Federal Register Vol. 80, No.135,

I. Background

This rule proposes to implement a provision of the Agricultural Act of 2014 (Pub. L. 113-79; the “2014 Farm Bill”), which amends the definition of “retail food store” in Section 3(o) of the Food and Nutrition Act of 2008 (7 U.S.C. 2011 note; the “FNA”) to include P&D Services that purchase and deliver food to households in which the head of household is an individual who is unable to shop for food, and who is 60 years of age or older, or physically or mentally handicapped, or otherwise disabled. Today, retail food stores are authorized to accept SNAP benefits in exchange for eligible foods, as defined in program regulations at 7 CFR part 271, at § 271.2. As a result of the 2014 Farm Bill, approved P&D Services will also be permitted to accept SNAP benefits for the SNAP eligible foods that they purchase and deliver to qualifying households.

Currently, a number of different types of firms may be authorized to accept SNAP benefits as retail food stores, including, but not limited to, public or private communal dining facilities, meal delivery services, private nonprofit cooperative food purchasing ventures and farmers' markets. All firms apply for authorization through FNS which may, or may not, authorize the firm as a SNAP retailer based upon the information provided in the application and a determination of whether the firm meets Program requirements and whether the firm's participation will further the purposes of the program. Accordingly, this rule proposes to amend and revise 7 CFR part 278 to include P&D Services as another type of firm which may be eligible for authorization as a retail food store, and to clarify and incorporate criteria for participation of P&D Services as SNAP retailers.

Although FNS is proposing this rule to amend and revise regulations in accordance with the 2014 Farm Bill, the Farm Bill also permits the Secretary to authorize up to 20 P&D Services as retail food stores prior to issuance of rules. FNS plans to authorize these stores in the upcoming year for a one year trial period and will incorporate any lessons learned into additional guidance for P&D Services' participation. Proposed amendments and revisions to program regulations are discussed more fully in the next section of the preamble.

FNS is proposing three minor amendments or revisions to 7 CFR part 271 to clarify the definition of “retail food store” and to distinguish and define P&D Services as retail food stores. All three changes are proposed for the definitions section located at § 271.2.

First, FNS proposes to add to § 271.2 a definition for “food purchasing and delivery services” which says that the term means governmental or private nonprofit food purchasing and delivery services that purchase eligible foods for, and delivers these foods to, households in which the head of household is an elderly or disabled member who is unable to shop for food. Second, FNS proposes to revise the definition of “house-to-house trade route” to clarify that it includes any retail food business operated by selling eligible foods in inventory from a truck bus, pushcart or other mobile vehicle. FNS proposes to add “by selling eligible foods in inventory” to this definition to distinguish P&D Services, which may also operate from a mobile vehicle, but which will not maintain an inventory of foods. Rather, P&D Services typically purchase eligible foods from another retailer and deliver these foods to SNAP households. Finally, FNS proposes to amend the definition of “retail food store” by adding paragraph (6) under the term, to incorporate P&D services as part of the definition of “retail food store.”

FNS proposes a few amendments to § 274.7, to clarify which households may use SNAP benefits to purchase eligible foods through P&D Services and to clarify transaction limits for P&D services. Specifically, FNS proposes to amend paragraph (c) of this section regarding transaction limits. Currently, program regulations provide that no minimum dollar amount per transaction may be established. However, given that P&D services are providing a delivery service, it may not be economical or efficient for such services to make deliveries of small dollar values of eligible foods. Therefore, FNS proposes to amend this paragraph by allowing P&D Services to establish a minimum dollar amount per transaction. In proposed § 278.2(m)(4), FNS specifies that P&D Services may require an order minimum of not more than $50.

In § 274.7, FNS inserts a new paragraph (i), which proposes to allow households in which the head of household is an elderly or disabled member who is unable to shop for food to use SNAP benefits to purchase eligible foods through a food purchasing and delivery service authorized in accordance with § 278.1(j). FNS then moves current paragraph (i) to paragraph (j) and amends it. Currently, this paragraph says that State agencies must implement a method to ensure that access to prepared meals and hunting and fishing equipment is limited to eligible households. FNS proposes to amend this paragraph by adding the same implementation requirement of State agencies for households eligible for P&D Services.

In this rule, FNS proposes to revise and amend 7 CFR part 278 to incorporate criteria for the authorization and participation of P&D Services throughout. Following is a discussion of the major changes to this part proposed in this rule. Additional minor conforming changes are also being made to § 278.6, imposing the same penalty requirements of P&D Services as are required of other firms.

As for major changes, FNS proposes to amend § 278.1, which provides the process and criteria for authorization of various firms as retail food stores, by inserting paragraph (j), which adds P&D Services as a type of firm that may be authorized as a retail food store. FNS also proposes the requirements that P&D Services must meet in order to be authorized in this paragraph and clarifies that P&D Services may purchase and deliver to households foods or non-food items not eligible for purchase with SNAP benefits, as long as these purchases are not paid for using SNAP benefits.

FNS then proposes to amend paragraph (k) of § 278.1, as redesignated, which provides 5 years as the period of authorization for retail food stores. Because P&D Services do not maintain an inventory of eligible foods and must have third party sources of eligible foods, and because they work with particularly vulnerable SNAP households in their own homes, FNS finds it is prudent to require a shorter authorization period of 2 years. The shorter authorization period would allow FNS to have greater oversight of P&D Services, thereby ensuring stronger program integrity.

FNS also proposes to amend § 278.2(b) regarding equal treatment for SNAP customers. Specifically, one provision of this paragraph provides that FNS is not authorized to specify prices at which retail food stores may sell food. While this remains true, the 2014 Farm Bill specifies that food purchasing and delivery services must provide eligible foods to the participating household at the price paid by the service for the food, without any cost markup, as a condition of being authorized. Accordingly, FNS proposes to include this language in this paragraph (b). To note, this paragraph also prohibits retail food stores from charging tax on eligible foods. Likewise, P&D Services authorized as retail food stores would not be permitted to charge households tax on eligible foods.

Finally, FNS proposes to add a new paragraph (m) to § 278.2, which details the requirements of participation for retail food stores, by adding paragraphs (m)(1) through (7) which contain requirements specific to P&D Services. Paragraphs (m)(1) through (3) contain proposed requirements specifically articulated in the 2014 Farm Bill, while paragraphs (4) through (7) contain proposed requirements either necessary to ensure the legitimate use of SNAP benefits or to help ensure that the participation of P&D Services will further the purposes of the program.

In paragraph (m)(1), FNS proposes to require that P&D Services notify the participating household, at the time the household places a food order, of any delivery fee that will be charged for the purchase and delivery of foods. FNS also proposes that, at the same time, P&D Services notify the household that a delivery fee cannot be paid with SNAP benefits. This ensures that the household can consider the cost of the delivery fee when making decisions regarding the use of the service and the purchase of foods, and that the household is aware that it must use another form of payment besides SNAP benefits for delivery fees. A clear understanding of the delivery fee and its payment method is important for both the household and the P&D Service to have a successful transaction.

In paragraph (m)(2), FNS would require P&D Services to provide its food purchasing and delivery services at low or no cost, as required by the 2014 Farm Bill. Although the Farm Bill does not specify any limit on the amount of the delivery fee, FNS believes that, given the vulnerable population being served, it is important to propose a required limitation on the amount of the delivery fee to ensure that the cost of the delivery service is not excessive. Accordingly, FNS proposes that the delivery fee charged cannot exceed 25 percent of the order total, up to a maximum of $20 per delivery for all items purchased for delivery, including items not eligible for payment with SNAP benefits and which are paid for using another form of payment. However, FNS would encourage P&D Services to base any delivery fee, within these parameters, on a sliding scale taking into account factors such as the household's income.

In paragraph (m)(3), FNS proposes to require P&D Services to sell eligible foods purchased for the household at the price paid by the service for the food without any additional cost markup. Again, this requirement is specified in the 2014 Farm Bill. P&D Services should also be aware that 278.2(b) prohibits retail food stores from charging tax on eligible foods purchased with SNAP benefits. Therefore, P&D Services would not be permitted to charge any tax paid for these foods to the households they serve.

In paragraph (m)(4), FNS proposes to allow P&D Services, at their option, to impose a total order minimum of up to $50 per delivery for all items purchased for delivery, including items not eligible for payment with SNAP benefits and which are paid for using another form of payment. This provision recognizes that it may be difficult for P&D Services to provide their services for very small order amounts. However, a larger limit may make the service inaccessible to many eligible SNAP participants. The Agency would be very interested in receiving comments on this proposed provision.

In paragraph (m)(5), FNS proposes to require P&D Services to be able to accept orders for eligible foods, and deliver these foods, at least monthly. This allows the homebound elderly and disabled persons served by P&D Services to have access to eligible foods with some regularity, and it allows them the opportunity to plan their collective food purchases during any given month.

In paragraph (m)(6), FNS proposes to require P&D Services to obtain the agreement of the household, at the time of the food order, of the date and timeframe of delivery. This proposed requirement, that both the P&D Service and the household agree to a specific date and timeframe of delivery, is intended to benefit both the service and the household. It is important that the household provides input and agreement as to the time that the delivery will take place. At the same time, it helps to ensure for the P&D Service that someone will be available to accept the delivery. While the proposed rule would not dictate the maximum window of delivery allowed, it is recommended that any delivery timeframe does not exceed two hours.

In paragraph (m)(7), FNS proposes that P&D Services may not impose any conditions on the use of the food purchase and delivery service which place a hardship on the SNAP household, or which are unrelated to the purchase and delivery of foods. Such additional conditions would include a requirement to tip the delivery driver or to participate in religious or affiliate activities. The eligible SNAP participants served by P&D Services are particularly vulnerable and will be accepting deliveries in their own homes. Conditions placed on delivery of eligible foods to these households may be perceived as being coercive, even if not intended as such. Therefore, FNS believes it is important that any conditions imposed on food purchase and delivery services be limited to those strictly necessary, and related to the purchase and delivery of foods.

Although FNS is proposing specific criteria related to the authorization and participation of P&D Services in SNAP, these retailers will be expected to meet all other existing program requirements for retailers, as appropriate. For example, in accordance with current 278.2(e), P&D Services may not redeem SNAP benefits before delivery of foods.

Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. FNS considers that the benefits of this regulation justify its costs. Although governmental or private nonprofit food purchasing and delivery services may incur additional operational costs should the proposals in this rule become final, most SNAP retailers also incur such costs. These costs are outweighed by the benefit of the greater program flexibility of allowing food purchasing and delivery services to serve the homebound elderly and disabled.

This proposed rule has been determined to be not significant and was not reviewed by the Office of Management and Budget (OMB) in conformance with Executive Order 12866.

This proposed rule has been designated as not significant by OMB. Therefore, no Regulatory Impact Analysis is required.

The Regulatory Flexibility Act (5 U.S.C. 601-612) requires agencies to analyze the impact of rulemaking on small entities and consider alternatives that would minimize any significant impacts on a substantial number of small entities. Pursuant to that review, it has been certified that this proposed rule would not have a significant impact on a substantial number of small entities. Although the rulemaking proposes to allow additional small not-for-profit organizations to accept SNAP benefits, it is not anticipated that a substantial number of small entities will begin accepting SNAP benefits as a result of the rulemaking, nor will the impact on these small entities be significant given that some of these entities already use another process to accept SNAP benefits and because SNAP benefits are just one of the forms of payment accepted by these entities.

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local and tribal governments and the private sector. Under section 202 of the UMRA, the Department generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures by State, local or Tribal governments, in the aggregate, or the private sector, of $100 million or more in any one year. When such a statement is needed for a rule, section 205 of the UMRA generally requires the Department to identify and consider a reasonable number of regulatory alternatives and adopt the most cost effective or least burdensome alternative that achieves the objectives of the rule.

This proposed rule contains no Federal mandates (under the regulatory provisions of Title II of the UMRA) for State, local and Tribal governments or the private sector of $100 million or more in any one year. Thus, the rule is not subject to the requirements of sections 202 and 205 of the UMRA.

SNAP is listed in the Catalog of Federal Domestic Assistance Programs under 10.551. For the reasons set forth in the final rule in 7 CFR part 3015, subpart V, and related notice (48 FR 29115, June 24, 1983), this program is included in the scope of Executive Order 12372, which requires intergovernmental consultation with State and local officials.

Executive Order 13132 requires Federal agencies to consider the impact of their regulatory actions on State and local governments. Where such actions have federalism implications, agencies are directed to provide a statement for inclusion in the preamble to the regulations describing the agency's considerations in terms of the three categories called for under section (6)(b)(2)(B) of Executive Order 13121.

The Department has considered the impact of this proposed rule on State and local governments and has determined that this rule does not have federalism implications. Therefore, under section 6(b) of the Executive Order, a federalism summary is not required.

This proposed rule has been reviewed under Executive Order 12988, Civil Justice Reform. This proposed rule is intended to have preemptive effect with respect to any State or local laws, regulations or policies which conflict with its provisions or which would otherwise impede its full and timely implementation. This proposed rule is not intended to have retroactive effect unless so specified in the Effective Dates section of the final rule. Prior to any judicial challenge to the provisions of the final rule, all applicable administrative procedures must be exhausted.

FNS has reviewed this proposed rule in accordance with USDA Regulation 4300-4, “Civil Rights Impact Analysis,” to identify any major civil rights impacts the rule might have on program participants on the basis of religion, age, race, color, national origin, sex, political beliefs or disability. After a careful review of the rule's intent and provisions, FNS has determined that this proposed rule is not expected to negatively affect the participation of protected individuals in the Supplemental Nutrition Assistance Program.

Executive Order 13175 requires Federal agencies to consult and coordinate with Tribes on a government-to-government basis on policies that have Tribal implications, including regulations, legislative comments or proposed legislation, and other policy statements or actions that have substantial direct effects on one or more Indian Tribes, on the relationship between the Federal Government and Indian Tribes, or on the distribution of power and responsibilities between the Federal Government and Indian Tribes. On February 18, 2015, as part of its regular quarterly Tribal consultation schedule, USDA engaged in a consultative session to obtain input by Tribal officials, or their designees, and Tribal members concerning the effect of this and other rules on the Tribes or Indian Tribal governments. No concerns regarding the provisions of this proposed rule were expressed.

The Paperwork Reduction Act of 1995 (44 U.S.C. chap. 35; 5 CFR part 1320) requires the Office of Management and Budget (OMB) approve all collections of information by a Federal agency before they can be implemented. Respondents are not required to respond to any collection of information unless it displays a current valid OMB control number. This rule does not contain information collection requirements subject to approval by the Office of Management and Budget under the Paperwork Reduction Act of 1994.

The Department is committed to complying with the E-Government Act, to promote the use of the Internet and other information technologies to provide increased opportunities for citizen access to Government information and services, and for other purposes.

For the reasons stated in the preamble, 7 CFR parts 271, 274, and 278 are proposed to be amended as follows:

The addition and revisions read as follows:

The revisions and addition read as follows:

The revisions and additions read as follows:

FAA Order 5190.6B, FAA Airport Compliance Manual (Order), published on September 30, 2009 defines flying clubs as: “a nonprofit or not-for-profit entity (e.g., corporation, association, or partnership) organized for the express purpose of providing its members with aircraft for their personal use and enjoyment only.” The Order states that “the ownership of the club aircraft must be vested in the name of the flying club or owned by all its members. The property rights of the members of the club shall be equal; no part of the net earnings of the club will benefit any one individual in any form, including salaries, bonuses, etc. The flying club may not derive greater revenue from the use of its aircraft than the amount needed for the operation, maintenance and replacement of its aircraft.” The Order also notes that “flying clubs may not offer or conduct . . . aircraft rental operations. They may conduct aircraft flight instruction for regular members only, and only members of the flying club may operate the aircraft.” While members may not be monetarily compensated, existing policy allows flying clubs to allow compensation only in the form of credit against payment of dues or flight time.

In addition, the Order states that “no flying club shall permit its aircraft to be used for flight instruction for any person, including members of the club owning the aircraft, when such person pays or becomes obligated to pay for such instruction. An exception applies when the instruction is given by a lessee based on the airport who provides flight training and the person receiving the training is a member of the flying club. Flight instructors who are also club members may not receive payment for instruction except that they may be compensated by credit against payment of dues or flight time” and that “any qualified mechanic who is a registered member and part owner of the aircraft owned and operated by a flying club may perform maintenance work on aircraft owned by the club. The flying club may not become obligated to pay for such maintenance work except that such mechanics may be compensated by credit against payment of dues or flight time.” [See FAA Order 5190.6B, paragraphs 10.6(a), (b), and (c).] Flying clubs are defined in such a way as to differentiate from for-profit aeronautical businesses offering aeronautical services to general public, e.g., FBOs, flight schools and aircraft rental providers.

The owner of any airport (airport sponsor) developed with Federal grant assistance is required to operate the airport for the use and benefit of the public and to make it available to all types, kinds, and classes of aeronautical activity on fair and reasonable terms, and without unjust discrimination. This includes flying clubs. Assurance 22, Economic Nondiscrimination, of the prescribed sponsor assurances implements the provisions of 49 U.S.C. 47107(a)(l) through (6), and requires, in pertinent part, that the sponsor of a federally obligated airport

As part of its effort to promote flying clubs, AOPA has recommended revisions to FAA guidance. These recommendations, designed to promote flying clubs, include allowing flight instructors and mechanics who are club members to receive monetary compensation for services conducted for other club members or club aircraft. Specifically, AOPA proposes the following language for consideration in FAA flying club policies:

In brief, AOPA requests that flight instructors and mechanics who are club members be permitted to receive monetary compensation for services conducted within the club. AOPA's request also emphasizes that airport sponsors must [emphasis added] permit the club to compensate club instructors and mechanics with credit against payment of dues or flight time.

AOPA-recommended revisions are available for review on the FAA Airports Web site, as well as in the docket locations described under Availability of documents in this notice.

Request for Comments: The FAA requests comments on whether AOPA's recommendations can be considered consistent with the FAA's general policies regarding commercial aeronautical services and flying clubs on an airport, and if so, whether the stated agency policy on flying clubs should be revised to amend its definition of flying clubs. In particular, the FAA seeks comments from commercial service providers that engage in flight training and aircraft rental, from associations representing such service providers, and other interested parties.

On May 26, 2015, EPA published a notice of proposed rulemaking (80 FR 30015). In the NPR, EPA proposed disapproval of a revision to the Delaware SIP related to nonattainment NSR preconstruction permit program requirements for emission offsets. In that action, EPA proposed disapproval, because the submittal did not satisfy the requirements of Clean Air Act (CAA) or the Federal implementing regulations, which establish the criteria under which the owner or operator of a new or modified major stationary source must obtain the required emission offsets “from the same source or other sources in the same nonattainment area” with limited exceptions, for Delaware's nonattainment NSR preconstruction permitting program. In addition, EPA proposed disapproval of the SIP revision because Delaware exercises authorities that are reserved for EPA under section 107 of the CAA.

1. Submitting Confidential Business Information (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 on 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:

• Identify the rulemaking by docket number and other identifying information (subject heading, Federal Register volume, date, and page number);

• Follow directions and organize your comments;

• Explain why you agree or disagree;

• Suggest alternatives and substitute language for your requested changes;

• Describe any assumptions and provide any technical information and/or data that you used;

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

• Provide specific examples to illustrate your concerns, and suggest alternatives;

• Explain your views as clearly as possible, avoiding the use of profanity or personal threats; and,

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

On March 12, 2008, EPA promulgated a new NAAQS for ozone, revising the levels of the primary and secondary 8-hour ozone standards from 0.08 parts per million (ppm) to 0.075 ppm (73 FR 16436). Subsequently, on October 15, 2008, EPA revised the level of the primary and secondary Pb NAAQS from 1.5 micrograms per cubic meter (μg/m3) to 0.15 μg/m3 (73 FR 66964). On January 22, 2010, EPA promulgated a new 1-hour primary NAAQS for NO2 at a level of 100 parts per billion (ppb) while retaining the annual standard of 53 ppb. The 2010 NO2 NAAQS is expressed as the three year average of the 98th percentile of the annual distribution of daily maximum 1-hour average concentrations. The secondary NO2 NAAQS remains unchanged at 53 ppb (75 FR 6474, Feb. 9, 2010).

EPA promulgated a revised NAAQS for PM2.5 on October 17, 2006, tightening the level of the 24-hour standard to 35 µg/m3 and retaining the level of the annual PM2.5 standard at 15 µg/m3. EPA approved element 110(a)(2)(D)(i)(I) (discussed below) of North Dakota's infrastructure SIP for this NAAQS on July 29, 2013 (78 FR 45457). EPA approved all other infrastructure elements (aside from element 110(a)(2)(D)(i)(II) regarding visibility) of North Dakota's 2006 PM2.5 infrastructure SIP on July 30, 2013 (78 FR 45866). We are acting on the visibility element in this action.

Under sections 110(a)(1) and (2) of the CAA, states are required to submit infrastructure SIPs to ensure their SIPs provide for implementation, maintenance, and enforcement of the NAAQS. These submissions must contain any revisions needed for meeting the applicable SIP requirements of section 110(a)(2), or certifications that their existing SIPs for ozone, Pb, and NO2 already meet those requirements. EPA highlighted this statutory requirement in an October 2, 2007, guidance document entitled “Guidance on SIP Elements Required Under Sections 110(a)(1) and (2) for the 1997 8-hour Ozone and PM2.5 National Ambient Air Quality Standards” (2007 Memo). On September 25, 2009, EPA issued an additional guidance document pertaining to the 2006 PM2.5 NAAQS entitled “Guidance on SIP Elements Required Under Sections 110(a)(1) and (2) for the 2006 24-Hour Fine Particle (PM2.5) National Ambient Air Quality Standards (NAAQS)” (2009 Memo), followed by the October 14, 2011, “Guidance on Infrastructure SIP Elements Required Under Sections 110(a)(1) and (2) for the 2008 Lead (Pb) National Ambient Air Quality Standards (NAAQS)” (2011 Memo). Most recently, EPA issued “Guidance on Infrastructure State Implementation Plan (SIP) Elements under Clean Air Act Sections 110(a)(1) and (2)” on September 13, 2013 (2013 Memo).

EPA is acting upon the SIP submissions from North Dakota that address the infrastructure requirements of CAA sections 110(a)(1) and 110(a)(2) for the 2008 ozone, 2008 Pb, and 2010 NO2 NAAQS. The requirement for states to make a SIP submission of this type arises out of CAA section 110(a)(1). Pursuant to section 110(a)(1), states must make SIP submissions “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 these SIP submissions are to provide for the “implementation, maintenance, and enforcement” of such NAAQS. The statute directly imposes on states the duty to make these SIP submissions, and the requirement to make the submissions is not conditioned upon EPA taking any action other than promulgating a new or revised NAAQS. Section 110(a)(2) includes a list of specific elements that “[e]ach such plan” submission must address.

EPA has historically referred to these SIP submissions made for the purpose of satisfying the requirements of CAA sections 110(a)(1) and 110(a)(2) as “infrastructure SIP” submissions. Although the term “infrastructure SIP” does not appear in the CAA, EPA uses the term to distinguish this particular type of SIP submission from submissions that are intended to satisfy other SIP requirements under the CAA, such as “nonattainment SIP” or “attainment plan SIP” submissions to address the nonattainment planning requirements of part D of title I of the CAA; “regional haze SIP” submissions required by EPA rule to address the visibility protection requirements of CAA section 169A; and nonattainment new source review (NSR) permit program submissions to address the permit requirements of CAA, title I, part D.

Section 110(a)(1) addresses the timing and general requirements for infrastructure SIP submissions, and section 110(a)(2) provides more details concerning the required contents of these submissions. 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 program provisions, and some of which pertain to requirements for both authority and substantive program provisions.1 EPA therefore believes that while the timing requirement in section 110(a)(1) is unambiguous, some of the other statutory provisions are ambiguous. In particular, EPA believes that the list of required elements for infrastructure SIP submissions provided in section 110(a)(2) contains ambiguities concerning what is required for inclusion in an infrastructure SIP submission.

Examples of some of these ambiguities and the context in which EPA interprets the ambiguous portions of section 110(a)(1) and 110(a)(2) are discussed at length in our notice of proposed rulemaking: Promulgation of State Implementation Plan Revisions; Infrastructure Requirements for the 1997 and 2006 PM2.5, 2008 Lead, 2008 Ozone, and 2010 NO2 National Ambient Air Quality Standards; South Dakota (79 FR 71040 Dec. 1, 2014) under “III. What is the Scope of this Rulemaking?”

With respect to certain other issues, EPA does not believe that an action on a state's infrastructure SIP submission is necessarily the appropriate type of action in which to address possible deficiencies in a state's existing SIP. These issues include: (i) Existing provisions related to excess emissions from sources during periods of startup, shutdown, or malfunction (SSM) that may be contrary to the CAA and EPA's policies addressing such excess emissions; (ii) existing provisions related to “director's variance” or “director's discretion” that may be contrary to the CAA because they purport to allow revisions to SIP-approved emissions limits while limiting public process or not requiring further approval by EPA; and (iii) 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, Dec. 31, 2002, as amended by 72 FR 32526, June 13, 2007. (“NSR Reform”).

CAA section 110(a)(1) provides the procedural and timing requirements for SIP submissions after a new or revised NAAQS is promulgated. Section 110(a)(2) lists specific elements the SIP must contain or satisfy. These infrastructure elements include requirements such as modeling, monitoring, and emissions inventories, which are designed to assure attainment and maintenance of the NAAQS. The elements that are the subject of this action are listed below.

• 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.

• 110(a)(2)(D): Interstate transport.

• 110(a)(2)(E): Adequate resources and authority, conflict of interest, and oversight of local governments and regional agencies.

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

• 110(a)(2)(G): Emergency powers.

• 110(a)(2)(H): Future SIP revisions.

• 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.

Two elements identified in section 110(a)(2) are not governed by the three year submission deadline of section 110(a)(1) and are therefore not addressed in this action. These elements relate to part D of Title I of the CAA, and submissions to satisfy them are not due within three years after promulgation of a new or revised NAAQS, but rather are due at the same time nonattainment area plan requirements are due under section 172. The two elements are: (1) Section 110(a)(2)(C) to the extent it refers to permit programs (known as “nonattainment NSR”) required under part D, and (2) section 110(a)(2)(I), pertaining to the nonattainment planning requirements of part D. As a result, this action does not address infrastructure elements related to the nonattainment NSR portion of section 110(a)(2)(C) or related to 110(a)(2)(I). Furthermore, EPA interprets the CAA section 110(a)(2)(J) provision on visibility as not being triggered by a new NAAQS because the visibility requirements in part C, title 1 of the CAA are not changed by a new NAAQS.

The North Dakota Department of Health (Department or NDDH) submitted certification of North Dakota's infrastructure SIP for the 2008 Pb NAAQS on May 25, 2012, and joint certifications for the 2008 ozone and the 2010 NO2 NAAQS on March 7, 2013. North Dakota's infrastructure certifications demonstrate how the State, where applicable, has plans in place that meet the requirements of section 110 for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS. These plans reference the current North Dakota Air Pollution Control Rules (NDAC) and North Dakota Century Code (NDCC). These submittals are available within the electronic docket for today's proposed action at www.regulations.gov. The NDAC and NDCC referenced in the submittals are publicly available at https://www.ndhealth.gov/aq/AirRules.htm and http://www.legis.nd.gov/general-information/north-dakota-century-code. North Dakota's SIP, air pollution control regulations, and statutes that have been previously approved by EPA and incorporated into the North Dakota SIP can be found at 40 CFR 52.1820.

1. Emission limits and other control measures: Section 110(a)(2)(A) requires SIPs to include enforceable emission limitations and other control measures, means, or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for compliance as may be necessary or appropriate to meet the applicable requirements of this Act.

Multiple SIP-approved State air quality regulations within the NDAC and cited in North Dakota's certifications provide enforceable emission limitations and other control measures, means of techniques, schedules for compliance, and other related matters necessary to meet the requirements of the CAA section 110(a)(2)(A) for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS, subject to the following clarifications.

First, this infrastructure element does not require the submittal of regulations or emission limitations developed specifically for attaining the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS. Furthermore, North Dakota has no areas designated as nonattainment for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS. North Dakota's certifications (contained within this docket) generally listed provisions within its SIP which regulate pollutants through various programs, including major and minor source permit programs. This suffices, in the case of North Dakota, to meet the requirements of section 110(a)(2)(A) for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS.

Second, as previously discussed, EPA is not proposing to approve or disapprove any existing state rules with regard to director's discretion or variance provisions. A number of states, including North Dakota, have such provisions which are contrary to the CAA and existing EPA guidance (52 FR 45109, Nov. 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.

Finally, in this action, EPA is also not proposing to approve or disapprove any existing state provision with regard to excess emissions during SSM of operations at a facility. A number of states, including North Dakota, have SSM provisions which are contrary to the CAA and existing EPA guidance 2 and the agency is addressing such state regulations separately (80 FR 33840, June 12, 2015).

Therefore, EPA is proposing to approve North Dakota's infrastructure SIP for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS with respect to the general requirement in section 110(a)(2)(A) to include enforceable emission limitations and other control measures, means, or techniques to meet the applicable requirements of this element.

2. Ambient air quality monitoring/data system: Section 110(a)(2)(B) requires SIPs to provide for establishment and operation of appropriate devices, methods, systems, and procedures necessary to “(i) monitor, compile, and analyze data on ambient air quality, and (ii) upon request, make such data available to the Administrator.”

Ambient monitoring is covered in Chapter 6 of the North Dakota SIP. It provides for the design and operation of a monitoring network, reporting of data obtained from the monitors, and annual network review including notification to EPA of any changes, and public notification of exceedances of NAAQS. EPA approved North Dakota's Division of Air Quality's (DAQ) 2013 Ambient Air Monitoring Network Plan for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS on April 2, 2015. North Dakota's air monitoring programs and data systems meet the requirements of CAA section 110(a)(2)(B) for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS.

3. Program for enforcement of control measures: Section 110(a)(2)(C) requires SIPs to include a program to provide for the enforcement of the measures described in subparagraph (A), and regulation of the modification and construction of any stationary source within the areas covered by the plan as necessary to assure NAAQS are achieved, including a permit program as required in parts C and D.

To generally meet the requirements of section 110(a)(2)(C), the State is required to have SIP-approved PSD, nonattainment NSR, and minor NSR permitting programs adequate to implement 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS. As explained elsewhere in this action, EPA is not evaluating nonattainment related provisions, such as the nonattainment NSR program required by part D of the Act. EPA is evaluating the State's PSD program as required by part C of the Act, and the State's minor NSR program as required by 110(a)(2)(C).

With respect to elements (C) and (J), EPA interprets the CAA to require each state to make an infrastructure SIP submission for a new or revised NAAQS that demonstrates that the air agency has a complete PSD permitting program meeting the current requirements for all regulated NSR pollutants. The requirements of element (D)(i)(II) may also be satisfied by demonstrating the air agency has a complete PSD permitting program correctly addressing all regulated NSR pollutants. North Dakota has shown that it currently has a PSD program in place that covers all regulated NSR pollutants, including greenhouse gases (GHGs).

North Dakota implements the PSD program by, for the most part, incorporating by reference the federal PSD program as it existed on a specific date. The State periodically updates the PSD program by revising the date of incorporation by reference and submitting the change as a SIP revision. As a result, the SIP revisions generally reflect changes to PSD requirements that EPA has promulgated prior to the revised date of incorporation by reference.

On June 3, 2010 (75 FR 31291), we approved a North Dakota SIP revision that revised the date of incorporation by reference of the federal PSD program to August 1, 2007. That revision addressed the PSD requirements of the Phase 2 Ozone Implementation Rule promulgated in 2005 (70 FR 71612). As a result, the approved North Dakota PSD program meets current requirements for ozone.

Similarly, on October 23, 2012 (77 FR 64736), we approved a North Dakota SIP revision that revised the date of incorporation by reference of the federal PSD program to July 2, 2010. As explained in the notice for that action, that revision addressed the PSD requirements related to GHGs provided in EPA's June 3, 2010 “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (75 FR 31514). The approved North Dakota PSD program thus also meets current requirements for GHGs.

On June 23, 2014, the United States Supreme Court issued a decision addressing the application of PSD permitting requirements to GHG emissions, Utility Air Regulatory Group v. Environmental Protection Agency, 134 S.Ct. 2427. The Supreme Court said that EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a PSD permit. The Supreme Court also said that EPA could continue to require that PSD permits, otherwise required based on emissions of pollutants other than GHGs, contain limitations on GHG emissions based on the application of Best Available Control Technology (BACT). In order to act consistently with its understanding of the Court's decision pending further judicial action to effectuate the decision, EPA is not continuing to apply EPA regulations that would require that SIPs include permitting requirements that the Supreme Court found impermissible. Specifically, EPA is not applying the requirement that a state's SIP-approved PSD program require that sources obtain PSD permits when GHGs are the only pollutant (i) that the source emits or has the potential to emit above the major source thresholds, or (ii) for which there is a significant emissions increase and a significant net emissions increase from a modification (e.g., 40 CFR 51.166(b)(48)(v)). EPA anticipates a need to revise federal PSD rules in light of the Supreme Court opinion. In addition, EPA anticipates that many states will revise their existing SIP-approved PSD programs in light of the Supreme Court's decision. The timing and content of subsequent EPA actions with respect to EPA regulations and state PSD program approvals are expected to be informed by additional legal process before the United States Court of Appeals for the District of Columbia Circuit. At this juncture, EPA is not expecting states to have revised their PSD programs for purposes of infrastructure SIP submissions and is only evaluating such submissions to assure that the state's program correctly addresses GHGs consistent with the Supreme Court's decision.

At present, EPA has determined that North Dakota's SIP is sufficient to satisfy elements (C), (D)(i)(II), and (J) with respect to GHGs because the PSD permitting program previously approved by EPA into the SIP continues to require that PSD permits (otherwise required based on emissions of pollutants other than GHGs) contain limitations on GHG emissions based on the application of BACT. Although the approved North Dakota PSD permitting program may currently contain provisions that are no longer necessary in light of the Supreme Court decision, this does not render the infrastructure SIP submission inadequate to satisfy elements (C), (D)(i)(II), and (J). The SIP contains the necessary PSD requirements at this time, and the application of those requirements is not impeded by the presence of other previously-approved provisions regarding the permitting of sources of GHGs that EPA does not consider necessary at this time in light of the Supreme Court decision. Accordingly, the Supreme Court decision does not affect EPA's proposed approval of North Dakota's infrastructure SIP as to the requirements of elements (C), (D)(i)(II), and (J).

Finally, we evaluate the PSD program with respect to current requirements for PM2.5. In particular, on May 16, 2008, EPA promulgated the rule, “Implementation of the New Source Review Program for Particulate Matter Less Than 2.5 Micrometers (PM2.5)” (73 FR 28321) and on October 20, 2010 EPA promulgated the rule, “Prevention of Significant Deterioration (PSD) for Particulate Matter Less Than 2.5 Micrometers (PM2.5)—Increments, Significant Impact Levels (SILs) and Significant Monitoring Concentration (SMC)” (75 FR 64864). EPA regards adoption of these PM2.5 rules as a necessary requirement when assessing a PSD program for the purposes of element (C).

On January 4, 2013, the U.S. Court of Appeals, in Natural Resources Defense Council v. EPA, 706 F.3d 428 (D.C. Cir.), issued a judgment that remanded EPA's 2007 and 2008 rules implementing the 1997 PM2.5 NAAQS. The court ordered EPA to “repromulgate these rules pursuant to Subpart 4 consistent with this opinion.” Id. at 437. Subpart 4 of part D, Title 1 of the CAA establishes additional provisions for particulate matter nonattainment areas.

The 2008 implementation rule addressed by the court decision, “Implementation of New Source Review (NSR) Program for Particulate Matter Less Than 2.5 Micrometers (PM2.5),” (73 FR 28321, May 16, 2008), promulgated NSR requirements for implementation of PM2.5 in nonattainment areas (nonattainment NSR) and attainment/unclassifiable areas (PSD). As the requirements of Subpart 4 only pertain to nonattainment areas, EPA does not consider the portions of the 2008 Implementation rule that address requirements for PM2.5 attainment and unclassifiable areas to be affected by the court's opinion. Moreover, EPA does not anticipate the need to revise any PSD requirements promulgated in the 2008 Implementation rule in order to comply with the court's decision. Accordingly, EPA's proposed approval of North Dakota's infrastructure SIP as to elements C or J with respect to the PSD requirements promulgated by the 2008 Implementation rule does not conflict with the court's opinion.

The court's decision with respect to the nonattainment NSR requirements promulgated by the 2008 Implementation rule also does not affect EPA's action on the present infrastructure action. EPA interprets the Act to exclude nonattainment area requirements, including requirements associated with a nonattainment NSR program, from infrastructure SIP submissions due three years after adoption or revision of a NAAQS. Instead, these elements are typically referred to as nonattainment SIP or attainment plan elements, which would be due by the dates statutorily prescribed under subpart 2 through 5 under part D, extending as far as 10 years following designations for some elements.

The second PSD requirement for PM2.5 is contained in EPA's October 20, 2010 rule, “Prevention of Significant Deterioration (PSD) for Particulate Matter Less Than 2.5 Micrometers (PM2.5)—Increments, Significant Impact Levels (SILs) and Significant Monitoring Concentration (SMC)” (75 FR 64864). EPA regards adoption of the PM2.5 increments as a necessary requirement when assessing a PSD program for the purposes of element (C).

As mentioned above, EPA previously approved a North Dakota SIP revision that revised the date of incorporation by reference of the federal PSD program to July 2, 2010 (77 FR 64736, Oct. 23, 2012). This SIP revision also addressed the requirements of the 2008 PM2.5 NSR Implementation Rule. On January 1, 2012, the State submitted revisions to chapter 33-15-15-01.2, Scope, of the NDAC that adopted all elements of the 2010 PM2.5 Increment Rule by incorporating by reference the federal PSD program at 40 CFR part 52, section 21, as it existed on January 1, 2012. The submitted revisions make North Dakota's PSD program up to date with respect to current requirements for PM2.5. EPA approved the necessary portions of North Dakota's January 24, 2013 submission which incorporate the requirements of the 2010 PM2.5 Increment Rule on July 30, 2013 (78 FR 45866). North Dakota's SIP-approved PSD program meets current requirements for PM2.5. EPA therefore is proposing to approve North Dakota's SIP for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS with respect to the requirement in section 110(a)(2)(C) to include a PSD permit program in the SIP as required by part C of the Act.

The State has a SIP-approved minor NSR program, adopted under section 110(a)(2)(C) of the Act. The minor NSR program was originally approved by EPA on August 21, 1995 (60 FR 43401). Since approval of the minor NSR program, the State and EPA have relied on the program to assure that new and modified sources not captured by the major NSR permitting programs do not interfere with attainment and maintenance of the NAAQS.

EPA is proposing to approve North Dakota's infrastructure SIP for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS with respect to the general requirement in section 110(a)(2)(C) to include a program in the SIP that regulates the enforcement, modification and construction of any stationary source as necessary to assure that the NAAQS are achieved.

4. Interstate Transport: The interstate transport provisions in CAA section 110(a)(2)(D)(i) (also called “good neighbor” provisions) require each state to submit a SIP that prohibits emissions that will have certain adverse air quality effects in other states. CAA section 110(a)(2)(D)(i) identifies four distinct elements related to the impacts of air pollutants transported across state lines. The two elements under 110(a)(2)(D)(i)(I) require SIPs to contain adequate provisions to prohibit any source or other type of emissions activity within the state from emitting air pollutants that will (element 1) contribute significantly to nonattainment in any other state with respect to any such national primary or secondary NAAQS, and (element 2) interfere with maintenance by any other state with respect to the same NAAQS. The two elements under 110(a)(2)(D)(i)(II) require SIPs to contain adequate provisions to prohibit emissions that will interfere with measures required to be included in the applicable implementation plan for any other state under part C (element 3) to prevent significant deterioration of air quality or (element 4) to protect visibility. In this action, EPA is addressing all four elements of CAA section 110(a)(2)(D)(i).

EPA is addressing the 2008 Pb and 2010 NO2 NAAQS with regard to elements 1 (significant contribution) and 2 (interference with maintenance). EPA is addressing elements 3 (interference with PSD) and 4 (interference with visibility protection) of 110(a)(2)(D)(i) with regard to the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS, and element 4 of 110(a)(2)(D)(i) with regard to the 2006 PM2.5 NAAQS. We are not addressing elements 1 and 2 for the 2008 ozone NAAQS in this action. These elements will be addressed in a later rulemaking.

North Dakota's analysis of potential interstate transport for the 2008 Pb NAAQS includes considerations of Pb emissions at sources near the State's borders and the distance of Pb sources in North Dakota to the nearest nonattainment area. The State's analysis is available in the docket for this action.

As noted in our 2011 Memo, there is a sharp decrease in Pb concentrations, at least in the coarse fraction, as the distance from a Pb source increases. For this reason, EPA found that the “requirements of subsection (2)(D)(i)(I) (prongs 1 and 2) could be satisfied through a state's assessment as to whether or not emissions from Pb sources located in close proximity to their state borders have emissions that impact the neighboring state such that they contribute significantly to nonattainment or interfere with maintenance in that state.” 3 In that guidance document, EPA further specified that any source appeared unlikely to contribute significantly to nonattainment unless it was located less than 2 miles from a state border and emitted at least 0.5 tons per year of Pb. North Dakota's 110(a)(2)(D)(i)(I) analysis specifically noted that there are no sources in the State that meet both of these criteria. EPA concurs with the State's analysis and conclusion that no North Dakota sources have the combination of Pb emission levels and proximity to nearby nonattainment or maintenance areas to contribute significantly to nonattainment in or interfere with maintenance by other states for this NAAQS. North Dakota's SIP is therefore adequate to ensure that such impacts do not occur. We are proposing to approve North Dakota's submission in that its SIP meets the requirements of section 110(a)(2)(D)(i) for the 2008 Pb NAAQS.

North Dakota's 2010 NO2 transport analysis for element 1 of 110(a)(2)(D)(i) notes that there are no designated nonattainment areas for the 2010 NO2 NAAQS. The State asserts that, because there are no nonattainment areas for this NAAQS, North Dakota does not significantly contribute to nonattainment.

North Dakota's analysis for element 2 of 110(a)(2)(D)(i) considered the distance to the South Coast Air Basin in California, the only NO2 maintenance area in the U.S., as well as the low monitored NO2 values in North Dakota and the historically decreasing NO2 emission levels in the State. North Dakota also noted that it anticipated further decreases in NOX emissions going forward, specifically noting the decreases resulting from the State's regional haze SIP. The State's analysis is available in the docket for this action. EPA concurs with the technical components of North Dakota's 2010 NO2 transport analyses for both elements 1 and 2, but clarifies that element 1 is not specific to designated nonattainment areas. In addition to the factors considered in the State's analysis, EPA also notes that the highest monitored NO2 design values in each state bordering or near North Dakota are significantly below the NAAQS (see Table 2, below). This fact further supports the State's contention that significant contribution to nonattainment or interference with maintenance of the NO2 NAAQS from North Dakota is very unlikely based on the lack of relatively nearby areas with high NO2. This is especially relevant for element 2 (interference with maintenance), because in addition to the lack of nonattainment areas, there are also no areas near the State approaching violation of the 2010 NO2 NAAQS which might therefore have difficulty with maintenance of the standard.

Based on all of these factors, EPA concurs with the State's conclusion that North Dakota does not contribute significantly to nonattainment or interfere with maintenance of the 2010 NO2 NAAQS in other states. EPA is therefore proposing to determine that North Dakota's SIP includes adequate provisions to prohibit sources or other emission activities within the State from emitting NO2 in amounts that will contribute significantly to nonattainment in or interfere with maintenance by any other state with respect specifically to the NO2 NAAQS.

With regard to the PSD portion of section 110(a)(2)(D)(i)(II), this requirement may be met by a state's confirmation in an infrastructure SIP submission that new major sources and major modifications in the state are subject to a comprehensive EPA-approved PSD permitting program in the SIP that applies to all regulated NSR pollutants and that satisfies the requirements of EPA's PSD implementation rule(s).6 As discussed in section VI.3 of this proposed action, North Dakota has such a PSD-permitting program.

As stated in the 2013 Memo, in-state sources not subject to PSD for any one or more of the pollutants subject to regulation under the CAA because they are in a nonattainment area for a NAAQS related to those particular pollutants may also have the potential to interfere with PSD in an attainment or unclassifiable area of another state. North Dakota does not contain any nonattainment areas. The consideration of nonattainment NSR for element 3 is therefore not relevant as all major sources locating in the State are subject to PSD. As North Dakota's SIP meets structural PSD requirements for all regulated NSR pollutants, and does not have any nonattainment areas, EPA is proposing to approve the infrastructure SIP submission as meeting the applicable requirements of element 3 of section 110(a)(2)(D)(i) for the 2008 Ozone, 2008 Pb and 2010 NO2 NAAQS.

The determination of whether the CAA section 110(a)(2)(D)(i)(II) requirement for visibility is satisfied is closely connected to EPA's Regional Haze (RH) program. Under the RH program, each state with a Class I area is required to submit a SIP with reasonable progress goals for each such area that provides for an improvement in visibility for the most impaired days and ensures no degradation of the best days. CAA § 169A.

Because of the often significant impacts on visibility from the interstate transport of pollutants, we interpret the provisions of CAA section 110(a)(2)(D)(i)(II) described above as requiring states to include in their SIPs measures to prohibit emissions that would interfere with the reasonable progress goals set to protect Class I areas in other states. This is consistent with the requirements in the RH program which explicitly require each state to address its share of the emission reductions needed to meet the reasonable progress goals for surrounding Class I areas. 64 FR 35714, 35735 (July 1, 1999). States working together through a regional planning process are required to address an agreed upon share of their contribution to visibility impairment in the Class I areas of their neighbors. Given these requirements in the RH program we have concluded that a fully approved RH SIP satisfies the requirements of section 110(a)(2)(D)(i)(II) with respect to visibility.

In the absence of a fully approved RH SIP, a state can still make a demonstration that its SIP satisfies the visibility requirements of section 110(a)(2)(D)(i)(II).7 States worked through regional planning organizations (RPOs), such as the Western Regional Air Partnership (WRAP) in the case of North Dakota, to develop strategies to address RH. To help states in establishing reasonable progress goals, the RPOs modeled future visibility conditions. The modeling assumed emissions reductions from each state, based on extensive consultation among the states as to appropriate strategies for addressing haze. In setting reasonable progress goals, states generally relied on this modeling. As a result, we generally consider a SIP that ensures emission reductions commensurate with the assumptions underlying the reasonable progress goals to meet the visibility requirement of CAA section 110(a)(2)(D)(i)(II).

In its 2006 PM2.5, 2008 ozone, 2008 Pb and 2010 NO2 infrastructure certifications, North Dakota points to existing portions in the North Dakota SIP, specifically referencing the North Dakota RH SIP, to certify that the State meets the visibility requirements of section 110(a)(2)(D)(i). For the 2006 PM2.5, 2008 ozone, 2008 Pb and 2010 NO2 NAAQS, the State also references the PSD (NDAC 33-15-15) and Visibility Protection (NDAC 33-15-19) portions of its SIP, as well as EPA's RH federal implementation plan (FIP).8 While Pb emissions have less impact on visibility, North Dakota addressed Pb no differently than other NAAQS in its 2008 Pb certification. Regardless, EPA noted in the 2013 Memo that “Pb-related visibility impacts were found to be insignificant,” and that “significant impacts from Pb emissions from stationary sources are expected to be limited to short distances from the source.” 9 As stated earlier in this section, North Dakota does not have any Pb sources near bordering states.

In this action, we are proposing to find that the emissions reductions approved into North Dakota's RH SIP are sufficient to ensure that emissions from sources within the State do not interfere with the reasonable progress goals of nearby states. North Dakota participated in a regional planning process with the WRAP. In the regional planning process, North Dakota accepted and incorporated the WRAP-developed visibility modeling into its RH SIP, and the SIP included the controls assumed in the modeling.

EPA did not fully approve the North Dakota RH SIP, as we partially disapproved, among other elements, the State's selection of NOX Best Available Retrofit Technology (BART) controls for Great River Energy's Coal Creek Station. 77 FR 20894 (April 6, 2012). As a result of our partial disapproval, North Dakota's SIP does not ensure NOX emission reductions from Coal Creek Station, emission reductions which were assumed in the WRAP's visibility modeling that was relied on in setting reasonable progress goals in nearby states.10 We note, however, that the North Dakota RH SIP also adopted NOX controls that were not included in the WRAP's modeling for Otter Tail Power Company's Coyote Station. EPA approved these controls into the North Dakota RH SIP as part of our April 6, 2012 final action. The SIP provision will reduce NOX emissions at Coyote Station by approximately 4,213 tons per year, a larger decrease in emissions than the assumed NOX BART reductions for Coal Creek Station of approximately 3,200 tons per year. As Coal Creek and Coyote Stations are roughly 32 miles apart, a relatively short distance, the visibility impacts from NOX emission reductions at either source on out-of-state Class I areas would be similar.

Because the reductions in North Dakota's approved RH SIP are greater than those assumed by the WRAP modeling, EPA is proposing to find that North Dakota's SIP includes controls sufficient to address the relevant requirements related to impacts on Class I areas in other states.

5. Interstate and International transport provisions: CAA section 110(a)(2)(D)(ii) requires SIPs to include provisions ensuring compliance with the applicable requirements of CAA sections 126 and 115 (relating to interstate and international pollution abatement). Specifically, CAA section 126(a) requires new or modified major sources to notify neighboring states of potential impacts from the source.

Section 126(a) of the CAA requires notification to affected, nearby states of major proposed new (or modified) sources. Sections 126(b) and (c) pertain to petitions by affected states to the Administrator of the EPA (Administrator) regarding sources violating the “interstate transport” provisions of section 110(a)(2)(D)(i). Section 115 of the CAA similarly pertains to international transport of air pollution.

With regard to section 126(a), North Dakota's SIP-approved PSD program requires notice of proposed new sources or modifications to states whose lands may be significantly affected by emissions from the source or modification (see NDAC 33-15-15-01.2(q)(2)(d)). This provision satisfies the notice requirement of section 126(a).

North Dakota has no pending obligations under sections 126(c) or 115(b); therefore, its SIP currently meets the requirements of those sections. In summary, the SIP meets the requirements of CAA section 110(a)(2)(D)(ii) for the 2008 ozone, 2008 Pb and 2010 NO2 NAAQS.

6. Adequate resources: Section 110(a)(2)(E)(i) requires states to provide necessary assurances that the State will have adequate personnel, funding, and authority under state law to carry out the SIP (and is not prohibited by any provision of federal or state law from carrying out the SIP or portion thereof). Section 110(a)(2)(E)(ii) also requires each state to comply with the requirements respecting state boards under CAA section 128. Section 110(a)(2)(E)(iii) requires states to “provide necessary assurances that, where the State has relied on a local or regional government, agency, or instrumentality for the implementation of any [SIP] provision, the State has responsibility for ensuring adequate implementation of such [SIP] provision.”

a. Sub-elements (i) and (iii): Adequate personnel, funding, and legal authority under state law to carry out its SIP, and related issues.

NDCC 23-25-03 provides adequate authority for the State of North Dakota and the Department to carry out its SIP obligations with respect to the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS. The State receives section 103 and 105 grant funds through its Performance Partnership Grant from EPA along with required state matching funds to provide funding necessary to carry out North Dakota's SIP requirements. North Dakota's resources meet the requirements of CAA section 110(a)(2)(E).

With respect to section 110(a)(2)(E)(iii), the regulations cited by North Dakota in their certifications and verified through additional communication 11 (NDCC 23-25-02(01), 33-15-04-02, 23-01-05(02), 23-25-03(5), and 23-25-10) and contained within this docket also provide the necessary assurances that the State has responsibility for adequate implementation of SIP provisions by local governments. Therefore, we propose to approve North Dakota's SIP as meeting the requirements of section 110(a)(2)(E)(i) and (E)(iii) for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS.

b. Sub-element (ii): State boards.

Section 110(a)(2)(E)(ii) requires each state's SIP to contain provisions that comply with the requirements of section 128 of the CAA. That provision contains two explicit requirements: (i) That any board or body which approves permits or enforcement orders under the CAA shall have at least a majority of members who represent the public interest and do not derive a significant portion of their income from persons subject to such permits and enforcement orders; and (ii) that any potential conflicts of interest by members of such board or body or the head of an executive agency with similar powers be adequately disclosed.

On July 30, 2013 (78 FR 45866) EPA approved revised language in North Dakota's SIP, chapter 2, section 15, Respecting Boards to include provisions for addressing conflict of interest requirements. Details on how this portion of chapter 2, section 15 rules meet the requirements of section 128 are provided in our May 13, 2013 proposal notice (78 FR 27898). North Dakota's SIP continues to meet the requirements of section 110(a)(2)(E)(ii), and we propose to approve the infrastructure SIP for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS for this element.

7. Stationary source monitoring system: Section 110(a)(2)(F) requires: (i) The installation, maintenance, and replacement of equipment, and the implementation of other necessary steps, by owners or operators of stationary sources to monitor emissions from such sources; (ii) Periodic reports on the nature and amounts of emissions and emissions-related data from such sources; and (iii) Correlation of such reports by the state agency with any emission limitations or standards established pursuant to the Act, which reports shall be available at reasonable times for public inspection.

The North Dakota statutory provisions listed in the State's certifications (NDCC 23-25-03) and contained within this docket provide authority to establish a program for measurement and testing of sources, including requirements for sampling and testing. North Dakota's SIP-approved minor source and PSD programs provide for monitoring, recordkeeping, and reporting requirements for sources subject to minor and major source permitting. The State cites several regulations (NDAC 33-15-14-02.9, 33-15-14-03.6, 33-15-14-06.5 and contained within this docket) requiring monitoring of emissions from stationary sources, recordkeeping and reporting of emissions, and monitoring date. Source surveillance is also addressed in Chapter 8 of the SIP. This chapter provides for the permitting of sources, inspection of the sources, recordkeeping and reporting by sources, and compliance determinations. Section 8.2 of the SIP commits the Department to the correlation of data with the applicable requirements. All reports are available for public inspection in accordance with NDAC 33-15-01-16.1.

Additionally, North Dakota is required to submit emissions data to the EPA for purposes of the National Emissions Inventory (NEI). The NEI is the EPA's central repository for air emissions data. The 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 the EPA's online Emissions Inventory System. States report emissions data for the six criteria pollutants and their associated precursors—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 Dakota made its latest update to the NEI on October 23, 2014. 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.

Based on the analysis above, we propose to approve the North Dakota SIP as meeting the requirements of CAA section 110(a)(2)(F) for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS.

8. Emergency powers: Section 110(a)(2)(G) of the CAA requires infrastructure SIPs to “provide for authority comparable to that in [CAA section 303] and adequate contingency plans to implement such authority.”

Under CAA section 303, the EPA Administrator has authority to bring suit to immediately restrain an air pollution source that presents an imminent and substantial endangerment to public health or welfare, or the environment.12 If such action may not practicably assure prompt protection, then the Administrator has authority to issue temporary administrative orders to protect the public health or welfare, or the environment, and such orders can be extended if EPA subsequently files a civil suit.

Chapter 23-25 of the NDCC provides relevant language and authority for “Air Pollution Control.” The purpose of this chapter is “to achieve and maintain the best air quality possible” and to “protect human health, welfare and property, [and] prevent injury to plant and animal life” (NDCC 23-25-01(2)). NDCC 23-25-01 defines “air pollution” as “the presence in the outdoor atmosphere of one or more air contaminants in such quantities and duration as is or may be injurious to human health, welfare, or property, animal or plant life, or which unreasonably interferes with the enjoyment of life or property.” As such, the chapter aims to protect all three areas required by section 303; human health, welfare, and environment. The “Air Pollution Control” chapter provides general grants of authority to maintain actions in certain situations. We find these grants provide comparable authority to that provided in Section 303. Furthermore, the NDAC 33-15-01-15(1) makes it unlawful to “permit or cause air pollution” as defined in NDCC 23-25-01. A person causing or contributing to emissions that endanger public health, welfare, or the environment, would be causing “air pollution” within the meaning of North Dakota law, and would therefore be in violation of NDAC 33-15-01-15(1). This could occur in either an emergency or non-emergency situation.13

NDCC 23-25-10(5) provides that “the department has the authority to maintain an action in the name of the state against any person to enjoin any threatened or continuing violation of any provision of this chapter or any permit condition, rule, order, limitation, or other applicable requirement implementing this chapter.” Under NDCC 23-25-10(5), the Department has the authority to bring an action to enjoin a violation of NDCC 23-25 or its rules. The Department may seek a court order to restrain a source from causing or contributing to emissions that endanger public health, welfare, or the environment. In an emergency, this may take the form of an injunction or temporary restraining order (see NDCC 32-06-02).14 Therefore, the NDDH has the authority to seek judicial actions during emergency situations.

North Dakota's statutes also provide the NDDH with the authority to issue administrative orders and emergency rules to protect the public health, welfare, and the environment under certain circumstances. NDCC 23-25-08, as cited in North Dakota's SIP submittals, authorizes that in the event of “an emergency requiring immediate action to protect the public health and safety,” the NDDH has the authority to “issue an order reciting the existence of such emergency and requiring that such action be taken as is necessary” to meet the emergency. The emergency order is effective immediately. Any person who violates the order is subject to enforcement, penalties, and injunctions under NDCC 23-25-10.

Furthermore, as cited in North Dakota's SIP submittals, the NDDH has the authority to “use an emergency adjudicative proceeding, in its discretion, in an emergency situation involving imminent peril to the public health, safety, or welfare” (NDCC 28-32-32). Accordingly, “in an emergency, the administrative agency may take action pursuant to a specific statute as is necessary to prevent or avoid imminent peril to the public health, safety, or welfare” (NDCC-28-32-32.1). In the absence of a specific statute requiring other administrative action, “the administrative agency shall issue an order” (NDCC 28-32-32(4)).

Further supplemental authority is found in a broad provision, cited by the State in their SIP submittals, granting additional authority to the NDDH. The NDDH has the authority to “[i]ssue such orders as may be necessary to effectuate the purposes” of the “Air Pollution Control” chapter NDCC 23-25-03.5. These orders can be enforced “by all appropriate administrative and judicial procedures” (NDCC 23-25-03.5). Thus, this broad grant of authority includes the authority to issue administrative orders during air pollution emergencies which would disrupt protection of human health, welfare, and animal and plant life.

The combination of NDCC and NDAC provisions discussed above provide for authority comparable to section 303 to immediately bring suit to restrain, issue emergency orders against, and use special rule adoption procedures for applicable emergencies to take prompt administrative action against, any person causing or contributing to air pollution that presents an imminent and substantial endangerment to public health or welfare, or the environment. We propose that they are sufficient to meet the authority requirement of CAA section 110(a)(2)(G).

States must also have adequate contingency plans adopted into their SIP to implement the air agency's emergency episode authority (as discussed above). This can be done by submitting a plan that meets the applicable requirements of 40 CFR part 51, subpart H for the relevant NAAQS if the NAAQS is covered by those regulations.

Subpart H of 40 CFR part 51 requires states to classify regions and to develop contingency plans (also known as emergency episode plans) after ambient concentrations of certain criteria pollutants in an area have exceeded specified levels. For example, if ambient concentrations of nitrogen dioxide in an area have exceeded 0.06 ppm (annual arithmetic mean), then the area is classified as a Priority I region, and the state must develop a contingency plan that meets the requirements of sections 51.151 and 51.152. North Dakota has not monitored any values above the priority cut point for ozone or NO2.

Prevention of air pollution emergency episodes is addressed in Section 5 of North Dakota's SIP and was approved on May 31, 1972 (37 FR 10842). We find that North Dakota's air pollution emergency provisions establish stages of episode criteria (Section 5.2), provide for public announcement whenever any episode stage has been determined to exist (Section 5.3), and specify emission control actions to be taken at each episode stage (Section 5.5) consistent with the EPA emergency episode SIP requirements set forth at 40 CFR part 51, subpart H (prevention of air pollution emergency episode) for ozone and NO2.

As noted in the October 14, 2011 guidance,15 based on EPA's experience to date with the Pb NAAQS and designating Pb nonattainment areas, EPA expects that an emergency episode associated with Pb emissions would be unlikely and, if it were to occur, would be the result of a malfunction or other emergency situation at a relatively large source of Pb. Accordingly, EPA believes the central components of a contingency plan would be to reduce emissions from the source at issue and communicate with the public as needed. We note that 40 CFR part 51, subpart H (51.150-51.152) and 40 CFR part 51, Appendix L do not apply to Pb.

Based on the above analysis, we propose approval of North Dakota's SIP as meeting the requirements of CAA section 110(a)(2)(G) for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS.

9. Future SIP revisions: Section 110(a)(2)(H) requires that SIPs provide for revision of such plan: (i) From time to time as may be necessary to take account of revisions of such national primary or secondary ambient air quality standard or the availability of improved or more expeditious methods of attaining such standard; and (ii), except as provided in paragraph (3)(C), whenever the Administrator finds on the basis of information available to the Administrator that the SIP is substantially inadequate to attain the NAAQS which it implements or to otherwise comply with any additional requirements under this [Act].

EPA approved relevant sections of the North Dakota SIP on September 17, 2012 (77 FR 57029). North Dakota's statutory provision at NDCC 23-25-03 provides adequate authority for the Department to carry out such revisions. Therefore, we propose to approve North Dakota's SIP as meeting the requirements of CAA section 110(a)(2)(H).

10. Consultation with government officials, public notification, PSD and visibility protection: Section 110(a)(2)(J) requires that each SIP “meet the applicable requirements of section 121 of this title (relating to consultation), section 127 of this title (relating to public notification), and part C of this subchapter (relating to PSD of air quality and visibility protection).”

The State has demonstrated it has the authority and rules in place through its certifications (contained within this docket) to provide a process of consultation with general purpose local governments, designated organizations of elected officials of local governments and any Federal Land Manager having authority over federal land to which the SIP applies, consistent with the requirements of CAA section 121. Furthermore, EPA previously addressed the requirements of CAA section 127 for the North Dakota SIP and determined public notification requirements are appropriate (45 FR 53475, Aug. 12, 1980).

As discussed above, the State has a SIP-approved PSD program that incorporates by reference the federal program at 40 CFR 52.21. EPA has further evaluated North Dakota's SIP approved PSD program in this proposed action under element (C) and determined the State has satisfied the requirements of element 110(a)(2)(C), as noted above. Therefore, the State has also satisfied the requirements of element 110(a)(2)(J).

Finally, with regard to the applicable requirements for visibility protection, EPA recognizes states are subject to visibility and regional haze program requirements under part C of the Act. 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, we find that there are no applicable visibility requirements under section 110(a)(2)(J) when a new NAAQS becomes effective.

Based on the above analysis, we propose to approve the North Dakota SIP as meeting the requirements of CAA section 110(a)(2)(J) for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS.

11. Air quality and modeling/data: Section 110(a)(2)(K) requires each SIP provide for: (i) The performance of such air quality modeling as the Administrator may prescribe for the purpose of predicting the effect on ambient air quality of any emissions of any air pollutant for which the Administrator has established a NAAQS; and (ii) the submission, upon request, of data related to such air quality modeling to the Administrator.

North Dakota's PSD program requires estimates of ambient air concentrations be based on applicable air quality models specified in Appendix W of 40 CFR part 51, and incorporates by reference the provisions at 40 CFR 52.21(I)(2) requiring that modification or substitution of a model specified in Appendix W must be approved by the Administrator. Section 7.7, Air Quality Modeling, of North Dakota's SIP commits the Department to performing air quality modeling to predict the impact of a source on air quality, and providing data to EPA upon request. As a result, the SIP provides for such air quality modeling as the Administrator has prescribed. Therefore, we propose to approve the North Dakota SIP as meeting the CAA section 110(a)(2)(K) for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS.

12. Permitting fees: Section 110(a)(2)(L) requires the owner or operator of each major stationary source to pay to the permitting authority, as a condition of any permit required under this act, a fee sufficient to cover: (i) The reasonable costs of reviewing and acting upon any application for such a permit; and (ii) if the owner or operator receives a permit for such source, the reasonable costs of implementing and enforcing the terms and conditions of any such permit (not including any court costs or other costs associated with any enforcement action), until such fee requirement is superseded with respect to such sources by the Administrator's approval of a fee program under title V.

The State cites the SIP approved fee provisions for construction permits (NDAC 33-15-23-02 approved at 62 FR 19224, April 21, 1997), which include costs of processing not covered by the application fee. We also note that all the State SIPs we are proposing to approve in this action cite the regulation that provides for collection of permitting fees under North Dakota's approved title V permit program (64 FR 32433, June 17, 1999). As discussed in that approval, the State demonstrated that the fees collected were sufficient to administer the program.

Therefore, based on the State's experience in relying on the funds collected through application and processing fees at NDAC 33-15-23, and the use of title V fees to implement and enforce PSD permits once they are incorporated into title V permits, we propose to approve the submissions as supplemented by the State for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS.

13. Consultation/participation by affected local entities: Section 110(a)(2)(M) requires states to provide for consultation and participation in SIP development by local political subdivisions affected by the SIP.

The statutory provisions cited in North Dakota's SIP submittals (NDCC 23-25-03 and 23-25-02, contained within this docket) meet the requirements of CAA section 110(a)(2)(M), so we propose to approve North Dakota's SIP as meeting these requirements for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS.

In this action, EPA is proposing to approve the following infrastructure elements for the 2008 Pb, 2008 ozone, and 2010 NO2 NAAQS: (A), (B), (C) with respect to minor NSR and PSD requirements, (D)(i)(II) elements 3 and 4, (D)(ii), (E), (F), (G), (H), (J), (K), (L), and (M). EPA proposes to approve element 4 of 110(a)(2)(D)(i)(II) for the 2006 PM2.5 NAAQS. Finally, EPA proposes approval of D(i)(I) elements 1 and 2 for the 2008 Pb, and 2010 NO2 NAAQS. EPA will act separately on infrastructure element (D)(i)(I), interstate transport, for the 2008 ozone NAAQS.

Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable federal regulations (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 some state law as meeting federal requirements and disapproves other state law because it does not meet federal requirements; this proposed action 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, Oct. 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, Aug. 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, Feb. 16, 1994).

The SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).

An EFV is a mechanical safety device installed inside the natural gas service line between the street and residential meter. The EFV will “trip or close” if there is sufficient damage to the line to minimize the flow of gas through the line and thus, the amount of gas that escapes into the atmosphere. During normal use, the valve is kept pushed open against oncoming gas flow by a spring. EFVs are designed so that general usage, such as turning on appliances, will not shut the valve. However, during a significant increase in the flow of gas (e.g., due to a damaged line), the spring cannot overcome the force of gas, and the valve will close and stay closed until the correct pressure is restored. When the correct pressure is restored, the EFV automatically resets itself.

On July 7, 1998, in South Riding, Virginia, a residential gas explosion resulted in one death and three injuries. It is not known if the explosion occurred on a branched or non-branched service line servicing an SFR; however, PHMSA believes that this proposed rule or its previous rule requiring EFVs on single lines serving SFRs would have mitigated the consequences of the explosion. An investigation by the National Transportation Safety Board (NTSB) found the explosion likely would not have occurred if an EFV had been installed for this single-family home. Similarly, PHMSA strongly believes this incident would have likely been would have been mitigated at a minimum. As a result, on June 22, 2001, the NTSB issued Safety Recommendation P-01-2, recommending that PHMSA require excess flow valves in all new and renewed gas service lines, regardless of a customer's classification, when the operating conditions are compatible with readily available valves.

In December of 2005, the “Integrity Management for Gas Distribution: Report of Phase I Investigations,” 1 developed by a multi-stakeholder group, was published. In the report, the stakeholder group recommended that “[A]s part of its distribution integrity management plan, an operator should consider the mitigative value of excess flow valves (EFVs). EFVs meeting performance criteria in § 192.381 and installed in accordance with § 192.383 may reduce the need for other mitigation options.”

In an effort to study the possible benefits of expanding EFVs beyond SFR applications, PHMSA began development of the Interim Evaluation in early 2009. In June and August of 2009, PHMSA held public meetings on NTSB Recommendation P-01-2.

The meeting participants included the National Association of Regulatory Utility Commissioners, the National Association of Pipeline Safety Representatives, the International Association of Fire Chiefs, the National Association of State Fire Marshals, natural gas distribution operators, trade associations, manufacturers, and the Pipeline Safety Trust. As a result of these meetings, PHMSA issued a report titled: “Interim Evaluation: NTSB Recommendation P-01-2 Excess Flow Valves in Applications Other Than Service Lines Serving One SFR”).2

On December 4, 2009, PHMSA amended the pipeline safety regulations to require the use of EFVs for new or replaced gas lines servicing SFRs.3 While this requirement met the mandate of the Pipeline Inspection, Protection, Enforcement and Safety Act (PIPES Act) enacted in 2006, distribution lines, including those that serve branched SFRs, apartment buildings, other multi-residential dwellings, commercial properties, and industrial service lines, are still not required to use EFVs. These structures are susceptible to the same risks as SFR service lines. PHMSA, already aware of this risk, was awaiting completion of the Interim Evaluation, which studied the possible expansion of EFVs beyond SFRs and the challenges of application. The Interim Evaluation also addressed other practical alternatives such as the use of manual isolation devices, such as curb valves. The evaluation identified challenges related to the feasibility and practicality of the proposed solutions, as well as significant cost factors and benefit factors. The evaluation found that there are no other devices or viable options to shut off gas supply quickly when gas services line ruptures.

On November 25, 2011, PHMSA published an Advance Notice of Proposed Rulemaking (ANPRM) (76 FR 72666) asking the public to comment on the findings of the Interim Evaluation and issues relating to the expanded use of EFVs in gas distribution systems. PHMSA also sought comments from gas distribution operators on their experiences using EFVs, including:

• Technical challenges of installing EFVs on services other than SFRs;

• Categories of service to be considered for expanded EFV use;

• Cost factors;

• Data analysis in the Interim Evaluation;

• Technical standards for EFV devices; and

• Potential safety and societal benefits, small business and environmental impacts, and costs of modifying the existing regulatory requirements.

In 2012, the President signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which requires PHMSA to study the possibility of expanding the use of EFVs beyond SFRs and issue a final report on the evaluation of the NTSB's recommendation on excess flow valves within 2 years after enactment of the Act. PHMSA is also mandated to, if appropriate, issue regulations requiring the use of EFVs or equivalent technology, where “economically, technically and operationally feasible”, for new or entirely replaced distribution branch services, multi-family lines, and small commercial service lines. PHMSA has determined for the purpose of this proposed rule, based on the study, that the safety benefits of expanding EFVs justify the cost and is appropriate. The only proposed exceptions are for large apartment buildings, industrial or commercial users for whom EFVs may not be practical due to inherent design complexity, continuous supply demands and/or contamination issues. Additionally, PHMSA is proposing that services exceeding 1,000 SFCH install curb valves on new or replaced gas service lines.

The proposed required use of curb valves for large commercial (greater than 1,000 SFCH) goes beyond the Section 22 language of the Pipeline Safety, Job Creation, and Regulatory Certainty Act of 2011, however it is based on ANPRM comments received from industry, trade associations and other stakeholders. PHMSA and industry in general believe that EFVs are not suitable larger commercial facilities over 1,000 SFCH. Curb valves are the best alternative to an EFV and provide an effective added level of safety for these facilities. These valves also are a feasible alternative based on the cost/benefit analyses.

PHMSA's authority for regulating natural gas pipelines was first established by the Natural Gas Pipeline Safety Act of 1968, Public Law 90-481, and has since been enlarged by additional legislation. The Pipeline Safety Laws specifically delegate authority to DOT to develop, prescribe, and enforce minimum Federal safety standards for the transportation of natural gas. PHMSA has used this statutory authority to promulgate comprehensive minimum safety standards. While the 2011 Act specifically directed PHMSA to require the installation of EFVs on new and replaced branched lines serving SFRs, multi-family and small commercial facilities, DOT's underlying prior statutory authority under 49 U.S.C. 60104 provides PHMSA with the authority to require the installation of curb valves for large commercial facilities.

In the time since the 1998 incident in South Riding, Virginia, the NTSB has investigated an additional 8 incidents, which resulted in 10 fatalities that could have possibly been averted if an EFV had been in place. The most recent incident occurred on November 23, 2012, when a gas pipeline exploded in Springfield, Massachusetts. The Springfield explosion injured 21 people and damaged more than 40 buildings. It is important also to note that this incident occurred on the day after Thanksgiving and the daycare adjacent to the explosion was closed. If the daycare would have been open, it is highly likely this incident would have resulted in even more losses. This incident is currently under investigation by the NTSB. All eight of these incidents occurred on lines that would be affected by this rulemaking.

Nineteen organizations and individuals submitted comments in response to the ANPRM. The individual docket item numbers are listed for each comment.

• Northeast Gas Association (NGA) (PHMSA-2011-0009-0012).

• Texas Pipeline Association (TPA) (PHMSA-2011-0009-0016).

• American Gas Association (AGA) (PHMSA-2011-0009-0023).

• American Public Gas Association (APGA) (PHMSA-2011-0009-0024).

• MidAmerican Energy Company (MAE) (PHMSA-2011-0009-0011).

• Avista Utilities (AU) (PHMSA-2011-0009-0013).

• Southwest Gas Corporation (SWC) (PHMSA-2011-0009-0015).

• National Grid (NG) (PHMSA-2011-0009-0022) (Supported AGA comments).

• Laclede Gas (LG) (PHMSA-2011-0009-0018) (Supported AGA comments).

• Kansas Gas Service (KGS) (PHMSA-2011-0009-0017).

• Nicor Gas (PHMSA-2011-0009-0014).

• City of Ellensburg, Washington (PHMSA-2011-0009-0004).

• NTSB (PHMSA-2011-0009-0009).

• Iowa Utilities Board (IUB) (PHMSA-2011-0009-0020).

• R.W. Lyall (PHMSA-2011-0009-0021).

• Gas Breaker, Inc. (GBI) (PHMSA-2011-0009-0019).

• Rebecca Lee Roter (PHMSA-2011-0009-0006).

• Courtney D. Brown (PHMSA-2011-0009-0010).

• Anonymous (PHMSA-2011-0009-0008) (The anonymous commenter expressed concerns regarding pipeline safety versus job creation, corruption, and politics. These topics are beyond the scope of this NPRM and are not discussed further.)

PHMSA reviewed all of the comments received in response to the ANPRM. The comments received from the trade associations largely supported expanded EFV use with certain limitations. The operators that responded with comments raised some concerns with expanded EFV use generally related to logistics and implementation. Municipality comments reflected a concern that State laws already in place could conflict with any new Federal requirements. The NTSB expressed strong approval of the expanded EFV use. The comments submitted are discussed below in the same order as presented in the questions from the ANPRM.

The ANPRM solicited feedback and comments regarding whether the Interim Evaluation fairly and accurately explained the challenges of expanded EFV use. These challenges, identified in the Interim Evaluation from a variety of stakeholders, may limit or exclude future EFV expansion beyond SFR applications due to safety reasons. The challenges included changing gas-usage patterns, snap loads (i.e. loads that lead to false closures), business-critical gas supply applications, system configurations, pressure ratings, and the sizes of commercially available EFVs. Among the challenges discussed by the commenters, snap loads (loads that lead to false closures), load variation, and proper EFV sizing seemed to be of the greatest concern.

Overall, industry, trade association, government, and municipality commenters agreed that the Interim Evaluation failed to accurately and fully portray a variety of the technical and operational challenges and costs and benefits associated with expanded EFV requirements. These commenters either stated the report was lacking in certain areas or did not comment. In general, commenters, including AGA and APGA, strongly cautioned against the broad expansion of EFV requirements beyond those for SFRs, citing operators' lack of experience and design complexities. Specifically, APGA, SWC, AGA, LG, NG, AU, TPA, IUB, NGA, and MAE all found the Interim Evaluation's discussion of the challenges of proper EFV sizing protocols, system configuration, and changes in gas-usage patterns to be inadequate and to contain false assumptions. Due to these concerns, MAE suggested that any EFV requirements should only affect new installations. Likewise, AGA supported the installation of EFVs on new and entirely replaced service lines in the following applications only:

• Service lines to SFRs;

• SFR service lines and branched SFR service lines installed at the same time;

• A branched SFR service line branching off an existing SFR service line that does not contain an EFV provided there is sufficient line capacity;

• A branched SFR service line branching off an existing SFR service line that contains an EFV sized appropriately for both customers provided there is sufficient line capacity;

• Multi-family installations, including duplexes, triplexes, and fourplexes, with individual meter sets, a known customer load (based on meter capacity) not exceeding 1,000 standard cubic feet per hour (SCFH), and a load that is not expected to increase over time; and

• Small commercial customers with a known customer load (based on meter capacity) not exceeding 1,000 SCFH through a single service line and where the load is not expected to increase over time.

AU, KGS, APGA, SWC, GBI, AGA, and the City of Ellensburg, WA, were concerned with the challenges of snap loads and the loss of continuous supply. Snap loads may occur when the amount of natural gas required to meet demand suddenly increases, which is generally due to many appliances being turned on at one time. GBI, AU, and AGA suggested that requiring EFVs for lines not exceeding 1,000 SCFH based on meter size is reasonable, but the false closure and load variation challenges make using EFVs for applications that exceed 1,000 SCFH difficult. AU specifically stated that the failure (false closure or malfunction) of EFVs at high loads during winter frost is difficult to mitigate and is an inconvenience to customers who lose service. AU stated that winter frost makes pipeline excavation to repair lines difficult due to frozen soil. SWC commented that business disruptions and loss of service in vital areas such as high-occupancy dwellings created a safety hazard. KGS recommended that service lines serving multiple customers should not use a single EFV due to the increased degree of variation in the gas flow rates.

PHMSA received different approaches from commenters regarding the proper selection of an EFV for a pipeline, or what is referred to in the Interim Evaluation as “EFV sizing”. The trip point is the specific point in which the EFV “trips”, or closes, the valve due to gas pressure differential and is essentially the factor that guides the size selection of an EFV. In the Interim Evaluation, PHMSA suggested an EFV's trip point should be less than, but close to, the flow rate of a complete line rupture.

Commenters indicated that PHMSA's approach for trip point selection either led to tripping too easily or not at all. R.W. Lyall, an EFV manufacturer, further submitted that EFVs should be sized so that the EFV trip point, at the minimum system pressure, is above the maximum anticipated load and is above meter capacity. GBI suggested an EFV should be selected that operates at least 1.5 times the meter rating at the minimum design inlet pressure. Finally, SWC and NGA specifically commented that, due to the complexity of design found in multi-family industrial and commercial service lines, a common approach for sizing is not possible. With regard to the challenges of commercially available EFVs, PHMSA received two comments. GBI, an EFV manufacturer, commented that the commercial availability for most applications, even those considered large, is not a problem. In contrast, MAE stated that the commercial availability of EFVs for non-residential load profiles is an assumption made on the part of PHMSA that may be inaccurate.

A number of the comments PHMSA received focused on a concern that EFVs could trip inadvertently and may cause unnecessary service disruptions. PHMSA agrees that variations in the configuration of service lines make it difficult to impose specific sizing requirements for various types of service lines and customers. However, if an operator installs an EFV and operates it in accordance with a manufacturer's specifications, the EFV should operate safely without the need for a prescriptive sizing requirement even when customer gas usage changes, unless the change were so large as to require a new service line.

Overall, PHMSA disagrees with the comments that EFVs are prone to failure and inadvertent tripping due to variations in gas flow, location, etc. Research and available data has shown very few failures with EFVs in actual usage. Operators in the United States have gained considerable experience with EFVs since 1999 mainly with SFRs. The NRRI conducted a survey on EFV installation and operators' experiences with EFVs installed on single family residential service lines found of 2.5 million EFVs installed on SFRs only 223 failed.4 In Europe, BEGAS, the government owned gas company in Eastern Austria, reported that EFVs have been installed since 1993 on service lines to hospitals, large facilities, production plants, etc. Out of 26,000 BEGAS installations there have been no spurious failures.5 PHMSA maintains proper operator installation using manufacture direction and maintenance of EFVs is paramount to their success. Therefore, PHMSA is not proposing a protocol for EFV installation. PHMSA is only advising operators to install EFVs as the manufacturer directs and the service safely requires.

Operators and manufacturers that PHMSA contacted stated they typically size an EFV in such a way that it trips at 20% to 30% above the maximum service load it will encounter. It is possible that this trip point could be too high for small leaks, however, EFVs are intended to react to ruptures, not small holes.

Likewise, one commenter mentioned winter time excavation of lines to repair them due to EFV failure was a concern. PHMSA suggests that digging in frozen ground in winter is not any more difficult than digging concrete or curbside if valve is located underneath. Again, PHMSA believes, proper sizing of an EFV is the key to avoiding all these issues. PHMSA has surveyed twice in the past, and there were only one or two instances of EFV failure in greater than a million services over many years. All major EFV manufacturers PHMSA contacted indicated that they are available to help operators to properly size their valves.

PHMSA received no information to indicate that pressure ratings and/or the size of commercially available EFVs are a problem for the expansion of EFVs to certain other types of service. Currently, the normal minimum pressure design (the minimum anticipated design pressure) is 10 psig. The maximum pressure of composite materials (250 psig), plastic (125 psig), and steel (1,000 psig and up), does not pose a problem. There is no pressure limit on an EFV's performance except that, when activated, the EFV seat must be able to withstand the pressure. The pressure limit is normally constrained by the design of the carrier pipe. EFVs covered by ASTM F2138 must have a maximum inlet pressure of at least 125 psig, while ASTM F1802 applies to EFVs with a pressure rating of up to 125 psig. However, for very high-volume EFV applications, such as those for industrial customers, technical standards may need to address operating design pressures that exceed 125 psig.

Therefore, PHMSA proposes to expand EFV applications to new or replaced service lines for SFRs with branched lines; multi-family installations, including duplexes, triplexes, and fourplexes with individual meter sets and known customer loads not exceeding 1,000 SCFH; and small commercial customers with known loads not exceeding 1,000 SCFH. EFVs will not be required in the above-mentioned applications if one of the existing § 192.383 exceptions is present.

While the proposed expansion of EFVs would have costs, PHMSA believes the costs are justified by the added protection for gas customers, as the only proposed exceptions are for large apartment buildings, industrial or commercial users for whom EFVs may not be practical due to inherent design complexity and continuous supply demands. In those situations (loads exceeding 1,000 SFCH), PHMSA believes curb valves will provide the best possible option for improved safety at this time. PHMSA does not have definitive data, but some commenters stated that 2% to 5% of customers would fall into one of the exceptions for EFVs, which would include many of those facilities over with loads exceeding 1,000 SFCH.

The ANPRM also solicited comments on whether additional challenges existed beyond those discussed in the Interim Evaluation. MAE commented that the addition of more EFVs in natural gas systems could create an increase in safety hazards resulting from the maintenance of failed EFVs and EFVs that fail to trip on small leaks (i.e., pinhole corrosion). These safety hazards would be due to increased excavation activities, which place more workers in high-traffic and congested areas. MAE also mentioned that excavation contractors may be less cautious around service lines if they believe they will not leak because of an installed EFV. TPA stated that the mandated use of EFVs for new or replaced transmission or gathering lines should not be pursued until further study is completed.

MAE's comment regarding excavation damage prevention can be addressed with proper EFV installation techniques and the normal course of training for pipeline operator personnel, including training on excavation damage prevention. Excavation contractors hired by operators go thru same damage prevention training as operators regarding safe digging practices and are aware of the dangers of gas leaks and explosions. In regard to TPA's comment, PHMSA agrees at this time and is proposing to expand EFV use only to distribution lines, not gathering or transmission lines. PHMSA has found that there is a lack of experience with EFVs on gathering and transmission lines in addition to problems with contaminants and other factors.

The ANPRM sought comments on the use of curb valves as an alternative to EFVs. Most commenters agreed that use of a curb valve is a viable alternative to EFV use in some cases. In fact, the City of Ellensburg, Washington, stated the installation of a curb valve should be considered by PHMSA to be equivalent to the installation of an EFV. The City of Ellensburg mentioned that current Washington State regulations require the use of a curb valve if an EFV is not installed.

MAE, APGA, and APA commented that operators have experience with curb valves, but their use presents certain challenges. The technical challenges expressed by commenters with regard to curb valve use include: Maintenance of the valve; location of the valve for accessibility; third-party damage to the valve; recordkeeping as to the location of the valve; ensuring the box does not place stress on the pipe; and the delayed shut-off response inherent in curb valve design during emergency situations. APGA commented that curb valves require trained personnel to manually close the valve with a special key. APGA further stated that “squeezing” off the gas in the line is sometimes quicker than using a curb valve for stopping the flow of gas.

Historically, curb valves have proven to be a very effective mechanism for interrupting the flow of gas in both routine maintenance situations and in emergencies. Other than a curb valves, distribution operators have tools (large pliers) to squeeze pipe to shut off gas supply. Curb valves require that a person make a conscious decision to physically close the valve itself, thereby avoiding inadvertent closures. Curb valves are slightly more expensive than EFVs and require some maintenance and need to be located in an accessible site. The primary disadvantage curb valves have is the time it can take to mobilize to the valve site and close the valve.

It is not technically feasible to expand EFV use to service lines operating at loads exceeding 1,000 SCFH. This is largely due to issues with reliable service, load fluctuation, the lack of experience with EFV usage in larger applications, and the complexity of design issues. Therefore, in the case of service lines operating at more than 1,000 SCFH, PHMSA proposes to require curb valves be installed and maintained in such a manner that emergency personnel can access them. Although it does not come at a prohibitive cost, the installation of curb valves is slightly more expensive than the installation of EFVs.

The ANPRM solicited comments concerning additional situations not found in the Interim Evaluation where the installation of an EFV may not be feasible or practical. AGA and SWC commented that they agreed with the examples cited in section 10.3.1 of the Interim Evaluation. MAE commented that lines containing contaminants, and distribution systems with a history of transporting liquids, may create situations where EFVs are impracticable.

Section 192.383 currently includes exceptions for EFV installations with regard to SFRs. With respect to MAE's concern regarding lines containing contaminants and distribution systems with a history of transporting liquids, the proposed exceptions would waive the EFV requirement for those systems for which installing EFVs would be impracticable. This proposed rule incorporates the existing § 192.383 exceptions in place and would extend them to the additional service line applications covered in this NPRM.

PHMSA requested comments on the potential costs of modifying the existing regulatory requirements. PHMSA requested that commenters provide information and supporting data on the potential quantifiable safety and societal benefits, the potential impacts on small businesses, and the potential environmental impacts of modifying the existing regulatory requirements. The economic analysis for the installation of EFVs on services other than SFRs involves challenges including the quantification and monetization of costs and benefits.

The ANPRM requested comments on section 10.3.2. of the Interim Evaluation. This section describes the “Categories of Services” in which PHMSA could expand EFV requirements. PHMSA sought input as to whether the categories accurately represented current “real world” applications and which categories are most likely to benefit from EFV expansion.6

AGA largely agreed with the categories of service presented in the Interim Evaluation, while MAE commented that the categories are sufficient for economic analysis only. MAE further states that if the rule in its final form creates different requirements among these five categories, the rule may prove difficult to implement because an operator may not be clear which category a service may fall into.

AGA, APGA, AU, Nicor, and SWC advised PHMSA not to apply the EFV requirements to all five categories named in the Interim Evaluation. Specifically, the commenters supported all categories of service with the exception of those with services requiring greater than 1,000 SCFH. Those services with 1,000 SCFH requirements or higher are generally sensitive to loss of supply and may have complex configurations not conducive to EFVs. Nicor, APGA, and AGA commented that service lines serving one multi-family building with one meter should be limited to duplexes, triplexes, and fourplexes with known loads not exceeding 1,000 SCFH, and that non-residential services to space and water heater customers should be limited to 1,000 SCFH due to possible snap loads. Additionally, AGA stated that there are factors to consider for applying EFVs to non-residential service lines such as commercial food sales, food service, and health care, and that these applications would require unique analysis. These service applications are susceptible to loss of service issues and frequently have complex designs. SWC likewise stated that EFVs work in applications not exceeding 1,000 SCFH. The industrial customer's category was mentioned by all those commenting on this question as a category not suitable for mandated EFV use due to unpredictable load changes over the life of the service and inherent design complexities.

PHMSA has reviewed the comments on the possible expansion of categories of gas services requiring EFVs. PHMSA proposes expansion of EFV use for only certain categories of service presented in the Interim Evaluation. Specifically, PHMSA proposes to expand EFV requirements to include:

• Branched SFR service lines off of existing SFR service lines that do not contain an EFV and have a known load not exceeding 1,000 SFCH based on meter capacity;

• SFR service lines and branched SFR service lines installed at the same time with a known load not exceeding 1,000 SFCH based on meter capacity;

• Branched SFR service lines off of existing SFR service lines with a known load not exceeding 1,000 SFCH based on meter capacity;

• Multi-family residences with individual meter sets and a known customer load not exceeding 1,000 standard cubic feet per hour (SCFH) based on meter capacity; and

• Small commercial customers with a known customer load (based on meter capacity) not exceeding 1,000 SCFH through a single service line.

Operators with services lines with loads exceeding 1,000 SCFH will be required to utilize curb valves. Since PHMSA has found commercial and industrial service lines often have complex designs and/or require constant reliable service requirements, PHMSA has decided that these categories of service are not good candidates for requiring EFV use. Often these services meet or exceed a demand for 1,000 SCFH. PHMSA therefore proposes the 1,000 SCFH threshold based on comments and PHMSA experience however we invite comment.

The ANPRM sought comments as to whether there are any other issues related to the costs associated with mandatory EFV or curb valve installation that should be considered aside from those mentioned in the Interim Evaluation. Both AGA and SWC noted that cleaning labor for EFVs on larger service lines, inadvertent trips and the subsequent loss of business for commercial customers and accidental environmental discharges are additional costs to the operator that PHSMA should consider. APGA commented that EFV installation costs for large-volume EFVs may be higher due to the fact there is less demand for them, and PHMSA should not assume the same unit price as a SFR EFV. Both NGA and Nicor mentioned that installation of EFVs may conflict with restrictions placed by local jurisdictions on excavating paved roads to access existing or install new EFVs.

PHMSA has determined that installing EFVs by using manufacturer guidelines should eliminate most EFV tripping errors. EFVs are commercially available in a wide variety of pipe sizes. Some manufacturers report that they make EFVs for larger than 2-inch IPS (Iron Pipe Size) diameters (typical SFR size), and at least one manufacturer is developing a 10,000 SCFH EFV. The principles of operation remain the same as valve size and trip point increase, making EFVs for larger loads and pipe sizes technically feasible. PHMSA also noted that SFR installation of EFVs, which began in 2010, depended on manufacturer guidelines for installation. No PHMSA guidance was issued. Since 2010 the SFR EFVs required to be installed have resulted in no false trips or failures if installed as manufacturer directed. PHMSA has found manufacture guidelines to be well within the safety margin and they know their product better than PHMSA in most instances.

Additional costs for purging lines are minimal as documented by AGA estimates. AGA states many operators either have already installed EFVs on some services beyond SFRs or are planning to start. The price per unit has decreased in recent years given the development, improved availability, and quality of EFVs. Higher installation costs for high volume EFVs have been taken into account in the cost/benefit analysis through the averaged cost. Similarly, installation costs for curb valves are more expensive than smaller volume EFVs and the cost/benefit analysis considered that aspect.

PHMSA sought comments as to who should pay for the costs of installation and maintenance of EFVs. Comments were received from AGA, SWC, and MAE concerning who should be expected to pay for the installation and maintenance of EFVs or other alternatives if applicable regulatory requirements were implemented. MAE stated that operators should pay for the initial installation of valves, but any changes to customer loads requiring EFV installation should be at the customer's expense.

Because operators would already be newly installing or replacing pipelines, i.e. they would already have a trench open and be in place to work at the site, the addition of an EFV adds only minor costs (PHMSA estimates the cost of an EFV including installation is $30). This is supported by the AGA response to the excess flow valve census (Docket PHMSA-2012-0086, page 2), in which AGA indicated “the incremental cost per installation of EFVs is relatively minimal.” AGA further committed to expand the installation of EFVs beyond SFR services by June 2013. This also supports the notion that cost is not a major factor for the expansion of EFV use on new and fully replaced service lines beyond SFRs as proposed by this NPRM. PHMSA additionally utilized ANPRM comments which included numerical data on the costs for EFVs provided by operators as well as PHMSA Technical Advisory Committee 7 input for this proposed rulemaking.

The ANPRM sought comment as to any opportunity costs and installation timelines that EFVs or alternatives may require. AGA, APGA, SWC, MAE, and Nicor commented on this question. These commenters all mentioned the loss of gas supply as a potential opportunity loss for customers due to the longer period of time needed to install an EFV on larger service lines. Additionally, the operators would spend more time and resources installing EFVs or alternatives versus maintenance, construction, operation, and inspection activities. APGA responded that EFVs do not need to be installed at any particular time of day, with most installations occurring during normal business hours.

Given industry's commitment to support EFV installation on new and fully replaced service lines where practically and technically feasible, PHMSA believes that the cost of installation of EFVs, as proposed by the regulation, are sufficiently low that they will not interfere with other operator expenditures. PHMSA agrees with industry that the incremental cost per installation is minimal and would be utilized during the new construction or the replacement of service lines when industry resources (labor) are already at the installation sites.

PHMSA asked for comments concerning any other issues that had not yet been considered regarding benefits associated with mandatory EFV or curb valve installation. IUB, NGA, MAE, and AGA commented on additional cost/benefit factors that had not yet been considered. NGA stated that upgrading existing EFVs to meet the increased demand loads will add significant costs to customers and will conflict with restrictions placed by local jurisdictions on excavating paved roads to access existing or install new EFVs. Similarly, MAE stated that load changes due to changes in ownership may cause extra expenses from service modifications and industrial process equipment damage. AGA and SWC were unaware of any additional cost/benefit factors other than those in the Interim Evaluation.

In terms of the methods PHMSA used in the Interim Evaluation to study EFV expansion, the comments were generally supportive. MAE, SWC, APGA, and AGA commented that they typically agreed with the methodology used by PHMSA. However, some trade association comments also indicated there was some concern about the assumptions PHMSA made with its methodology. In particular, there were concerns with the “incidents averted calculation,” including the associated root cause analyses and assumed continued operations of all lines over 10 psi. AGA further commented that the analysis could not draw reliable conclusions. IUB suggested PHMSA should develop a separate analysis for each of the classes of service.

PHMSA's analysis was based on incident-specific data, which were obtained from the incident reports submitted by operators. PHMSA explained how it used the data, including the assumptions it made in applying the operational and other data obtained from incident reports, to filter past incidents that would likely not have been averted or mitigated had an EFV been installed. The remaining candidate incidents might have been averted or mitigated had an EFV been installed, but PHMSA did not conclusively assert that all of those candidate incidents definitively would have been averted or mitigated. However, based on the analysis of the best available data, PHMSA is convinced that the installation of EFVs on additional service lines could help avert or mitigate future incidents. The candidate incidents, incidents that PHMSA can classify as preventable by EFV installation, represent the scope of incidents that might have benefited from an EFV during the time period studied. PHMSA requests comments on whether the incidents that PHMSA has identified are likely to have been averted or mitigated if an EFV or manual service line shut-off valve had been in place. In addition, PHMSA does not have an EFV sizing protocol, nor was one proposed in the Interim Evaluation. The methodology for sizing EFVs was one of the challenges described in section 9.1 of the Interim Evaluation.

The OMB circular A-119, “Federal Participation in the Development and Use of Voluntary Consensus Standards in Conformity Assessment Activities,” directs Federal agencies to utilize voluntary standards, both domestic and international, whenever feasible and consistent with law and regulation. The current regulation at 49 CFR 192.381 only requires EFVs to be manufactured and tested by the manufacturer according to an industry specification or the manufacturer's written specification. The regulation does not prescribe a precise specification. PHMSA solicited comments as to the need for the adoption of consensus standards for EFV specification.

The comments received by PHMSA largely indicated that the incorporation by reference of any standards for EFVs is not necessary. AGA, supported by MAE, stated in their comments that manufacturers already construct and test EFVs according to industry consensus standards MSS SP-115-2006, ASTM F-1802, and ASTM F-2138. Operators have been successfully installing EFVs using manufacturer guidance with no known safety issues arising. Similarly, AGA and SWC expressed concern regarding the incorporation by reference of any industry standards due to the delay in updating the pipeline safety statutes, which in turn would prevent the timely installation of the newest and best EFVs on the market. As an alternative to PHMSA incorporating standards, commenters suggested that PHMSA continue to allow operators to utilize manufacturer installation guidance already available.

PHMSA will not be incorporating any new standards by reference for EFVs into the pipeline statutes at this time but may do so in the future. All EFVs currently available have been manufactured and tested to current consensus standards. Additionally, PHMSA has not incorporated any standards for EFVs into the pipeline safety regulations for SFRs and has not found any issues with that approach. If the need for incorporation by reference does become necessary, PHMSA will review the issue.

PHMSA also asked for comments on three current consensus standards and if there are alternatives to them. APGA and APA stated they were unaware of additional standards beyond those listed in the Interim Evaluation, with the exception of “MSS SP-142-2012 Excess Flow Valve for fuel gas service, NPS 1 1/2 through 12” for larger sized EFVs. Similarly, MAE, deferring to AGA comments, stated it was aware of no other standards except for the Gas Piping Technology Committee (GPTC) Appendix G192-8 in the Z380 Guide.

PHMSA is also unaware of any alternatives to the three standards listed in the Interim Evaluation for EFVs for natural gas service. As for selection and sizing guidelines, PHMSA will request GPTC to develop comprehensive standards for selection, installation, and performance testing of EFVs for a variety of design considerations and service line configurations and operating conditions. This guidance will be in addition to guidance provided by manufacturers and will act as a supplement to address various situations which may not be elaborated on in manufacturer guidance. PHMSA will also issue advisory bulletins if we become aware of new conditions of concern for EFV installation.

PHMSA asked for comments as to whether EFV guidelines or technical standards are in need of development, and if so, why. Both MAE and SWC commented that a standard approach or some sort of guidance for sizing EFVs, and criteria for identifying adverse conditions, may be needed. SWC agreed and stated that additional guidance, not necessarily standards, need to be developed. SWC additionally asked PHMSA to issue advisory bulletins if PHMSA finds additional conditions in which an EFV installation is advisable. Likewise, AGA stated that the current industry standards used in manufacturing are satisfactory, and EFV performance testing using industry standards cannot be accomplished in an economically, technically, and operationally feasible manner on installed service lines.

PHMSA finds that additional technical standards development for EFVs at this time is not necessary. However, PHMSA is considering requesting a new or existing industry committee to develop guidelines for a standard approach to the sizing and installation of EFVs. Industry guidelines have already been developed for the implementation of (Distribution Integrity Management Program) DIMP by the GPTC and industry gas associations. PHMSA believes these guidelines should be developed in a more comprehensive manner to include the selection, installation, and performance testing of EFVs for a variety of design considerations and service line configurations. The identification of operating conditions and system configurations that are incompatible with EFVs could also be included in the guidelines.

Only one commenter, MAE, provided additional information and supporting data with regard to additional potential costs and impacts of expanding EFV use. Specifically, MAE stated that it had installed 5,102 EFVs on SFRs in 2010. If applications beyond SFRs were required for service lines, MAE would have installed an additional 1,123 EFVs in 2010. MAE stated the estimated average cost for an EFV is $50.00 and that there would be no anticipated significant impact on the environment.

Several comments from members of the public were received in response to the ANPRM. One commenter, Courtney D. Brown, supported the expanded use of EFVs to protect people in the vicinity of large businesses and/or entertainment venues. Brown commented that the cost of installing EFVs does not outweigh the loss of lives, homes, or businesses when an incident occurs. Commenter Rebecca Lee Roter expressed concern with the lack of regulatory requirements in place for natural gas and transmission lines in Class 1 areas. Roter indicated that these areas required little routine inspection and no emergency plans.

PHMSA received several additional comments on the topic of the expanded use of EFVs. The information from MAE was helpful for PHMSA to get a better understanding of the costs and impacts of expanding EFV use. PHMSA has estimated an average cost of $30 per valve—see the initial RIA for further discussion. Additionally, PHMSA is aware of the concern for public safety expressed by Brown and Roter.

PHMSA is proposing to revise the language used in § 192.381(a) to remove the words “single residence”. This change reflects the proposed expansion of EFVs to applications beyond SFRs.

PHMSA is proposing to revise § 192.383(b) to include the proposed new categories of service on which EFVs would be installed. The existing category of service (new or replaced service line serving a SFR) would remain. The new categories of service would include branched service lines to a SFR installed concurrently with the primary SFR service line; branched service lines to a SFR installed off a previously installed SFR service line that does not contain an EFV; and small commercial customers and multi-family installations. The existing exceptions for EFV installation found in § 192.383(b)(1) through (4) would remain but would be moved to § 192.383(c)(1) through (4).

PHMSA is proposing the addition of § 192.383(d) to allow existing service line customers the option of requesting an EFV installation on their service line if one or more of the exceptions listed in § 192.383(c)(1) through (4) are not met. Operators would install an EFV at the request of customer on a mutually agreeable date and time. This option would be available to service line customers on existing service lines when the customer applies for service and for a period of 90 days after service has started. Operators will rely upon the appropriate State regulatory agencies to determine who would bear the costs of installation for customer requested EFVs.

With regard to the issue of installation costs of a customer requested EFV, PHMSA has no jurisdiction concerning natural gas rates or any costs incurred due to installation of an optional EFV at a consumer's request. Rather, the appropriate State regulatory agency will determine all issues related to the costs of installation.

PHMSA proposes to add paragraphs (e)(1) through (2) which would require that operators notify existing service line customers of their right to request an EFV in writing. Master meter operators may continuously post a general notification in a prominent location frequented by customers. Operators must also have evidence of customer notification. Operator evidence of notification could include such items as a statement printed on customer bills or mailings. Small Master meters would be ask to prove that they posted a notice at some common location. Each operator must maintain a copy of the customer EFV notice for three years. This notice must be available for inspection by the Administrator or a State agency participating under 49 U.S.C. 60105 or 60106.

PHMSA is proposing the addition of § 192.385 to require the installation of a manual service line shut-off valve, such as a curb valve, when an EFV is not installed in accordance with § 192.383. This proposed section also includes a definition for “Manual service line shut-off valve” to further clarify the applicability of this provision.

This Notice of Proposed Rulemaking is published under the authority of the Federal pipeline safety law (49 U.S.C. 60101 et seq.). Section 60102 authorizes the Secretary of Transportation to issue regulations governing design, installation, inspection, emergency plans and procedures, testing, construction, extension, operation, replacement, and maintenance of pipeline service lines. Further, section 60109(e)(3)(B) states that “the Secretary, if appropriate, shall by regulation require the use of excess flow valves, or equivalent technology, where economically, technically, and operationally feasible on new or entirely replaced distribution branch services, multifamily facilities, and small commercial service facilities.”

Executive Orders 12866 (Regulatory Planning and Review) and 13563 (Improving Regulation and Regulatory Review) require agencies to regulate in the “most cost-effective manner,” to make a “reasoned determination that the benefits of the intended regulation justify its costs,” and to develop regulations that “impose the least burden on society.” Expansion of the use of EFVs and curb valves is a non-significant regulatory action under Executive Order 12866 and the Department of Transportation's (DOT's) Regulatory Policies and Procedures. This proposed requirement has been reviewed by the Office of Management and Budget in accordance with Executive Order 13563 and Executive Order 12866 and is consistent with the requirements in both Orders.

During the initial stages of the development of the regulatory evaluation, PHMSA developed the survey recommended by the Interim Evaluation, which was aimed at gathering data on EFV and curb valve costs and benefits. PHMSA intended to send the survey to all operators in order to ensure that any proposed changes were based upon comprehensive and useful data. The goal was to have a better understanding of the costs of EFVs on installations beyond SFRs from those who have deployed them already, and on the costs and effectiveness of curb valves. Nine companies were asked to pilot the census, and a copy was published in the Federal Register.

Both the census pilot and the comments to the proposed census published in the Federal Register quickly revealed that company databases are not currently set up to provide the necessary data. Load and customer type data are stored separately from data on EFVs and from data on incidents, and grouping customers into the census categories would, in some cases, cost more in labor for the database work and analysis than it would cost to implement this proposed rule itself. As a result of discussions with industry representatives and the NTSB, PHMSA chose to propose a rule similar to the framework included in Section 22 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.

The initial Regulatory Impact Analysis (RIA), which is included in the docket for this rulemaking, does not address the benefits and costs of the proposal to require operators to install EFVs on branched service lines servicing SFRs because the benefits and costs of this proposal were addressed in the regulatory impact analysis for a previous rulemaking 8 . The initial RIA found that the estimated monetized benefits do not exceed the monetized costs in all cases. For the proposal to require EFVs on new or replaced service lines servicing MFRs, the monetized costs exceed monetized benefits even when using lower bound cost estimates. PHMSA believes that the proposals are nevertheless justified by the significant unquantifiable benefits, such as avoided evacuations and environmental damage from EFV-preventable incidents, including incidents that could not be included in the analysis because they do not meet PHMSA reporting criteria. EFVs also provide protection against a low-probability but high-consequence incident that could inflict mass casualties.

The proposed rule is assumed to affect approximately 1,289 natural gas distribution operators and 222,114 service lines per year on average. The RIA assumed valves do not have network effects, in other words, each EFV operates independently and the costs and benefits of EFV installation simply scale linearly. The total annual benefits of the rule are $7,735,725 when discounted at 7 percent, while the costs range from $4,381,734 to $17,848,499 depending on the costs of the valve. At the 3% discount rate the total benefits of the rule are $2,748,456, while the costs range from $4,967,145 to $20,311,030. PHMSA requests public comments on its monetized estimates of the proposed rule's benefits and costs.

The following tables summarize the quantified benefits and costs of this proposed rule at the 3 and 7% discount rates:

The Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act) requires each regional fishery management council to submit any fishery management plan or amendment to NMFS for review and approval, partial approval, or disapproval. The Magnuson-Stevens Act also requires that NMFS, upon receiving a plan or amendment, publish an announcement in the Federal Register notifying the public that the plan or amendment is available for review and comment.

This amendment would revise the AMs for golden tilefish, snowy grouper, gag, red grouper, black grouper, scamp, the shallow-water grouper complex, greater amberjack, the other jacks complex, bar jack, yellowtail snapper, mutton snapper, the other snappers complex, gray triggerfish, wreckfish (recreational sector), Atlantic spadefish, hogfish, red porgy, the other porgies complex, and golden crab (commercial sector).

Currently, the snapper-grouper species and golden crab addressed in this amendment have slightly different AMs in place compared to other snapper-grouper species. The Generic AM Amendment intends to modify the AMs for these species and species complexes to make them consistent with the majority of AMs already in place for other snapper-grouper species. Specifically, the recreational AMs would be updated to allow NMFS to close the recreational sectors in-season when the recreational ACLs are met or projected to be met. The proposed action would also modify the AMs to trigger post-season reductions in the following year's catch limit in the commercial and recreational sectors if the species, or one or more species in a species complex, is overfished and the total (commercial and recreational combined) ACL has been exceeded. Additionally, for the recreational sector, the fishing season may also be shortened to compensate for a total ACL overage in the previous year if the species or one or more species in a species complex is overfished. Modifying the AMs in this manner would create regulatory consistency among most federally managed species in the South Atlantic region.

The Generic AM Amendment revises the sector allocations for dolphin. The current sector allocations for dolphin are 92.46 percent for the recreational sector and 7.54 percent for the commercial sector. The Council chose these allocations using a sector allocation formula where 50 percent of the sector allocations are based on landings from a longer time series (1999-2008) and 50 percent of the sector allocations are based on landings from a shorter time series (2006-2008). This results in the current annual catch limits (ACL) of 1,157,001 lb (524,807 kg), round weight, for the commercial sector and 14,187,845 lb (6,435,498 kg), round weight, for the recreational sector. The Generic AM Amendment would revise the sector allocation formula for dolphin to be based on the average of the percentages of the total catch for 2008-2012. The recreational sector allocation for dolphin would be 90 percent with an ACL of 13,810,361 lb (6,264,274 kg), round weight, and the commercial sector allocation would be 10 percent with an ACL of 1,534,485 lb (696,031 kg), round weight.

The Council has submitted the Generic AM Amendment for Secretarial review, approval, and implementation. The decision to approve, partially approve, or disapprove the Generic AM Amendment will be based, in part, on consideration of comments, recommendations, and information received during the comment period on this notice of availability.

A proposed rule that would implement the Generic AM Amendment has been drafted. In accordance with the Magnuson-Stevens Act, NMFS is evaluating the proposed rule to determine whether it is consistent with the FMP, the Magnuson-Stevens Act, and other applicable laws. If that determination is affirmative, NMFS will publish the proposed rule in the Federal Register for public review and comment.

Comments received by September 14, 2015 will be considered by NMFS in the decision to approve, disapprove, or partially approve the amendment. Comments received after that date will not be considered by NMFS in this decision. All comments received by NMFS on the amendment or the proposed rule during their respective comment periods will be addressed in the final rule.