Federal Register Vol. 80, No.188,

We invite you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under the ADDRESSES section. Include “Docket No. FAA-2015-3637; Directorate Identifier 2014-NM-219-AD” at the beginning of your comments. We specifically invite comments on the overall regulatory, economic, environmental, and energy aspects of this proposed AD. We will consider all comments received by the closing date and may amend this proposed AD because of those comments.

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

We have received a report of fuel odor in the cabin. Fuel was found leaking from a cracked fuel line shroud in the left cargo compartment equipment tunnel. This condition, if not corrected, could result in fuel accumulation below the cargo compartment floor and consequent increased risk of fire.

We reviewed Boeing Alert Service Bulletin MD11-28A148, dated August 29, 2014. The service information describes procedures for checking for the presence of fuel at the fuel shroud drain; a HFEC inspection for cracked fuel line shrouds; a pressure test of the drain system of the tail tank fuel shroud and a pressure test of the drain system of the aft fuselage fuel shroud to determine cracking; and corrective actions. This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the ADDRESSES section of this NPRM.

We are proposing this AD because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of the same type design.

This proposed AD would require accomplishing the actions specified in the service information described previously.

We estimate that this proposed AD affects 90 airplanes of U.S. registry.

We estimate the following costs to comply with this proposed AD:

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

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

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

We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.

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

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

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

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

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

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

Authority for This Rulemaking

The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part, A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it would amend Class E airspace at U. S. Coast Guard Station Neah Bay Heliport, Neah Bay, WA.

Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. FAA-2015-3321; Airspace Docket No. 15-ANM-17.” The postcard will be date/time stamped and returned to the commenter.

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

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

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

This document proposes to amend FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, and effective September 15, 2015. FAA Order 7400.9Z is publicly available as listed in the ADDRESSES section of this proposed rule. FAA Order 7400.9Z lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

The FAA is proposing an amendment to Title 14 Code of Federal Regulations (14 CFR) Part 71 by establishing Class E airspace extending upward from 700 feet above the surface at U.S. Coast Guard Station Neah Bay Heliport, Neah Bay, WA. Establishment of a GPS approach has made this action necessary for the safety and management of IFR operations at the heliport. Class E airspace would be established within a 1-mile radius of the U.S. Coast Guard Station Neah Bay Heliport, with a segment extending from the 1-mile radius to 2.5 miles northeast of the heliport.

Class E airspace designations are published in paragraph 6005 of FAA Order 7400.9Z, dated August 6, 2015, and effective September 15, 2015, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designations listed in this document will be published subsequently in the Order.

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

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

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

I. Background A. Introduction

The Commission has long established and enforced speculative position limits for futures and options contracts on various agricultural commodities as authorized by the Commodity Exchange Act (“CEA”).1 The part 150 position limits regime 2 generally includes three components: (1) The level of the limits, which set a threshold that restricts the number of speculative positions that a person may hold in the spot-month, individual month, and all months combined,3 (2) exemptions for positions that constitute bona fide hedging transactions and certain other types of transactions,4 and (3) rules to determine which accounts and positions a person must aggregate for the purpose of determining compliance with the position limit levels.5

The Commission's existing aggregation policy under regulation 150.4 generally requires that unless a particular exemption applies, a person must aggregate all positions for which that person controls the trading decisions with all positions for which that person has a 10 percent or greater ownership interest in an account or position, as well as the positions of two or more persons acting pursuant to an express or implied agreement or understanding.6 The scope of exemptions from aggregation include the ownership interests of limited partners in pooled accounts,7 discretionary accounts and customer trading programs of futures commission merchants (“FCM”),8 and eligible entities with independent account controllers that manage customer positions (“IAC” or “IAC exemption”).9 Market participants claiming one of the exemptions from aggregation are subject to a call by the Commission for information demonstrating compliance with the conditions applicable to the claimed exemption.10

On November 15, 2013, the Commission proposed to amend regulation 150.4, and certain related regulations, to include rules to determine which accounts and positions a person must aggregate (the “2013 Aggregation Proposal”).11 Among other elements, the 2013 Aggregation Proposal included a notice filing procedure, effective upon submission, to permit a person in specified circumstances to disaggregate the positions of a separately organized entity (“owned entity”), if such person has between a 10 percent and 50 percent ownership or equity interest in the owned entity.12 The notice filing would need to demonstrate compliance with certain conditions set forth in the proposed rule. Under the 2013 Aggregation Proposal, persons with a greater than 50 percent ownership or equity interest in the owned entity would have to apply on a case-by-case basis to the Commission for permission to disaggregate, and await the Commission's decision as to whether certain conditions specified in the proposed rule had been satisfied and therefore disaggregation would be permitted.13

The 2013 Aggregation Proposal reflected the Commission's long-standing incremental approach to exemptions from the aggregation requirement for persons owning a financial interest in an entity. In the 2013 Aggregation Proposal, the Commission reaffirmed its belief that ownership of an entity is an appropriate criterion for aggregation of that entity's positions, noting that section 4a(a)(1) of the CEA provides that “[i]n determining whether any person has exceeded such limits, the positions held and trading done by any persons directly or indirectly controlled by such person shall be included with the positions held and trading done by such person.” 14 The Commission explained that as early as 1957, the Commission's predecessor (the Commodity Exchange Authority) issued determinations requiring that accounts in which a person has a financial interest be included in aggregation.15

Regarding the threshold level at which an exemption from aggregation on the basis of ownership would be available, the Commission noted in the 2013 Aggregation Proposal that it has generally found that an ownership or equity interest of less than 10 percent in an account or position that is controlled by another person who makes discretionary trading decisions does not present a concern that such ownership interest results in control over trading or can be used indirectly to create a large speculative position through ownership interests in multiple accounts. As such, the Commission has exempted an ownership interest below 10 percent from the aggregation requirement.16

The Commission noted that while other of its rulemakings prior to the 2013 Aggregation Proposal generally restricted exemptions from aggregation based on ownership to FCMs, limited partner investors in commodity pools, and independent account controllers managing customer funds for an eligible entity, a broader passive investment exemption has previously been considered but not enacted by the Commission.17 Further, the Commission reiterated its belief in incremental development of aggregation exemptions over time.18 Consistent with that incremental approach, in the 2013 Aggregation Proposal the Commission considered the additional information provided and the concerns raised by commenters on the May 2012 aggregation proposal and proposed two new tiers of relief from the ownership criteria of aggregation—relief on the basis of a notice filing, effective upon submission, by persons holding an interest of between 10 percent and 50 percent in an owned entity, and relief on the basis of an application by persons holding an interest of more than 50 percent in an owned entity.19 Each of these procedures for relief in the 2013 Aggregation Proposal is described briefly below.

Proposed rule § 150.4(b)(2), as set out in the 2013 Aggregation Proposal, would continue the Commission's longstanding rule that persons with either an ownership or an equity interest in an account or position of less than 10 percent need not aggregate such positions solely on the basis of the ownership criteria, and persons with a 10 percent or greater ownership interest would still generally be required to aggregate the account or positions.20 However, proposed rule § 150.4(b)(2), as set out in the 2013 Aggregation Proposal, would establish a notice filing procedure, effective upon submission, to permit a person with either an ownership or an equity interest in an owned entity of 50 percent or less to disaggregate the positions of an owned entity in specified circumstances, even if such person has a 10 percent or greater interest in the owned entity.21 The notice filing would have to demonstrate compliance with certain conditions set forth in proposed rule § 150.4(b)(2). Similar to other exemptions from aggregation, the notice filing would be effective upon submission to the Commission, but the Commission would be able to subsequently call for additional information, and to amend, terminate or otherwise modify the person's aggregation exemption for failure to comply with the provisions of rule § 150.4(b)(2). Further, the person would be obligated to amend the notice filing in the event of a material change to the circumstances described in the filing.

The Commission preliminarily based the 2013 Aggregation Proposal's limit of 50 percent on the ownership interest in another entity on a belief that the limit would be a reasonable, “bright line” standard for determining when aggregation of positions is required, even where the ownership interest is passive.22 The 2013 Aggregation Proposal explained that majority ownership (i.e., over 50 percent) is indicative of control, and this standard would address the Commission's concerns about circumvention of position limits by coordinated trading or direct or indirect influence between entities. For these reasons, the Commission preliminarily believed that aggregation based upon an ownership or equity interest of greater than 50 percent would be appropriate to address the heightened risk of direct or indirect influence over the owned entity.23

Referring to commenters who said that if an owned entity's positions are aggregated with the owner's position, the aggregation should be pro rata to the ownership interest, the Commission stated its belief that a pro rata approach could be administratively burdensome for both owners and the Commission.24 For example, the Commission explained, the level of ownership interest in a particular owned entity may change over time for a number of reasons, including stock repurchases, stock rights offerings, or mergers and acquisitions, any of which may dilute or concentrate an ownership interest. Thus, it may be burdensome to determine and monitor the appropriate pro rata allocation on a daily basis. Moreover, the Commission also noted that it has historically interpreted the statute to require aggregation of all the relevant positions of owned entities, absent an exemption. This is consistent with the view that a holder of a significant ownership interest in another entity may have the ability to influence all the trading decisions of the entity in which such ownership interest is held.

The 2013 Aggregation Proposal also included a provision for disaggregation relief for ownership or equity interests of greater than 50 percent, which was consistent with the Commission's preliminary view that relief from the aggregation requirement should not be available merely upon a notice filing by a person who has a greater than 50 percent ownership or equity interest in the owned entity. The Commission explained that, in its view, a person with a greater than 50 percent ownership interest in multiple accounts would have the ability to hold and control a significant and potentially unduly large overall position in a particular commodity, which position limits are intended to prevent. Also, as noted above, the Commission believed that in general this “bright line” approach would provide administrative certainty.25

Nonetheless, the Commission considered points raised by commenters in this regard, and concluded that in some situations disaggregation relief may be appropriate even for a person holding a majority ownership interest, on the conditions that the owned entity is not required to be, and is not, consolidated on the financial statement of the person, the person can demonstrate that the person does not control the trading of the owned entity, based on the criteria in proposed rule § 150.4(b)(2)(i), and both the person and the owned entity have procedures in place that are reasonably effective to prevent coordinated trading.26

The Commission acknowledged that to provide such relief in order to address issues raised by commenters would represent a break by the Commission from past practice, but it explained that it has authority to provide such relief pursuant to section 4a(a)(7) of the CEA, which authorizes the Commission to provide relief from the requirements of the position limits regime.27

Consequently, the 2013 Aggregation Proposal included a provision (proposed rule § 150.4(b)(3)) that would permit a person with a greater than 50 percent ownership of an owned entity to apply to the Commission for relief from aggregation on a case-by-case basis. The person would be required to demonstrate to the Commission that:

i. The owned entity is not required to be, and is not, consolidated on the financial statement of the person,

ii. the person does not control the trading of the owned entity (based on criteria in rule § 150.4(b)(2)(i)), with the person showing that it and the owned entity have procedures in place that are reasonably effective to prevent coordinated trading in spite of majority ownership,28

iii. each representative of the person (if any) on the owned entity's board of directors attests that he or she does not control trading of the owned entity, and

iv. the person certifies that either (a) all of the owned entity's positions qualify as bona fide hedging transactions or (b) the owned entity's positions that do not so qualify do not exceed 20 percent of any position limit currently in effect, and the person agrees in either case that:

If this certification becomes untrue for the owned entity, the person will aggregate the owned entity for three complete calendar months and if all of the owned entity's positions qualify as bona fide hedging transactions for that entire time the person would have the opportunity to make the certification again and stop aggregating,

upon any call by the Commission, the owned entity(ies) will make a filing responsive to the call, reflecting the owned entity's positions and transactions only, at any time (such as when the Commission believes the owned entities in the aggregate may exceed a visibility level), and

the person will provide additional information to the Commission if any owned entity engages in coordinated activity, short of common control (understanding that if there were common control, the positions of the owned entity(ies) would be aggregated).

The Commission clarified that the proposed relief would not be automatic, but rather would be available only if the Commission finds, in its discretion, that the four conditions above are met. The proposed rule would not impose any time limits on the Commission's process for making the determination of whether relief is appropriately granted, and relief would be available only if and when the Commission acts on a particular request for relief.29

The Commission also explained that, under the 2013 Aggregation Proposal, it would interpret factors such as the owned entity being a newly acquired standalone business or a joint venture subject to special restrictions on control, or two different owned entities conducting operations at different levels of commerce (such as retail and wholesale), to be favorable to granting relief from the aggregation requirement.30 The Commission also noted that if a person with greater than 50 percent ownership of an owned entity could not meet the conditions in proposed rule § 150.4(b)(3), the person could apply to the Commission for relief from aggregation under CEA section 4a(a)(7).31 The Commission noted that CEA section 4a(a)(7) does not impose any time limits on the Commission's process for determining whether relief under that section is appropriate, nor does it prescribe or limit the factors that the Commission may consider to be relevant in determining whether to grant relief.32

In light of the language in section 4a of the CEA, its legislative history, subsequent regulatory developments, and the Commission's historical practices in this regard, the Commission continues to believe that section 4a requires aggregation on the basis of either ownership or control of an entity. The Commission also believes that aggregation of positions across accounts based upon ownership is a necessary part of the Commission's position limit regime.33 However, the Commission is also mindful that, as discussed by commenters on the 2013 Aggregation Proposal, aggregation of positions held by owned entities may in some cases be impractical, burdensome, or not in keeping with modern corporate structures. Therefore, the Commission is proposing a limited revision to the 2013 Aggregation Proposal that would permit all owners of 10 percent or more of an owned entity (i.e., the owners of up to and including 100 percent of an owned entity) to disaggregate the positions of the owned entity in the circumstances specified in proposed rule § 150.4(b)(2). All other aspects of the 2013 Aggregation Proposal, including the proposed criteria for disaggregation relief and other aspects not discussed herein, remain the same.

The Commission has the authority to revise its proposed relief under section 4a(a)(7) of the CEA, which authorizes the Commission to provide relief from the requirements of the position limits regime. The reasons for this proposed revision are discussed below.

Commenters on the 2013 Aggregation Proposal generally praised the proposed relief for owners of between 10 percent and 50 percent of an owned entity, but asserted that the proposed application procedures for owners of a more than 50 percent equity or ownership interest were unnecessary and inappropriate.34

A few commenters opposed providing aggregation relief for owners of more than 10 percent of an owned entity. Better Markets, Inc. (“Better Markets”), an organization that advocates for financial reform, commented that allowing disaggregation of majority-owned subsidiaries would ignore the clear language of CEA section 4a(a)(1) and “would allow traders to easily circumvent Position Limits by creating multiple subsidiaries and dividing its positions among them.” 35 Better Markets said the Commission must therefore not allow any disaggregation relief for owners holding a more than 10 percent interest in an owned entity.36 Occupy the SEC, another organization that advocates for financial reform, said that the provision for relief for owners of more than 50 percent of an owned entity should be removed because “there can be no plausible justification for exempting largely interconnected firms from the position limits regime,” and in any case the proposed relief for greater than 50 percent owners would be of little use because it “adds a veritable gauntlet of conditions [in proposed rule 150.4(b)(3)] that few companies will be able to pass.” 37

The Futures Industry Association (“FIA”), a trade association, commented that the Commission should permit majority-owned affiliates to be disaggregated regardless of whether the entities are required to consolidate financial statements.38 The FIA opined that conditioning disaggregation of majority-owned affiliates on the lack of a requirement for consolidated financial statements would be arbitrary, because the accounting principles “are wholly unrelated to the question of actual control of day-to-day trading decisions and positions.” 39 The FIA requested that the Commission amend the proposal to allow a person to rebut the presumption of control of a majority-owned affiliate solely by demonstrating that the person does not control the trading and positions of the owned entity through, among other things, effective procedures that prevent coordinated trading.40 The FIA recommended that the Commission remove the condition for each representative of the board of directors to certify that he or she does not control the trading decisions of the owned entity.41

Other commenters said that the Commission should provide the same disaggregation relief for owners of more than 50 percent of an owned entity as is proposed to be provided for owners of 50 percent or less. For example, the Asset Management Group of the Securities Industry and Financial Markets Association said that the Commission should extend “the owned entity exemption at proposed [rule] 150.4(b)(2) to include all third party ownership interests (greater than 50 [percent]) that do not involve actual common trading control.” 42 The Center for Capital Markets Competitiveness of the U.S. Chamber of Commerce said that the requirement in proposed rule § 150.4(b)(3) to submit an application to the Commission and await its approval would be unworkable in practice and not provide any apparent regulatory benefit.43

The Commodity Markets Council recommended that the Commission not require aggregation based solely on ownership of legal entities, but instead extend the IAC exemption to all separately organized companies, whether or not they are affiliated.44 The Natural Gas Supply Association (“NGSA”) recommended that the Commission leave the current rules on aggregation in place unchanged, because “[u]nder the status quo, the Commission may bring enforcement action against an investor if it directs or otherwise controls the trading of an owned entity whose positions it claims it does not control.” 45

MidAmerican Energy Holdings Company (“MidAmerican”), an energy services company which is controlled by Berkshire Hathaway, Inc. (“Berkshire”), commented that, absent aggregation relief for majority-owned affiliates that are consolidated for accounting purposes, the proposed position limits would impose “serious regulatory costs and consequences” to establish an extensive compliance monitoring and coordination program across independently managed, disparate businesses, and would be contrary to policies, procedures, systems, and controls established to provide functional and legal separation for individual operating businesses.46 MidAmerican explained that Berkshire and its industrial operating businesses are generally managed on a decentralized basis, with no centralized or integrated business functions and minimal involvement by Berkshire's corporate headquarters in day-to-day business activities of MidAmerican or Berkshire's other operating businesses.47 MidAmerican recommended that the Commission provide for disaggregation upon a notice filing by a group of majority-owned entities that meet the four criteria in the proposal or, if the group does not meet all four criteria in the proposal, provide for the group to rely on the submission of an application for relief until the Commission has acted on the application.48

CME Group (“CME”), a holding company for a number of DCMs, stated that the Commission did not identify any basis or justification for the various features of the proposed aggregation regime.49 CME contended that features of the 2013 Aggregation Proposal (regarding the owned entity aggregation rules, the IAC exemption, and the “substantially identical trading strategies” rule) are not in accordance with law, arbitrary and capricious, an unexplained departure from the Commission's administrative precedent, and not more permissive than existing aggregation standards.50 The Commodity Markets Council and the NGSA were also of the opinion that the 2013 Aggregation Proposal was not supported by the Commission's administrative precedent.51 CME and NGSA asserted that section 4a(a)(1) of the CEA provides no basis for requiring aggregation of positions held by another person in the absence of control of such other person.52 CME also stated that rule § 150.4(b) generally exempts a commodity pool's participants with an ownership interest of 10 percent or greater from aggregating the positions held by the pool.53 Finally, CME and NGSA contended that two of the Commission's enforcement cases indicate that the Commission has viewed aggregation as being required only where there is common trading control.54

1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory Commission (Commission) proposes, pursuant to sections 222, 301(b), 307(a) and 309 of the Federal Power Act (FPA),1 to amend its regulations to require each regional transmission organization (RTO) and independent system operator (ISO) to electronically deliver to the Commission, on an ongoing basis, data required from its market participants that would: (i) Identify the market participants by means of a common alpha-numeric identifier; (ii) list their “Connected Entities,” which includes entities that have certain ownership, employment, debt, or contractual relationships to the market participants, as specified in this NOPR; and (iii) describe in brief the nature of the relationship of each Connected Entity. The uniform identification of market participants, together with the listing of entities that comprise a network of common interests, would enhance the Commission's efforts to detect and deter market manipulation, a central objective of the Commission as identified in its FY 2014-2018 Strategic Plan.2 Unless the RTOs and ISOs request continuation of existing affiliate disclosure requirements based on a particularized need, the Commission expects that this new disclosure obligation will supplant all existing affiliate disclosures requirements contained in the RTOs and ISOs tariffs.

2. In the Strategic Plan, the Commission cited monitoring and surveillance activities as a key function in meeting the objective of detecting and deterring market manipulation.3 In recent years the Commission has greatly enhanced its capabilities in this regard, having developed automated screens of market activities and set up analytical procedures to detect potential market manipulation. Understanding the ownership, employment, debt, and contractual relationships of market participants would provide context for such data, and help determine whether there appears to be a legitimate business rationale for seemingly anomalous trading patterns, or whether there may be market manipulation, fraud, or abuse. This in turn will further the Commission's goal of detecting and deterring possible market manipulation. As we explain below, the existing affiliate disclosure requirements do not appropriately enable the Commission to identify and monitor these business relationships.

3. Beginning in the late 1960s, the electric industry gradually transformed itself from one populated by mostly self-sufficient vertically integrated utilities compensated by cost-based rates, to competitive markets characterized by open transmission access, partial disaggregation of generation and transmission, and market-based rates.4 Competitive markets brought with them the potential for market manipulation, and Congress, acting in response to the abuses characterizing the Western Energy Crisis of 2000-2001, passed the Energy Policy Act of 2005 (EPAct 2005).5 This legislation, among other things, gave the Commission authority to address market manipulation, including the ability to assess substantial civil fines and seek criminal penalties.6

4. In 2012, utilizing the authority granted by Congress under the FPA, the Commission expanded the tools available to staff to investigate market activity for potential manipulation. In Order No. 771,7 the Commission required e-Tag Authors and Balancing Authorities to ensure Commission access to their e-Tags. And in Order No. 760,8 the Commission required the RTOs and ISOs to electronically deliver to the Commission, on a regular basis, their existing data relating to physical and virtual offers and bids, market awards, resource outputs, marginal cost estimates, shift factors, financial transmission rights, internal bilateral contracts, uplift, and interchange pricing. These orders have provided needed tools for staff to monitor market activities.

5. The Commission has also been granted access by the Commodity Futures Trading Commission (CFTC) to its Large Trader Report, and the information contained therein has significantly added to the Commission's ability to carry out its enforcement responsibilities. In addition, on January 2, 2014, the Commission and the CFTC signed a new Memorandum of Understanding (MOU) to share information in connection with market surveillance and investigations into potential market manipulation, fraud, or abuse.9 This MOU establishes procedures for sharing information of mutual interest related to market surveillance and investigative matters, while maintaining confidentiality and data protection.10

6. Nonetheless, despite increased access to trading data, the Commission cannot fully utilize this information in order to detect and deter market manipulation because of uncertainty regarding the identity of a given market participant, which may trade under different identifiers in different markets and venues. The Commission also lacks a clear window into the relationships between market participants and other entities, which can be complex. Without an understanding of which companies share ownership or debt interests, or who may function in key employment or other contractual roles (such as asset management), it can be difficult to ascertain which individuals or companies may benefit from a given transaction or, indeed, who may be jointly participating in a common course of conduct.

7. Currently, each RTO and ISO requires market participants to provide it with a list of the participant's affiliates.11 However, requirements vary as to the nature of a reportable affiliate relationship and the frequency for updating the information. In addition, for purposes of ferreting out potential market manipulation, it is important to explore relationships that extend beyond corporate affiliation. Such additional relationships may involve contractual relationships such as tolling and asset management agreements, or debt structures that are convertible to ownership interests.

8. The existing affiliate disclosure rules do not provide the tools necessary for the Commission to sufficiently monitor these increasingly complex business relationships that impact our jurisdictional markets. Thus, the Commission believes it is desirable to use a new term, one that is free of any associations that have developed around the term “affiliate,” and one that is uniform across all of the RTOs and ISOs, to describe a relationship of interest in probing for potential market manipulation. We propose the term “Connected Entity,” and further propose to make the definition of that term uniform across the organized electric markets.

9. The Commission employs a variety of screens to identify anomalous trading. When it detects such anomalies, it attempts to determine whether the behavior is legitimate market activity. It does this in large part by analyzing the circumstances surrounding the activity, including trading patterns and trader explanations. Some patterns that have emerged to date are: limited risk or riskless combinations of trades to enhance the value of a position or portfolio, such as wash trades; repetitive, uneconomic physical trading or flows to benefit a position; trading to affect the formation of an index price; withholding physical generation to benefit a financial and/or physical position; and using virtual bids to benefit a financial and/or physical position.

10. Rather than performing a trade or other action that results in a direct benefit to itself, a market participant might instead take actions that benefit another entity that bears a financial or legal relationship to it. Entities under common control, whether by ownership, beneficial interest, or contractual relationships, might also collude to set prices by taking positions that together result in a market manipulation. An understanding of these relationships is crucial in exploring the design and possible purposes behind a trading pattern, from which inferences of intent can be drawn and investigated. The existing affiliate disclosure requirements imposed through the RTOs and ISOs tariffs do not capture all of these business relationships.

11. As evidence of intent is critical in establishing whether there has been market manipulation,12 the Commission can better monitor and protect the markets from wrongdoing if these relationships are fully known. Moreover, more complete information about these relationships will reduce the number of informal inquiries in response to false positive surveillance screen trips that may result from an incomplete picture of market participants' incentive structures.

12. Although there are a few third-party sources of public information that contain data about the affiliate relationships of entities trading in the electric energy markets, their information and manner of collection is insufficient for the Commission's market monitoring responsibilities. These sources include vendors such as Dun & Bradstreet, SNL Financial, and Ventyx. The primary service provided by these companies is tracking trading information, not compiling affiliate data, and their affiliate information is generally derived from public sources that do not cover all market participants. Further, whether such information is current or complete cannot be ascertained from the listings. Nor do such listings include entities that are connected by contractual relationships, rather than ownership. For all these reasons, an up-to-date, reliable, and complete listing of Connected Entities cannot be obtained from these third-party sources.

13. Obtaining Connected Entity data from RTOs and ISOs leaves unaddressed similar data from entities operating outside the organized electric markets. However, the Commission has estimated, using Electric Quarterly Report (EQR) data and existing affiliation information gleaned from market-based rate filings and other available sources, that approximately 90 percent of the reported wholesale sales of electricity subject to the Commission's jurisdiction are made either by market participants in one or more of the six RTOs and ISOs, or by companies related by ownership to such a market participant.13 Therefore, access to Connected Entity data for all the market participants in each of the RTOs and ISOs would provide most of such data for all the transactions of interest in the Commission's electric manipulation screening. We invite comment on the desirability and feasibility of expanding our proposal to require the submission of Connected Entity information from non-RTO/ISO market participants, and on any difficulties commentators might perceive to exist in doing so.

14. The Commission recognizes that this proposal would place additional burden on market participants to implement the new reporting requirement and to submit the Connected Entity information to the RTOs and ISOs as proposed. However, we believe that the benefits of this proposal will outweigh the additional burden imposed on market participants. Moreover, as noted above, each of the six RTOs and ISOs already requires its market participants to submit data identifying certain affiliate relationships. It is possible that some, if not all, market participants will be able to use its existing processes for reporting affiliate information to the RTOs and ISOs to lessen the burden of this proposed reporting. For market participants that are active in more than one market, it is also possible that the burden of making a uniform Connected Entity filing in all those markets, once the initial implementation period is over, would be no greater than the current burden of making multiple affiliate filings, each of which is unique to its particular RTO or ISO. For participants in only one market, we recognize that there will likely be an increase in the administrative time needed for compliance. As for the RTOs and ISOs themselves, we believe they would incur the initial implementation costs required to make compliance filings to amend their tariffs to conform the filed information to the new Commission standards, and revising their collection processes to be consistent with those standards.

15. The Commission has the authority to require the type of record keeping and submittals contemplated in this NOPR. As discussed below, the Commission's anti-manipulation authority under section 222 of the FPA, taken together with its investigative authority under section 307(a) of the FPA, its administrative powers under section 309 of the FPA, and its inspection and examination authority under section 301(b) of the FPA, provides ample basis for accessing Connected Entity data.

16. Section 222 of the FPA grants the Commission authority over the prohibition of market manipulation in connection with the purchase or sale of electric energy and transmission subject to the Commission's jurisdiction.14 It also prohibits manipulation by “any entity,” including entities exempted from the Commission's rate-related jurisdiction. Section 301(b) of the FPA provides that the Commission shall at all times have access to, and the right to inspect and examine all accounts and records of public utilities,15 which includes RTOs and ISOs. Section 309 of the FPA grants the Commission the authority to “perform any and all acts, and to prescribe, issue, make, amend, and rescind such orders, rules and regulations as it may find necessary and appropriate to carry out the provisions of [the FPA].” 16 And section 307(a) of the FPA provides that the Commission has authority to investigate any facts, conditions, practices, or matters it may deem necessary or proper to determine whether any person, electric utility, transmitting utility, or other entity may have violated or might violate the FPA or the Commission's regulations.17 It also has investigatory authority to aid in the enforcement of the FPA or the Commission's regulations, or to obtain information about wholesale electric energy sales or the transmission of electric energy in interstate commerce.18 This investigatory authority is not limited to a particular case or controversy, but allows an agency to “investigate merely on suspicion that the law is being violated, or even just because it wants assurance that it is not.” 19

17. The Commission has already required the RTOs and ISOs to provide this type of information to the Commission. Most notably, in Order No. 760, the Commission required the RTOs and ISOs to electronically deliver to it, on an ongoing basis, data relating to physical and virtual offers and bids, market awards, resource outputs, marginal cost estimates, shift factors, financial transmission rights, internal bilateral contracts, uplift, and interchange pricing.20 The information sought under this NOPR would typically be provided with less frequency than that which the RTOs and ISOs submit under Order No. 760. And the submittal of Connected Entity data would be transmitted through the same channels as the RTOs and ISOs already employ for Order No. 760 data.

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1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory Commission (Commission) is proposing to address two existing practices that may fail to compensate resources at prices that reflect the value of the service resources provide to the system, thereby distorting price signals. In certain instances, this creates a disincentive for resources to respond to dispatch signals. The Commission proposes to require that each regional transmission organization (RTO) and independent system operator (ISO) align settlement and dispatch intervals by settling energy transactions in its real-time markets at the same time interval it dispatches energy and settling operating reserves transactions in its real-time markets at the same time interval it prices operating reserves.1 The Commission is also proposing to require that each RTO/ISO trigger shortage pricing 2 for any dispatch interval during which a shortage of energy or operating reserves 3 occurs.

2. The Commission requires that rates for jurisdictional electricity service be just and reasonable and not unduly discriminatory or preferential. This requirement extends to market- and cost-based rates. The Commission has taken action to correct rates that become unjust and unreasonable, and has done so not only when the rates do not reflect costs but also when the underlying features, rate design, or market design fail to align.4 It is paramount that resources have appropriate incentives to respond to an energy or operating reserve shortage and that each resource is compensated based on a price that reflects the value of the service it provides.

3. It has become apparent that there are instances in which certain current RTO/ISO practices may fail to reflect the value of providing a given service, thereby distorting price signals and failing to provide appropriate signals for resources to respond to the actual operating needs of the market. One such practice that the Commission has identified and proposes to reform occurs when RTOs/ISOs dispatch resources every five minutes but perform settlements based on an hourly integrated price.5 This misalignment between dispatch and settlement intervals may distort the price signals sent to resources and fail to reflect the actual value of resources responding to operating needs because compensation will be based on average output and average prices across an hour rather than output and prices during the periods of greatest need within a particular hour.

4. The Commission also preliminarily finds that a second problem occurs if there is a delay between the time when a system experiences a shortage of energy and operating reserves and the time when prices reflect the shortage condition. This can be particularly problematic when, for example, a shortage is required to last a minimum time period before shortage pricing is triggered. In this instance, short-term prices may fail to reflect potential reliability costs, as well as the value of both internal and external market resources responding to a dispatch signal.

5. To address the problems associated with differing dispatch intervals and settlement intervals, as well as with shortage pricing triggers, the Commission proposes to require that each RTO/ISO (1) settle energy transactions in its real-time markets at the same time interval it dispatches energy and settle operating reserves transactions in its real-time markets at the same time interval it prices operating reserves, and (2) trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs.6 The settlement interval and shortage pricing reforms proposed herein will help ensure that resources have price signals that provide incentives to conform their output to dispatch instructions, and that prices reflect operating needs at each dispatch interval.

6. In Docket No. AD14-14-000, the Commission initiated a proceeding to evaluate issues regarding price formation in the energy and ancillary services markets operated by RTOs/ISOs (price formation proceeding). The Commission stated that the goals of price formation are to (1) maximize market surplus for consumers and suppliers; (2) provide correct incentives for market participants to follow commitment and dispatch instructions, make efficient investments in facilities and equipment, and maintain reliability; (3) provide transparency so that market participants understand how prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system; and (4) ensure that all suppliers have an opportunity to recover their costs.7

7. The action the Commission takes herein is the first step to advancing the goals of the Commission's price formation proceeding. The Commission expects to undertake further action addressing various price formation topics, including offer price caps, mitigation, uplift transparency, and uplift drivers. The proposed reforms in this NOPR advance at least two of the Commission's goals with respect to price formation. Specifically, the proposed reforms will help provide correct incentives for market participants to follow commitment and dispatch instructions, to make efficient investments in facilities and equipment, and to maintain reliability. The proposed reforms will also help provide transparency and certainty so that market participants understand how prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system. Price signals that reflect operating needs and system conditions would enhance incentives for resources to respond to dispatch instructions.8 In the long-term, the Commission expects that appropriate price signals would produce prices that consistently reflect operating needs and system conditions which, in turn, would help to encourage efficient investments in facilities and equipment, enabling reliable service.9

8. Requiring settlement intervals to match dispatch intervals would make resource compensation more transparent by, among other things, increasing the proportion of resource payment provided through payments of energy and operating reserves rather than uplift.10 Apportioning a greater proportion of a resource's revenue through payments for energy and operating reserves, rather than through uplift payments, increases transparency to the market by reflecting the costs of meeting system needs in settlement prices that are factored into a market price. In contrast, uplift payments bundle together a multitude of costs that are not factored into a market price. This increased transparency, in turn, better informs decisions to build or maintain resources and enhances consumers' ability to hedge. The benefits summarized above and discussed in detail below would ultimately help to ensure just and reasonable rates.

9. Implementing shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs would provide an incentive for resources to ensure that they are available to respond to high prices, which should help alleviate shortages and avoid shortage pricing during subsequent dispatch intervals. This reform would also ensure that resources operating during a shortage are compensated for the value of the service that they provide, regardless of whether the shortage is short-lived.

10. The Commission seeks comment on these proposed reforms sixty (60) days after publication of this NOPR in the Federal Register.

11. The Commission has addressed price formation in organized markets on prior occasions. In Order No. 719, the Commission addressed shortage pricing 11 and required RTOs/ISOs to develop and implement shortage pricing rules that would apply during operating reserve shortages to “ensure that the market price for energy reflects the value of energy during an operating reserve shortage.” 12 The Commission required such rules out of concern that inappropriate price signals during an operating reserve shortage would provide an insufficient incentive for market participants to take appropriate actions.

12. On June 19, 2014, the Commission initiated the price formation proceeding. In initiating that proceeding, the Commission stated that there may be opportunities for the RTOs/ISOs to improve the energy and ancillary service price formation process. The Commission explained that locational marginal prices (LMPs) used in energy and ancillary services markets ideally “would reflect the true marginal cost of production, taking into account all physical system constraints, and these prices would fully compensate all resources for the variable cost of providing service.” 13 The Commission directed staff to conduct outreach and to convene technical workshops on the following four general issues: (1) Use of uplift payments; (2) offer price mitigation and offer price caps; (3) scarcity and shortage pricing; and (4) operator actions that affect prices.14 During the fall of 2014, staff convened technical workshops and issued reports on these topics. In one of those reports, issued in October 2014, staff analyzed shortage pricing issues.15

13. In its January 2015 Notice Inviting Comments, the Commission invited comments on specific questions that arose from the price formation technical workshops.16 In response, among other price formation issues, commenters addressed settlement intervals and shortage pricing, as detailed below.

14. In the following section, for each of the two proposals, the Commission first summarizes the views of commenters in the price formation proceeding on settlement intervals and triggers for shortage pricing. The Commission then explains the need for the reform set forth in the proposal and describes the proposed reform in detail. To remedy the potential unjust and unreasonable rates that are based on the use of hourly integrated prices for settlement as well as on restrictions on shortage pricing discussed more fully herein, the Commission proposes, pursuant to section 206 of the Federal Power Act (FPA),17 to require that each RTO/ISO (1) settle energy transactions in its real-time markets at the same time interval it dispatches energy and settle operating reserves transactions in its real-time markets at the same time interval it prices operating reserves, and (2) trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs.18

15. Some RTOs/ISOs do not settle resources at the same intervals at which they dispatch resources in their real-time energy markets.19 Rather, they settle resources based on hourly average prices, as shown below.

16. In the price formation proceeding, commenters discussed using shorter settlement intervals (i.e., sub-hourly) and provided implementation and transition recommendations.

17. Commenters in support of sub-hourly settlements describe general benefits, as well as specific related improvements, from the adoption of sub-hourly settlements. Commenters from a broad range of the industry state that sub-hourly settlement intervals would provide significant benefits to the market by compensating resources fully for their flexibility and ability to follow dispatch instructions. According to these commenters, sub-hourly settlement intervals would permit resources to be rewarded for their ability to perform by earning greater revenues when prices fluctuate, which in the long run should induce more flexibility from new and existing resources and eventually lower dispatch costs and improve reliability.22

18. Commenters detail other potential benefits to sub-hourly settlement in the real-time market. PJM Utilities Coalition notes that sub-hourly settlement would address price distortions and uneconomic incentives to produce power caused by the use of hourly settlements.23 PJM Utilities Coalition also states that sub-hourly settlement would solve the problem of dispatching resources just before or after the clock hour and the resulting implications of averaging output during the clock hour.24 Wartsila states that the transition to sub-hourly settlements provides valuable price signals to flexible capacity and notes that internal combustion engines in SPP have seen a three-fold increase in their capacity factor since SPP adopted sub-hourly real-time settlements, thus increasing compensation to those resources and lowering overall system costs.25

19. PSEG Companies state that the inefficiencies of hourly settlements in PJM's real-time market are evident when the LMP becomes relatively high during the first few dispatch intervals.26 PSEG Companies add that internal resources will ramp up to respond to the price signal and other resources and external suppliers will also schedule interchange into PJM to capture the higher prices; when demand falls off in the subsequent intervals, however, resources will not reduce output in response to the lower prices (because they know they will be compensated at the hourly average prices), which has led to operational problems.27 EPSA supports sub-hourly real-time market settlement in order to better align dispatch with price.28

20. At the Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps Workshop held on October 28, 2014, representatives from RTOs/ISOs discussed the effect of settlement intervals on appropriately compensating resources based on actual performance, on providing an incentive for resources to follow dispatch signals, and on reducing uplift.29 At the Uplift Workshop held on September 8, 2014, the representative from Potomac Economics asserted that settling transactions on an hourly price, when dispatch instructions change every five or fifteen minutes, has caused flexible units in MISO to operate inflexibly in order to obtain a higher hourly price. According to this panelist, this disparity between settlement and dispatch intervals has prompted development of a class of uplift payments meant to hold inflexible generators harmless for following dispatch instructions and to ensure generators' flexibility. This panelist suggested that aligning settlement and dispatch intervals could eliminate such uplift payments.30

21. In its comments, CAISO indicates that it uses both fifteen-minute and five-minute settlement intervals in its real-time market and that these intervals provide a dynamic price signal to reflect grid conditions. According to CAISO, fifteen-minute intertie schedules and prices provide an incentive for variable energy resources to offer economic bids into the CAISO market, which can reduce variable energy resources' exposure to the difference between day-ahead and five-minute real-time prices.31

22. Commenters in the price formation proceeding express caution about implementation and costs resulting from RTOs'/ISOs' adoption of sub-hourly settlements—costs both to RTOs/ISOs and market participants. SPP states that its sub-hourly settlement rules cost more to implement due to increased data storage and validation requirements.32 ISO-NE and GDF SUEZ state that the one impediment to implementing sub-hourly real-time settlements in the ISO-NE market is the need for five-minute revenue quality metering; ISO-NE states that, according to stakeholders, it could take several years to implement and cost up to $20 million to install the necessary equipment, software, and data systems.33 PJM similarly states that moving to sub-hourly settlements will require it to make software and hardware changes to multiple applications and systems at a cost that is anecdotally comparable to a moderately complex market integration proposal.34

23. Several commenters stress that, while sub-hourly settlements can bring benefits and efficiencies to the real-time market, transitioning to that settlement structure would require significant expenditures. Some RTOs/ISOs assert that there will be significant costs to make the necessary upgrades to metering equipment, software, hardware, and data systems, and that some of these upgrades could take several years to implement. As a result of these expenditures, some commenters note that action to align the settlement and dispatch interval may not occur absent a Commission directive.35 Other commenters observe that load-serving entities might incur significant costs associated with telemetry and related equipment upgrades; increases in RTO/ISO administrative charges; and additional costs to meter, transfer, and store the data and to process settlements in accordance with RTO/ISO timelines.36

24. Due to the anticipated costs, several commenters request that the Commission require cost-benefit analyses before adoption of sub-hourly settlements, or that the Commission leave the decision to adopt sub-hourly settlements to RTO/ISO stakeholders.37 Some commenters assert that RTO/ISO stakeholders must vet the implementation of sub-hourly settlements to ensure that appropriate market power mitigation measures are in place.38 Exelon states that, while sub-hourly settlements can improve market efficiency, the timing and prioritization of adopting sub-hourly settlements should be evaluated when RTOs/ISOs develop work plans to analyze the causes of uplift.39

25. Commenters also provide the Commission with recommendations for implementation of sub-hourly settlement. PJM Utilities Coalition recommends that any move to sub-hourly settlements include at least one year notice of intent to allow for system readiness.40 PJM Utilities Coalition suggests that RTOs/ISOs could first transition to fifteen-minute settlement intervals before moving to five-minute settlement intervals with stakeholders vetting the costs and benefits.41 ANGA recommends that, to the extent possible, five-minute settlement intervals be made consistent across different RTOs/ISOs. According to ANGA, inconsistencies across RTO/ISO boundaries can increase market and interchange volatility and result in large price fluctuations that are not based upon market fundamentals and which could create an incentive for gaming between markets as market participants arbitrage distorted prices.42

26. The Commission preliminarily finds that the use of hourly integrated prices for real-time settlement may have the unintended effect of distorting price signals and, in certain instances, contributing to markets failing to respond appropriately to operating needs. Specifically, hourly integrated prices for real-time settlement may (1) not accurately reflect the value a resource provides to the system; (2) discourage resources from following dispatch instructions; and (3) cause increased uplift payments. Therefore, the Commission preliminarily finds that the use of hourly integrated prices for real-time settlement may result in rates that are unjust and unreasonable.

27. First, because hourly prices are an integrated average of sub-hourly dispatch interval prices over an hour, the hourly price does not reflect system needs and costs within a dispatch interval; thus, resources are not necessarily paid a price that reflects the value of the service they provide to the system during the dispatch interval. For example, a resource providing energy during high-priced dispatch intervals, that is then paid based on a lower hourly integrated price, is not compensated based on a price that reflects actual market conditions or the price at which it was economic to dispatch this resource.

28. Real-time settlement using prices that are averaged over an hour cannot capture the varying value of the service resources provide over the hour, which decreases the efficiency of RTO/ISO operations because RTOs/ISOs require resources to move within the hour to address changing operating conditions. Such settlement prices become the prices made transparent to the market and, when they are averaged to the point of not reflecting operating conditions and resultant supply and demand conditions, they may be unjust and unreasonable. In Order No. 719, the Commission found that then-existing rules on shortage pricing “that do not allow for prices to rise sufficiently during an operating reserve shortage to allow supply to meet demand” may be unjust and unreasonable.43 Similarly, the Commission preliminarily finds here that market rules that settle real-time transactions at hourly integrated prices may be unjust and unreasonable because they result in settlement prices that do not reflect actual operating conditions or the value of energy resulting from supply and demand.

29. Second, the use of hourly integrated prices for settling transactions can provide an unwarranted incentive for resources to disregard dispatch instructions. For example, PSEG Companies and PJM Utilities Coalition explain that high prices in the beginning of an hour can cause internal resources to ramp up and external transactions to schedule into PJM to capture higher prices; when demand and prices fall in subsequent intervals, however, hourly integrated prices create an incentive to continue producing or importing energy, regardless of dispatch instructions to reduce output.44

30. As PSEG Companies illustrate by example, the use of hourly integrated prices for real-time settlement can create incentives that do not necessarily align with the system operator's dispatch instructions.45 Consider a resource with $100/MWh cost, and an LMP that is $500/MWh for the first fifteen minutes of the hour (three intervals). Even if the LMP dropped to $0/MWh for the remainder of the hour, the hourly integrated price ($125/MWh) would still exceed the resource's cost of production. This settlement structure would provide an incentive to generate as much energy as possible, not only during the first fifteen minutes of very high prices, but during the entire hour, irrespective of the five-minute price thereafter. Studies have shown that, due to the incentives created by hourly integrated settlements, resources can earn significant additional payments by not following dispatch signals.46

31. Failing to follow dispatch instructions can impair the ability of the system operator to manage dispatch costs. Specifically, failing to follow dispatch instructions can result in power imbalances that the system operator must address by taking action, such as increasing use of regulating reserves or committing additional resources, which may result in increased uplift. These actions result in additional costs that are ultimately passed on to consumers. Because hourly integrated prices can impair the ability of the system operator to manage dispatch and the costs of dispatch, the Commission finds preliminarily that hourly integrated prices for real-time settlement can lead to unjust and unreasonable rates.47

32. Third, as MISO notes, dispatching resources within the hour based on their offers, but then compensating those resources based on a lower hourly integrated price can result in uplift costs because additional uplift payments are then necessary to enhance incentives for resources to follow dispatch instructions.48 A study by Potomac Economics shows that changes to sub-hourly settlement intervals can reduce uplift payments. Specifically, Potomac Economics estimates that, if MISO had implemented a real-time settlement interval that was equal to its dispatch interval (i.e., five minutes) in 2014, it would have reduced uplift payments by approximately $6.6 million.49

33. For these reasons, the Commission proposes to require that each RTO/ISO settle energy transactions in its real-time markets at the same time interval it dispatches energy and settle operating reserves transactions in its real-time markets at the same time interval it prices operating reserves. The Commission also seeks comment on two additional aspects of the proposal, relating to intertie transactions and to operating reserves.

34. To remedy any potentially unjust and unreasonable rates caused by the use of hourly integrated prices for real-time settlement, the Commission proposes, pursuant to section 206 of the FPA,50 to require that each RTO/ISO settle energy transactions in its real-time markets at the same time interval it dispatches energy and settle operating reserves transactions in its real-time markets at the same time interval it prices operating reserves.51

35. As explained further below, in the short term, the settlement interval reform proposed in this NOPR should improve incentives for resources to respond quickly to dispatch instructions, which should in turn lead to operators taking fewer out-of-market actions to ensure that supply meets demand. In the long-term, these reforms should provide more accurate price signals, which should provide, together with other market price signals, the appropriate incentives to build or maintain resources that can respond to an energy or operating reserve deficiency. In addition, where settlement and dispatch intervals are aligned, resources dispatched economically during high-priced periods would receive those high prices rather than an hourly average of the dispatch interval LMPs, thereby reducing the need to make uplift payments. Apportioning a greater proportion of a resource's revenue through payments for energy and operating reserves, rather than through uplift payments, would increase transparency to the market by reflecting the costs of resource dispatch in settlement prices that are factored into a market price. In contrast, uplift payments bundle together a multitude of costs that are not factored into a market price. This increased transparency, in turn, better informs decisions to build or maintain resources and enhances consumers' ability to hedge.

36. By improving resources' response to dispatch instructions, the settlement interval reform proposed herein would result in a more efficient use of generation resources to the benefit of all consumers. As described above, Wartsila explains that internal combustion engines have seen a three-fold increase in their capacity factor since SPP adopted sub-hourly real-time settlements, thus increasing compensation to those resources and lowering overall system costs.52

37. As the Commission has concluded in the past, more efficient use of generation resources can ensure that jurisdictional services are provided at rates, terms, and conditions of service that are just and reasonable and not unduly discriminatory or preferential, in accord with the Commission's statutory obligations.53

38. While the Commission expects that the settlement interval reform proposed in this NOPR should provide significant benefits, the Commission understands that modifying settlement systems can be a complex and costly endeavor.54 Accordingly, the Commission proposes to allow twelve months from the date of the compliance filings for implementation of reforms to settlement systems to become effective. Further, the Commission seeks comment on the potential cost and time necessary to implement the reforms proposed in this NOPR. Specifically, the Commission seeks comment on required software changes, increased data storage and validation, and required changes to market participant metering or other equipment that would result from implementing the reforms proposed in this NOPR. The Commission also seeks comment on whether the changes necessary to implement the settlement interval reform proposed in this NOPR would be necessary in whole or in part to implement other reforms planned by the RTOs/ISOs or sought by stakeholders. The Commission further requests comments concerning whether such a long implementation period is necessary and how that implementation period may be shortened.

39. The Commission also seeks comment on two aspects of the substance of the settlement interval proposal relating to external transactions and to operating reserves. First, the logic underlying our reforms to settlement of internal transactions appears to apply equally to intertie transactions. While the Commission does not propose to extend the reforms to intertie transactions, the Commission seeks comment on whether settlement reforms are appropriate for intertie transactions that are scheduled on intervals different from the intervals on which RTOs/ISOs dispatch internal real-time energy.55 The Commission also seeks comment on whether it is necessary to align the settlement interval for intertie transactions with external scheduling intervals, i.e., fifteen minutes.

40. Second, the Commission recognizes that dispatch and pricing of energy and operating reserves are closely linked through co-optimization in the real-time market. This co-optimization ensures that resources are compensated for following RTO/ISO instructions and are indifferent to providing either energy or operating reserves during periods of high energy or operating reserves prices. Despite the close linkage between energy and operating reserves, the Commission understands that some of the problems associated with the use of hourly integrated prices for settling energy transactions might not apply as fully to settling operating reserves transactions. Further, the Commission recognizes the set of resources that are paid the real-time operating reserve price are potentially much smaller than the set of resources that are paid the real-time energy price. The Commission understands that certain RTOs/ISOs acquire operating reserves on a different interval than these RTOs/ISOs dispatch energy. Accordingly, the Commission seeks comment on whether the Commission should require RTOs/ISOs to settle all real-time operating reserves transactions at the same interval as real-time energy dispatch and settlement intervals or whether a settlement interval that differs from an RTO's/ISO's real-time energy dispatch interval would be appropriate for some operating reserves transactions.

41. Panelists at the October 28, 2014 Shortage Pricing/Mitigation Workshop and commenters in the price formation proceeding discussed shortage pricing triggers. Panelists and commenters were divided on whether all shortage events should trigger shortage pricing.56 Some favored such a trigger. These panelists explained that triggering shortage pricing for any shortage would allow pricing to reflect fluctuations across the hour better and also to offer more granular and accurate compensation.57 In contrast, the panelist from PJM was more hesitant in sending a shortage price signal when a combined-cycle turbine with a thirty-minute startup time took five additional minutes to come online, explaining that a shortage price signal during such an event would diverge from an operator's understanding that the system is not experiencing a shortage.58

42. In its comments, EPSA argues that it is a high priority for all markets to establish shortage pricing based on operating reserves demand curves and co-optimized with the energy market.59 New York Transmission Owners argue that if the electric system is short of resources, even for only five or ten minutes, that shortage should trigger shortage pricing.60 Similarly, NYISO and Potomac Economics state that pricing each shortage, even a “transient shortage,” provides incentives to resources that have the capability to respond to brief-duration shortages.61

43. Several commenters favor triggering shortage pricing without any minimum duration for the event.62 Arguments in favor of triggering shortage pricing for any shortage rely on the need to send price signals that provide an incentive for resources to offer their full flexibility and for market entry by reflecting actual system conditions in real time.63 EEI states that generators should be able to recover reasonable and supportable costs incurred in unexpected circumstances.64 PSEG Companies maintain that, while the ISO-NE and NYISO markets' rules (which price all shortages, no matter the duration) enable them to provide accurate price signals, PJM's market rules (which restrict “transient shortage” events from triggering shortage pricing) can distort its market prices.65

44. In contrast, Wisconsin Electric and PJM prefer that a shortage event last a minimum duration before triggering shortage pricing. Wisconsin Electric argues that there should be a minimum duration for invoking shortage pricing, and that this duration should allow flexibility to account for the nature of transmission limits and reserve levels in the operating environment, with shorter minimum intervals to invoke shortage pricing applicable under extreme load and temperatures.66 PJM states that the minimum duration for shortage pricing should be at least as long as (and perhaps longer than) the settlement interval and that a minimum interval for triggering shortage pricing is required to stimulate investment.67

45. Some commenters argue that a “transient” or relatively brief shortage is not a “real” shortage because either the shortage is merely a mathematical artifact of the modeling, or the shortage will soon be resolved before generators can respond to shortage prices, even though the system is technically short of resources.68

46. Shortage prices send a short-term price signal to provide an incentive for the performance of existing resources and help to maintain reliability.69 However, some RTOs/ISOs currently restrict the triggering of shortage pricing to shortages due only to certain causes, or they require a shortage to exist for a certain time, e.g., thirty minutes, before invoking shortage pricing.70

47. As several commenters during the price formation proceeding noted, not invoking shortage pricing when there is a shortage (regardless of the duration or cause of that shortage) distorts price signals that are designed to elicit increased supply and to compensate resources for the value of the services they provide when the system needs energy or operating reserves. Moreover, prices in each dispatch interval should reflect the value provided by dispatched resources. In times of shortage, the value of services a resource provides increases because operating needs have increased. When shortage pricing is not applied when a shortage exists, the resulting price fails to reflect adequately the value that a resource provides to the system. This failure impairs efficient system dispatch and hinders appropriate incentives for resources to address an energy or operating reserves shortage. Because of such effects, the Commission finds preliminarily that the resulting price is not just and reasonable.

48. In making this preliminary finding, the Commission's rationale here is similar to the rationale the Commission relied on in Order No. 719. In that order, the Commission required shortage pricing in RTOs and ISOs. The Commission reasoned that “rules that do not allow for prices to rise sufficiently during an operating reserve shortage to allow supply to meet demand are unjust, unreasonable, and may be unduly discriminatory.” 71 The Commission added: “In particular, [such rules] may not produce prices that accurately reflect the value of energy. . . .” 72 For similar reasons, the Commission now believes that not invoking shortage pricing during a shortage may result in unjust and unreasonable rates because prices do not accurately reflect the value of energy during a shortage. Accordingly, the Commission preliminarily finds that restricting shortage pricing to shortages lasting longer than one dispatch interval, or not invoking shortage pricing during relatively brief shortages, even though a shortage exists, results in rates that may be unjust and unreasonable.

49. Commenters that do not support triggering shortage pricing during “transient shortages” argue that such shortages can be either merely a mathematical artifact of the modeling, or a shortage that will soon be resolved before generators can respond to shortage prices, even though the system is technically short of resources.73 The Commission, however, believes there are steps an RTO/ISO can take to mitigate seemingly artificial shortages, such as using the RTO's/ISO's look-ahead capability to prevent or minimize the occurrence of shortages that are caused by modeling or other operating deficiencies.74 The Commission believes that reflecting the shortage in prices is still necessary even when a reserve shortage is so short-lived that resources may be unable to respond to the price signal, so that resources operating during the shortage are compensated for the value of the service that they provide. The Commission acknowledges that an RTO/ISO may need to calibrate administrative shortage prices to better reflect the value of the service.75

50. Based upon information gathered during the price formation proceeding and as discussed above, the Commission preliminarily determines that prices that result from a failure to trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs may be unjust and unreasonable.

51. In order to remedy the potentially unjust and unreasonable rates caused by restrictions on shortage pricing, the Commission proposes, pursuant to section 206 of the FPA,76 to require that RTOs/ISOs trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs. The Commission seeks comments on this proposal.

52. The shortage pricing reform in this NOPR should ensure that a resource is compensated based on a price that reflects the value of the service the resource provides. Implementing the shortage pricing reform proposed in this NOPR would ensure that resources have appropriate incentives to address energy or reserve shortages. The Commission expects that if shortage pricing is triggered for all shortage events, then resources are expected to take actions to ensure that they are available to respond to high prices. Resources taking actions to ensure their availability should, in turn, alleviate shortages and avoid shortage pricing during subsequent dispatch intervals.

53. The shortage pricing reform proposed in this NOPR addresses the trigger for invoking shortage pricing, not the shortage price. While the Commission asked commenters to address the level of shortage pricing in the price formation proceeding,77 the Commission is not at this time proposing to change the price paid by any RTO/ISO when it triggers shortage pricing.

54. The Commission expects that implementation of the shortage pricing reform proposed in this NOPR would not be as complex as implementing the proposed settlement interval reform. The Commission therefore proposes that the deadline for full implementation of the shortage pricing reform be effective within four months from the date of the compliance filing in response to a final rule in this proceeding. The Commission seeks comment on whether that proposed compliance and implementation timeline would provide sufficient time for RTOs/ISOs to develop and implement changes to technological systems and business processes in response to a final rule adopting the proposed shortage pricing reform.

55. The Commission proposes to require that each RTO/ISO submit a compliance filing within four months of the effective date of the final Rule in this proceeding to demonstrate that it meets the proposed requirements set forth in the final Rule. While the Commission believes that four months is a reasonable deadline for RTOs/ISOs to submit compliance filings, the Commission understands that the proposed settlement interval reform could take more time to implement than the proposed shortage pricing reform due to the complexity of settlement systems. As discussed above, the Commission proposes (1) to allow twelve months from the date of the compliance filings for implementation of reforms to settlement systems to become effective and (2) to allow four months from the date of the compliance filings for implementation of reforms to shortage pricing to become effective.

56. The Commission seeks comment on the proposed deadline for RTOs/ISOs to submit the compliance filing four months following the effective date of the final rule in this proceeding. Specifically, the Commission seeks comment on whether the proposed compliance timeline would allow sufficient time for RTOs/ISOs to develop and implement changes to technological systems and business processes in response to a final rule.

57. To the extent that any RTO/ISO believes that it already complies with the settlement intervals and shortage pricing reforms proposed in this NOPR, the RTO/ISO would be required to demonstrate how it complies in the filing required four months after the effective date of the final rule in this proceeding. The proposed implementation deadlines would apply only to RTOs/ISOs to the extent they do not already comply with the reforms proposed in this NOPR.

58. The Paperwork Reduction Act (PRA) 78 requires each federal agency to seek and obtain Office of Management and Budget (OMB) approval before undertaking a collection of information directed to ten or more persons or contained in a rule of general applicability. OMB's regulations,79 in turn, require approval of certain information collection requirements imposed by agency rules. Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of a rule will not be penalized for failing to respond to these collection(s) of information unless the collection(s) of information display a valid OMB control number.

59. The reforms proposed in this NOPR would amend the Commission's regulations to improve the operation of organized wholesale electric power markets operated by RTOs and ISOs. The Commission proposes to require that each RTO/ISO (1) settle energy transactions in its real-time markets at the same time interval it dispatches energy and settle operating reserves transactions in its real-time markets at the same time interval it prices operating reserves and (2) trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs. The reforms proposed in this NOPR would require one-time filings of tariffs with the Commission and potential software and hardware upgrades to implement the reforms proposed in this NOPR. The Commission anticipates the reforms proposed in this NOPR, once implemented, would not significantly change currently existing burdens on an ongoing basis. With regard to those RTOs and ISOs that believe that they already comply with the reforms proposed in this NOPR, they could demonstrate their compliance in their compliance in the filing required four months after the effective date of the final rule in this proceeding. The Commission will submit the proposed reporting requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act.80

60. While the Commission expects the adoption of the reforms proposed in this NOPR to provide significant benefits, the Commission understands that implementation and modifying settlement systems can be a complex and costly endeavor. The Commission solicits comments on the accuracy of provided burden and cost estimates and any suggested methods for minimizing the respondents' burdens, including the use of automated information techniques. Specifically, the Commission seeks detailed comments on the potential cost and time necessary to implement aspects of the reforms proposed in this NOPR, including (1) hardware, software, and business processes changes; (2) increased data storage and validation; (3) changes to market participant metering or other equipment; and (4) processes for RTOs and ISOs to vet proposed changes amongst their stakeholders.

61. The Commission also seeks comment on whether changes in settlement systems would disrupt existing contractual relationships and, if so, what burdens this might impose and how the Commission should address any potential issues resulting from such disruption.

Burden Estimate and Information Collection Costs: The Commission believes that the burden estimates below are representative of the average burden on respondents, including necessary communications with stakeholders. The estimated burden and cost 81 for the requirements contained in this NOPR follow.82

Cost to Comply: The Commission has projected the total cost of compliance as follows: 83

After Year 2, the reforms proposed in this NOPR, once implemented, would not significantly change existing burdens on an ongoing basis.

The Commission notes that these estimates do not include costs for software and hardware. Based on comment from industry, current estimates of overall costs for software and hardware could be as high as $20,000,000, for market participants and RTOs/ISOs combined, for each RTO/ISO that does not yet comply with the settlement interval reform proposed in this NOPR.84 As stated above, the Commission requests comment on the estimated costs for any additional software and hardware needed to comply with the reforms proposed in this NOPR.

Title: FERC-516, Electric Rate Schedules and Tariff Filings.

Action: Proposed revisions to an information collection.

OMB Control No. 1902-0096.

Respondents for this Rulemaking: RTOs and ISOs.

Frequency of Information: One-time during years one and two.

Necessity of Information: The Federal Energy Regulatory Commission proposes this rule to improve competitive wholesale electric markets in the RTO and ISO regions.

Internal Review: The Commission has reviewed the proposed changes and has determined that such changes are necessary. These requirements conform to the Commission's need for efficient information collection, communication, and management within the energy industry. The Commission has specific, objective support for the burden estimates associated with the information collection requirements.

62. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], email: [email protected], Phone: (202) 502-8663, fax: (202) 273-0873. Comments concerning the collection of information and the associated burden estimate(s), may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-0710, fax (202) 395-7285]. Due to security concerns, comments should be sent electronically to the following email address: [email protected]. Comments submitted to OMB should include FERC-516 and OMB Control No. 1902-0096.

63. The Regulatory Flexibility Act of 1980 (RFA) 85 generally requires a description and analysis of rules that will have significant economic impact on a substantial number of small entities. The RFA does not mandate any particular outcome in a rulemaking. It only requires consideration of alternatives that are less burdensome to small entities and an agency explanation of why alternatives were rejected.

64. This rule would apply to six RTOs and ISOs (all of which are transmission organizations). The average estimated annual cost to each of the RTOs/ISOs is $89,625 in year 1, and $80,625 in Year 2. This one-time cost of filing and implementing these changes is significant.86 The RTOs and ISOs, however, are not small entities, as defined by the RFA.87 This is because the relevant threshold between small and large entities is 500 employees and the Commission understands that each RTO and ISO has more than 500 employees. Furthermore, because of their pivotal roles in wholesale electric power markets in their regions, none of the RTOs/ISOs meet the last criterion of the two-part RFA definition a small entity: “not dominant in its field of operation.” As a result, the Commission certifies that the reforms proposed in this NOPR would not have a significant economic impact on a substantial number of small entities. The Commission does not expect other entities to incur compliance costs as a result of the reforms proposed in this NOPR, but seeks detailed comments on whether other entities, such as load-serving entities, would incur costs as a result of the reforms proposed in this NOPR.

65. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.88 The Commission concludes that neither an Environmental Assessment nor an Environmental Impact Statement is required for this NOPR under section 380.4(a)(15) of the Commission's regulations, which provides a categorical exemption for approval of actions under sections 205 and 206 of the FPA relating to the filing of schedules containing all rates and charges for the transmission or sale of electric energy subject to the Commission's jurisdiction, plus the classification, practices, contracts and regulations that affect rates, charges, classifications, and services.89

66. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due November 30, 2015. Comments must refer to Docket Nos. RM15-24-000, and must include the commenter's name, the organization they represent, if applicable, and their address.

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

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

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

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

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

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

In consideration of the foregoing, the Commission proposes to amend part 35, chapter I, title 18, Code of Federal Regulations, as follows:

Throughout this document “we,” “us,” or “our” refer to EPA. This section provides additional information by addressing the following:

States are required to submit a progress report in the form of a SIP revision every five years that evaluates progress toward the RPGs for each mandatory Class I Federal area within the state and in each mandatory Class I Federal area outside the state which may be affected by emissions from within the state. 40 CFR 51.308(g). States are also required to submit, at the same time as the progress report, a determination of the adequacy of the state's existing regional haze SIP. 40 CFR 51.308(h). The first progress report SIP is due five years after submittal of the initial regional haze SIP. The Missouri Department of Natural Resources (MDNR) submitted the state's first regional haze SIP on August 5, 2009, and supplemented on January 30, 2012, in accordance with 40 CFR 51.308(b).1

On February 14, 2014, MDNR provided to the Federal Land Managers a revision to Missouri's SIP reporting on progress made during the first implementation period toward RPGs for Class I areas in the state and Class I areas outside the state that are affected by Missouri sources. Missouri has two Class I areas, Mingo National Wildlife Refuge (Mingo) and Hercules Glades Wilderness Area (Hercules Glades). Missouri also hosts an additional Interagency Monitoring of Protected Visual Environments (IMPROVE) monitoring site, located at El Dorado Springs.2 Notification was published on MDNR's Air Pollution Control Program Web site on April 28, 2014. A public hearing was held on held at the St. Louis Regional Office on Thursday, May 29, 2014.

On August 5, 2014, MDNR submitted the five year progress report SIP to EPA. This progress report SIP and accompanying cover letter also included a determination that the state's existing regional haze SIP requires no substantive revision to achieve the established regional haze visibility improvement and emissions reduction goals for 2018. EPA is proposing to approve Missouri's progress report SIP on the basis that it satisfies the requirements of 40 CFR 51.308(g) and 51.308(h).

Under 40 CFR 51.308(g), states must submit a regional haze progress report as a SIP revision every five years and must address, at a minimum, the seven elements found in 40 CFR 51.308(g). As described in further detail in section III below, 40 CFR 51.308(g) requires a description of the status of measures in the approved regional haze SIP; a summary of emissions reductions achieved; an assessment of visibility conditions for each Class I area in the state; an analysis of changes in emissions from sources and activities within the state; an assessment of any significant changes in anthropogenic emissions within or outside the state that have limited or impeded progress in Class I areas impacted by the state's sources; an assessment of the sufficiency of the approved regional haze SIP; and a review of the state's visibility monitoring strategy.

Under 40 CFR 51.308(h), states are required to submit, at the same time as the progress report SIP, a determination of the adequacy of their existing regional haze SIP and to take one of four possible actions based on information in the progress report. As described in further detail in section III below, 40 CFR 51.308(h) requires states to either: (1) Submit a negative declaration to EPA that no further substantive revision to the state's existing regional haze SIP is needed; (2) provide notification to EPA (and other states(s) that participated in the regional planning process) if the state determines that its existing regional haze SIP is or may be inadequate to ensure reasonable progress at one or more Class I areas due to emissions from sources in other state(s) that participated in the regional planning process, and collaborate with these other state(s) to develop additional strategies to address deficiencies; (3) provide notification with supporting information to EPA if the state determines that its existing regional haze SIP is or may be inadequate to ensure reasonable progress at one or more Class I areas due to emissions from sources in another country; or (4) revise its regional haze SIP to address deficiencies within one year if the state determines that its existing regional haze SIP is or may be inadequate to ensure reasonable progress in one or more Class I areas due to emissions from sources within the state.

On August 5, 2014, MDNR submitted a revision to Missouri's regional haze SIP to address progress made toward RPGs of Class I areas in the state and Class I areas outside the state that are affected by emissions from Missouri's sources. This progress report SIP also included a determination of the adequacy of the state's existing regional haze SIP. Missouri has two Class I areas within its borders, and maintains an additional IMPROVE monitoring site. MDNR utilized particulate matter source apportionment (PSAT) techniques for photochemical modeling conducted by the Central Regional Air Planning Association (CENRAP) to identify two Class I areas in nearby Arkansas potentially impacted by Missouri sources: Upper Buffalo Wilderness Area (UBWA) and Caney Creek Wilderness Area (CCWA). 77 FR 38007.

The following sections summarize: (1) Each of the seven elements that must be addressed by the progress report under 40 CFR 51.308(g); (2) how Missouri's progress report SIP addressed each element; and (3) EPA's analysis and proposed determination as to whether the state satisfied each element.

40 CFR 51.308(g)(1) requires a description of the status of implementation of all measures included in the regional haze SIP for achieving RPGs for Class I areas both within and outside the state.

Missouri evaluated the status of all measures included in its 2009 regional haze SIP in accordance with 40 CFR 51.308(g)(1). Specifically, in its progress report SIP, Missouri summarizes the status of the emissions reduction measures that were included in the final iteration of the CENRAP regional haze emissions inventory and RPG modeling. Such control measures included the CAIR, BART, Tier 2 Federal emissions standards for passenger vehicles, EPA's Clean Air Nonroad Diesel Rule (Tier 4), and the NOX SIP Call. Missouri found that these ongoing air pollution control programs are sufficient to meet the 2018 RPGs for Mingo and Hercules Glades Class I areas, and that programs such as CAIR, CSAPR, and BART were very cost-effective in reducing visibility impairment at Missouri's Class I areas.

Missouri also discusses the status of those measures that were not included in the final CENRAP emissions inventory and were not relied upon in the initial regional haze SIP to meet RPGs. The state notes that the emissions reductions from these measures could aid in reducing visibility impairment and in achieving the RPGs in Missouri's Class I areas. The measures include the 2010 SO2 NAAQS Attainment Demonstrations, Illinois Multi-Pollutant Regulation, Federal Tier 3 vehicle emission and fuel standards, and the 2007 Federal Heavy-Duty Highway Rule.

In addition, Missouri addressed facilities with expected emission changes to occur between 2012 and 2017. These changes were not included in the 2009 initial regional haze SIP modeling, as they are not yet permanent and enforceable.

EPA proposes to find that Missouri's analysis adequately addresses 40 CFR 51.308(g)(1). The state documents the implementation status of measures from its regional haze SIP and describes significant measures resulting from EPA regulations other than the regional haze program as they pertain to the state's sources. The progress report SIP highlights the effect of several Federal control measures both nationally and in the CENRAP region, and when possible, in the state.

Regarding the status of BART and reasonable progress control requirements for sources in the state, Missouri's progress report SIP notes that of the twenty-six potential BART sources identified, only one source was subject to BART. This remaining source, Holcim (US) Inc. (Holcim-Clarksville), located in Clarksville, Missouri, entered into a consent agreement with MDNR, and set emissions limits for SO2 and NOX to be met as expeditiously as practicable, but no later than four years after approval of Missouri's regional haze plan. EPA approved their regional haze plan on June 26, 2012 (77 FR 38007), including the consent agreement with Holcim-Clarksville, therefore compliance must be achieved no later than June 26, 2016. Since the consent agreement was signed and initial regional haze plan approved, Holcim-Clarksville discontinued Portland cement manufacturing and hazardous waste fuel burning operations. Remaining operations at the facility include receiving, storing, and shipping. Thus the facility's new SO2 and NOX potential emissions are both zero tons per year, which is included in the state-issued operating permit. Because no other sources were found to be subject to BART, the state found that other emission controls or alternative measures in place of BART were not necessary, and no further discussion of the status of controls was necessary in the progress report SIP.

EPA proposes to conclude that Missouri has adequately addressed the status of control measures in its regional haze SIP as required by 40 CFR 51.308(g)(1). Missouri describes the implementation status of measures from its regional haze SIP, including the status of control measures to meet BART and reasonable progress requirements, the status of significant measures resulting from EPA regulations, as well as measures that came into effect since the CENRAP analyses for the regional haze SIP were completed.

40 CFR 51.308(g)(2) requires a summary of the emissions reductions achieved in the state through the measures subject to 40 CFR 51.308(g)(1).

In its regional haze SIP and progress report SIP, Missouri focuses its assessment on NOX and SO2 emissions from electric generating units (EGUs) because available information from multiple sources (CENRAP, EPA's Clean Air Markets Division (CAMD), etc.) determined that these compounds accounted for the majority of the visibility-impairing pollution in the Central Region.

During the period from 2007-2012, SO2 emissions decreased by 45.6% as a result of several factors, including installation of controls, units switching to cleaner fuels, load shifting from dirtier units to cleaner units, and an overall decrease in demand for generation.3 Missouri noted that the downward trend continued, even though demand increased during the period from 2009 through 2011. Additionally, there was a 43.4 percent decrease in pounds of SO2 generated per MMBtu of energy produced. Missouri stated this decrease in emissions, while demand remained relatively steady, indicates that the reductions reflect cleaner generation and not decreased electricity demand.

During that same period, NOX emissions generally decreased, as did the generation rate of NOX. However, neither NOX emissions nor NOX generation trended downward every year.

Missouri noted that as additional controls are installed to meet the stringent requirements of CSAPR, the Industrial Boiler Maximum Achievable Control Technology (MACT) regulation, and the Mercury and Air Toxics Standard (MATS),4 emission rates are expected to decrease even further. Missouri asserts that the current downward trend, particularly for SO2 as the species of predominant concern to visibility impairment at Mingo and Hercules Glades, plus the imminent implementation of additional federal regulations, reinforces their determination that Missouri's Class I areas will meet the established RPGs in the required timeframe.

EPA proposes to conclude that Missouri has adequately addressed 40 CFR 51.308(g)(2). The state provides actual emissions reductions of NOX and SO2 from EGUs in Missouri that have occurred since Missouri submitted its regional haze SIP. Missouri appropriately focused on SO2, and to a lesser extent, NOX, emissions from its EGUs in its progress report SIP because it previously identified these emissions as the most significant contributors to visibility impairment at Missouri's Class I areas. Given the large SO2 and NOX reductions at EGUs that have actually occurred, further analysis of emissions from other sources or other pollutants was ultimately unnecessary in this first implementation period. Because no additional controls were found to be needed for reasonable progress for the first implementation period for evaluated sources in Missouri, EPA proposes to find that no further discussion of emissions reductions from controls was necessary in this progress report SIP.

40 CFR 51.308(g)(3) requires that states with Class I areas provide the following information for the most impaired and least impaired days for each area, with values expressed in terms of five-year averages of these annual values: 5

Missouri provides figures with the latest supporting data available at the time that it developed the progress report SIP that address the three requirements of 40 CFR 51.308(g)(3) for Mingo and Hercules Glades. For the first regional haze SIPs, baseline conditions were represented by the 2000-2004 time period. 64 FR 35730. Baseline visibility conditions at Mingo are 28.02 deciviews (dv) for the most impaired (20 percent worst) days and 14.3 dv for the least impaired (20 percent best) days. Current visibility conditions (for the five year period from 2008-2012) are 25.7 dv for the 20 percent worst days and 13.1 dv for the 20 percent best days. The difference between current visibility and baseline visibility for the 20 percent worst days is 2.3 dv of improvement (i.e., 28.0-25.7 dv). The difference between current visibility and baseline visibility conditions for the 20 percent best days is 1.2 dv of improvement (i.e., 14.3-13.1 dv). Further, visibility impairment due to SO2 has shown a downward trend (improved visibility) in terms of the 5-year rolling average for the worst 20 percent days for each of the five-year progress periods evaluated by Missouri. Visibility has also improved in nearly all of the five-year progress periods for SO2 for the best 20 percent days. Missouri noted that the goal for the 20 percent best sampling days is to show no degradation in visibility conditions from the baseline; and available monitored data for the first planning period showed no degradation, and in fact showed improvement. Missouri noted that for the worst 20 percent days, the established 2018 RPG is 23.71 dv, and that based on the current rate of improvement, it is expected that this RPG will be met.

Hercules Glades has an established baseline condition of 26.75 dv for the most impaired days. Current visibility conditions (for the five year period from 2008-2012) are 23.5 dv for the 20 percent worst days, showing 3.25 dv of improvement. Baseline conditions for the least impaired days are 12.8 dv. Current visibility conditions are 11.3 dv for the 20 percent best days, showing 1.5 dv of improvement. Further, for both the most impaired days and the least impaired days, there has been a steady downward trend in the rolling average visibility, meaning visibility has improved since the baseline for both the worst and the best days. Looking at SO2, there has been a steady downward trend in visibility impairment since the baseline for the worst 20 percent days, and a general downward trend in visibility impairment since the baseline for the best 20 percent days. Missouri noted that the goal was to show improvement in the worst visibility days, and show no further degradation on the best days; in fact, monitored data showed improvement in both. Missouri also noted that for the worst 20 percent days, the established 2018 RPG is 23.06 dv, and that based on the current rate of improvement, it is expected that this RPG will be met.

Missouri also has an IMPROVE Protocol monitoring site located in El Dorado Springs. This is not a Class I area, but does provide a more comprehensive data set in areas where Class I areas are spread out. Missouri established a baseline condition for the period from 2005-2007, with 26.97 dv for the 20 percent worst days. Missouri stated that the analysis and trends at El Dorado Springs help strengthen the argument that visibility conditions across the entire state, not just at the Class I areas, are improving and are expected to achieve the 2018 RPGs.

Nearby Class I areas in Arkansas were also reviewed in Missouri's progress report SIP. Upper Buffalo Wildlife Area and Caney Creek Wildlife Area both show a downward trend in visibility impairment for the worst 20 percent days. This downward trend is also seen in SO2 measurements and total light extinction. Missouri notes that this trend at the Class I areas outside the state that are affected by Missouri's sources supports the claim that Missouri's current strategy is still adequate and that reductions achieved in Missouri have benefited areas both in and outside the state.

EPA proposes to conclude that Missouri has adequately addressed 40 CFR 51.308(g)(3). The state provides the information regarding visibility conditions and notes that no changes are needed to meet the requirements of 40 CFR 51.308(g)(3). The progress report SIP includes current conditions based on the latest available IMPROVE monitoring data for the years 2008-2012, the difference between current visibility conditions and baseline visibility conditions, and the change in visibility impairment over the most recent five-year period for which data were available at the time of the progress report SIP development (i.e., 2008-2012).

40 CFR 51.308(g)(4) requires an analysis tracking emissions changes of visibility-impairing pollutants from the state's sources by type or category over the past five years based on the most recent updated emissions inventory.

In its progress report SIP, Missouri presents data from a statewide emissions inventories conducted in 2005, 2008, and 2011. This data was reported in the National Emissions Inventory (NEI) for each of those years. Pollutants inventoried include carbon oxides, ammonia, NOX, coarse particulate matter, fine particulate matter (PM2.5), SO2, and volatile organic compounds. The emissions inventories from all three datasets include the following sources: Nonpoint, non-road/area, on-road, point, and biogenic sources. Missouri noted that changes in how data is reported under the NEI may impact certain species.

Missouri examined primarily point-source emissions, because control of point sources provides a higher level of reduction certainty than other source sectors, and therefore is the most relevant to visibility improvement. The state noted that the decreasing trend in point source emissions of SO2 and NOX are of greatest significance to visibility improvement. Other changes in emission levels that were noted include increases in CO levels and increases in PM2.5. Missouri noted that increases in PM2.5 emissions are due to updated stack test emission factors and increased activity at several sources. Missouri also noted that fire source emissions increased for all pollutants between 2008 and 2011, as explained in EPA's 2011 NEIv1 Technical Support Document (November 2013.) This document estimates about 30 percent more acres burned in 2011 than in 2008 due to several forest fires of over 1,000 acres within the Mark Twain National Forest in southern Missouri.

Biogenic emissions also changed between 2008 and 2011, with some pollutants increasing and some decreasing. Missouri notes that the Biogenic Emissions Inventory System (BEIS) version 3.14, developed by EPA to model the biogenic emissions for the NEI, did not address changes to vegetation or other factors between years, so the state cannot specifically address why some pollutants increased.

Missouri noted that the purpose at this point is to evaluate the paramount pollutants to visibility improvement, SO2 and NOX, and notes that both show a steady downward trend over the last five years, which can be linked to steadily improving visibility conditions.

EPA proposes to conclude that Missouri has adequately addressed 40 CFR 51.308(g)(4). While ideally the five-year period to be analyzed for emissions inventory changes is the time period since the current regional haze SIP was submitted, there is an inevitable time lag in developing and reporting complete emissions inventories once quality-assured emissions data becomes available. Therefore, EPA believes there is some flexibility in the five-year time period that states can select, Missouri tracked changes in emissions of visibility-impairing pollutants using the 2005, 2008, and 2011 National Emissions Inventory, the latter of which was the most recent updated inventory of actual emissions for the state at the time that it developed the progress report SIP. EPA believes that Missouri's use of the seven-year period from 2005-2011 reflects a conservative picture of the actual emissions realized between 2005-2014, because there is a general downward trend in both SO2 and NOX emissions.

40 CFR 51.308(g)(5) requires an assessment of any significant changes in anthropogenic emissions within or outside the state that have occurred over the past five years that have limited or impeded progress in reducing pollutant emissions and improving visibility in Class I areas impacted by the state's sources.

In its progress report SIP, Missouri indicates that visibility and pollutant trends from the three monitoring sites have an overall downward trend in visibility impairment. The state noted that an anomalous peak appears in the data for 2010, especially at the El Dorado protocol site. Missouri notes that this can most likely be attributed to a fire event that occurred that year. Missouri State University in Springfield, Missouri, monitored an exceedance of PM2.5 on March 6, 2010. Prior to March 6, 2010, there was a prescribed agricultural burn in the region. The state's current Smoke Management Plan (SMP) establishes a basic framework of procedures and requirements for managing smoke from fires managed for resource benefits. The intent is to mitigate nuisance and public safety hazards; to prevent deterioration of air quality and NAAQS violations; and to address visibility impacts in mandatory federal Class I areas. Missouri noted that if in the future there is a fire event that results in a NAAQS violation or other extreme case, the SMP may be re-evaluated.

EPA proposes to conclude that Missouri has adequately addressed 40 CFR 51.308(g)(5). Missouri demonstrated that there are no significant changes in anthropogenic emissions that have impeded progress in reducing emissions and improving visibility in Class I areas impacted by Missouri's sources. The state referenced its analyses in the progress report SIP identifying an overall downward trend from 2007 to 2012. Further, the progress report SIP shows that Missouri is on track to meet its 2018 emissions projections. Lastly, Missouri acknowledges that plans may be revised as necessary.

40 CFR 51.308(g)(6) requires an assessment of whether the current regional haze SIP is sufficient to enable Missouri, or other states, to meet the RPGs for Class I areas affected by emissions from the state.

In its progress report, Missouri states that it believes that the elements and strategies outlined in its original regional haze SIP are sufficient to enable Missouri and other neighboring states to meet all the established RPGs. To support this, Missouri notes that based on available monitored data, the current trendline is below the glidepath from baseline conditions to the 2018 RPGs. Visibility is improving at both Class I areas in Missouri, at the El Dorado Springs IMPROVE protocol site, and at the two Class I areas in Arkansas affected by Missouri sources. Thus, Missouri concludes that the realized and planned controls and reductions that form the current strategy for this first implementation period are sufficient to meet the established RPGs.

EPA proposes to conclude that Missouri has adequately addressed 40 CFR 51.308(g)(6). EPA views this requirement as a qualitative assessment that should evaluate emissions and visibility trends and other readily available information, including expected emissions reductions associated with measures with compliance dates that have not yet become effective. Missouri referenced the improving visibility trends at affected Class I areas and the downward emissions trends in the state, with a focus on SO2 and NOX emissions from Missouri's EGUs that support Missouri's determination that its regional haze SIP is sufficient to meet RPGs for Class I areas in Missouri and outside of Missouri impacted by Missouri sources. EPA believes that Missouri's conclusion regarding the sufficiency of the regional haze SIP is appropriate because of the calculated visibility improvement using the latest available data and the downward trend in SO2 and NOX emissions from EGUs in Missouri.

40 CFR 51.308(g)(7) requires a review of the state's visibility monitoring strategy and an assessment of whether any modifications to the monitoring strategy are necessary. In its progress report SIP, Missouri summarizes the existing IMPROVE monitoring network and its intended continued reliance on IMPROVE for visibility planning. Missouri notes that it will continue IMPROVE monitoring at Hercules Glades and Mingo, consistent with the requirements of 40 CFR 51.308(d)(4)(iv). Missouri also notes that IMPROVE protocol monitoring will continue at El Dorado Springs, since the data can supplement potential data analysis projects which may be needed to address PM2.5 NAAQS.

EPA proposes to conclude that Missouri has adequately addressed the sufficiency of its monitoring strategy as required by 40 CFR 51.308(g)(7). Missouri reaffirmed its continued reliance upon the IMPROVE monitoring network.

Under 40 CFR 51.308(h), states are required to take one of four possible actions based on the information gathered and conclusions made in the progress report SIP.

In its progress report SIP, Missouri took the action provided for by 40 CFR 51.308(h)(1), which allows a state to submit a negative declaration to EPA if the state determines that the existing regional haze SIP requires no further substantive revision at this time to achieve the RPGs for Class I areas affected by the state's sources. The basis for Missouri's negative declaration is the findings from the progress report (as discussed in section III.A of this action), including the findings that: SO2 and NOX emissions from Missouri's sources have decreased below original projections, that visibility has improved at both Class I areas in Missouri, both Class I areas in Arkansas affected by Missouri's sources, and at the IMPROVE protocol site in Missouri, and that emissions reductions and visibility improvement are expected to continue over the next five years. Based on these findings, EPA proposes to agree with Missouri's conclusion under 40 CFR 51.308(h) that no further substantive changes to its regional haze SIP are required at this time.

Decisions by the Courts regarding EPA rules addressing interstate transport of pollutants have had a substantial impact on EPA's review of the regional haze SIPs of many states. In 2005, EPA issued regulations allowing states to rely on the Clean Air Interstate Rule (CAIR) to meet certain requirements of the Regional Haze Rule. See 70 FR 39104 (July 6, 2005).6 A number of states, including Missouri, submitted regional haze SIPs consistent with these regulatory provisions. CAIR, however, was remanded to EPA in 2008, North Carolina v. EPA, 550 F. 3d 1176, 1178 (D.C. Cir. 2008), and replaced by CSAPR.7 76 FR 48208 (August 8, 2011). Implementation of CSAPR was scheduled to begin on January 1, 2012, when CSAPR would have superseded the CAIR program. However, numerous parties filed petitions for review of CSAPR, and at the end of 2011, the D.C. Circuit issued an order staying CSAPR pending resolution of the petitions and directing EPA to continue to administer CAIR. Order of December 30, 2011, in EME Homer City Generation, L.P. v. EPA, D.C. Cir. No. 11-1302.

EPA finalized a limited approval of Missouri's regional haze SIP on June 26, 2012. 77 FR 38007. In a separate action, published on June 7, 2012, EPA finalized a limited disapproval of the Missouri regional haze SIP because of the state's reliance on CAIR to meet certain regional haze requirements, and issued a Federal Implementation Plan (FIP) to address the deficiencies identified in the limited disapproval of Missouri and other states' regional haze plans. 77 FR 33642 (June 7, 2012). In our FIP, we relied on CSAPR to meet certain regional haze requirements notwithstanding that it was stayed at the time. As we explained, the determination that CSAPR will provide for greater reasonable progress than BART is based on a forward-looking projection of emissions and any year up to 2018 would have been an acceptable point of comparison. Id. At 33647. When we issued this FIP, we anticipated that the requirements of CSAPR would be implemented prior to 2018. Id. Following these EPA actions, however, the D.C. Circuit issued a decision in EME Homer City (696 F.3d 7 (D.C. Cir. 2012)), vacating CSAPR and ordering EPA to continue administering CAIR pending the promulgation of a valid replacement. On April 28, 2014, the Supreme Court reversed the D.C. Circuit's decision on CSAPR and remanded the case to the D.C. Circuit for further proceedings. EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 (2014). After the Supreme Court decision, EPA filed a motion to lift the stay on CSAPR and asked the D.C. Circuit to toll CSAPR's compliance deadlines by three years, so that the Phase 1 emissions budgets apply in 2015 and 2016 (instead of 2012 and 2013), and the Phase 2 emissions budgets apply in 2017 and beyond (instead of 2014 and beyond). On October 23, 2014, the D.C. Circuit granted EPA's motion. Order of October 23, 2014, in EME Homer City Generation, L.P. v. EPA, D.C. Cir. No. 11-1302. EPA issued an interim final rule to clarify how EPA will implement CSAPR consistent with the D.C. Circuit's order granting EPA's motion requesting lifting the stay and tolling the rule's deadlines. 79 FR 71663 (December 3, 2014) (interim final rulemaking).8

Throughout the litigation described above, EPA has continued to implement CAIR. Thus, at the time that Missouri submitted its progress report SIP revision, CAIR was in effect, and the State included an assessment of the emission reductions from the implementation of CAIR in its report. The progress report discussed the status of litigation concerning CAIR and CSAPR, but because CSAPR was not at that time in effect, Missouri did not take emissions reductions from CSAPR into account in assessing its regional haze implementation plan. For the same reason, EPA is not assessing at this time the impact of CSAPR on our FIP on the ability of Missouri and its neighbors to meet their reasonable progress goals.

Given the complex background summarized above, EPA is proposing to determine that Missouri appropriately took CAIR into account in its progress report SIP in describing the status of the implementation of measures included in its regional haze SIP and in summarizing the emissions reductions achieved. CAIR was in effect during the 2008-2014 period addressed by Missouri's progress report. EPA approved Missouri's regulations implementing CAIR as part of the Missouri SIP in 2009, and neither Missouri nor EPA has taken any action to remove CAIR from the Missouri SIP. See 40 CFR 52.2520(c). Therefore, Missouri appropriately evaluated and relied on CAIR reductions to demonstrate the State's progress toward meeting its reasonable progress goals.9 The State's progress report also demonstrated Class I areas in other states impacted by Missouri sources were on track to meet their reasonable progress goals. EPA's intention in requiring the progress reports pursuant to 40 CFR 51.308(g) was to ensure that emission management measures in the regional haze SIPs are being implemented on schedule and that visibility improvement appears to be consistent with the reasonable progress goals. 64 FR 35713, 35747 (July 1, 1999). As the D.C. Circuit only recently lifted the stay on CSAPR, CAIR was in effect in Missouri through 2014, providing the emission reductions relied upon in Missouri's regional haze SIP. Thus, Missouri appropriately took into account CAIR reductions in assessing the implementation of measures in the regional haze SIP for the 2008-2014 timeframe, and EPA believes that it is appropriate to rely on CAIR emission reductions for purposes of assessing the adequacy of Missouri's progress report demonstrating progress up to the end of 2014 as CAIR remained effective until that date, pursuant to 40 CFR 51.308(g) and (h).

In addition, EPA also believes reliance upon CAIR reductions to show Missouri's progress toward meeting its RPGs from 2008-2014 is consistent with our prior actions. During the continued implementation of CAIR per the direction of the D.C. Circuit through October 2014, EPA has approved redesignations of areas to attainment of the 1997 PM2.5 NAAQS in which states relied on CAIR as an “enforceable measure.” See 77 FR 76415 (December 28, 2012) (redesignation of Huntington-Ashland, West Virginia); and similar examples. While EPA did previously state in a rulemaking action on the Florida regional haze SIP that a five year progress report may be the appropriate time to address changes, if necessary, for reasonable progress goal demonstrations and long term strategies, EPA does not believe the remanded status of CAIR or the implementation of its replacement CSAPR at this time impacts the adequacy of the Missouri regional haze SIP to address reasonable progress from 2008 through 2014 to meet requirements in 40 CFR 51.308(g) and (h) because CAIR was implemented during the time period evaluated by Missouri for its progress report. See generally 77 FR 73369, 73371 (December 10, 2012) (proposed action on Florida haze SIP).

EPA's December 3, 2014, interim final rule sunsets CAIR compliance requirements on a schedule coordinated with the implementation of CSAPR compliance requirements. 79 FR at 71655. As noted above, EPA's June 7, 2012, FIP replaced Missouri's reliance upon CAIR for regional haze requirements with reliance on CSAPR to meet those requirements for the long-term. Because CSAPR should result in greater emissions reductions of SO2 and NOX than CAIR throughout the affected region, including in Missouri and neighboring states, EPA expects Missouri to maintain and continue its progress toward its reasonable progress goals for 2018 through continued and additional SO2 and NOX reductions. See generally 76 FR 48208 (promulgating CSAPR).

At the present time, the requirements of CSAPR apply to sources in Missouri under the terms of a FIP, because Missouri to date has not incorporated the CSAPR requirements into its SIP. The Regional Haze Rule requires an assessment of whether the current “implementation plan” is sufficient to enable the states to meet all established reasonable progress goals. 40 CFR 51.308(g)(6). The term “implementation plan” is defined for purposes of the Regional Haze Rule to mean “any [SIP], [FIP], or Tribal Implementation Plan.” 40 CFR 51.301. EPA is, therefore, proposing to determine that we may consider measures in any issued FIP as well as those in a state's regional haze SIP in assessing the adequacy of the “existing implementation plan” under 40 CFR 51.308(g)(6) and (h). Because CSAPR will ensure the control of SO2 and NOX emissions reductions relied upon by Missouri and other states in setting their reasonable progress goals beginning in January 2015 at least through the remainder of the first implementation period in 2018, EPA is proposing to approve Missouri's finding that there is no need for revision of the existing implementation plan for Missouri to achieve the reasonable progress goals for the Class I areas in Missouri and for Class I areas in nearby states impacted by Missouri sources.

We note that the Regional Haze Rule provides for periodic evaluation and assessment of a state's reasonable progress toward achieving the national goal of natural visibility conditions by 2064 for CAA section 169A(b). The regional haze regulations at 40 CFR 51.308 required states to submit initial SIPs in 2007 providing for reasonable progress toward the national goal for the first implementation period from 2008 through 2018. 40 CFR 51.308(b). Pursuant to 40 CFR 51.308(f), SIP revisions reassessing each state's reasonable progress toward the national goal are due every five years after that time. For such subsequent regional haze SIPs, 40 CFR 51.308(f) requires each state to reassess its reasonable progress and all the elements of its regional haze SIP required by 40 CFR 51.308(d), taking into account improvements in monitors and control technology, assessing the state's actual progress and effectiveness of its long term strategy, and revising reasonable progress goals as necessary. 40 CFR 51.308(f)(1)-(3). Therefore, Missouri has the opportunity to reassess its reasonable progress goals and the adequacy of its regional haze SIP, including its reliance upon CAIR and CSAPR for emission reductions from EGUs, when it prepares and submits its second regional haze SIP to cover the implementation period from 2018 through 2028. As discussed previously in this notice, emissions of SO2 and NOX are below original trendline projections for the first implementation period, and in some cases, are below projections for 2018. In addition, the visibility data provided by Missouri shows that their Class I areas and Class I areas affected by Missouri sources are all currently on track to achieve their reasonable progress goals.

EPA is proposing approval of a revision to the Missouri SIP, submitted by the State of Missouri on August 5, 2014, as meeting the applicable regional haze requirements as set forth in 40 CFR 51.308(g) and 51.308(h).

Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the CAA 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 action merely proposes to approve state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this proposed action:

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

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

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

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

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

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

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

• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because this action does not involve technical standards; and

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

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

Effective Date

This proposed rule, if and when final, would become effective on the date that the court enters a consent decree among the United States, the Gulf Coast States and BP with respect to the civil penalty and natural resource damages in MDL No. 2179 (United States District Court for the Eastern District of Louisiana).

The Gulf Coast region is vital to our nation and our economy, providing valuable energy resources, abundant seafood, extraordinary beaches and recreational activities, and a rich natural and cultural heritage. Its waters and coasts are home to one of the most diverse natural environments in the world—including over 15,000 species of sea life and millions of migratory birds. The Gulf has endured many catastrophes, including major hurricanes such as Katrina, Rita, Gustav and Ike in the last ten years alone. The region has also experienced the loss of critical wetland habitats, erosion of barrier islands, imperiled fisheries, water quality degradation and significant coastal land loss. More recently, the health of the region's ecosystem was significantly affected by the Deepwater Horizon oil spill. As a result of the oil spill, the Council has been given the great responsibility of helping to address ecosystem challenges across the Gulf.

In 2010 the Deepwater Horizon oil spill caused extensive damage to the Gulf Coast's natural resources, devastating the economies and communities that rely on it. In an effort to help the region rebuild in the wake of the spill, Congress passed and the President signed the RESTORE Act, Public Law 112-141, Sec. 1601-1608, 126 Stat. 588 (Jul. 6, 2012), codified at 33 U.S.C. 1321(t) and note. The RESTORE Act created the Gulf Coast Restoration Trust Fund (Trust Fund) and dedicates to the Trust Fund eighty percent (80%) of any civil and administrative penalties paid under the Clean Water Act, after enactment of the RESTORE Act, by parties responsible for the Deepwater Horizon oil spill.

Under the RESTORE Act, these funds will be made available through five components. The Department of the Treasury (Treasury) has issued regulations (79 FR 48,039 (Aug. 15, 2014), adopting interim final rule at 31 CFR part 34) (Treasury Regulations) applicable to all five components that generally describe the responsibilities of the Federal and State entities that administer RESTORE Act programs and carry out restoration activities in the Gulf Coast region.

Two of the five components, the Council-Selected Restoration Component and the Spill Impact Component, are administered by the Council, an independent Federal entity created by the RESTORE Act. Under the Spill Impact Component (33 U.S.C. 1321(t)(3)), the subject of this rule, 30 percent of funds in the Trust Fund will be disbursed to the States based on allocation criteria set forth in the RESTORE Act.1 In order for funds to be disbursed to a State, the RESTORE Act requires each State to develop a State Expenditure Plan (SEP) and submit it to the Council for approval. The RESTORE Act specifies particular entities within the States to prepare these plans.

SEPs must meet the following four criteria set forth in the RESTORE Act: (1) All projects, programs and activities (activities) included in the SEP are eligible activities under the RESTORE Act (33 U.S.C. 1321(t)(3)(B)(i)(I)); (2) all activities included in the SEP contribute to the overall economic and ecological recovery of the Gulf Coast (33 U.S.C. 1321(t)(3)(B)(i)(II)); (3) the SEP takes the Council's Comprehensive Plan into consideration and is consistent with the goals and objectives of the Comprehensive Plan (33 U.S.C. 1321(t)(3)(B)(i)(III)); and (4) no more than 25 percent of the allotted funds are used for infrastructure projects unless the SEP contains certain certifications pursuant to 33 U.S.C. 1321(t)(3)(B)(ii). If the Council determines that an SEP meets the four criteria listed above and otherwise complies with the RESTORE Act and the applicable Treasury Regulations, the Council must approve the SEP based upon such determination within 60 days after a State submits an SEP to the Council. 33 U.S.C. 1321(t)(3)(B)(iv).

The funds the Council disburses to the States upon approval of an SEP will be in the form of grants. As required by Federal law, the Council will award a Federal grant or grants to each of the States and incorporate into the grant award(s) standard administrative terms on such topics as recordkeeping, reporting and auditing. The Council will establish and implement a compliance program to ensure that the grants it issues comply with the terms of the grant agreement.

The ultimate amount of administrative and civil penalties potentially available to the Trust Fund is not yet known. On January 3, 2013, the United States announced that Transocean Deepwater Inc. and related entities agreed to pay $1 billion in civil penalties for violating the Clean Water Act in relation to their conduct in the Deepwater Horizon oil spill. The settlement was approved by the court in February 2013, and pursuant to the RESTORE Act approximately $816 million (including interest) has been paid into the Trust Fund. On July 2, 2015, BP announced that it reached Agreements in Principle (AIPs) for settlement of civil claims arising from the Deepwater Horizon oil spill. According to the announcement, the AIPs provide for a payment to the United States of a civil penalty of $5.5 billion under the Clean Water Act, payable over 15 years. As discussed above, the RESTORE Act provides that 80% of civil penalties paid under the Clean Water Act arising out of the Deepwater Horizon oil spill are dedicated to the Trust Fund. There are, however, additional steps that must be completed before those funds become available. The terms of the proposed settlements are subject to a confidentiality order and will not become final until, among other things, a consent decree is negotiated, is made available for public review and comment, and is approved and entered by the court.

This proposed rule establishes the formula for allocating among the five States funds made available through the Spill Impact Component of the Trust Fund (Spill Impact Component), as required by the RESTORE Act, and would supplement the Treasury Regulations. This rule, and the application of any determinations made hereunder, is limited to the Spill Impact Component and is promulgated solely for the purpose of establishing such allocation. The Council takes no position on what data or determinations may be appropriate for other uses, including for any other Component of the RESTORE Act or in connection with natural resource damage assessments, ongoing litigation, any other law or regulation or any rights or obligations in connection therewith.

The RESTORE Act mandates that funds made available from the Trust Fund for the Spill Impact Component be disbursed to each State based on a formula established by the Council by a regulation based on a weighted average of the following three criteria: (1) Forty (40) percent based on the proportionate number of miles of shoreline in each State that experienced oiling on or before April 10, 2011, compared to the total number of miles of shoreline throughout the Gulf Coast region that experienced oiling as a result of the Deepwater Horizon oil spill; (2) forty (40) percent based on the inverse proportion of the average distance from the mobile offshore drilling unit Deepwater Horizon at the time of the explosion to the nearest and farthest point of the shoreline that experienced oiling of each State; and (3) twenty (20) percent based on the average population in the 2010 Decennial Census of coastal counties bordering the Gulf of Mexico within each State. 33 U.S.C. 1321(t)(3)(A)(ii).

For the first criterion, the Council used Shoreline Cleanup and Assessment Technique (SCAT) and Rapid Assessment Technique (RAT) data supplied by the United States Coast Guard. SCAT and RAT represent the U.S. Government's official dataset for tracking and responding to oil spills and thus represent the most consistent, clear and reasonable currently available dataset to use for determining the first criterion, which calls for a determination of the proportionate number of miles of shoreline in each State that experienced oiling on or before April 10, 2011, compared to the total number of miles of shoreline throughout the Gulf Coast region that experienced oiling as a result of the Deepwater Horizon oil spill.

For the second criterion, the Council used the same SCAT and RAT data along with official latitude and longitudinal data supplied by the U.S. Coast Guard to determine the inverse proportion of the average distance from the location of the Deepwater Horizon mobile offshore drilling unit at the time of the explosion to the nearest and farthest point of the shoreline that experienced oiling of each State.

For the third criterion, the Council first had to determine what constituted “coastal counties bordering the Gulf of Mexico within each Gulf Coast State” before it could determine the average population based on the 2010 Decennial Census. The RESTORE Act and Treasury's implementing regulations define the relevant counties for the State of Florida. 33 U.S.C. 1321(t)(1)(C). The Treasury regulations implementing the RESTORE Act specify these counties as: Bay, Charlotte, Citrus, Collier, Dixie, Escambia, Franklin, Gulf, Hernando, Hillsborough, Jefferson, Lee, Levy, Manatee, Monroe, Okaloosa, Pasco, Pinellas, Santa Rosa, Sarasota, Taylor, Wakulla, and Walton. 31 CFR 34.2. For the purposes of this draft rule, the Council proposes to define the Florida counties listed in the Treasury regulations as “coastal counties.”

However, the RESTORE Act does not specifically define the term “coastal counties,” nor does it identify specific counties in the States of Alabama, Louisiana, Mississippi or Texas that are “coastal counties” under the RESTORE Act. Nor does any other relevant Federal law or regulation define or identify these counties. Accordingly, the Council must itself determine which counties in those States qualify as “coastal counties” for the purposes of the Spill Impact Component.

For the States of Alabama, Louisiana, Mississippi and Texas, the Council proposes to interpret the term “coastal counties” as those counties that, according to a generally accessible geographic map of the states, physically touch the Gulf of Mexico. Using this interpretation, the Council proposes identifying the following counties as “coastal counties” for the purposes of the rule: Baldwin and Mobile Counties for Alabama; Cameron, Iberia, Jefferson, Lafourche, Orleans, Plaquemines, St. Bernard, St. Mary, St. Tammany, Terrebonne, and Vermilion Parishes for Louisiana; Hancock, Harrison, and Jackson Counties for Mississippi; and Aransas, Brazoria, Calhoun, Cameron, Chambers, Galveston, Jefferson, Kenedy, Kleberg, Matagorda, Nueces, and Willacy Counties for Texas.

Additionally, with respect to the State of Texas the Council considered the list of coastal counties used by the State of Texas Railroad Commission (TRC) (http://www.rrc.state.tx.us/), the Texas state agency responsible for regulating exploration, production and transportation of oil and natural gas in Texas as well as related pollution prevention measures—matters that are topically related to the purposes of the RESTORE Act. The counties identified in the TRC list are the same as those identified for Texas above.2 The Council also considered other possible sources for determining the Texas coastal counties but has determined that they are insufficient for such purposes.

After determining the “coastal counties,” the RESTORE Act requires the Council to use the 2010 Decennial Census figures for those counties to determine the average population of the coastal counties bordering the Gulf of Mexico within each State.

Using the figures calculated based on the above assumptions and applying the criteria specified in the RESTORE Act, the Council proposes that the final allocation among the five States be: Alabama—20.40%; Florida—18.36%; Louisiana—34.59%; Mississippi—19.07%; and Texas—7.58%.3

After consideration of public comment on this proposed rule, the Council will respond to those comments and revise the rule as appropriate. Consistent with the requirements of the RESTORE Act, the Council will then publicly vote on whether to adopt a final rule and publish the final rule in the Federal Register. 33 U.S.C. 1321(t)(2)(C)(vi). Approval of the rule requires the affirmative vote of the Chairperson and a majority of the five State members. 33 U.S.C. 1321(t)(2)(C)(vi)(I).

The Council does not regard promulgating this proposed rule, including the allocation formula and State allocation percentages set forth herein, as requiring National Environmental Policy Act (NEPA) review, because the Council has no discretion in either establishing such elements of the Spill Impact Component or weighting such elements, both of which are specified in the RESTORE Act.

NEPA review will apply to specific activities undertaken pursuant to Council-approved SEPs that require significant Federal action before they can commence. For example, an SEP project requiring a Federal permit would generally require NEPA review by the issuing Federal agency, and obtaining such a permit might also require other Federal environmental compliance. No SEP implementation funds for an activity will be disbursed by the Council to a State until all requisite permits and licenses have been obtained.

The Council invites public comment on whether the Council's approving and funding SEPs under the RESTORE Act will require NEPA review, as outlined in the following analysis:

The Council does not anticipate that its review or approval of SEPs, or the issuance of related grants under the Spill Impact Component of the RESTORE Act, will require NEPA review. The Council has a limited statutory role in the review of SEPs and administration of Spill Impact Component grants, and a limited timeframe for Council SEP review under the RESTORE Act.

Under the RESTORE Act the Council has no role in the creation of SEPs or the design or selection of Spill Impact Component activities; those activities are undertaken solely by the States. The RESTORE Act specifies the four criteria that SEPs must meet in order to be eligible for funding, and when an SEP meets these criteria the Council has no authority or discretion to reject an SEP, to select or designate alternative versions of an SEP, or to select or designate alternative activities within an SEP. Although the Council must determine whether an SEP has met these criteria, the RESTORE Act does not grant the Council discretion to separately consider external factors, such as environmental impacts, in its review.

NEPA is designed to help Federal agencies consider environmental consequences during their decision-making process, and to consider alternatives to a proposed action. Since the Council has no role in creating SEPs and lacks the discretion to separately consider environmental consequences or SEP alternatives, a NEPA review would have no bearing on the Council's decision to either approve or reject an SEP.

Moreover, under the RESTORE Act the Council is given 60 days after submission of an SEP to approve or disapprove it for funding. This timeframe would not allow the Council sufficient time to conduct meaningful NEPA review. NEPA reviews, even those concluding that environmental impacts are not significant, typically require several months at a minimum—certainly longer than the 60 days allowed for Council approval of an SEP. Nor could the Council require a completed NEPA analysis to accompany a proposed SEP before starting the 60-day review (e.g., as part of or prior to an SEP submission); this would in effect impose an additional criterion for approval of an SEP, which is beyond Council authority under the RESTORE Act.

NEPA would therefore not apply to Council approval or funding of an SEP.

As an independent Federal entity that is composed of, in part, six Federal agencies, including the Departments of Agriculture, the Army, Commerce, and the Interior, and the Department in which the Coast Guard is operating, and the Environmental Protection Agency, the requirements of Executive Orders 12866 and 13563 are inapplicable to this rule.

The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) generally requires agencies to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. This rule will not have a significant economic impact on a substantial number of small entities because the direct recipients of the funds allocated under this rule are the five States, and states are not small entities under the Regulatory Flexibility Act. Additionally, this rule does not place any economic burden on the “coastal counties”; rather those counties will receive funds from their respective States' share of the allocated funds. Therefore, the Council has certified to the Chief Counsel for Advocacy of the Small Business Administration that this rule does not have a significant economic impact on a substantial number of small entities. Thus, an initial regulatory flexibility analysis is not required and has not been prepared. The Council invites comments on the rule's impact on small entities.

This rule is promulgated solely to establish an allocation formula and State allocation percentages. As such, there are no associated paperwork requirements. Any paperwork necessary to submit a SEP under the Spill Impact component of the RESTORE Act is a statutory requirement unaffected by this rule. 31 U.S.C. 1321(t)(3).

The Council requests public and Tribal comment on all aspects of this proposed rule.

For the reasons set forth in the preamble, the Gulf Coast Ecosystem Restoration Council proposes to amend 40 CFR part 1800 as follows:

This is a summary of the Commission's Notice of Proposed Rulemaking, FCC 15-105, released on September 1, 2015. The document is available for download at http://fjallfoss.fcc.gov/edocs-public/. The complete text of this document is also available for inspection and copying during normal business hours in the FCC Reference Information Center, Portals II, 445 12th Street SW., Room CY-A257, Washington, DC 20554. To request materials in accessible formats for people with disabilities (Braille, large print, electronic files, audio format), send an email to [email protected] or call the Consumer & Governmental Affairs Bureau at 202-418-0530 (voice), 202-418-0432 (TTY).

In the Notice of Proposed Rulemaking (NPRM) in PS Docket No. 15-199, the Commission initiates a new proceeding to amend the part 90 rules governing access to public safety interoperability and mutual aid channels. The Commission seeks comment on expanding eligibility to allow railroad police officers employed by Class I, Class II and Class III railroads as defined by the U.S. Department of Transportation's Surface Transportation Board (STB) and recognized by the Federal Railroad Administration (FRA) to operate on public safety interoperability and mutual aid channels. Further, the Commission seeks comment on alternatives for defining eligible railroad police officers, including expanding the definition to include part-time rail police and Amtrak. The Commission also seeks comment on requiring railroad police officers to obtain governmental authorization to operate on the 700 MHz interoperability channels as required by § 90.523 of the Commission's rules and Section 337(f)(1) of the Communications Act of 1934, as amended. Additionally, the Commission seeks comment on requiring railroad police officers seeking to license the interoperability channels to obtain frequency coordination and submit a license application, in the event that it is decided that railroads can operate base and control stations on interoperability channels.

Pursuant to §§ 1.415 and 1.419 of the Commission's rules, 47 CFR 1.415, 1.419, interested parties may file comments and reply comments on or before the dates indicated on the first page of this document. Comments may be filed using the Commission's Electronic Comment Filing System (ECFS). See Electronic Filing of Documents in Rulemaking Proceedings, 63 FR 24121 (1998).

Electronic Filers: Comments may be filed electronically using the Internet by accessing the ECFS: http://fjallfoss.fcc.gov/ecfs2/.

Paper Filers: Parties who choose to file by paper must file an original and one copy of each filing. If more than one docket or rulemaking number appears in the caption of this proceeding, filers must submit two additional copies for each additional docket or rulemaking number.

Filings can be sent by hand or messenger delivery, by commercial overnight courier, or by first-class or overnight U.S. Postal Service mail. All filings must be addressed to the Commission's Secretary, Office of the Secretary, Federal Communications Commission.

All hand-delivered or messenger-delivered paper filings for the Commission's Secretary must be delivered to FCC Headquarters at 445 12th St., SW., Room TW-A325, Washington, DC 20554. The filing hours are 8:00 a.m. to 7:00 p.m. All hand deliveries must be held together with rubber bands or fasteners. Any envelopes and boxes must be disposed of before entering the building.

Commercial overnight mail (other than U.S. Postal Service Express Mail and Priority Mail) must be sent to 9300 East Hampton Drive, Capitol Heights, MD 20743.

U.S. Postal Service first-class, Express, and Priority mail must be addressed to 445 12th Street SW., Washington, DC 20554.

People with Disabilities: To request materials in accessible formats for people with disabilities (braille, large print, electronic files, audio format), send an email to [email protected] or call the Consumer & Governmental Affairs Bureau at 202-418-0530 (voice), 202-418-0432 (tty). Commenters who file information that they believe should be withheld from public inspection may request confidential treatment pursuant to § 0.459 of the Commission's rules. Commenters should file both their original comments for which they request confidentiality and redacted comments, along with their request for confidential treatment. Commenters should not file proprietary information electronically. See Examination of Current Policy Concerning the Treatment of Confidential Information Submitted to the Commission, Report and Order, 13 FCC Rcd 24816 (1998), Order on Reconsideration, 14 FCC Rcd 20128 (1999). Even if the Commission grants confidential treatment, information that does not fall within a specific exemption pursuant to the Freedom of Information Act (FOIA) must be publicly disclosed pursuant to an appropriate request. See 47 CFR 0.461; 5 U.S.C. 552. We note that the Commission may grant requests for confidential treatment either conditionally or unconditionally. As such, we note that the Commission has the discretion to release information on public interest grounds that does fall within the scope of a FOIA exemption.

This proceeding shall be treated as a “permit-but-disclose” proceeding in accordance with the Commission's ex parte rules. Persons making ex parte presentations must file a copy of any written presentation or a memorandum summarizing any oral presentation within two business days after the presentation (unless a different deadline applicable to the Sunshine period applies). Persons making oral ex parte presentations are reminded that memoranda summarizing the presentation must (1) list all persons attending or otherwise participating in the meeting at which the ex parte presentation was made, and (2) summarize all data presented and arguments made during the presentation. If the presentation consisted in whole or in part of the presentation of data or arguments already reflected in the presenter's written comments, memoranda or other filings in the proceeding, the presenter may provide citations to such data or arguments in his or her prior comments, memoranda, or other filings (specifying the relevant page and/or paragraph numbers where such data or arguments can be found) in lieu of summarizing them in the memorandum. Documents shown or given to Commission staff during ex parte meetings are deemed to be written ex parte presentations and must be filed consistent with § 1.1206(b). In proceedings governed by § 1.49(f) or for which the Commission has made available a method of electronic filing, written ex parte presentations and memoranda summarizing oral ex parte presentations, and all attachments thereto, must be filed through the electronic comment filing system available for that proceeding, and must be filed in their native format (e.g., .doc, .xml, .ppt, searchable .pdf). Participants in this proceeding should familiarize themselves with the Commission's ex parte rules.

As required by the Regulatory Flexibility Act of 1980, as amended (RFA) the Commission prepared this Initial Regulatory Flexibility Analysis (IRFA) of the possible significant economic impact on a substantial number of small entities by the policies and rules proposed in this Notice of Proposed Rulemaking (NPRM). Written public comments are requested on this IRFA. Comments must be filed by the same dates as listed on the first page of the NPRM and must have a separate and distinct heading designating them as responses to this IRFA. The Commission will send a copy of the NPRM, including this IRFA, to the Chief Counsel for Advocacy of the Small Business Administration (SBA). In addition, the NPRM and IRFA (or summaries thereof) will be published in the Federal Register.

The NPRM is intended to determine whether it is in the public interest, convenience and necessity to amend the Part 90 rules to reduce regulatory barriers and facilitate railroad police access to public safety interoperability and mutual aid channels. Specifically, in response to a Petition for Rulemaking filed by the National Public Safety Telecommunications Council (NPSTC), the NPRM seeks comment on expanding eligibility to allow railroad police officers employed by a Class I, Class II and Class III railroad as defined by the U.S. Department of Transportation's Surface Transportation Board (STB) and recognized by the Federal Railroad Administration (FRA) to operate on public safety interoperability channels in the VHF and UHF bands below 512 MHz, 700 MHz narrowband and 800 MHz NPSPAC band. Commenters were uniformly supportive of the NPSTC proposal, which the Public Safety and Homeland Security Bureau placed on Public Notice. These commenters, including the U.S. Department of Transportation, cited the safety of life and property role that railroad police officers play in emergencies. In certain emergencies, such as accidents involving railroads or security incidents involving the U.S. rail network, public safety personnel may need to communicate with railroad police. Additionally, Congress enacted the Implementing Recommendations of the 9/11 Commission Act of 2007 (9/11 Recommendations Act), which provides that railroad grant funding may be used, inter alia, to acquire “communications equipment, including equipment that is interoperable with Federal, State, and local agencies and tribal governments[.]” Therefore, in light of the record and expression of Congressional intent, the NPRM seeks comment on amending the eligibility rules applicable to interoperability spectrum.

As discussed below, the Commission has endeavored to keep the burdens associated with this rule change as simple and minimal as possible. The NPRM seeks comment on requiring railroad police officers to obtain governmental authorization to operate on the 700 MHz interoperability channels as required by § 90.523 of the Commission's rules and Section 337(f)(1) of the Communications Act of 1934, as amended. Further, the NPRM seeks comment on requiring railroad police officers seeking to license the interoperability channels to obtain frequency coordination and submit a license application, in the event that it is decided that railroads can operate base and control stations on interoperability channels. Additionally, the NPRM seeks comment on alternatives to licensing on the interoperability channels in order to minimize the burden on railroad entities, as discussed below. OMB, the general public, and other Federal agencies are invited to comment on the new or modified information collection requirements contained in this proceeding. In addition, we note that pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107-198, see 44 U.S.C. 3506(c)(4), we seek specific comment on how the Commission might further reduce the information collection burden for small business concerns with fewer than 25 employees.

Finally, we propose to update § 90.20 of the Commission's rules to explicitly identify the nationwide interoperability channels to facilitate interoperability among Federal, State, Local, Tribal and Railroad Police entities. The Commission concludes that it is necessary to eliminate uncertainty and to codify the flexible licensing approach concerning the use of all the public safety interoperability channels.

These proposed actions are taken under Sections 1, 2, 4(i), 4(j), 301, 303, 316, and 337 of the Communications Act of 1934, as amended, 47 U.S.C. 151, 152, 154(i), 154(j), 301, 303, 316, 332 and 337.

The RFA directs agencies to provide a description of and, where feasible, an estimate of the number of small entities that may be affected by the proposed rules, if adopted. The RFA generally defines the term “small entity” as having the same meaning as the terms “small business,” “small organization,” and “small governmental jurisdiction.” “Small governmental jurisdiction” generally means “governments of cities, counties, towns, townships, villages, school districts, or special districts, with a population of less than 50,000.” The official count of local governments in the United States for 2012 was 90,056, comprising 38,910 general-purpose governments and 51,146 special-purpose governments. General purpose governments include those classified as counties, municipalities, and townships. For this category, census data for 2012 show that there were approximately 37,132 counties, cities and towns that have populations of fewer than 50,000. In addition, the term “small business” has the same meaning as the term “small business concern” under the Small Business Act. A small business concern is one which: (1) Is independently owned and operated; (2) is not dominant in its field of operation; and (3) satisfies any additional criteria established by the SBA. Below, we describe and estimate the number of small entities that may be affected by the rules changes proposed in this NPRM.

Private Land Mobile Radio Licensees. PLMR systems serve an essential role in a range of industrial, business, land transportation, and public safety activities. These radios are used by companies of all sizes operating in all U.S. business categories, and are often used in support of the licensee's primary (non-telecommunications) business operations. Because of the vast array of PLMR users, which includes railroads, the Commission has not developed a small business size standard specifically applicable to PLMR users. The SBA rules, however, contain a definition for Wireless Telecommunications Carriers (except Satellite) which encompasses business entities engaged in radiotelephone communications employing no more than 1,500 persons. For this category, census data for 2007 show that there were 11,163 establishments that operated for the entire year. Of this total, 10,791 establishments had employment of 999 or fewer employees and 372 had employment of 1000 employees or more. Under this category and the associated small business size standard, the Commission estimates that the majority of wireless telecommunications carriers (except satellite) are small entities. The Commission, however, does not require PLMR licensees to disclose information about number of employees, so the Commission does not have information that could be used to determine how many PLMR licensees constitute small entities under this definition. We note that PLMR licensees generally use the licensed facilities in support of other business activities, and therefore, it would also be helpful to assess PLMR licensees under the standards applied to the particular industry subsector to which the licensee belongs.

Public Safety Radio Pool Licensees. As a general matter, Public Safety Radio Pool licensees include police, fire, local government, forestry conservation, highway maintenance, and emergency medical services. Spectrum in the 700 MHz band for public safety services is governed by 47 U.S.C. 337. Non-Federal governmental entities may be eligible licensees for these services. All governmental entities with populations of less than 50,000 fall within the definition of a small entity. According to the Commission's records, there were (1) 1,318 public safety licensees licensed on at least one of the VHF and UHF public safety interoperability channels; (2) 59 public safety licensees licensed on at least one of the narrowband interoperability channels in the public safety band between 764-776 MHz/794-806 MHz; and (3) 4,715 public safety licensees operating in the public safety band between 806-809/851-854 MHz (NPSPAC band). In total there are 6,092 public safety entities, including small governmental jurisdictions, licensed to operate on at least one of the interoperability and mutual aid channels.

Class I, Class II, and Class III Railroads. NPSTC proposes expanding eligibility to operate on the interoperability channels to include full-time railroad police employed by a Class I, II, or III railroad, as defined by the STB and recognized by the FRA. The SBA stipulates “size standards” for small entities. It provides that the largest a for-profit railroad business firm may be and still be classified as a “small entity” is 1,500 employees for “Line-Haul” railroads, and 500 employees for “Short-Line” railroads. SBA size standards may be altered by Federal agencies in consultation with SBA, and in conjunction with public comment. Pursuant to the authority provided to it by SBA, the FRA has published a final policy, which formally establishes small entities as railroads that meet the line haulage revenue requirements of a “Class III railroad.” This threshold is based on the STB's threshold for a Class III railroad carrier, which is adjusted by applying the railroad revenue deflator adjustment. Consistent with FRA's approach, we are using this definition for this rulemaking. Approximately 700 railroads meet the criteria for small entity. We are using this as our estimate of the universe of small entities that could be directly impacted by the proposed rule.

The NPRM seeks comment on expanding eligibility to operate on the interoperability channels. The primary beneficiaries of this increased flexibility would be railroads, including small railroads, and PLMR licensees, including small governmental jurisdictions, that have a need to interoperate with each other. The FCC notes that the requirement that railroads obtain governmental authorization to operate on the 700 MHz interoperability channels is statutorily required and the Commission is without authority to exempt railroads from this requirement. Additionally, railroad entities may be required to obtain frequency coordination and submit a license application on FCC Form 601 in order to license, construct and operate base and control stations on the interoperability channels. The NPRM seeks comment on additional flexibility that may reduce the impact on railroad police officers operating on the interoperability channels. Those alternatives are discussed below.

This NPRM contains modified information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA), Public Law 104-13. It will be submitted to the Office of Management and Budget (OMB) for review under Section 3507(d) of the PRA. The NPRM seeks comment on whether railroad police officers who are certified and/or commissioned as a police officer under the laws of any state, in accordance with the regulations issued by the Secretary of the U.S. Department of Transportation and employed full time as a railroad police officer for a Class I, II, or III railroad, as defined by the U.S. Department of Transportation's Surface Transportation Board and recognized by the Federal Railroad Administration (FRA) should be eligible to operate on the nationwide interoperability and mutual aid channels specified in §§ 90.20 and 90.525 of the Commission's rules. The NPRM also seeks comment on alternatives for defining eligible railroad police officers, including expanding the definition to include part-time rail police and Amtrak consistent with FRA regulations. The NPRM seeks comment on its tentative conclusion that the definition of railroad police officers established by the Department of Transportation best captures the eligibility criteria for railroad police use of the interoperability and mutual aid channels.

The NPRM also seeks comment on requiring railroad police officers to obtain governmental authorization to operate on the 700 MHz interoperability channels as required by § 90.523 of the Commission's rules and Section 337(f)(1) of the Communications Act of 1934, as amended. In accordance with the Paperwork Reduction Act, the Office of Management and Budget (OMB) has already approved the collection of state and local government certifications from non-governmental organizations that seek to operate on the 700 MHz narrowband channels. See ICR Reference Number: 201403-3060-018, OMB Control No. 3060-0805. The nationwide interoperability and mutual aid channels are designed to meet a variety of public safety interoperability needs, but railroad entities have traditionally been licensed in the Industrial/Land Transportation/Business spectrum bands and thus have not been subject to the licensing requirements applicable to the interoperability and mutual aid channels. We do not propose to change the wording of the OMB-approved collection in any material or substantive manner, but we do seek to determine whether railroad police meet the statutory eligibility criteria to operate on the 700 MHz interoperability channels. If so, then only the number of respondents would change as we would expect that railroad police officers will comply with these existing statutory requirements and regulations, which are the minimum necessary to ensure effective use of the spectrum and to minimize interference potential to public safety entities, including State, local and tribal governments. Thus, requiring railroad police to obtain governmental authorization in order to operate on the 700 MHz interoperability channels would increase the number of respondents by approximately 763 entities. See ICR Reference Number: 201308-2130-009, OMB Control No. 2130-0537.

The NPRM also seeks comment on licensing base and control stations on the interoperability and mutual aid channels. The NPRM notes that licensing base and controls stations would require frequency coordination (e.g. railroad police officers would be required to submit a license application on Form 601 demonstrating evidence of frequency coordination). Similarly, mobile-only authorizations require frequency coordination and submission of FCC form 601. Railroad entities seeking licenses in the Industrial Land Transportation and Business Pool are required to obtain coordination from certain frequency coordinators as specified in § 90.35 of the Commission's rules. However, the interoperability and mutual aid channels are subject to frequency coordination from the four certified public safety frequency coordinators as specified in § 90.20(c). OMB has already approved the information collection requirements, including frequency coordination requirement associated with Form 601. See ICR Reference Number: 201311-3060-018, OMB Control No. 3060-0798. We do not propose any substantive or material changes to the wording of the existing information collection. Instead, if we amend to rules to allow railroad police officers to license the interoperability and mutual aid channels, then the number of respondents subject to the existing information collections would increase by approximately 763 entities.

Additionally, the NPRM notes that the 700 MHz interoperability channels are administered by State entities and/or regional planning committees. OMB has already approved the information collections associated with obtaining State/RPC concurrence to operate on the 700 MHz interoperability channels. See ICR Reference Number: 201404-3060-023, OMB Control No. 3060-1198. We do not propose any substantive or material changes to the wording of this existing information collection but if we allow railroad police to operate on these interoperability channels, then the number of respondents subject to the existing information collections would increase by approximately 763 entities.

The NPRM also seeks comment on less burdensome alternatives to licensing, constructing and operating base stations on the interoperability and mutual aid channels. Specifically, the NPRM seeks comment on allowing railroad police officers to (1) operate mobile stations on these channels under a “blanket” licensing approach or (2) allowing public safety licensees to share their facilities with railroad police pursuant to a sharing agreement. With regard to blanket licensing, we would essentially clarify that Section 90.421 permits railroad police to operate mobile stations so long as their employer holds a PLMR license and therefore would not impose any new or modified information collections requirements. However, allowing public safety entities to “share” their facilities with railroad police would require reducing such an arrangement into writing as required by § 90.179. OMB has already approved the information collection requirements in § 90.179 and we do not propose any substantive or material changes to the wording of the existing information collection. See ICR Reference Number: 200111-3060-016, OMB Control No. 3060-0262. If we amend the eligibility rules, then the number of respondents would increase by approximately 763 entities.

The Commission believes that applying the same information collection rules equally to public safety and railroad police entities in this context will promote interoperability and advance Congressional objectives. The Commission does not believe that the costs and/or administrative burdens associated with the rules will unduly burden small entities. The rule revisions the Commission proposes should benefit public safety and railroad police entities by giving them more flexibility, and more options for gaining access to interoperability and mutual aid spectrum. As noted above, the FCC invites comment on these new or modified information collection requirements.

Finally, the rule amendment proposed relative to § 90.20(i) has been analyzed with respect to the Paperwork Reduction Act of 1980 and found to contain no new or modified form, information collection and/or record keeping, labeling, disclosure, or record retention requirements; and will not increase burden hours imposed on the public.

The RFA requires an agency to describe any significant, specifically small business, alternatives that it has considered in reaching its proposed approach, which may include the following four alternatives (among others): (1) The establishment of differing compliance or reporting requirements or timetables that take into account the resources available to small entities; (2) the clarification, consolidation, or simplification of compliance and reporting requirements under the rule for small entities; (3) the use of performance rather than design standards; and (4) an exemption from coverage of the rule, or any part thereof for small entities. We have evaluated our proposals in this NPRM in the context of small business entities and find no alternatives, to the benefit of small entities that would achieve our goals of facilitating interoperability between public safety entities and railroad police officers and efficient use of nationwide interoperability spectrum. Additionally, this NPRM proposes rules that are deregulatory in nature and consistent with Federal railroad interoperability mandates. Accordingly, the proposed rule changes minimize any significant economic impact on small entities.

The NPRM also seeks comment on four alternatives that may minimize the impact on small entities, including small railroads. First, the NPRM seeks comment on issuing a mobile-only license that would allow railroad police officers to operate mobiles on the interoperability channels without having to construct and operate base and control stations. Second, the NPRM seeks comment on “blanket licensing”, an approach that would allow railroad police officers to operate on the interoperability channels provided their railroad employer already holds a license for PLMR spectrum. Third, the NPRM seeks comment on amending Section 90.421 of the Commission's rules to allow railroad police officers to operate mobiles under the license of public safety licensees. Fourth, the NPRM seeks comment on amending Section 90.179 to allow public safety entities to “share” their facilities with railroad police. Any significant alternative presented in the comments will be considered.

Finally, we propose to amend Section 90.20 of the Commission's rules to explicitly identify the nationwide interoperability channels i.e. the VHF, UHF and 700 MHz interoperability channels, and the 800 MHz mutual aid channels. We believe that flexible licensing policies are necessary to encourage the use of the most spectrally efficient technology to meet user-defined needs. Recognizing the budgetary constraints that small public safety entities face, we seek to make explicit in the Commission's rules the flexible licensing approach that the Commission previously adopted for all of the public safety interoperability channels.

None.

Accordingly, IT IS ORDERED, pursuant to sections 1, 2, 4(i), 4(j), 301, 302, 303, 308, 309, 316, 324, and 332 of the Communications Act of 1934, as amended, 47 U.S.C. 151, 152, 154(i), 154(j), 301, 302a, 303, 308, 309, 324, 316, 332 and 337, that this Notice of Proposed Rulemaking is hereby ADOPTED.

It is further ordered that pursuant to applicable procedures set forth in §§ 1.415 and 1.419 of the Commission's rules, 47 CFR 1.415 and 1.419, interested parties may file comments on the NPRM on or before November 13, 2015, and reply comments on or before November 30, 2015.IT IS FURTHER ORDERED that the Commission's Consumer and Governmental Affairs Bureau, Reference Information Center, SHALL SEND a copy of this Notice of Proposed Rulemaking, including the Initial Regulatory Flexibility Analysis, to the Chief Counsel for Advocacy of the Small Business Administration.

For the reasons discussed in the preamble, the Federal Communications Commission proposes to amend CFR 47 part 90 as follows:

Section 118 of the MMPA requires NMFS to place all U.S. commercial fisheries into one of three categories based on the level of incidental mortality and serious injury of marine mammals occurring in each fishery (16 U.S.C. 1387(c)(1)). The classification of a fishery on the LOF determines whether participants in that fishery may be required to comply with certain provisions of the MMPA, such as registration, observer coverage, and take reduction plan requirements. NMFS must reexamine the LOF annually, considering new information in the Marine Mammal Stock Assessment Reports (SARs) and other relevant sources, and publish in the Federal Register any necessary changes to the LOF after notice and opportunity for public comment (16 U.S.C. 1387 (c)(1)(C)).

The definitions for the fishery classification criteria can be found in the implementing regulations for section 118 of the MMPA (50 CFR 229.2). The criteria are also summarized here.

The fishery classification criteria consist of a two-tiered, stock-specific approach that first addresses the total impact of all fisheries on each marine mammal stock and then addresses the impact of individual fisheries on each stock. This approach is based on consideration of the rate, in numbers of animals per year, of incidental mortalities and serious injuries of marine mammals due to commercial fishing operations relative to the potential biological removal (PBR) level for each marine mammal stock. The MMPA (16 U.S.C. 1362 (20)) defines the PBR level as the maximum number of animals, not including natural mortalities, that may be removed from a marine mammal stock while allowing that stock to reach or maintain its optimum sustainable population. This definition can also be found in the implementing regulations for section 118 of the MMPA (50 CFR 229.2).

Tier 1: Tier 1 considers the cumulative fishery mortality and serious injury for a particular stock. If the total annual mortality and serious injury of a marine mammal stock, across all fisheries, is less than or equal to 10 percent of the PBR level of the stock, all fisheries interacting with the stock will be placed in Category III (unless those fisheries interact with other stock(s) in which total annual mortality and serious injury is greater than 10 percent of PBR). Otherwise, these fisheries are subject to the next tier (Tier 2) of analysis to determine their classification.

Tier 2: Tier 2 considers fishery-specific mortality and serious injury for a particular stock.

Category I: Annual mortality and serious injury of a stock in a given fishery is greater than or equal to 50 percent of the PBR level (i.e., frequent incidental mortality and serious injury of marine mammals).

Category II: Annual mortality and serious injury of a stock in a given fishery is greater than 1 percent and less than 50 percent of the PBR level (i.e., occasional incidental mortality and serious injury of marine mammals).

Category III: Annual mortality and serious injury of a stock in a given fishery is less than or equal to 1 percent of the PBR level (i.e., a remote likelihood of or no known incidental mortality and serious injury of marine mammals).

Additional details regarding how the categories were determined are provided in the preamble to the final rule implementing section 118 of the MMPA (60 FR 45086, August 30, 1995).

Because fisheries are classified on a per-stock basis, a fishery may qualify as one Category for one marine mammal stock and another Category for a different marine mammal stock. A fishery is typically classified on the LOF at its highest level of classification (e.g., a fishery qualifying for Category III for one marine mammal stock and for Category II for another marine mammal stock will be listed under Category II). Stocks driving a fishery's classification are denoted with a superscript “1” in Tables 1 and 2.

The tier analysis requires a minimum amount of data, and NMFS does not have sufficient data to perform a tier analysis on certain fisheries. Therefore, NMFS has classified certain fisheries by analogy to other Category I or II fisheries that use similar fishing techniques or gear that are known to cause mortality or serious injury of marine mammals, or according to factors discussed in the final LOF for 1996 (60 FR 67063, December 28, 1995) and listed in the regulatory definition of a Category II fishery: “In the absence of reliable information indicating the frequency of incidental mortality and serious injury of marine mammals by a commercial fishery, NMFS will determine whether the incidental mortality or serious injury is `frequent,' `occasional,' or `remote' by evaluating other factors such as fishing techniques, gear used, methods used to deter marine mammals, target species, seasons and areas fished, qualitative data from logbooks or fisher reports, stranding data, and the species and distribution of marine mammals in the area, or at the discretion of the Assistant Administrator for Fisheries” (50 CFR 229.2).

Further, eligible commercial fisheries not specifically identified on the LOF are deemed to be Category II fisheries until the next LOF is published (50 CFR 229.2).

The LOF includes a list of marine mammal species and/or stocks incidentally killed or injured in each commercial fishery. The list of species and/or stocks incidentally killed or injured includes “serious” and “non-serious” documented injuries as described later in the List of Species and/or Stocks Incidentally Killed or Injured in the Pacific Ocean and the Atlantic Ocean, Gulf of Mexico, and Caribbean sections. To determine which species or stocks are included as incidentally killed or injured in a fishery, NMFS annually reviews the information presented in the current SARs and injury determination reports. The SARs are based upon the best available scientific information and provide the most current and inclusive information on each stock's PBR level and level of interaction with commercial fishing operations. The best available scientific information used in the SARs reviewed for the 2016 LOF generally summarizes data from 2008-2012. NMFS also reviews other sources of new information, including injury determination reports, bycatch estimation reports, observer data, logbook data, stranding data, disentanglement network data, fisher self-reports (i.e. MMPA reports), and anecdotal reports from that time period. In some cases, more recent information may be available, but in an effort to be consistent with the most recent SARs and across the LOF, NMFS typically restricts the analysis to data within the five-year time period summarized in the current SAR.

For fisheries with observer coverage, species or stocks are generally removed from the list of marine mammal species and/or stocks incidentally killed or injured if no interactions are documented in the five-year timeframe summarized in that year's LOF. For fisheries with no observer coverage and for observed fisheries with evidence indicating that undocumented interactions may be occurring (e.g., fishery has low observer coverage and stranding network data include fisheries that cannot be attributed to a specific fishery) species and stocks may be retained for longer than five years. For these fisheries, NMFS will review the other sources of information listed above and use its discretion to decide when it is appropriate to remove a species or stock.

The best available information on the level of observer coverage and the spatial and temporal distribution of observed marine mammal interactions is presented in the SARs. Data obtained from the observer program and observer coverage levels are important tools in estimating the level of marine mammal mortality and serious injury in commercial fishing operations. Starting with the 2005 SARs, each SAR includes an appendix with detailed descriptions of each Category I and II fishery on the LOF, including the observer coverage in those fisheries. The SARs generally do not provide detailed information on observer coverage in Category III fisheries because, under the MMPA, Category III fisheries are generally not required to accommodate observers aboard vessels due to the remote likelihood of mortality and serious injury of marine mammals. Fishery information presented in the SARs' appendices and other resources referenced during the tier analysis may include: Level of observer coverage, target species, levels of fishing effort, spatial and temporal distribution of fishing effort, characteristics of fishing gear and operations, management and regulations, and interactions with marine mammals. Copies of the SARs are available on the NMFS Office of Protected Resources Web site at: http://www.nmfs.noaa.gov/pr/sars/. Information on observer coverage levels in Category I, II, and III fisheries can be found in the fishery fact sheets on the NMFS Office of Protected Resources' Web site: http://www.nmfs.noaa.gov/pr/interactions/fisheries/lof.html. Additional information on observer programs in commercial fisheries can be found on the NMFS National Observer Program's Web site: http://www.st.nmfs.gov/st4/nop/.

This rule includes three tables that list all U.S. commercial fisheries by LOF Category. Table 1 lists all of the commercial fisheries in the Pacific Ocean (including Alaska); Table 2 lists all of the commercial fisheries in the Atlantic Ocean, Gulf of Mexico, and Caribbean; and Table 3 lists all U.S.-authorized commercial fisheries on the high seas. A fourth table, Table 4, lists all commercial fisheries managed under applicable take reduction plans (TRPs) or take reduction teams (TRTs).

Beginning with the 2009 LOF, NMFS includes high seas fisheries in Table 3 of the LOF, along with the number of valid High Seas Fishing Compliance Act (HSFCA) permits in each fishery. As of 2004, NMFS issues HSFCA permits only for high seas fisheries analyzed in accordance with the National Environmental Policy Act (NEPA) and the Endangered Species Act (ESA). The authorized high seas fisheries are broad in scope and encompass multiple specific fisheries identified by gear type. For the purposes of the LOF, the high seas fisheries are subdivided based on gear type (e.g., trawl, longline, purse seine, gillnet, troll, etc.) to provide more detail on composition of effort within these fisheries. Many fisheries operate in both U.S. waters and on the high seas, creating some overlap between the fisheries listed in Tables 1 and 2 and those in Table 3. In these cases, the high seas component of the fishery is not considered a separate fishery, but an extension of a fishery operating within U.S. waters (listed in Table 1 or 2). NMFS designates those fisheries in Tables 1, 2, and 3 by a “*” after the fishery's name. The number of HSFCA permits listed in Table 3 for the high seas components of these fisheries operating in U.S. waters does not necessarily represent additional effort that is not accounted for in Tables 1 and 2. Many vessels/participants holding HSFCA permits also fish within U.S. waters and are included in the number of vessels and participants operating within those fisheries in Tables 1 and 2.

HSFCA permits are valid for five years, during which time Fishery management plans (FMPs) can change. Therefore, some vessels/participants may possess valid HSFCA permits without the ability to fish under the permit because it was issued for a gear type that is no longer authorized under the most current FMP. For this reason, the number of HSFCA permits displayed in Table 3 is likely higher than the actual U.S. fishing effort on the high seas. For more information on how NMFS classifies high seas fisheries on the LOF, see the preamble text in the final 2009 LOF (73 FR 73032; December 1, 2008). Additional information about HSFCA permits can be found at: http://www.nmfs.noaa.gov/ia/permits/highseas.html.

Starting with the 2010 LOF, NMFS developed summary documents, or fishery fact sheets, for each Category I and II fishery on the LOF. These fishery fact sheets provide the full history of each Category I and II fishery, including: When the fishery was added to the LOF, the basis for the fishery's initial classification, classification changes to the fishery, changes to the list of species and/or stocks incidentally killed or injured in the fishery, fishery gear and methods used, observer coverage levels, fishery management and regulation, and applicable TRPs or TRTs, if any. These fishery fact sheets are updated after each final LOF and can be found under “How Do I Find Out if a Specific Fishery is in Category I, II, or III?” on the NMFS Office of Protected Resources' Web site: http://www.nmfs.noaa.gov/pr/interactions/fisheries/lof.html, linked to the “List of Fisheries by Year” table. NMFS is developing similar fishery fact sheets for each Category III fishery on the LOF. However, due to the large number of Category III fisheries on the LOF and the lack of accessible and detailed information on many of these fisheries, the development of these fishery fact sheets is taking significant time to complete. NMFS will begin posting Category III fishery fact sheets online with the proposed 2016 LOF.

Owners of vessels or gear engaging in a Category I or II fishery are required under the MMPA (16 U.S.C. 1387(c)(2)), as described in 50 CFR 229.4, to register with NMFS and obtain a marine mammal authorization to lawfully take non-endangered and non-threatened marine mammals incidental to commercial fishing operations. Owners of vessels or gear engaged in a Category III fishery are not required to register with NMFS or obtain a marine mammal authorization.

NMFS has integrated the MMPA registration process, implemented through the Marine Mammal Authorization Program (MMAP), with existing state and Federal fishery license, registration, or permit systems for Category I and II fisheries on the LOF. Participants in these fisheries are automatically registered under the MMAP and are not required to submit registration or renewal materials. In the Pacific Islands, West Coast, and Alaska regions, NMFS will issue vessel or gear owners an authorization certificate via U.S. mail or with their state or Federal license or permit at the time of issuance or renewal. In the Greater Atlantic Region, NMFS will issue vessel or gear owners an authorization certificate via U.S. mail automatically at the beginning of each calendar year. Certificates may also be obtained by visiting the Greater Atlantic Regional Office Web site (http://www.greateratlantic.fisheries.noaa.gov/Protected/mmp/mmap/). In the Southeast Region, NMFS will issue vessel or gear owners notification of registry and vessel or gear owners may receive their authorization certificate by contacting the Southeast Regional Office at 727-209-5952 or by visiting the Southeast Regional Office Web site (http://sero.nmfs.noaa.gov/protected_resources/marine_mammal_authorization_program/) and following the instructions for printing the certificate.

The authorization certificate, or a copy, must be on board the vessel while it is operating in a Category I or II fishery, or for non-vessel fisheries, in the possession of the person in charge of the fishing operation (50 CFR 229.4(e)). Although efforts are made to limit the issuance of authorization certificates to only those vessel or gear owners that participate in Category I or II fisheries, not all state and Federal license or permit systems distinguish between fisheries as classified by the LOF. Therefore, some vessel or gear owners in Category III fisheries may receive authorization certificates even though they are not required for Category III fisheries. Individuals fishing in Category I and II fisheries for which no state or Federal license or permit is required must register with NMFS by contacting their appropriate Regional Office (see ADDRESSES).

In Alaska regional and Greater Atlantic regional fisheries, registrations of vessel or gear owners are automatically renewed and participants should receive an authorization certificate by January 1 of each new year. In Pacific Islands regional fisheries, vessel or gear owners receive an authorization certificate by January 1 for state fisheries and with their permit renewal for federal fisheries. In West Coast regional fisheries, vessel or gear owners receive authorization with each renewed state fishing license, the timing of which varies based on target species. Vessel or gear owners who participate in fisheries in these regions and have not received authorization certificates by January 1 or with renewed fishing licenses must contact the appropriate NMFS Regional Office (see FOR FURTHER INFORMATION CONTACT).

In Southeast regional fisheries, vessel or gear owners' registrations are automatically renewed and participants will receive a letter in the mail by January 1 instructing them to contact the Southeast Regional Office to have an authorization certificate mailed to them or to visit the Southeast Regional Office Web site (http://sero.nmfs.noaa.gov/protected_resources/marine_mammal_authorization_program/) to print their own certificate.

In accordance with the MMPA (16 U.S.C. 1387(e)) and 50 CFR 229.6, any vessel owner or operator, or gear owner or operator (in the case of non-vessel fisheries), participating in a fishery listed on the LOF must report to NMFS all incidental mortalities and injuries of marine mammals that occur during commercial fishing operations, regardless of the category in which the fishery is placed (I, II, or III) within 48 hours of the end of the fishing trip or, in the case of non-vessel fisheries, fishing activity. “Injury” is defined in 50 CFR 229.2 as a wound or other physical harm. In addition, any animal that ingests fishing gear or any animal that is released with fishing gear entangling, trailing, or perforating any part of the body is considered injured, regardless of the presence of any wound or other evidence of injury, and must be reported.

Mortality/injury reporting forms and instructions for submitting forms to NMFS can be found at: http://www.nmfs.noaa.gov/pr/interactions/mmap/#form or by contacting the appropriate Regional office (see FOR FURTHER INFORMATION). Forms may be submitted via any of the following means: (1) Online using the electronic form, (2) emailed as an attachment to [email protected], (3) faxed to the NMFS Office of Protected Resources at 301-713-0376, or (4) mailed to the NMFS Office of Protected Resources (mailing address is provided on the postage-paid form that can be printed from the Web address listed above). Reporting requirements and procedures can be found in 50 CFR 229.6.

Individuals participating in a Category I or II fishery are required to accommodate an observer aboard their vessel(s) upon request from NMFS. MMPA section 118 states that the Secretary is not required to place an observer on a vessel if the facilities for quartering an observer or performing observer functions are so inadequate or unsafe that the health or safety of the observer or the safe operation of the vessel would be jeopardized; thereby authorizing the exemption of vessels too small to accommodate an observer from this requirement. However, U.S. Atlantic Ocean, Caribbean, or Gulf of Mexico large pelagics longline vessels operating in special areas designated by the Pelagic Longline Take Reduction Plan implementing regulations (50 CFR 229.36(d)) will not be exempted from observer requirements, regardless of their size. Observer requirements can be found in 50 CFR 229.7.

Table 4 in this rule provides a list of fisheries affected by TRPs and TRTs. TRP regulations can be found at 50 CFR 229.30 through 229.37. A description of each TRT and copies of each TRP can be found at: http://www.nmfs.noaa.gov/pr/interactions/trt/teams.html. It is the responsibility of fishery participants to comply with applicable take reduction regulations.

Information regarding the LOF and the Marine Mammal Authorization Program, including: registration procedures and forms; current and past LOFs; descriptions of each Category I and II fishery, and some Category III fisheries; observer requirements; and marine mammal mortality/injury reporting forms and submittal procedures; may be obtained at: http://www.nmfs.noaa.gov/pr/interactions/fisheries/lof.html, or from any NMFS Regional Office at the addresses listed below:

NMFS, Greater Atlantic Regional Fisheries Office, 55 Great Republic Drive, Gloucester, MA 01930-2298, Attn: Allison Rosner;

NMFS, Southeast Region, 263 13th Avenue South, St. Petersburg, FL 33701, Attn: Jessica Powell;

NMFS, West Coast Region, Seattle Office, 7600 Sand Point Way NE., Seattle, WA 98115, Attn: Elizabeth Petras or Brent Norberg, Protected Resources Division;

NMFS, Alaska Region, Protected Resources, P.O. Box 22668, 709 West 9th Street, Juneau, AK 99802, Attn: Bridget Mansfield; or

NMFS, Pacific Islands Regional Office, Protected Resources Division, 1845 Wasp Blvd., Building 176, Honolulu, HI 96818, Attn: Nancy Young.

NMFS reviewed the marine mammal incidental mortality and serious injury information presented in the SARs for all fisheries to determine whether changes in fishery classification are warranted. The SARs are based on the best scientific information available at the time of preparation, including the level of mortality and serious injury of marine mammals that occurs incidental to commercial fishery operations and the PBR levels of marine mammal stocks. The information contained in the SARs is reviewed by regional Scientific Review Groups (SRGs) representing Alaska, the Pacific (including Hawaii), and the U.S. Atlantic, Gulf of Mexico, and Caribbean. The SRGs were created by the MMPA to review the science that informs the SARs, and to advise NMFS on marine mammal population status, trends, and stock structure, uncertainties in the science, research needs, and other issues.

NMFS also reviewed other sources of new information, including marine mammal stranding data, observer program data, fisher self-reports through the Marine Mammal Authorization Program, reports to the SRGs, conference papers, FMPs, and ESA documents.

The LOF for 2016 was based on, among other things, stranding data; fisher self-reports; and SARs, primarily the 2014 SARs, which are generally based on data from 2008-2012. The final SARs referenced in this LOF include: 2013 (79 FR 49053, August 19, 2014) and 2014 (80 FR 50599, August 20, 2015). The SARs are available at: http://www.nmfs.noaa.gov/pr/sars/.

The following summarizes proposed changes to the LOF for 2016, including the fisheries listed in the LOF, the estimated number of vessels/persons in a particular fishery, and the species and/or stocks that are incidentally killed or injured in a particular fishery. The proposed LOF for 2016 proposes three re-classifications of the fisheries provided in the LOF for 2015. NMFS proposes changes to the list of species and/or stocks killed or injured in certain fisheries and the estimated number of vessels/persons in certain fisheries, as well as certain administrative changes. Additionally, NMFS proposes adding two Category III fisheries to the LOF and removing six fisheries from the LOF. Most Category III fisheries on the LOF have never been described in the LOF. While detailed information describing each fishery in the LOF is included within the SARs, a Fishery Management Plan, or a TRP, or by state agencies, general descriptive information is important to include in the LOF for improved clarity. NMFS is developing Category III fishery fact sheets that will be available online at: http://www.nmfs.noaa.gov/pr/interactions/fisheries/lof.html. NMFS is requesting public comment on fact sheet content. The classifications and definitions of U.S. commercial fisheries for 2016 are identical to those provided in the LOF for 2015 with the proposed changes discussed below. State and regional abbreviations used in the following paragraphs include: AK (Alaska), BSAI (Bering Sea and Aleutian Islands), CA (California), DE (Delaware), FL (Florida), GMX (Gulf of Mexico), HI (Hawaii), MA (Massachusetts), ME (Maine), NC (North Carolina), NY (New York), OR (Oregon), RI (Rhode Island), SC (South Carolina), VA (Virginia), WA (Washington), and WNA (Western North Atlantic).

NMFS proposes to reclassify the Category III Alaska Bering Sea/Aleutian Island Pacific Cod Longline Fishery as Category II. Category II classification for this fishery is driven by a 2012 take of Gulf of Alaska, Bering Sea/Aleutian Islands transient stock of killer whales. Based on the most recent five years of available information, annual mortality and serious injury of the Gulf of Alaska, Bering Sea/Aleutian Islands transient stock of killer whales across all fisheries is 1 per year, which is 17 percent of the PBR of 5.87. Mortality and serious injury of this stock by this fishery is 0.2 per year, which is 3.41 percent of the PBR of 5.87 (Helker et al., 2015). Mortality and serious injury levels greater than 1 percent and less than 50 percent of PBR meet the Category II threshold. Therefore, NMFS proposes to reclassify the Alaska Bering Sea/Aleutian Island Pacific Cod Longline Fishery as a Category II fishery.

NMFS proposes to reclassify the Category II Alaska Kodiak Salmon Purse Seine Fishery as Category III. No mortalities or serious injuries to marine mammal stocks by this fishery have been documented during the most recent five years of available information. Therefore, NMFS proposes to reclassify the Alaska Kodiak Salmon Purse Seine Fishery as a Category III fishery.

NMFS proposes to reclassify the Category II Alaska Cook Inlet Salmon Purse Seine Fishery as Category III. No mortalities or serious injuries to marine mammal stocks by this fishery have been documented during the most recent five years of available information. Therefore, NMFS proposes to reclassify the Alaska Cook Inlet Salmon Purse Seine Fishery as a Category III fishery.

NMFS proposes to add the CA sea cucumber trawl fishery to the LOF as Category III. NMFS reviewed the recently published Magnuson-Stevens Fishery Conservation and Management Act List of Authorized Fisheries and Gear (79 FR 76914, December 23, 2014) and spoke with the California Department of Fish and Wildlife (CDF&W) and determined that this fishery was not included in the MMPA LOF. This is one of two gear types authorized by the state of California to commercially harvest sea cucumber. Most of the effort with trawls occurs in southern California. NMFS proposes to list this fishery as Category III analogous to the WA/OR/CA shrimp trawl fishery because the fisheries use similar fishing techniques, habitat, and gear. There were 16 permits issued for this fishery in 2013.

NMFS proposes to add the WA/OR Mainstem Columbia River eulachon gillnet fishery to the LOF as Category III. NMFS spoke with the Washington Department of Fish and Wildlife (WDF&W) and Oregon Department of Fish and Wildlife (OD&W) and determined this fishery was not previously on the LOF. Eulachon smelt were historically harvested in target fisheries in the Columbia River. As a result of the eulachon listing under the Endangered Species Act in 2010 commercial harvest was prohibited. The commercial fishery using dip net gear was closed in 2011 through 2013. In 2014 and 2015 a small-scale, research-based commercial eulachon fishery using gillnet gear was re-established to collect biological and catch per unit effort data. NMFS proposes to list this as Category III by analogy to other gillnet fisheries because the fisheries use similar fishing techniques, habitat, and gear. There are currently 15 participants in this fishery.

NMFS proposes to remove the Category III WA/OR herring, smelt, shad, sturgeon, bottom fish, mullet, perch, rockfish gillnet fishery from the LOF. NMFS spoke with WDF&W and ODF&W and was advised that gillnet is not legal for any ocean fishing off of Washington or Oregon.

NMFS proposes to remove the Category III WA/OR smelt, herring dip net fishery from the LOF. Harvesting smelt and herring off Oregon is allowed but this gear type is not utilized. Herring harvest off Washington is closed. Smelt can be harvested off Washington using dip net gear; however, there are currently no participants in the fishery.

NMFS proposes to rename the Category III “WA (all species) beach seine or drag seine” as the “WA/OR Lower Columbia River salmon seine” fishery. Drag seine is not an authorized gear in Oregon. While authorized in Washington, it is not active. In 2014, a pilot commercial seine fishery was implemented in the mainstem Columbia River downstream of Bonneville Dam. The pilot fishery was conducted to address research-related questions regarding use of this gear type in a new commercial fishery. A total of 10 fishers using seine gear (4 purse seine and 6 beach seine) were permitted for the 2014 pilot fishery.

NMFS proposes to split three fisheries from the Category III “AK North Pacific halibut, AK bottom fish, WA/OR/CA albacore, groundfish, bottom fish, CA halibut non-salmonid troll” fishery and rename them as: “WA/OR/CA albacore surface hook and line/troll” fishery, “CA halibut hook and line/handline” fishery, and “CA White seabass hook and line/handline” fishery and remove the remaining fisheries in the group. The WA/OR/CA albacore surface hook and line/troll fishery uses surface hook and line and/or troll gear and is managed under the Fishery Management Plan (FMP) of U.S. West Coast Fisheries for Highly Migratory Species. There is effort in this fishery along the entire coast and landings can be made in any of the three states. The number of vessels making landing in 2013 was 705. The CA halibut hook and line/handline fishery is managed by the CDF&W and is one of three gear types authorized by the state of California to commercially harvest CA halibut (along with gillnet and trawl). It is a not restrictive fishery and no special permits are required. Most landings occur in the San Francisco Bay area. The CA white seabass hook and line/handline fishery is managed by the CDF&W and is one of two gear types authorized by the state of California to commercially harvest CA white seabass (along with gillnets). There are no special permits required in this fishery. Most effort occurs in Southern California.

NMFS proposes to combine the Category III “CA anchovy, mackerel, sardine purse seine” and “WA/OR sardine purse seine” fisheries and name it the “CA/OR/WA anchovy, mackerel, sardine purse seine” fishery. These species are managed under the Coastal Pelagic Species FMP developed by the Pacific Fishery Management Council and can be harvested along the entire coast.

NMFS proposes to rename the Category III “WA/OR salmon net pens” fishery as the “WA salmon net pen” fishery. There are no commercial non-tribal salmon net pens in Oregon.

NMFS proposes to rename (by revising, separating, and combining) the Category III “WA/OR sea urchin, other clam, octopus, oyster, sea cucumber, scallop, ghost shrimp, dive, hand/mechanical collection” and “CA sea urchin” fisheries to become the “WA/OR bait shrimp, clam hand, dive or mechanical collection” and “OR/CA sea urchin, sea cucumber dive, hand/mechanical collection” fisheries. Some of the target species listed in the “WA/OR sea urchin, other clam, octopus, oyster, sea cucumber, scallop, ghost shrimp, dive, hand/mechanical collection” have changed, have been prohibited, or are no longer active so the new name reflects target species in the WA/OR fishery. NMFS is proposing to combine the OR and CA components of the sea urchin and sea cucumber dive, hand/mechanical collections because these fisheries are functionally equivalent.

NMFS proposes to rename the Category III “WA shellfish aquaculture” fishery as the “WA/OR shellfish aquaculture” fishery. There are a number of shellfish being raised in aquaculture facilities in Oregon and the fisheries are functionally equivalent. There are 23 companies engaged in shellfish aquaculture in Washington and Oregon.

NMFS proposes to update the estimated number of vessels/persons in the Pacific Ocean (Table 1) as follows. Fisheries are labeled with their name on the proposed 2016 LOF: