC 2012, p. 5-13). Please refer to the DEA of the proposed critical habitat designation for a more detailed discussion of potential economic impacts.

In summary, we have considered whether the proposed designation would result in a significant economic impact on a substantial number of small entities. Information for this analysis was gathered from the Small Business Administration, stakeholders, and our files. We have identified 161 small entities that may be impacted by the proposed critical habitat designation. For the above reasons and based on currently available information, we certify that, if promulgated, the proposed critical habitat designation would not have a significant economic impact on a substantial number of small business entities. Therefore, an initial regulatory flexibility analysis is not required.

The primary authors of this notice are the staff members of the Ventura Fish and Wildlife Office, Pacific Southwest Region, U.S. Fish and Wildlife Service.

The authority for this action is the Endangered Species Act of 1973, as amended (16 U.S.C. 1531 et seq. ).