Federal Register Vol. 82, No.87,

Comments Invited

We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the ADDRESSES section. Include “Docket No. FAA-2017-0417; Directorate Identifier 2017-CE-008-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://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.

On September 6, 2002, we issued AD 2002-19-01, Amendment 39-12881 (67 FR 59137; September 20, 2002) (“AD 2002-19-01”). That AD requires actions intended to address an unsafe condition on SOCATA Model TBM 700 airplanes and was based on mandatory continuing airworthiness information (MCAI) originated by an aviation authority of another country.

Since we issued AD 2002-19-01, a revision to the service information was issued to provide instructions for replacement of the rivets in the roll primary stops as a terminating action for the repetitive inspections.

The European Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Community, has issued EASA AD No.: 2017-0018, dated February 3, 2017 (referred to after this as “the MCAI”), to correct an unsafe condition for the specified products. The MCAI states:

SOCATA has issued DAHER SOCATA Mandatory Service Bulletin SB 70-095, Revision 2, dated October 2016, which describes procedures for replacement of the flight control wheel primary stop rivets; and EADS SOCATA SB 70-114-27, dated December 2004, which describes procedures for installation of roll control emergency stops on the flight control wheel.

SOCATA issued SOCATA TBM Aircraft Mandatory SB 70-095 27, dated November 2001, approved for incorporation by reference on October 29, 2002 (67 FR 59137; September 20, 2002), which describes procedures for testing the pilot and right-hand (RH) station control wheels for jamming and procedures for adjusting the roll control stops if jamming occurs.

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.

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

DAHER SOCATA Mandatory Service Bulletin SB 70-095, Revision 2, dated October 2016, requires a modification that terminates any repetitive inspections and also gives credit for another modification that may have previously been done. We are retaining the repetitive inspection requirement from AD 2002-19-01 and allowing installation of one of the two different modifications as terminating action for the repetitive inspections.

We estimate that this proposed AD will affect 203 products of U.S. registry.

For inspection of the pilot and right-hand (RH) station control wheels we estimate that it would take about 1 hour per product to comply with the basic requirements of this proposed AD. The average labor rate is $85 per work-hour. Based on these figures, we estimate the cost of the inspection on U.S. operators to be $17,255, or $85 per product.

In addition, we estimate that any necessary follow-on actions would cost the following amounts. We have no way of determining the number of products that may need these actions.

We estimate that it will take about 3 work-hours per product for any adjustment of the roll control stops if jamming occurs on either the pilot control wheel or the RH station control wheel. The average labor rate is $85 per work-hour. Based on these figures, we estimate the cost of this action on U.S. operators to be $255 per product.

For replacement of the rivets in the roll primary stops we estimate that it would take about 3.5 work-hours per product to comply with the basic requirements of this proposed AD. The average labor rate is $85 per work-hour. Required parts would cost about $10 per product. Based on these figures, for replacement of the rivets we estimate the cost of the proposed AD on U.S. operators to be $307.50 per product.

For the installation of a roll control emergency stop on each control wheel we estimate that it would take about 19.5 work-hours per product to comply with the basic requirements of this proposed AD. The average labor rate is $85 per work-hour. Required parts would cost about $1,650 per product. Based on these figures, for installation of the roll control emergency stop, we estimate the cost of the proposed AD on U.S. operators to be $3,307.50 per product.

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

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

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

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

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

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

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

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

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

I. Background A. Statutory and Regulatory Background

As amended by the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”),3 sections 4d(d) and 4s(k) of the Commodity Exchange Act (“CEA” or “Act”) require each Registrant to designate an individual to serve as its CCO.4 Sections 4s(k)(2) and (3) set forth certain requirements and duties for CCOs of SDs and MSPs, including the requirement to prepare and sign an annual compliance report (“CCO Annual Report”).5 CEA section 4d(d) requires CCOs of FCMs to “perform such duties and responsibilities” as are established by Commission regulation or the rules of a registered futures association.6 In 2012, the Commission adopted regulations 3.3(d) through (f) implementing the duties described in CEA sections 4d(d) and 4s(k).7

Using language identical to CEA section 4s(k), the Dodd-Frank Act amended the Securities Exchange Act of 1934 (“Exchange Act”) by adding section 15F(k) to establish the same CCO requirements for security-based swap dealers and major security-based swap participants (collectively, “SEC Registrants”).8 In compliance with sections 712(a)(1)-(2) of the Dodd-Frank Act, the Commission and SEC staffs consulted and coordinated together and with prudential regulators in developing the respective CCO rules for purposes of regulatory consistency and comparability.9

The SEC initially proposed rule 15Fk-1 to implement CCO requirements and duties for SEC Registrants in July 2011.10 In May 2013, after the CFTC adopted the CCO Rules, the SEC re-opened the comment period for its outstanding Dodd-Frank Act Title VII rulemakings, including rule 15Fk-1.11 In its reopening release, the SEC sought comment on, among other things: (1) The relationship of the proposed SEC rules to any parallel CFTC requirements; and (2) the extent to which the SEC should emphasize consistency with the CFTC rules or should tailor its rules to the security-based swap market.12 Comments received by the SEC largely urged the SEC to harmonize its business conduct rules, including rule 15Fk-1, with those of the CFTC because the industry had already implemented the CFTC's regulations.13 Specifically, with respect to supervision and CCO obligations, commenters urged that the SEC's final rules “be informed by industry experience complying with . . . the CFTC internal business conduct standards” among others.14 A number of comments also suggested specific conforming modifications to the SEC's proposed rules.15

SEC staff continued to consult with CFTC staff leading up to adoption of the SEC's business conduct standards rules, which became effective July 12, 2016.16 As explained in the SEC Adopting Release, the SEC modified the proposed rules “to harmonize with CFTC requirements to create efficiencies for entities that have already established infrastructure for compliance with analogous CFTC requirements” where such modifications “will continue to provide the protections (as explained in the context of the particular rule) that the rules were intended to accomplish.” 17

Although the SEC's CCO rules are largely harmonized with the CFTC's corresponding regulations, rule 15Fk-1 as adopted differs in several respects. Based on CFTC staff experience in implementing the CCO Rules, review of the comments to the proposed SEC rule 15Fk-1, and discussions with SEC staff, the Commission believes that some of the differences adopted by the SEC are beneficial for market participants and regulatory oversight.

The CCO Rules, among other things, seek to ensure that the CCO is actively engaged in compliance activities with the appropriate authority, resources, and access to the board of directors or senior officer to administer the firm's compliance activities.18 As described below, the proposed amendments to the CCO Rules preserve these objectives and should increase efficiencies, reduce regulatory burden, particularly for dual registrants, and further clarify the scope of CCO duties.

The Commission proposes to add a definition of “senior officer” to § 3.1 to provide greater clarity regarding the CCO reporting line required by CEA section 4s(k)(2)(A) and § 3.3(a)(1) of the Commission's regulations.19 The Commission has not previously formally defined this term for purposes of the CCO Rules. However, Commission staff has generally interpreted this term to refer to a Registrant's most senior officer, typically the chief executive officer or the equivalent. This interpretation is consistent with the SEC's definition of “senior officer” in SEC rule 15Fk-1(e)(2). Accordingly, the Commission is proposing to define “senior officer” in new paragraph (j) to § 3.1 as “the chief executive officer or other equivalent officer of a registrant.”

This definition is in keeping with the Commission's continued belief that, as stated in the CCO Rules Adopting Release, a “direct reporting line” from the CCO to the board of directors or highest executive officer ensures CCO independence.20 The “chief executive officer” is typically the highest executive level, but the definition includes the phrase “other equivalent officer” to acknowledge that a firm may have a different title for the highest executive officer.

Request for comment: The Commission requests comment regarding the proposed definition in § 3.1. The Commission specifically requests comment on the following questions:

• Should the proposed definition for “senior officer” be revised? If yes, please provide alternative suggestions.

• Should other definitions be added?

Paragraph (d) of § 3.3 implements the CCO duties required by CEA section 4s(k). Generally, paragraph (d) requires the CCO to: (1) Establish and administer policies and procedures, including those related to ensuring compliance and remediating noncompliance issues; (2) resolve any conflicts of interest; and (3) prepare the CCO Annual Report. Based on the practical experience gained from four years of implementation, the Commission has determined that certain CCO Rules could be revised to more accurately convey the Commission's intent with respect to the scope of the CCO's duties and to further harmonize with the SEC's recently finalized CCO rules. In this regard, the proposed amendments are intended to maintain and clarify the underlying goal of the CCO's active engagement in compliance monitoring while reducing regulatory burdens that provide limited corresponding benefit.21

Paragraph (d)(1) of § 3.3 implements CEA section 4s(k)(2)(D), which requires a CCO to “be responsible for administering each policy and procedure that is required to be established pursuant to this section.” 22 The current text of § 3.3(d)(1) states that the CCO's duties include “administering the registrant's policies and procedures reasonably designed to ensure compliance with the Act and Commission regulations.” 23 The Commission is proposing to amend § 3.3(d)(1) to require the CCO to administer “each of the registrant's policies and procedures relating to its business as a futures commission merchant, swap dealer, or major swap participant that are required to be established pursuant to the Act and Commission regulations.”

The proposed change clarifies that the CCO is responsible for administering the policies and procedures specifically related to the Registrant's business as a SD, MSP, or FCM, as applicable, not all of the Registrant's business that may otherwise be subject to CFTC regulation. Further, the proposed change more closely tracks the language of CEA section 4s(k)(2)(D) and is consistent with the Commission's stated intent when finalizing the CCO Rules.24 Finally, the amended rule text more closely tracks the language of the SEC's parallel rule 25 and should alleviate concerns regarding consistency with the SEC's interpretation of identical statutory language as it applies to dual CFTC Registrants and SEC Registrants.

Paragraph (d)(2) of § 3.3 requires the CCO to, in consultation with the board of directors or the senior officer, resolve any conflicts of interest that may arise. The Commission is proposing to modify § 3.3(d)(2) to clarify that the CCO must take “reasonable steps” to resolve conflicts. This proposed change makes explicit an implied reasonableness standard and recognizes that resolution of non-material conflicts need not always require the CCO's direct expertise or directly involve the board of directors or senior officer.26

The Commission is of the view that a CCO's duty to resolve conflicts of interest should not be interpreted to require the CCO to personally resolve every potential conflict of interest that may arise or require consultation with the board of directors or senior office. If strictly interpreted, the current rule text creates an undue burden on CCOs, likely taking them away from more important compliance activities. The proposed changes are intended to clarify that routinely encountered conflicts could be resolved in the normal course of business consistent with the CCO's general administration of internal policies and procedures, which must include conflicts of interest policies.27 With this amendment, the CCO and his or her resources may more effectively engage in working to resolve conflicts practically and within normal business operations procedures.

Similarly, the SEC in its adopting release noted that the CCO's role in resolving conflicts of interest would likely include the recommendation of actions to resolve the conflict, as well as the escalation and reporting of issues related to resolution, but not executing the business decisions to ultimately resolve the conflict.28 The SEC articulated this understanding in its final rule 15Fk-1(b)(3) by requiring a CCO to “take reasonable steps” to resolve conflicts of interests. The Commission believes it is appropriate to incorporate this language into § 3.3(d)(2) to more accurately reflect its interpretation of the statutory requirement.

The Commission proposes to amend paragraph (d)(3) of § 3.3 to incorporate further guidance regarding the extent of a CCO's compliance duties. Current § 3.3(d)(3) effectuates CEA section 4s(k)(2)(E) 29 by requiring CCOs to take “reasonable steps to ensure compliance with the Act and Commission regulations relating to the swap dealer's or major swap participant's swaps activities, or to the futures commission merchant's business as a futures commission merchant.” 30 The Commission proposes to amend § 3.3(d)(3) by clarifying that the CCO's duty in this subsection includes “ensuring the registrant establishes, maintains and reviews written policies and procedures reasonably designed to achieve compliance” with the Act and Commission regulations. This change is consistent with the SEC's parallel rule.31

When finalizing § 3.3(d)(3), the Commission intended to address commenter concerns that fully “ensuring compliance” with the CEA could be an impracticable standard for CCOs and that the regulatory responsibility for ensuring compliance is ultimately borne by the registrant.32 The Commission modified the proposal in the final rule by limiting the CCO duties to taking “reasonable steps to ensure compliance” rather than simply “ensure compliance.” 33

Under the authority provided in 14 U.S.C. 85, 43 U.S.C. 1333, and Department of Homeland Security Delegation No. 0170.1, Title 33, CFR 147.1 and 147.10 permit the establishment of safety zones for facilities located on the Outer Continental Shelf (OCS) for the purpose of protecting life and property on the facilities, their appurtenances and attending vessels, and on the adjacent waters within the safety zones.

The safety zone proposed by this rulemaking is on the OCS in the deepwater area of the Gulf of Mexico at Green Canyon Block 468. The area for the safety zone would be 500 meters (1640.4 feet) from each point on the facility, which is located at 27°30′33.3431″ N., 90°33′22.963″ W. For the purpose of the safety zone, the deepwater area is waters of 304.8 meters (1,000 feet) or greater depth extending to the limits of the Exclusive Economic Zone (EEZ) contiguous to the territorial sea of the United States and extending to a distance up to 200 nautical miles from the baseline from which the breadth of the sea is measured. Navigation in the vicinity of the safety zone consists of large commercial shipping vessels, fishing vessels, cruise ships, tugs with tows and the occasional recreational vessels. The deepwater area also includes an extensive system of fairways.

HESS Corporation requested that an OCS safety zone extending 500 meters from each point on the Stampede Tension Leg Platform (TLP) facility structure's outermost edge is required. There are safety concerns for both the personnel aboard the facility and the environment. The District Commander has determined that it was highly likely that any allision with the facility would result in a catastrophic event. Placing a safety zone around the facility will significantly reduce the threat of allisions, oil spills, and releases of natural gas, and thereby protect the safety of life, property, and the living marine resources.

In evaluating this request, the Coast Guard explored relevant safety factors and considered several criteria, including but not limited to (1) the level of the existing and foreseeable shipping activity around the facility, (2) safety concerns for personnel aboard the facility, (3) concerns for the environment, (4) the likelihood that an allision would result in a catastrophic event based on the proximity to shipping fairways, offloading operations, production levels, and size of the crew, (5) the volume of traffic in the vicinity of the proposed safety zone, (6) the types of vessels navigating in the vicinity of the proposed area, and (7) the structural configuration of the facility.

Results from a thorough and comprehensive examination of the criteria, International Maritime Organization (IMO)'s guidelines, and existing regulations, warrant the establishment of a safety zone of 500 meters around the facility. The proposed safety zone would significantly reduce the threat of allisions, oil spills, and releases of natural gas, and increase the safety of life, property, and the environment in the Gulf of Mexico by prohibiting entry into the zone. Only vessels measuring less than 100 feet in length overall and not engaged in towing, attending vessels as defined in 33 CFR 147.20, or those vessels specifically authorized by the Eighth Coast Guard District Commander or a designated representative would be permitted to enter the proposed safety zone.

We developed this proposed rule after considering numerous statutes and executive orders related to rulemaking, and we considered the First Amendment rights of protestors. Below we summarize our analyses based on a number of these statutes or executive orders.

Executive Orders 12866 (“Regulatory Planning and Review”) and 13563 (“Improving Regulation and Regulatory Review”) direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. Executive Order 13771 (“Reducing Regulation and Controlling Regulatory Costs”), directs agencies to reduce regulation and control regulatory costs and provides that “for every one new regulation issued, at least two prior regulations be identified for elimination, and that the cost of planned regulations be prudently managed and controlled through a budgeting process.”

The Office of Management and Budget (OMB) has not designated this proposed rule a significant regulatory action under section 3(f) of Executive Order 12866. Accordingly, the Office of Management and Budget (OMB) has not reviewed it. As this proposed rule is not a significant regulatory action, this proposed rule is exempt from the requirements of Executive Order 13771. See OMB's Memorandum titled “Interim Guidance Implementing Section 2 of the Executive Order of January 30, 2017 titled `Reducing Regulation and Controlling Regulatory Costs' ” (February 2, 2017). A regulatory analysis (RA) follows.

This proposed rule is not a significant regulatory action due to the location of the Stampede TLP, on the Outer Continental Shelf, and its distance from both land and safety fairways. Vessels traversing waters near the proposed safety zone will be able to safely travel around the zone using alternate routes. Exceptions to this proposed rule include vessels measuring less than 100 feet in length overall and not engaged in towing. The Eighth Coast Guard District Commander, or a designated representative, will consider requests to transit through the proposed safety zone on a case-by-case basis.

The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities.

This proposed rule would affect the following entities, some of which might be small entities: The owners or operators of vessels intending to transit or anchor in Green Canyon Block 468.

This safety zone will not have a significant economic impact or a substantial number of small entities for the following reasons. Vessel traffic can pass safely around the safety zone using alternate routes. Based on the limited scope of the safety zone, any delay resulting from using an alternate route is expected to be minimal depending on vessel traffic and speed in the area. Additionally, exceptions to this proposed rule include vessels measuring less than 100 feet in length overall and not engaged in towing, as well as any attending vessel, as defined in 33 CFR 147.20. Entry into and transit through the proposed safety zone may be requested. Such requests will be considered on a case-by-case basis and may be authorized by the Eighth Coast Guard District Commander or a designated representative.

If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see ADDRESSES) explaining why you think it qualifies and how and to what degree this rule would economically affect it.

Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this proposed rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section. The Coast Guard will not retaliate against small entities that question or complain about this proposed rule or any policy or action of the Coast Guard.

This proposed rule would not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

A rule has implications for federalism under Executive Order 13132, Federalism, if it has 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. We have analyzed this proposed rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.

Also, this proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. If you believe this proposed rule has implications for federalism or Indian tribes, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section.

The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.

We have analyzed this proposed rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.1D, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves establishing a safety zone around an offshore deepwater facility. Normally such actions are categorically excluded from further review under paragraph 34(g) of Figure 2-1 of Commandant Instruction M16475.lD. We seek any comments or information that may lead to the discovery of a significant environmental impact from this proposed rule.

The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the FOR FURTHER INFORMATION CONTACT section to coordinate protest activities so that your message can be received without jeopardizing the safety or security of people, places, or vessels.

We view public participation as essential to effective rulemaking, and will consider all comments and material received during the comment period. Your comment can help shape the outcome of this rulemaking. If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation.

We encourage you to submit comments through the Federal eRulemaking Portal at http://www.regulations.gov. If your material cannot be submitted using http://www.regulations.gov, contact the person in the FOR FURTHER INFORMATION CONTACT section of this document for alternate instructions.

We accept anonymous comments. All comments received will be posted without change to http://www.regulations.gov and will include any personal information you have provided. For more about privacy and the docket, you may review a Privacy Act notice regarding the Federal Docket Management System in the March 24, 2005, issue of the Federal Register (70 FR 15086).

Documents mentioned in this NPRM as being available in the docket, and all public comments, will be in our online docket at http://www.regulations.gov and can be viewed by following that Web site's instructions. Additionally, if you go to the online docket and sign up for email alerts, you will be notified when comments are posted or a final rule is published.

For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 147 as follows:

The Captain of the Port Upper Mississippi River proposes to amend 33 CFR 165.801 to update our current list of recurring safety zones in the COTP Zone.

The current list of annual and recurring safety zones occurring in the COTP Zone is published under 33 CFR 165.801 in Table 2. This list was established through a rulemaking process providing for comment and public participation. No adverse comments were received, resulting in the final rulemaking 81 FR 36171, which was published June 6, 2016.

The Coast Guard proposes to amend 33 CFR 165.801 and update the annual and recurring safety zone regulations to include the most up to date list of annual and recurring safety zones for events held on or around navigable waters within the COTP Zone. These events include fireworks displays, air shows, festival events, and other recurring marine related safety events. The current list under 33 CFR 165.801 needs to be amended to provide new information on existing safety zones, include new safety zones expected to recur annually, and to remove safety zones that are no longer required. Issuing individual regulations for each new safety zone, amendment, or removal of an existing safety zones creates unnecessary administrative costs and burdens. This single proposed rulemaking will considerably reduce administrative overhead and provide the public with notice through publication in the Federal Register of the upcoming annual and recurring safety zones. The Coast Guard proposes this rulemaking under the authority in 33 U.S.C. 1221.

The Coast Guard encourages the public to participate in this proposed rulemaking through the comment process so that any necessary changes can be identified and implemented in a timely and efficient manner.

Section 165 of 33 CFR contains regulations establishing limited access areas on U.S. navigable waters. Section 165.801 lists the established recurring safety zones taking place in the Eighth Coast Guard District is separated into tables for each of the seven sectors within the Eighth District. Table 2 lists the recurring safety zones for Sector Upper Mississippi River. This section, and table, requires amendment from time to time to properly reflect the recurring safety zones in the COTP Zone. This proposed rule amends and updates § 165.801 by revising Table 2 for Sector Upper Mississippi River.

Additionally, this proposed rule adds 4 new and removes 1 recurring safety zone as listed below.

This proposed rule adds 4 new safety zones to Table 2 in § 165.801 as follows:

This proposed rule removes the following 1 safety zone from the existing Table 2 in § 165.801 as follows:

We developed this proposed rule after considering numerous statutes and Executive Orders related to rulemaking. Below we summarize our analyses based on a number of these statutes and Executive Orders and we discuss First Amendment rights of protestors.

Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This NPRM has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, the NPRM has not been reviewed by the Office of Management and Budget.

The Coast Guard expects the economic impact of this proposed rule to be minimal, and therefore a full regulatory evaluation is unnecessary. This proposed rule establishes safety zones limiting access to certain areas under 33 CFR 165 within the COTP Zone. The effect of this proposed rulemaking will not be significant because these safety zones are limited in scope and duration. Additionally, the public is given advance notification through local forms of notice, the Federal Register, and Notices of Enforcement and thus will be able to plan operations around the safety zones in advance. Vessel traffic may request permission from the COTP or a designated representative to enter the restricted areas.

The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities.

While some owners or operators of vessels intending to transit these safety zones may be small entities, for the reasons stated in section IV.A. above this proposed rule would not have a significant economic impact on any vessel owner or operator.

If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see ADDRESSES) explaining why you think it qualifies and how and to what degree this rule would economically affect it.

Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this proposed rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section. The Coast Guard will not retaliate against small entities that question or complain about this proposed rule or any policy or action of the Coast Guard.

This proposed rule would not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

A rule has implications for federalism under Executive Order 13132, Federalism, if it has 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. We have analyzed this proposed rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.

Also, this proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. If you believe this proposed rule has implications for federalism or Indian tribes, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section.

The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.

We have analyzed this proposed rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves establishing safety zones limiting access to certain areas under 33 CFR 165 within the COTP Zone and is categorically excluded from further review under paragraph 34(g) of Figure 2-1 of Commandant Instruction M16475.lD. A preliminary environmental analysis checklist and Categorical Exclusion Determination are available in the docket where indicated under ADDRESSES. We seek any comments or information that may lead to the discovery of a significant environmental impact from this proposed rule.

The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the FOR FURTHER INFORMATION CONTACT section to coordinate protest activities so that your message can be received without jeopardizing the safety or security of people, places, or vessels.

We view public participation as essential to effective rulemaking, and will consider all comments and material received during the comment period. Your comment can help shape the outcome of this proposed rulemaking. If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation.

We encourage you to submit comments through the Federal eRulemaking Portal at http://www.regulations.gov. If your material cannot be submitted using http://www.regulations.gov, contact the person in the FOR FURTHER INFORMATION CONTACT section of this document for alternate instructions.

We accept anonymous comments. All comments received will be posted without change to http://www.regulations.gov and will include any personal information you have provided. For more about privacy and the docket, visit http://www.regulations.gov/privacyNotice.

Documents mentioned in this NPRM as being available in the docket, and all public comments, will be in our online docket at http://www.regulations.gov and can be viewed by following that Web site's instructions. Additionally, if you go to the online docket and sign up for email alerts, you will be notified when comments are posted or a final rule is published.

For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 165 as follows:

Table of Contents I. The EPA's Proposed Action A. What action is the EPA proposing today? B. Why is the EPA proposing this action? C. What are the Clean Air Act requirements for NOX RACT? D. What is the EPA's evaluation of New Jersey's SIP Revision? II. New Jersey's SIP Revision A. What are New Jersey's NOX RACT requirements? B. What are New Jersey's facility specific NOX RACT requirements? C. When was New Jersey's RACT determination proposed and adopted? D. When was New Jersey's proposed SIP revision submitted to the EPA? III. Conclusion IV. Statutory and Executive Order Reviews I. The EPA's Proposed Action A. What action is the EPA proposing today?

The EPA is proposing to approve two source-specific State Implementation Plan (SIP) revisions for ozone submitted by the State of New Jersey. These SIP revisions relate to New Jersey's oxides of nitrogen (NOX) reasonably available control technology (RACT) determinations for the Transcontinental Gas Pipeline Corp., LNG Station 240 (Transco-240) located in Carlstadt, New Jersey, Bergen County and for Joint Base McGuire-Dix-Lakehurst (JB-MDL) located in Lakehurst, New Jersey, Ocean County. These SIP revisions were submitted to the EPA for approval on July 1, 2014 and July 25, 2016 respectively. The determinations are for the four natural gas-fired water bath heaters at the Transco-240 facility and the two natural gas-fired boilers (Nos 2 and 3) at the JB-MDL facility.

The EPA is proposing this action to:

• Give the public the opportunity to submit comments on the EPA's proposed action, as discussed in the DATES and ADDRESSES sections.

• Fulfill New Jersey's and the EPA's requirements under the Clean Air Act (Act).

• Make New Jersey's RACT determination federally-enforceable.

The Act requires certain states to develop RACT regulations for stationary sources of NOX and to provide for the implementation of the required measures as soon as practicable. For detailed information on the requirements of the Act for NOX RACT and for the EPA's technical evaluation of New Jersey's SIP revision, see the Technical Support Document (TSD), prepared in support of this proposed action. A copy of the TSD is available in the Docket for this action, and by contacting the individual in the For Further Information Section.

The EPA has determined that New Jersey's proposed SIP revisions for the NOX RACT determinations for Transco-240 and JB-MDL are consistent with New Jersey's NOX RACT regulation and the EPA's guidance. The EPA's basis for evaluating New Jersey's proposed SIP revisions is whether they meet the SIP requirements described in section 110 of the Act. The EPA has determined that New Jersey's proposed SIP revisions will not interfere with any applicable requirement concerning attainment and reasonable further progress, or any other applicable requirement of the Act.

The EPA has determined that the NOX emission limits identified in New Jersey's Conditions of Approval document and alternative emission limit compliance plan represent RACT for Transco-240 and JB-MDL respectively. The conditions contained in these documents currently specify emissions limits, work practice standards, testing, monitoring, and recordkeeping/reporting requirements. These conditions are consistent with the NOX RACT requirements specified in Subchapter 19 of Chapter 27, Title 7 of the New Jersey Administrative Code and conform to the EPA's NOX RACT guidance. More specifically, the EPA proposes to approve the current Conditions of Approval document for Transco-240 which includes the following:

1. The emission rate of NOX from each water bath heater, while firing natural gas, shall not exceed 0.10 pounds per million British thermal units (lb/MMBTU);

2. The total emission rate of NOX from all four water bath heaters, while combusting natural gas shall not exceed 6.7 tons per year;

3. Transco-240 shall operate the four natural gas-fired water bath heaters for a combined total of 1600 hours per year or less;

4. Transco-240 shall not operate the four water bath heaters during the ozone season; and

5. The flue gas recirculation (FGR) system shall operate at all times the heater is operating.

1. An alternative NOX Emission Limit (AEL) of 0.1 lb/MMBTU for boiler #2 and boiler #3 pursuant to N.J.A.C.7:27-19.13; and

2. Decrease in natural gas use from 181.43 to 108.6 million cubic feet (MMft3) per year for boiler #2 and from 113.04 to 57 MMft3 per year for boiler #3.

New Jersey's NOX RACT requirements are contained in Subchapter 19 entitled “Control And Prohibition of Air Pollution From Oxides of Nitrogen”, of Chapter 27, Title 7 of the New Jersey Administrative Code. New Jersey has made numerous revisions to Subchapter 19 since the original SIP submission. The current SIP approved version of Subchapter 19 was approved by the EPA on August 3, 2010 (75 FR 45483). New Jersey RACT requirements specify the emission rate of NOX from each water bath or boiler, while firing natural gas, shall not exceed 0.10 lb/MMBTU. The maximum allowable emission limit becomes effective on the effective date of EPA's approval, as published in the Federal Register, of New Jersey's SIP revision for the AEL. Until EPA's approval becomes effective, the maximum allowable emission rate for each water bath heater or boiler is 0.05 lb/MMBTU, as required by Subchapter 19.

Section 19.13 of New Jersey's regulation establishes a procedure for a case-by-case determination of what represents RACT for a major NOX facility, item of equipment, or source operation. This procedure applies to facilities considered major for NOX, which are in one of the following two situations: (1) If the NOX facility contains any source operation or item of equipment of a category not listed in section 19.2(b) or (c) which has the potential to emit more than 10 tons of NOX per year, or (2) if the owner or operator of a source operation or item of equipment of a category listed in section 19.2(b) or (c) seeks approval of an alternative maximum allowable emission rate. This proposal applies to both facilities for the second situation listed above.

New Jersey's procedure requires either submission of a NOX control plan, if specific emission limitations do not apply to the specific source, or submission of a request for an alternative maximum allowable emission rate if specific emission limitations do apply to the specific source. In either case, the owners/operators must include a technical and economic feasibility analysis of the possible alternative control measures. Also, in either case, Subchapter 19 requires that New Jersey establish emission limits which rely on a RACT determination specific to the facility. The resulting NOX control plan or alternative maximum allowable emission rate must be submitted to the EPA for approval as a SIP revision.

New Jersey's RACT determination for Transco-240 was proposed on March 26, 2014, with the public comment period ending April 25, 2014. New Jersey approved the RACT determination on June 12, 2014. New Jersey's RACT determination for JB-MDL was proposed on June 8, 2016, with the public comment period ending July 8, 2016. New Jersey approved the RACT determination on August 26, 2016. New Jersey did not receive any comments during either of the two comment periods.

New Jersey's SIP revision for Transco-240 was submitted to the EPA on July 1, 2014 and New Jersey's SIP revision for JB-MDL was submitted on July 25, 2016. By operation of law the submittals were deemed administratively and technically complete six months from the submittal dates.

The EPA is proposing to approve the New Jersey SIP revisions for alternative RACT emission limit determinations for the following two sources: (1) The four water bath heaters for the Transcontinental Gas Pipeline Corp., LNG Station 240 which includes source-specific NOX emissions limits, combustion process adjustments, emission testing, monitoring, recordkeeping and reporting requirements; and (2) the two boilers (No's 2 and 3) for the Joint Base McGuire-Dix-Lakehurst which includes source-specific NOX emissions limits, combustion process adjustments, emission testing, monitoring, recordkeeping and reporting requirements. The EPA is proposing to approve these revisions since the evaluated alternative control measures at both facilities were determined not to be economically feasible. In addition, the revised RACT requirements will include limits on fuel use and total number of hours of operation at Transcontinental Gas Pipeline Corp., LNG Station 240 and limits on fuel use resulting in a decrease in natural gas use at Joint Base McGuire-Dix-Lakehurst. The EPA will consider all comments submitted prior to any final rulemaking action.

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

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

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

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

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

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

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

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

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

• does not provide the 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).

Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA. Organization of this document. The following outline is provided to aid in locating information in this preamble.

On August 28, 2015, the Maine Department of Environmental Protection (DEP) submitted to the EPA a revision to its State Implementation Plan (SIP). The SIP revision consists of Maine's revised Chapter 119 Motor Vehicle Fuel Volatility Limits. Chapter 119 was revised to require retailers to sell reformulated gasoline (RFG) in the counties of York, Cumberland, Sagadahoc, Androscoggin, Kennebec, Knox, and Lincoln (hereinafter, the “Southern Maine Counties”) effective June 1, 2015. RFG is gasoline that is blended to burn more cleanly as compared to conventional gasoline. This regulation was revised to be consistent with existing federal regulations at 40 CFR part 80, subpart D.

In April, 2013, the Maine Legislature enacted Public Law 2013 c.221 calling for the use of RFG in the Southern Maine Counties beginning May 1, 2014. On July 23, 2013, the Governor of Maine formally requested, pursuant to Clean Air Act (CAA) section 211(k)(6)(B), that the EPA extend the requirement for the sale of RFG to these counties beginning on May 1, 2014. The Maine legislature subsequently enacted an emergency law, Public Law 2013 c.452, effective March 6, 2014, to postpone the requirement for the sale of RFG in the Southern Maine Counties until June 1, 2015. Pursuant to that legislation, the Commissioner of the Maine DEP submitted a request to the EPA on March 10, 2014, modifying Maine's request for the implementation date for the sale of RFG in the Southern Maine Counties to coincide with the new June 1, 2015 effective date.

Per Maine's request, the EPA extended the requirements of the RFG program to the Southern Maine Counties. The final rule, Regulation of Fuels and Fuel Additives: Extension of the Reformulated Gasoline Program to Maine's Southern Counties, was published in the Federal Register on February 6, 2015 (80 FR 6658).

On August 28, 2015, the Maine DEP submitted to EPA a SIP revision containing Maine's revised Chapter 119 Motor Vehicle Fuel Volatility Limits rule adopted on May 21, 2015. The rule's prohibition on selling or dispensing motor vehicle fuel having a Reid Vapor Pressure (RVP) greater than 7.8 pounds per square inch (psi), in the Southern Maine Counties, during the period of May 1 through September 15 was revised to apply through September 15 of 2014, and a new provision, requiring retailers who sell gasoline in the Southern Maine Counties to only sell RFG in those counties year round, was added to the rule. The revisions to Chapter 119 maintain the 9.0 psi maximum RVP requirement in the reminder of the State during the period of May 1 through September 15 each year.

EPA previously approved Maine's Chapter 119 into the Maine SIP on March 6, 2002 (67 FR 10100). EPA has reviewed Maine's revised Chapter 119 Motor Vehicle Fuel Volatility Limits rule and has concluded that Maine's August 28, 2015 SIP revision is consistent with the anti-back sliding requirements of CAA section 110(l). The previous version of Chapter 119 currently in the Maine SIP states that in the Southern Maine Counties “no owner or operator shall dispense, sell, or supply as fuel for motor vehicles a gasoline having a RVP greater than 7.8 psi during the period of May 1 through September 15 of each year.” The revised rule instead requires RFG in the Southern Maine Counties year-round beginning June 1, 2015, without the 7.8 psi RVP requirement, and maintains the 9.0 psi RVP requirement in the reminder of the State. Requiring a lower RVP for fuels means less evaporative emissions, and therefore removal of such a requirement might be of concern. In this case, however, although the low RVP requirement for the Southern Maine Counties has been removed, it has been replaced with a requirement for the sale of RFG. The requirement for RFG, in practice, results in a similar RVP for the fuel. Specifically, an analysis of summer time RFG for 2011-2015 indicates an annual average RVP between 7.01 and 7.13 psi, with a standard deviation of approximately 0.19 psi.1 Therefore, Maine's revised Chapter 119 meets the CAA section 110(l) anti-back sliding requirements and EPA is proposing to approve the revised regulation.

EPA is proposing to approve Maine's August 28, 2015 SIP revision. Specifically, EPA is proposing to approve, and incorporate into the Maine SIP, Maine's revised Chapter 119 Motor Vehicle Fuel Volatility Limits rule. EPA is proposing to approve this SIP because it meets all applicable requirements of the CAA and relevant EPA guidance, and it will not interfere with any applicable requirement concerning National Ambient Air Quality Standards (NAAQS) attainment and reasonable further progress or with any other applicable requirement in the Clean Air Act.

In this rule, the EPA is proposing to include in a final EPA rule regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is proposing to incorporate by reference the Maine regulation referenced in Section IV. of this preamble. The EPA has made, and will continue to make, these documents generally available electronically through http://www.regulations.gov and/or in hard copy at the appropriate EPA office.

Section 1541(b) of the Energy Policy Act of 2005 required EPA in consultation with the U.S. Department of Energy to determine the number of fuels programs approved into all SIPs as of September 1, 2004 and to publish a list of such fuels. On December 28, 2006, EPA published the list of boutique fuels. (See 71 FR 78192.) EPA maintains the current list of boutique fuels on its Web site at: https://www.epa.gov/gasoline-standards/state-fuels. The final list of boutique fuels was based on a fuel type approach. CAA section 211(c)(4)(C)(v)(III) requires that EPA remove a fuel from the published list if it is either identical to a federal fuel or is removed from the SIP in which it is approved. Under the adopted fuel type approach, EPA interpreted this requirement to mean that a fuel would have to be removed from all SIPs in which it was approved in order for it to be removed from the list. (See 71 FR 78195)

The 7.8 psi RVP fuel program, which is approved into Maine's SIP, is a fuel type that is included in EPA's boutique fuel list, 71 FR 78198-99; (https://www.epa.gov/gasoline-standards/state-fuels) and the specific counties in Southern Maine where the 7.8 psi RVP gasoline was required are identified on EPA's Gasoline Reid Vapor Pressure Web page (https://www.epa.gov/gasoline-standards/gasoline-reid-vapor-pressure). If today's proposed approval of the removal of Maine's 7.8 psi RVP requirement from the State's SIP is subsequently granted final approval, EPA intends to update the State Fuels and Gasoline Reid Vapor Pressure Web pages on the effective date of the removal. While EPA intends to delete the entry for Maine from the list of boutique fuels, this would not result in an opening on the boutique fuels list because the 7.8 psi RVP fuel type remains in other state SIPs.

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

• Is not a significant regulatory action subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);

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

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

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

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

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

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

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

Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA.

Organization of this document. The following outline is provided to aid in locating information in this preamble.

On April 13, 2016, the Maine DEP submitted a revision to its State Implementation Plan (SIP). The SIP revision consists of Maine's revised Chapter 118, Gasoline Dispensing Facilities Vapor Control, which has been revised to require the decommissioning of Stage II vapor recovery systems and to update Stage I vapor recovery testing requirements. The SIP submittal also includes a demonstration that removal of Stage II vapor recovery systems in Maine is consistent with the Clean Air Act and relevant EPA guidance.

Stage II and onboard refueling vapor recovery (ORVR) systems are two types of emission control systems that capture fuel vapors from vehicle gas tanks during refueling. Stage II vapor recovery systems are installed at GDFs and capture the refueling fuel vapors at the gasoline pump. The system carries the vapors back to the underground storage tank at the GDF to prevent the vapors from escaping to the atmosphere. ORVR systems are carbon canisters installed directly on automobiles to capture the fuel vapors evacuated from the gasoline tank before they reach the nozzle. The fuel vapors captured in the carbon canisters are then combusted in the engine when the automobile is in operation.

Stage II vapor recovery systems and vehicle ORVR systems were initially both required by the 1990 Amendments to the Clean Air Act (CAA). Section 182(b)(3) of the CAA requires moderate and above ozone nonattainment areas to implement Stage II vapor recovery programs. Also, under CAA section 184(b)(2), states in the Ozone Transport Region (OTR) are required to implement Stage II or comparable measures. CAA section 202(a)(6) required EPA to promulgate regulations for ORVR for light-duty vehicles (passenger cars). EPA adopted these requirements in 1994, at which point moderate ozone nonattainment areas were no longer subject to the CAA section 182(b)(3) Stage II vapor recovery requirements. ORVR equipment has been phased in for new passenger vehicles beginning with model year 1998, and starting with model year 2001 for light-duty trucks and most heavy-duty gasoline powered vehicles. ORVR equipment has been installed on nearly all new gasoline-powered light-duty vehicles, light-duty trucks, and heavy-duty vehicles since 2006.1

During the phase-in of ORVR controls, Stage II has provided volatile organic compound (VOC) reductions in ozone nonattainment areas and certain attainment areas of the OTR. Congress recognized that ORVR systems and Stage II vapor recovery systems would eventually become largely redundant technologies, and provided authority to EPA to allow states to remove Stage II vapor recovery programs from their SIPs after EPA finds that ORVR is in “widespread use.” Effective May 16, 2012, the date the final rule was published in the Federal Register (see 77 FR 28772), EPA determined that ORVR systems are in widespread use nationwide for control of gasoline emissions during refueling of vehicles at GDFs. As of the end of 2016, EPA estimates that more than 88 percent of gasoline refueling nationwide occurs with ORVR-equipped vehicles.2 Thus, Stage II vapor recovery programs have become largely redundant control systems and Stage II vapor recovery systems achieve an ever declining emissions benefit as more ORVR-equipped vehicles continue to enter the on-road motor vehicle fleet.3 In its May 16, 2012 rulemaking, EPA also exercised its authority under CAA section 202(a)(6) to waive certain federal statutory requirements for Stage II vapor recovery systems at GDFs. This decision exempts all new ozone nonattainment areas classified serious or above from the requirement to adopt Stage II vapor recovery programs. Finally, EPA's May 16, 2012 rulemaking also noted that any state currently implementing Stage II vapor recovery programs may submit SIP revisions that would allow for the phase-out of Stage II vapor recovery systems.

Stage I vapor recovery systems are systems that capture vapors displaced from storage tanks at GDFs during gasoline tank truck deliveries. When gasoline is delivered into an aboveground or underground storage tank, vapors that were taking up space in the storage tank are displaced by the gasoline entering the storage tank. The Stage I vapor recovery systems route these displaced vapors into the delivery truck's tank. Some vapors are vented when the storage tank exceeds a specified pressure threshold, however the Stage I vapor recovery systems greatly reduce the possibility of these displaced vapors being released into the atmosphere.

Stage I vapor recovery systems have been in place since the 1970s. EPA has issued the following guidance regarding Stage I systems: “Design Criteria for Stage I Vapor Control Systems—Gasoline Service Stations” (November 1975, EPA Online Publication 450R75102), which is regarded as the control techniques guideline (CTG) for the control of VOC emissions from this source category; and the EPA document “Model Volatile Organic Compound Rules for Reasonably Available Control Technology” (Staff Working Draft, June 1992) contains a model Stage I regulation.

Maine adopted its Stage II Vapor Recovery Program in 1995 in order to satisfy the requirements of sections 182(b)(3) and 184(b)(2) of the CAA. The Maine Stage II vapor recovery program requirements were codified in Maine's Chapter 118, Gasoline Dispensing Facilities Vapor Control, and EPA approved the program into the Maine SIP on October 15, 1996 (61 FR 53636). Maine's rule required gasoline dispensing facilities located in the counties of York, Cumberland, and Sagadahoc to install Stage II vapor recovery systems.

On April 13, 2016, Maine submitted a SIP revision consisting of its revised Chapter 118. This revised rule requires GDFs to decommission their Stage II vapor recovery systems as of January 1, 2013, and contains an appendix detailing the requirements and procedures for disabling the Stage II vapor recovery systems based on the Petroleum Equipment Institute's Recommended Practices for Installation and Testing of Vapor-Recovery Systems at Vehicle-Fueling Sites, PEI RP 300-09, Section 14, Decommissioning Stage II Vapor Recovery Piping, 2009 edition.

In addition, the revised regulation also includes requirements that any GDF whose monthly throughput ever exceeds a threshold of 100,000 gallons per calendar month be subject to the requirements of 40 CFR part 63 Subpart CCCCCC—National Emission Standards for Hazardous Air Pollutants (NESHAP) for Source Category: Gasoline Dispensing Facilities. Furthermore, any GDF that ever exceeds 100,000 gallons per calendar month threshold will remain subject to the NESHAP requirements even if the monthly throughput ever falls below this threshold.

Maine's revised Chapter 118 also includes updated Stage I testing procedures. The procedures now mirror the NESHAP testing requirements for Stage I vapor recovery systems. Any GDF with a monthly throughput over 100,000 gallons per month must perform an initial “P/V Cap Test” in accordance with California Air Resources Board's TP-201.1E. The test must be repeated at least every three years thereafter. In addition, any GDF with at least a 100,000 gallons per month throughput must perform a pressure decay test every three years in accordance with CARB's TP-201.3. Furthermore, all installation and function of Stage I vapor recovery systems must be re-verified upon any major system replacement or modification. Functional tests must be performed within 30 days upon request by the Maine DEP when inspections, records, or other evidence show noncompliance with the state regulation. These tests must be performed during normal business hours, with notification to the Maine DEP provided in writing at least 5 days prior to the test. All test results must be provided to the Maine DEP within 30 days.

The revised Chapter 118 also includes additional procedures for ensuring that the hoses in the Stage I vapor balance system are properly connected. The vapor hose must be connected to the cargo tank and delivery elbow before connecting to the facility storage tank; the cargo tank valve must be opened only after all vapor connections are made, and closed before any vapor connections are disconnected; and the vapor return hose must be disconnected from the facility storage tank before it is disconnected from the cargo tank.

The April 13, 2016 SIP submission also includes a narrative demonstration supporting the discontinuation of the Maine Stage II vapor recovery program. This demonstration, discussed in greater detail below, consists of an analysis that the Stage II vapor recovery controls provide only de minimis emission reductions due to the prevalence of ORVR-equipped vehicles.

EPA has reviewed Maine's revised Chapter 118, Gasoline Dispensing Facilities Vapor Control, and accompanying SIP narrative, and has concluded that Maine's April 13, 2016 SIP revision is consistent with EPA's widespread use rule (77 FR 28772, May 16, 2012) and with EPA's “Guidance on Removing Stage II Gasoline Vapor Control Programs from State Implementation Plans and Assessing Comparable Measures” (EPA-457/B-12-001; August 7, 2012), hereafter referred to as EPA's Guidance Document.

Maine's April 13, 2016 SIP revision includes a CAA section 110(l) anti-back sliding demonstration based on the relevant equations contained in EPA's Guidance Document. Maine's demonstration uses the EPA Guidance Document's estimate that, in 2012, 71.4% of gasoline refueling nationwide occurred with ORVR-equipped vehicles.4 According to these calculations, the potential loss of refueling emission reductions resulting from the removal of Stage II vapor recovery systems in 2012 (the year leading up to Maine's January 1, 2013 decommissioning deadline) is between 6.2 and 9.2 percent, thus meeting the 10 percent de minimis recommendation in EPA's Guidance Document.5

In addition, Maine's April 13, 2016 SIP revision also includes calculations illustrating that the overall effect of removing the Stage II vapor recovery program would be an increase of between 45 and 68 tons of VOC in 2012. EPA's 2011 National Emissions Inventory database illustrates that Maine's anthropogenic VOC emissions for York, Cumberland, and Sagadahoc Counties were about 48,484 tons (see https://www.epa.gov/air-emissions-inventories/2011-national-emissions-inventory-nei-data); therefore the 45 to 68 annual tons of VOC emissions increase calculated by Maine to have occurred in 2012 are only about 0.2 to 0.4 percent of the total anthropogenic VOC emissions in these three counties for that year. Also, these foregone emissions reductions continue to diminish rapidly over time as ORVR phase-in continues. That is, the estimated 45 to 68 tons of VOC in 2012 have decreased since that time on an annual basis. Therefore, EPA believes that the resulting temporary increases in VOC emissions that occurred by removing the Stage II program will not interfere with attainment or maintenance of the ozone NAAQS.

With respect to Stage I vapor recovery requirements, Maine's revised Chapter 118 is at least as stringent as the previously approved version of the rule, thus meeting the CAA section 110(l) anti-back sliding requirements. The revision includes updated instructions for ensuring the hoses in the vapor balance system were properly connected, and includes more comprehensive testing procedures than the previous SIP-approved rule. This revision will help to ensure that the Stage I vapor recovery equipment is working properly so that the expected emission reductions occur. These testing procedures mirror the guidelines for GDFs with a monthly throughput of 100,000 gallons or more identified in 40 CFR 63, Subpart CCCCCC.

EPA is proposing to approve Maine's April 13, 2016 SIP revision. Specifically, EPA is proposing to approve Maine's revised Chapter 118, Gasoline Dispensing Facilities Vapor Control, and incorporate it into the Maine SIP. EPA is proposing to approve this SIP revision because it meets all applicable requirements of the Clean Air Act and relevant EPA guidance, and it will not interfere with attainment or maintenance of the ozone NAAQS.

EPA is soliciting public comments on the issues discussed in this notice or on other relevant matters. These comments will be considered before taking final action. Interested parties may participate in the Federal rulemaking procedure by submitting written comments to the EPA New England Regional Office listed in the ADDRESSES section of this Federal Register.

In this rule, the EPA is proposing to include in a final EPA rule regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is proposing to incorporate by reference of the State of Maine's revised Chapter 118 described in section IV of this notice. The EPA has made, and will continue to make, these documents generally available electronically through http://www.regulations.gov and/or in hard copy at the appropriate EPA office.

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

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

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

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

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

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

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

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

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

Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA.

On June 22, 2010 (75 FR 35520), EPA promulgated a revised primary NAAQS for SO2 at a level of 75 ppb, based on a 3-year average of the annual 99th percentile of 1-hour daily maximum concentrations. Pursuant to section 110(a)(1) of the CAA, states are required to submit SIPs meeting the applicable requirements of section 110(a)(2) within three years after promulgation of a new or revised NAAQS or within such shorter period as EPA may prescribe. These SIPs, which EPA has historically referred to as “infrastructure SIPs,” are to provide for the “implementation, maintenance, and enforcement” of such NAAQS, and the requirements are designed to ensure that the structural components of each state's air quality management program are adequate to meet the state's responsibility under the CAA. A detailed history, interpretation, and rationale of these SIPs and their requirements can be found among other citations, in EPA's May 13, 2014 proposed rule titled, “Infrastructure SIP requirements for the 2008 Lead NAAQS” in the section, “What is the scope of this rulemaking?” (see 79 FR 27241 at 27242-27245). Section 110(a) of the CAA imposes the obligation upon states to make a SIP submission to EPA for a new or revised NAAQS, but the contents of individual state submissions may vary depending upon the facts and circumstances. The content of the revisions proposed in such SIP submissions may also vary depending upon what provisions the state's approved SIP already contains.

On May 30, 2013, the Connecticut Department of Energy and Environmental Protection (CT DEEP) submitted a revision to its SIP, certifying its SIP meets the requirements of section 110(a)(2) of the CAA with respect to the 2010 SO2 NAAQS. On June 3, 2016 (81 FR 35636), EPA approved CT DEEP's certification that its SIP was adequate to meet most of the program elements required by section 110(a)(2) of the CAA with respect to the 2010 SO2 NAAQS. However, at that time, EPA did not take action on CT DEEP's certification that its SIP met the requirements of section 110(a)(2)(D)(i)(I). EPA is now proposing to act on this element, section 110(a)(2)(D)(i)(I) of CT DEEP's May 30, 2013 submission to address the 2010 SO2 NAAQS.

This proposed approval of Connecticut's SIP addressing interstate transport of SO2 is intended to show that the state is meeting its obligations regarding CAA section 110(a)(2)(D)(i)(I) relative to the 2010 SO2 NAAQS.1 Interstate transport requirements for all NAAQS pollutants prohibit any source—or other type of emissions activity—in one state from emitting any air pollutant in amounts that will contribute significantly to nonattainment, or interfere with maintenance, of the NAAQS in another state. As part of this analysis, and as explained in detail below, EPA has taken several approaches to addressing interstate transport in other actions based on the characteristics of the pollutant, the interstate problem presented by emissions of that pollutant, the sources that emit the pollutant, and the information available to assess transport of that pollutant.

Despite being emitted from a similar universe of point and nonpoint sources, interstate transport of SO2 is unlike the transport of fine particulate matter (PM2.5) or ozone that EPA has addressed in other actions in that SO2 is not a regional mixing pollutant that commonly contributes to widespread nonattainment of the SO2 NAAQS over a large (and often multi-state) area. While transport of SO2 is more analogous to the transport of lead (Pb) since its physical properties result in localized pollutant impacts very near the emissions source, the physical properties and release height of SO2 are such that impacts of SO2 do not experience the same sharp decrease in ambient concentrations as rapidly and as nearby as for Pb. Emissions of SO2 travel further and have sufficiently wider ranging impacts than emissions of Pb to require a different approach than handling Pb transport, but not far enough to be treated in a manner similar to regional transport pollutants such as ozone or PM2.5.

Put simply, a different approach is needed for interstate transport of SO2: The approaches EPA has adopted for Pb transport are too tightly circumscribed to the source, and the approaches for ozone or PM2.5 transport are too regionally focused. SO2 transport is therefore a unique case, and EPA's evaluation of whether Connecticut has met is transport obligations was accomplished in several discrete steps. First, EPA evaluated what universe of sources are likely to be responsible for SO2 emissions that could contribute to interstate transport. An assessment of the 2014 National Emissions Inventory (NEI) for Connecticut made it clear that the vast majority of SO2 emissions in Connecticut are from fuel combustion at point and nonpoint sources, and therefore it would be reasonable to evaluate the downwind impacts of emissions from the combined fuel combustion source categories in order to help determine whether the state has met is transport obligations.

Second, EPA selected a spatial scale—essentially, the geographic area and distance around the point sources in which we could reasonably expect SO2 impacts to occur—that would be appropriate for its analysis, ultimately settling on utilizing an “urban scale” with dimensions from 4 to 50 kilometers from point sources given the usefulness of that range in assessing trends in both area-wide air quality and the effectiveness of large-scale pollution control strategies at those point sources. As such, EPA utilized an assessment up to 50 kilometers from fuel-combustion point sources in order to assess trends in area-wide air quality that might have an impact on the transport of SO2 from Connecticut to downwind states.

Third, EPA assessed all available data at the time of this rulemaking regarding SO2 emissions in Connecticut and their possible impacts in downwind states, including: SO2 ambient air quality; SO2 emissions and SO2 emissions trends; SIP-approved SO2 regulations and permitting requirements; available air dispersion modeling; and, other SIP-approved or Federally promulgated regulations which may yield reductions of SO2 at Connecticut's fuel-combustion point and nonpoint sources.

Fourth, using the universe of information identified in steps 1-3 (i.e., emissions sources, spatial scale and available data, modeling results and enforceable regulations), EPA then conducted an analysis under CAA section 110(a)(2)(D)(i)(I) to evaluate whether or not fuel-combustion sources in Connecticut would significantly contribute to nonattainment in other states, and then whether they would interfere with maintenance of the NAAQS in other states.

Based on the analysis provided by the state in its SIP submission and EPA's assessment of the information in that submittal for each of the factors discussed at length below in this action, EPA proposes to find that sources or emissions activity within Connecticut will not contribute significantly to nonattainment, nor will they interfere with maintenance of, the 2010 primary SO2 NAAQS in any other state.

Section 110(a)(2)(D)(i)(I) requires SIPs to include provisions prohibiting any source or other type of emissions activity in one state from emitting any air pollutant in amounts that will contribute significantly to nonattainment, or interfere with maintenance, of the NAAQS in another state. The two clauses of this section are referred to as prong 1 (significant contribution to nonattainment) and prong 2 (interference with maintenance of the NAAQS).

EPA's most recent infrastructure SIP guidance, the September 13, 2013 “Guidance on Infrastructure State Implementation Plan (SIP) Elements under Clean Air Act Sections 110(a)(1) and 110(a)(2),” did not explicitly include criteria for how the Agency would evaluate infrastructure SIP submissions intended to address section 110(a)(2)(D)(i)(I).2 With respect to certain pollutants, such as ozone and particulate matter, EPA has addressed interstate transport in eastern states in the context of regional rulemaking actions that quantify state emission reduction obligations.3 In other actions, such as EPA action on western state SIPs addressing ozone and particulate matter, EPA has considered a variety of factors on a case-by-case basis to determine whether emissions from one state interfere with the attainment and maintenance of the NAAQS in another state. In such actions, EPA has considered available information such as current air quality, emissions data and trends, meteorology, and topography.4

For other pollutants such as Pb, EPA has suggested the applicable interstate transport requirements of section 110(a)(2)(D)(i)(I) can be met through a state's assessment as to whether or not emissions from Pb sources located in close proximity to its borders have emissions that impact a neighboring state such that they contribute significantly to nonattainment or interfere with maintenance in that state. For example, EPA noted in an October 14, 2011 memorandum titled, “Guidance on Infrastructure SIP Elements Required Under Sections 110(a)(1) and 110(a)(2) for the 2008 Pb NAAQS,” 5 that the physical properties of Pb prevent its emissions from experiencing the same travel or formation phenomena as PM2.5 or ozone, and there is a sharp decrease in Pb concentrations, at least in the coarse fraction, as the distance from a Pb source increases. Accordingly, while it may be possible for a source in a state to emit Pb in a location and in quantities that may contribute significantly to nonattainment in, or interfere with maintenance by, any other state, EPA anticipates that this would be a rare situation, e.g., where large sources are in close proximity to state boundaries.6 Our rationale and explanation for approving the applicable interstate transport requirements under section 110(a)(2)(D)(i)(I) for the 2008 Pb NAAQS, consistent with EPA's interpretation of the October 14, 2011 guidance document, can be found among other instances, in the proposed approval and a subsequent final approval of interstate transport SIPs submitted by Illinois, Michigan, Minnesota, and Wisconsin.7

As previously noted, section 110(a)(2)(D)(i)(I) requires an evaluation of any source or other type of emissions activity in one state and how emissions from these source categories may impact air quality in other states. The EPA believes that a reasonable starting point for determining which sources and emissions activities in Connecticut are likely to impact downwind air quality with respect to the SO2 NAAQS is by using information in the NEI.8 The NEI is a comprehensive and detailed estimate of air emissions of criteria pollutants, criteria precursors, and hazardous air pollutants from air emissions sources, and is updated every three years using information provided by the states. At the time of this rulemaking, the most recently available dataset is the 2014 NEI, and the state summary for Connecticut is included in the table below.

The EPA observes that according to the 2014 NEI, the vast majority of SO2 emissions in Connecticut originate from fuel combustion at point and nonpoint sources. Therefore, an assessment of Connecticut's satisfaction of all applicable requirements under section 110(a)(2)(D)(i)(I) of the CAA for the 2010 SO2 NAAQS may be reasonably based upon evaluating the downwind impacts of emissions from the combined fuel combustion categories (i.e., electric utilities, industrial processes, and other sources 9 ).

The definitions contained in appendix D to 40 CFR part 58 are helpful indicators of the travel and formation phenomenon for SO2 in its stoichiometric gaseous form in the context of the 2010 primary SO2 NAAQS originating from stationary sources. Notably, section 4.4 of this appendix titled, “Sulfur Dioxide (SO2) Design Criteria” provides definitions for SO2 Monitoring Spatial Scales for microscale, middle scale, neighborhood, and urban scale monitors. The microscale includes areas in close proximity to SO2 point and area sources, and extend approximately 100 meters from a facility. The middle scale generally represents air quality levels in areas 100 meters to 500 meters from a facility, and may include locations of maximum expected short-term concentrations due to proximity of major SO2 point, area, and non-road sources. The neighborhood scale characterizes air quality conditions between 0.5 kilometers and 4 kilometers from a facility, and emissions from stationary and point sources may under certain plume conditions, result in high SO2 concentrations at this scale. Lastly, the urban scale is used to estimate concentrations over large portions of an urban area with dimensions of 4 to 50 kilometers from a facility, and such measurements would be useful for assessing trends and concentrations in area-wide air quality, and hence, the effectiveness of large-scale pollution control strategies. Based on these definitions contained in EPA's own regulations, we believe that it is appropriate to examine the impacts of emissions from electric utilities and industrial processes in Connecticut in distances ranging from 0 km to 50 km from the facility. In other words, SO2 emissions from stationary sources in the context of the 2010 primary NAAQS do not exhibit the same long-distance travel, regional transport or formation phenomena as either ozone or PM2.5, but rather, these emissions behave more like Pb with localized dispersion. Therefore, an assessment up to 50 kilometers from potential sources would be useful for assessing trends and SO2 concentrations in area-wide air quality.10 Based on the fact that SO2 emissions from residential fuel combustion consists of 73% of all SO2 emissions in the NEI, EPA believes it is reasonable to evaluate any regulations intended to address fuel oil, specifically with respect to the sulfur content in order to determine interstate transport impacts from the category of “other” sources of fuel combustion.

Our current implementation strategy for the 2010 primary SO2 NAAQS includes the flexibility to characterize air quality for stationary sources via either data collected at ambient air quality monitors sited to capture the points of maximum concentration, or air dispersion modeling.11 Our assessment of SO2 emissions from fuel combustion categories in the state and their potential on neighboring states are informed by all available data at the time of this rulemaking, and include: SO2 ambient air quality; SO2 emissions and SO2 emissions trends; SIP-approved SO2 regulations and permitting requirements; available air dispersion modeling; and, other SIP-approved or Federally promulgated regulations which may yield reductions of SO2. This notice describes EPA's evaluation of Connecticut's May 30, 2013 infrastructure SIP submission to satisfy the requirements of CAA section 110(a)(2)(D)(i)(I).12

Prong 1 of the good neighbor provision requires state plans to prohibit emissions that will significantly contribute to nonattainment of a NAAQS in another state. In order to evaluate Connecticut's satisfaction of prong 1, EPA evaluated the state's SIP submission with respect to the following four factors: (1) SO2 ambient air quality and emissions trends for Connecticut and neighboring states; (2) potential ambient impacts of SO2 emissions from certain facilities in Connecticut on neighboring states based on available air dispersion modeling results; (3) SIP-approved regulations specific to SO2 emissions and permit requirements; and (4) other SIP-approved or Federally enforceable regulations that, while not directly intended to address or reduce SO2 emissions, may yield reductions of the pollutant. A detailed discussion of each of these factors is below.

Connecticut's infrastructure SIP submission refers to EPA's previous designation efforts for the 2010 SO2 NAAQS. In particular, Connecticut explains that on February 7, 2013, EPA transmitted a letter to the state observing that, based on ambient air quality data collected between 2009 and 2011, no monitored violations of the 2010 SO2 NAAQS had been recorded in Connecticut.13 Additionally, the state references a technical support document it submitted with its SIP titled, “Technical Justification to Support a Designation of Attainment of the 1-hour Sulfur Dioxide (SO2) NAAQS for Connecticut” (hereafter referred to as the Technical Justification), which includes state-specific information about ambient monitoring data, large sources of SO2, and air dispersion modeling.14 Where applicable, supporting information from the Technical Justification will be referenced in the discussions below.

As noted above, EPA's approach for addressing the interstate transport of SO2 in Connecticut is based upon emissions from fuel combustion at electric utilities, industrial sources, and residential heating. As part of the Technical Justification document, Connecticut observed that, in accordance with the most recently available designations guidance at the time,15 there were four facilities (all electric utilities) in Connecticut with reported actual emissions greater than or equal to 100 tons per year (tpy) of SO2 in any given year between 2009 and 2011. The four facilities and each facility's maximum SO2 emissions in any one year between 2009 and 2011 are presented in the table below.

While the information in Table 2 provides the highest yearly SO2 emissions between 2009 and 2011 based on the state point source inventory, an emissions summary for all electric utilities within the state subject to the federal Acid Rain Program will help determine whether the emissions from the facilities above can be relied upon as a general indicator of state-wide SO2 emissions from all electric utilities. Data for this purpose can be found in the most recent EPA Air Markets Program Data (2016 AMPD).16 The 2016 AMPD is an application that provides both current and historical data collected as part of EPA's emissions trading programs. A summary of all 2016 SO2 emissions from electric utilities in Connecticut subject to the Acid Rain Program is below.

Table 3 provides several key pieces of information. First, the emissions from the still-operational facilities referenced in the state's Technical Justification have decreased significantly compared to the historical high level during the 2009 to 2011 time period. The combined emissions from PSEG Power BPT Harbor, PSEG Power New Haven, and Middletown Power were 3,426.7 tons according to the state point source inventory during the highest year between for 2009-2011, whereas the 2016 AMPD data indicate that the combined emissions from these same facilities is slightly less than 300 tons. Additionally, the combined emissions from the still operational facilities referenced in the Technical Justification from the state point source inventory between 2009-2011 is significantly higher than the combined 2016 AMPD emissions from all electric utilities, indicating that the overall SO2 emissions from large sources (such as electric generating units) within Connecticut has decreased substantially between 2009 and the time of this rulemaking. Lastly, according to the 2016 AMPD, SO2 emissions from the still-operational facilities referenced in the Technical Justification account for the vast majority of the SO2 emissions from all electric utilities in the state; therefore, EPA believes that any assessment of SO2 emissions from electric utilities in the state may be informed by the emissions from PSEG Power BPT Harbor, PSEG Power New Haven, and Middletown Power. As previously noted, Norwalk Power was deactivated on June 1, 2013, and the permit for the facility was officially revoked in November 2013.

Data collected at ambient air quality monitors indicate the monitored values of SO2 in the state have remained below the NAAQS. Relevant data from AQS Design Value (DV) 17 reports for recent and complete 3-year periods are summarized in the table below.

As shown in Table 4 above, the DVs for the two monitoring sites for which there are complete data for all years between 2009 and 2015 have decreased between each of the 3-year blocks shown in the table. The highest valid DV in Connecticut for 2013-2015 is 13 ppb, which is well below the NAAQS.

It is not known whether the monitors in Table 4 were sited to capture points of maximum impact from PSEG Power BPT Harbor, PSEG Power New Haven, and Middletown Power. The monitoring information, when considered alone, might not support a conclusion that the areas most impacted by these sources are attaining the NAAQS when considered in the context of the spatial scales defined in the background section of this rulemaking.

Table 5 indicates that while the monitors closest to PSEG Power BPT Harbor (AQS Site ID 09-001-0012) and PSEG New Haven (AQS Site ID 09-009-0027) may not be sited in the area to capture points of maximum concentration from the facilities, the monitors are located in the neighborhood spatial scale in relation to the facilities, i.e., emissions from stationary and point sources may under certain plume conditions, result in high SO2 concentrations at this scale. Forty CFR part 58, appendix D, section 4.4.4(3) defines neighborhood scale as “[t]he neighborhood scale would characterize air quality conditions throughout some relatively uniform land use areas with dimensions in the 0.5 to 4.0 kilometer range.” The closest AQS monitor to Middletown Power with complete 2013-2015 data (AQS Site ID 09-009-0027) would be considered an urban scale monitor when compared to the location of the facility. The most recently available DVs based on 2013-2015 at all three monitors are well below the NAAQS.

However, the absence of a violating ambient air quality monitor within the state is insufficient to demonstrate that Connecticut has met its interstate transport obligation. While the decreasing DVs and their associated spatial scales support the notion that emissions originating within Connecticut are not contributing to a violation of the NAAQS within the state, prong 1 of section 110(a)(2)(D)(i)(I) specifically addresses the effects that sources within Connecticut have on air quality in neighboring states. Therefore, an evaluation and analysis of SO2 emissions data from facilities within the state, together with the potential effects of such emissions on ambient data in neighboring states, is appropriate.

As previously discussed, EPA's definitions of spatial scales for SO2 monitoring networks indicate that the maximum impacts from stationary sources can be expected within 4 kilometers of such sources, and that distances up to 50 kilometers would be useful for assessing trends and concentrations in area-wide air quality. The only nearby state within 50 km of any of the currently operating facilities in Connecticut is New York; all other areas within 50 km of these facilities are contained within Connecticut's borders.18 As a result, no further analysis of the other neighboring states (Rhode Island and Massachusetts) or any other states is necessary for assessing the impacts of the interstate transport of SO2 pollution from these facilities.

As discussed in the Section I of this rulemaking, EPA's current approach for implementing the 2010 primary SO2 NAAQS provides the flexibility to characterize air quality from stationary sources through either air dispersion modeling or ambient air quality monitors that have been sited to capture the points of maximum concentration. EPA observes that Appendix A.1 titled, “AERMOD (AMS/EPA Regulatory Model)” of appendix W to 40 CFR part 51 is appropriate for SO2 in instances where transport distances over which steady-state assumptions are appropriate, up to 50 kilometers. While not written specifically to address interstate transport, the 50 kilometer range in AERMOD aligns with the urban monitoring scale, and thus, EPA believes that the use of AERMOD provides a reliable indication of air quality for transport purposes. In order to further analyze the impact of certain electric utilities in Connecticut on air quality in neighboring states, the state performed air dispersion modeling using emissions data from 2009-2011, which reflects emissions from PSEG Power Bridgeport Harbor, PSEG Power New Haven, and Middletown Power, as well as the now deactivated Norwalk Power Station. As previously discussed, each of these facilities emitted at least 100 tpy of SO2 or more in any given year between 2009 and 2011, and based on the 2016 AMPD, the emissions from the still-operational facilities account for almost 80% of the total SO2 emissions from all electric utilities in Connecticut subject to the Acid Rain Program.

The state performed the air dispersion modeling using the most recent version of the AERMOD modeling system available at the time, which included the dispersion model AERMOD (version 12345), along with its pre-processor modules AERMINUTE, AERMET, AERSURFACE, and AERMAP. A discussion of the state's procedures and results follows below, with references to EPA's “SO2 NAAQS Designations Modeling Technical Assistance Document” (Modeling TAD), most recently updated in August 2016, as appropriate. The EPA observes that while the Modeling TAD is intended to assist states and other interested parties in characterizing local air quality for designations purposes, these same methodologies can be used to determine whether SO2 emissions from electric utilities in Connecticut are leading to exceedances of the NAAQS in a neighboring state. As a result of the localized dispersion pattern and ranges of expected maximum impacts of SO2 emissions from stationary sources in the context of the 2010 primary NAAQS along with our current flexibility to characterize air quality through either properly sited monitors or air dispersion monitoring, EPA believes that the analysis performed by Connecticut for designations purposes is also adequate to address interstate transport requirements.

Individual unit emission rates modeled at the four facilities reflected either the allowable hourly rates based on the maximum firing rate of the unit or hourly continuous emissions monitoring (CEM) data correlated with hourly meteorological data. In other words, Connecticut modeled actual emissions for units at each facility based on CEMs data where it was available, and modeled the allowable hourly rates for units at each facility where CEMs data was not available. EPA believes the use of actual and allowable emissions adequately represented operating conditions at the time of Connecticut's overall infrastructure SIP submission, and therefore the modeled concentrations adequately characterized air quality with respect to emissions from the four facilities.

Furthermore, the overall SO2 emissions levels in Connecticut from these four sources are declining, and the higher emissions levels reflected in the state's modeling analysis represent a conservative estimate of future emissions from these facilities. In particular, EPA expects continued lower emissions from these four facilities as a result of Norwalk Power's closure and permit revocation, along with the measures contained in Regulations of Connecticut State Agencies (RCSA) Section 22a-174-19a 19 intended to limit SO2 emissions within the state. The EPA believes that the 2016 AMPD data presented in Table 3, which shows an overall decrease at each facility, adequately characterizes the extent of these sources' contribution to future air quality in the area.20

To develop the receptor networks for the modeling domains, the state used the AERMOD terrain pre-processor AERMAP. EPA's recommended procedure for characterizing an area by prevalent land use is based on evaluating the dispersion environment within 3 kilometers of the facility. According to EPA's modeling guidelines contained in documents such as the Modeling TAD, rural dispersion coefficients are to be used in the dispersion modeling analysis if more than 50% of the area within a 3 km radius of the facility is classified as rural. Conversely, if more than 50% of the area is urban, urban dispersion coefficients should be used in the modeling analysis. Consistent with these guidelines, the state modeled three of the facilities using urban dispersion, i.e., PSEG Power New Haven, PSEG Power BPT Harbor, and Norwalk Power, and one facility using rural dispersion, i.e., Middletown.

The modeling domain for each facility consisted of a Cartesian grid centered around the facility with each side measuring 100 km, i.e., 50 km from the center of the grid in length. Consistent with the best practices contained in the Modeling TAD, the state's receptors for modeling were placed as follows: 250 meter spacing from the center to 2 km from the center of the grid; 500 meter spacing from 2 km to 10 km from the center of the grid; 1 km spacing from 10 km to 20 km from the center of the grid; and, 2 km spacing from 20 km to 50 km from the center of the grid. The extent of each facility's domain into counties in New York and New Jersey is summarized in the table below.

As part of its technical justification for the designation process, Connecticut provided EPA with access to AERMOD-ready five-year meteorological data processed through AERMET. These datasets were generated from National Weather Service Automated Surface Observing System (ASOS) stations in the state and upper air sounding data at either Albany, New York or Brookhaven, New York. The state used Integrated Surface Hourly Data (ISHD for surface observations), as well as archived one-minute data pre-processed through AERMINUTE, which uses the archived one-minute wind data to develop hourly average wind speed and wind direction for use in AERMET. The meteorological databases used by the state for each of the 4 facilities are summarized in the table below.

The EPA notes that, consistent with the Modeling TAD, the most recent years of meteorological data at the time were used in the state's modeling.

Consistent with EPA's March 1, 2011 memorandum titled, “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2 National Ambient Air Quality Standard,” Connecticut developed background values from hourly SO2 levels measured by Federal Reference Method (FRM) equivalent monitors located throughout the state. The FRM monitors corresponding to each of the facilities' modeling domain are listed in the table below.

In the development of background concentrations, the state adopted what is referred to as a “Tier II” approach: A multi-year average of 2nd high measured 1-hour concentrations of each season and hour-of-day combinations from 2009-2011. These concentrations represent SO2 emissions from out-of-state transport, as well as local/state point, area, and mobile source emissions that were not explicitly modeled. These background concentrations were included in Connecticut's final AERMOD modeling results for the four facilities emitting at or above 100 tpy in any given year between 2009 and 2011. The “Tier II” approach adopted by the state for incorporating background concentration into the total modeled impacts from the four facilities is consistent with EPA guidelines. Furthermore, EPA notes that the emissions from any un-modeled large emissions sources which emit SO2 through fuel combustion can be adequately represented through the calculated background concentrations because of their low emissions. As shown in Table 3, the remaining SO2 emissions from all electric utilities in Connecticut subject to the Acid Rain Program sum to only 63.7 tons, and the largest of these facilities, Montville Station (26.1 tpy), is approximately 70 kilometers away from the closest modeled facility. Based on these low emissions and distance from any of the modeled domains, EPA does not believe that emissions from Montville Station have the potential to alter the concentration gradient around the modeled sources. In a similar manner, EPA does not believe that the remaining 37.6 tpy of SO2 from the remaining electric utilities subject to the Acid Rain Program, ranging from just 11.9 tons per year to almost 0 tons per year, have the potential to alter the concentration gradient around the modeled sources. While data is not available for any year after the 2014 NEI for SO2 emissions as a result of fuel combustion at industrial processes, EPA believes that based on all available information, these emissions do not have the potential to alter the concentration gradient around the modeled sources, and can therefore be adequately represented as background concentration. Specifically, the 2014 NEI lists the sum of these industrial processes with fuel combustion leading to SO2 emissions as approximately 759 tons. See Table 1. EPA has confirmed these industrial processes are not centralized in such a manner that all 759 tons are concentrated in one area.

Due to the proximity between Norwalk Power, PSEG Power BPT Harbor, and PSEG Power New Haven, the emissions units from all three facilities were included in each facility's modeling domain. Middletown Power emissions were modeled separately in the Middletown Power domain, and no other emission units were included in the Middletown Power domain. The modeling results, including the impacts of background concentration, are summarized in the table below.

Table 9 above shows that the highest modeled concentration of SO2 for areas within the modeling domain (including areas outside of Connecticut) of the four facilities in Connecticut emitting at least 100 tpy of SO2 in any given year between 2009 and 2011 is 159 µg/m3, which corresponds to slightly over 80% of the 2010 SO2 NAAQS (set at 75 ppb or approximately 196 µg/m3). This value was modeled at the PSEG Power BPT Harbor domain, and can be attributed to the higher modeled emissions rate input than any of the other three facilities. As displayed above in Table 2, the PSEG Power BPT Harbor facility had the highest SO2 emissions according to the state provided point source inventory, and the facility also has the highest SO2 emissions according to the 2014 NEI.

As noted earlier, the emissions from all facility units except for Middletown Power were used in the modeling domains for Norwalk Power, PSEG Power BPT Harbor, and PSEG Power New Haven. The modeling results consistently demonstrate that the points of maximum impact for these three facilities, all of which are below the level of the 2010 SO2 NAAQS, are located within 2.5 km of the center of each facility and are not located in neighboring states. Furthermore, the modeled concentrations of SO2 decrease dramatically to levels under 80 µg/m3 (approximately 30.5 ppb, or 41% of the NAAQS) at a distance of no more than 10 km away from the center of each facility; therefore, the cumulative impacts from the three facilities' SO2 emissions are not expected to contribute to a violation of the 2010 SO2 NAAQS. It should also be noted that the modeled concentrations at each of these modeling domains are potentially over-estimating current impacts from the facilities because of the permanent closure and permit revocation of Norwalk Power, which occurred after Connecticut developed its Technical Justification for this submission.21

The modeled results for Middletown Power indicate the maximum concentration of 89.7 µg/m3, or approximately 34 ppb (45% of the NAAQS), is expected no more than 2.5 km from the center of the facility and are not located in neighboring states. Furthermore, modeled concentrations where the Middletown Power domain intersects with that of the closest facility (PSEG Power New Haven) specifically in areas encompassed by the town of North Branford, would be at most 125 µg/m3, or approximately 48 ppb (64% of the NAAQS). EPA believes that this cumulative value potentially overestimates the impacts of the facilities' emissions at the intersection of the domains because this value was obtained by adding the highest values in the range of concentrations corresponding to the modeling results at the intersection of the domains. As a result, EPA believes that the SO2 emissions from Middletown Power, when considered alone or in aggregate with the SO2 emissions from the PSEG Power North Haven domain, are not expected to contribute to a violation of the 2010 SO2 NAAQS either within or outside of the modeling domain.

EPA believes that based on all available information at the time of this rulemaking, including the Technical Justification provided by the state, a reasonable way to estimate the impacts from SO2 emissions as a result of electric utility or industrial fuel combustion originating in Connecticut on its neighboring states is to evaluate the following two factors in tandem: (1) The most recent and highest DV based on data collected from ambient air quality monitors in any county included in the individual domains for the four sources in Connecticut, i.e., the counties listed in Table 6; and, (2) the modeled concentrations from each of the facilities in the areas closest to the neighboring states. The approach described below combines the modeled impacts from the electric utilities and industrial processes in Connecticut without a background concentration with a reasonable background concentration in neighboring states to yield a final estimated impact that reflects projected air quality in those neighboring states. The resultant calculated impacts support the notion that based on all available information, emissions from facilities in Connecticut are not contributing significantly to a violation of the NAAQS in neighboring states under a worst case scenario analysis.

As noted in the discussion above, the modeled concentrations of SO2 originating from Norwalk Power, PSEG Power BPT Harbor, and PSEG Power New Haven (and representative of all electric utilities and industrial processes in Connecticut that emit SO2 as a result of fuel combustion) dramatically decrease after 2.5 km from the center of each facility, and at a distance of no more than 10 km from the center of each of these facilities the modeled concentrations are under 30.5 ppb. All emissions from the three sources were included in each individual facility's modeling domain. Therefore, EPA believes that 30.5 ppb is a reasonable value that represents the worst-case potential combined contribution from any electric utility or industrial process in Connecticut which emits SO2 via fuel combustion on any neighboring county included in the modeling domains, particularly because Norwalk Power has ceased operation and its permit has been revoked following Connecticut's infrastructure SIP submission. This value includes background concentrations of SO2 calculated by Connecticut using a Tier II approach, which consisted of the multi-year average of 2nd high measured 1-hour concentrations for each season and hour-of-day combination from 2009-2011. Although Connecticut's Technical Justification did not include the numerical background concentration value for each of the modeling domains, EPA believes that a reasonable background air quality concentration for any of the domains can be estimated using a Tier Ib approach, which consists of the 1-hour DV for the most recent 3-year period from ambient air quality monitors located in Connecticut. The lowest valid DV at any of the monitors listed above (AQS Site ID 09-001-0012) in Table 8 based on ambient air quality data collected between 2013 and 2015 is 9 ppb. The worst-case potential combined contribution from the combined electric utilities and industrial processes on any neighboring county included in the modeling domain, not including background concentrations of SO2, can therefore be estimated to be 21.5 ppb. Additionally, this 21.5 ppb value can be used to estimate the worst case impacts from these sources on any neighboring state, without taking into account the background concentrations of SO2 in those neighboring states.

In order to estimate the worst case combined SO2 impacts from electric utilities and industrial processes in Connecticut on any neighboring state with an appropriate background concentration, EPA added the 21.5 ppb described above to the highest DV in each neighboring county included in the modeling domains for Norwalk Power, PSEG Power BPT Harbor, and PSEG Power New Haven. It should be noted that the DV in each neighboring county included in the modeling domains already includes a monitored background concentration of SO2, and therefore adding a worst case potential combined contribution from the 3 sources of 21.5 ppb using the process described above, instead of 30.5 ppb from the state's Technical Justification, eliminates the double counting of background SO2 concentrations:

As shown in Table 10, the estimated highest worst case SO2 concentrations for all contributing sources, given background combined with all of the potential effects of transport from Norwalk Power, PSEG Power BPT Harbor, and PSEG Power New Haven (also representative of all electric utilities and industrial processes in Connecticut that emit SO2 via fuel combustion) on neighboring states is no greater than 37.5 ppb, or approximately 50% of the NAAQS, and not contributing to a violation of the 2010 standard. This superimposed value includes a valid 2013-2015 DV (which is representative of background concentration) for the monitor in Bronx County, New York (AQS ID 36-005-0133), and modeled concentrations of SO2 that represent the worst case currently and the upper bound for projected future emissions from all electric utilities and industrial processes in Connecticut that emit SO2 through fuel combustion, one of which is no longer operating. After consideration of these factors and based on all available information at the time of this rulemaking, and including an analysis of the worst case scenario including all relevant emissions sources, EPA does not believe that combined emissions from the two remaining operational facilities in Connecticut closest to New York and New Jersey, i.e., PSEG Power BPT Harbor and PSEG Power New Haven, would contribute significantly to a violation of the 2010 SO2 NAAQS anywhere in either New York or New Jersey.

In a similar manner for Middletown Power, EPA observes that the modeling domain for the facility extends only into a small portion of Suffolk County, New York; all other areas in the modeling domain are contained within Connecticut's borders. PSEG Power New Haven is the only other modeled source where the modeling domain intersects the portion of the modeling domain in New York from Middletown Power. As described earlier, the predicted modeled concentration of SO2 at the intersection of the Middletown Power and the PSEG Power New Haven domains is no more than 48 ppb. Subtracting a reasonable estimate of background concentration of SO2 via a Tier 1b approach using the 1-hour design value for the latest 3-year period, the predicted modeled concentration of SO2 at the intersection of the two domains is 39 ppb. Therefore, the estimated worst case SO2 impact on Suffolk County, New York that superimposes the modeled SO2 concentrations from the intersection of the two modeling domains, and the 2013-2015 DV (which includes background) for Suffolk County, New York (AQS ID 36-103-0009) is 48 ppb, or approximately 64% of the NAAQS. EPA acknowledges that the 2013-2015 DV for Suffolk County of 9 ppb is not valid for comparison to the NAAQS due to an incomplete dataset. Available data reported into AQS from the monitor between 2013 and 2015 indicates that the highest 99th percentile 1-hour concentration of SO2 was 10 ppb. Thus, an even more conservative estimate of the worst case SO2 impact on Suffolk County, New York is 49 ppb, or approximately 65% of the NAAQS. Based on all available information at the time of this rulemaking, EPA therefore does not believe that sources or emissions activity originating from Middletown Power, when considered alone or along with those from PSEG Power New Haven, would contribute significantly to a violation of the 2010 SO2 NAAQS in New York. Because the modeling results also adequately account for SO2 emissions originating from fuel combustion at all other electric utilities and industrial process, EPA does not believe that such facilities would contribute significantly to a violation of the 2010 SO2 NAAQS anywhere in New York.

With respect to the potential transport impacts from sources or emissions activity originating in Connecticut on the neighboring states of Rhode Island and Massachusetts, EPA reiterates that all other areas within 50 km of the currently operating sources modeled by the state are contained within Connecticut's borders. In addition, the design value for 2015 for all SO2 monitors within Massachusetts and Rhode Island were below 75 ppb. The monitor with the highest design value in 2015 in either Rhode Island or Massachusetts was 28 ppb (37% of the standard) in Fall River, Massachusetts. As a result, no further analysis of these states is provided, nor does EPA believe that further analysis is needed to establish that SO2 emissions originating in Connecticut as a result of fuel combustion from electric utilities or industrial processes do not significantly contribute to nonattainment of the 1-hour SO2 NAAQS in those neighboring states.

The state has various provisions and regulations to ensure that SO2 emissions are not expected to substantially increase in the future. Notably, federally enforceable conditions contained in RCSA Section 22a-174-19a, “Control of sulfur dioxide emissions from power plants and other large stationary sources of air pollution,”apply to emissions at the four facilities outlined in the state's Technical Justification as well as other sources of SO2 emissions. Specifically, this SIP-approved regulation requires these four facilities, and some others such as fossil-fuel-fired boilers with a maximum heat input capacity of 250 MMBTU/hr or more, to limit their SO2 emissions by either meeting an SO2 emission limit of 0.33 lbs/MMBtu or limiting the amount of sulfur contained in any liquid or gas the facilities may burn to 0.3% sulfur by weight. The recently revised RSCA Section 22a-174-19b 22 will limit those stationary sources that are not subject to RSCA 22a-174-19a to combusting residual fuel oil with a sulfur content of 0.3% or less by weight and distillate fuel oil of 0.0015% or less by weight by July 1, 2018.

The 2014 NEI indicates the single largest, albeit diffuse, source category of SO2 emissions from Connecticut is from fuel combustion for residential heating, in excess of 9,000 tons. To address SO2 emissions originating from the combustion of residential heating, the state's Legislature adopted Connecticut General Statute Title 16a, Chapter 296, Section 16a-21a.23 As of July 1, 2014 the sulfur content for home heating oil in Connecticut is 500 parts per million (ppm), or 0.05% by weight. The new limit of 15 ppm or 0.0015% by weight, which will be federally effective on July 1, 2018, represents a 97% reduction in emissions compared with allowable levels.

According to EPA's guidance “Air Emission Factors and Quantification AP 42, Compilation of Air Pollutant Emission Factors” Chapter 1.3 titled, “Fuel Oil Combustion,” 24 more than 95% of the sulfur in fuel is converted to SO2. The Census Bureau estimates that in 2000 approximately 52.4% of the 1.3 million households in Connecticut relied on fuel oil as their heating fuel, or 681,200 households.25 It is not uncommon for typical households in northeastern states such as Connecticut to use 800 gallons of fuel oil per season, and prior to July 1, 2014, the sulfur content in fuel oil in Connecticut ranged between 2,000-3,000 ppm, approximately six times the current limit. EPA's emission factor to determine the approximate amount of SO2 per 1000 gallons of fuel oil is 142 × S, where S is the percent by weight of sulfur in fuel oil.26 At 3,000 ppm, the percent by weight is 0.3, and therefore the amount of SO2 produced by the combustion of 1000 gallons of fuel oil is approximately 42.6 pounds. This yields an approximate yearly mass amount SO2 emissions, as a result of fuel oil combustion, of over 11,600 tons, which is consistent with the 2011 NEI data of 11,437 tons for home heating oil.

At the time of this proposed rulemaking, the maximum allowable sulfur content in fuel oil allowed by the Connecticut SIP is 0.05% by weight, which should yield estimated yearly SO2 emissions of 1,900 tons from these diffuse emissions sources, which is substantially less than the 2011 NEI data. By 2018, the annual SO2 emissions in Connecticut as a result of the 0.0015% maximum sulfur content in heating oil will be approximately 60 tons. While EPA does not currently have a way to quantify the impacts of multiple small sources of SO2 (the current estimate is approximately 6 pounds of SO2 per year per household that uses fuel oil) in neighboring states, the drastic decrease in the allowable sulfur content in fuel oil and the associated reductions in SO2 emissions, combined with the diffuse nature of these emissions, make it unlikely that the current and future emissions from residential combustion of fuel oil are likely to lead to an exceedance of the NAAQS in a neighboring state. Specifically, by 2018, the yearly SO2 emissions per household using fuel oil will drop to under 0.20 pounds per year.

Lastly, for the purposes of ensuring that SO2 emissions at new or modified sources in Connecticut do not adversely impact air quality, the state's SIP-approved new source review (NSR) and prevention of significant deterioration (PSD) programs are contained in RCSA Section 22a-174-2a, “Procedural Requirements for New Source Review and Title V Permitting” and RCSA Section 22a-174-3a, “Permit to Construct and Operate Stationary Sources.” Both sets of regulations ensure that SO2 emissions due to new facility construction or modifications at existing facilities will not adversely impact air quality in Connecticut or in neighboring states.

In addition to the state's SIP-approved provisions that directly control emissions of SO2, sources in Connecticut are also subject to additional requirements that will have the effect of further limiting SO2 emissions. On September 24, 2013 (78 FR 58467), EPA published its final rulemaking approving Connecticut's request to re-designate the Connecticut portion of the New York-N. New Jersey-Long Island, NY-NJ-CT PM2.5 nonattainment area to attainment. The controls and federally enforceable measures approved into the SIP were for the purposes of attaining the 1997 annual and 2006 24-hour PM2.5 NAAQS. However, as part of state's re-designation request and consistent with the requirements of the CAA, Connecticut submitted SO2 emissions projections for Fairfield and New Haven Counties, showing that SO2 emissions in those counties are projected to decrease by more than 50% between 2007 and 2025 as a result of federal regulations and state regulations adopted into the Connecticut SIP. EPA expects similar reductions throughout the rest of the state following the state's adoption of a low sulfur fuel regulation that requires further reductions in the fuel oil sulfur content by July 1, 2018.27

In addition to the SIP-approved regulations in RCSA, EPA observes that facilities in Connecticut are also subject to the Federal requirements contained in regulations such as Mercury Air Toxic Standards, and the National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. These regulations reduce acid gases, which includes reductions in SO2 emissions.

As discussed in more detail above, EPA has considered the following information in evaluating the state's satisfaction of the requirements of prong 1 of CAA section 110(a)(2)(D)(i)(I):

(1) EPA has not identified any current air quality problems in nearby areas in the adjacent states (Massachusetts, Rhode Island, and New York) relative to the 2010 SO2 NAAQS;

(2) Connecticut demonstrated using air dispersion modeling, that its largest stationary source SO2 emitters are not expected to cause SO2 air quality problems in other states relative to the 2010 SO2 NAAQS;

(3) Past and projected future emission trends demonstrate that such air quality problems in other nearby states are unlikely to occur due to sources in Connecticut; and

(4) Current SIP provisions and other federal programs will further reduce SO2 emissions from sources within Connecticut.

Based on the analysis provided by the state in its SIP submission and based on each of the factors listed above, EPA proposes to find that that sources or emissions activity within the state will not contribute significantly to nonattainment of the 2010 SO2 NAAQS in any other state.

Prong 2 of the good neighbor provision requires state plans to prohibit emissions that will interfere with maintenance of a NAAQS in another state. Given the continuing trend of decreased emissions from sources within Connecticut, EPA believes that reasonable criteria to ensure that sources or emissions activity originating within Connecticut do not interfere with its neighboring states' ability to maintain the NAAQS consists of evaluating whether these decreases in emissions can be maintained over time.

Table 11 below summarizes the SO2 emissions data for the period of time between 2000 and 2015 for the four facilities in Connecticut emitting at least 100 tpy of SO2 in any given year between 2009 and 2011. These facilities were chosen by the state in its analysis and Technical Justification because they were the only facilities to be emitting greater than 100 tons per year of SO2 at the time of the state's submission.

The data shows SO2 emissions from these four facilities have decreased substantially over time, with one facility, Norwalk Power, ceasing operations in June of 2013 and having its permit permanently revoked in November 2013. A number of factors are involved that caused this decrease in emissions, including the effective date of RSCA 22a-174-19a (December 28, 2000) and the change in capacity factors over time due to increased usage of natural gas to generate electricity. The EPA believes that since actual SO2 emissions from the facilities currently operating in Connecticut have decreased between 2000 and 2015, this trend is not expected to interfere with the neighboring states' ability to maintain the 2010 SO2 NAAQS.

EPA expects SO2 from sources other than the four identified electric generating units will be lower in the future. In 2014, the state adopted lower sulfur-in-fuel limits for stationary sources that are not subject to RSCA 22a-174-19a. These new limits are codified in RSCA 22a-174-19b, which as noted above, were approved into the SIP in 2016 as part of Connecticut's regional haze plan. The sulfur-in-fuel limits contained in RSCA 22a-174-19b will limit these stationary sources that are not subject to RSCA 22a-174-19a to combusting residual fuel oil with a sulfur content of 0.3% or less by weight and distillate fuel oil of 0.0015% or less by weight will take effect on July 1, 2018.

Significant reductions from the largest category of SO2 emissions in Connecticut, home heating oil, will also continue into the future. According to the NEI, there already was a reduction of SO2 emissions from this source category of over 3,000 tons between 2011 and 2014. Further reductions will occur as the sulfur-in-fuel limit for home heating oil was lowered to 0.05% by weight on July 1, 2014, therefore only impacting half of the heating season in 2014, and an even more restrictive limit of 0.0015% by weight on July 1, 2018.

Lastly, any future large sources of SO2 emissions will be addressed by Connecticut's SIP-approved Prevention of Significant Deterioration (PSD) program. Future minor sources with SO2 emissions of 15 tons but less than the PSD thresholds will be addressed by the state's minor new source review permit program. The permitting regulations contained within these programs are expected to ensure that ambient concentrations of SO2 in Massachusetts, New York, New Jersey, and Rhode Island are not exceeded as a result of new facility construction or modification originating in Connecticut.

It is worth noting air quality trends for concentrations of SO2 in the Northeastern United States.28 This region has experienced a 77% decrease in the annual 99th percentile of daily maximum 1-hour averages between 2000 and 2015 based on 46 monitoring sites, and the most recently available data for 2015 indicates that the mean value at these sites was 17.4 ppb, or less than 25% of the NAAQS. When this trend is evaluated alongside the monitored SO2 concentrations within the state of Connecticut as well as the SO2 concentrations recorded at monitors in Massachusetts, New York, and Rhode Island, EPA does not believe that sources or emissions activity from within Connecticut are significantly different than the overall decreasing monitored SO2 concentration trend in the Northeast region. As a result, EPA finds it unlikely that sources or emissions activity from within Connecticut will interfere with other states' ability to maintain the 2010 SO2 NAAQS.

Based on each of factors contained in the maintenance analysis, EPA proposes to find the sources or emissions activity within the state will not interfere with maintenance of the 2010 SO2 NAAQS in any other state.

In light of the above analysis, EPA is proposing to approve Connecticut's infrastructure submittal for the 2010 SO2 NAAQS as it pertains to section 110(a)(2)(D)(i)(I) of the CAA. EPA is soliciting public comments on the issues discussed in this notice. These comments will be considered before taking final action. Interested parties may participate in the Federal rulemaking procedure by submitting written comments to EPA New England Regional Office listed in the ADDRESSES section of this Federal Register or by submitting comments electronically, by mail, or through hand delivery/courier following the directions in the ADDRESSES section of this Federal Register.

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

• Is not a significant regulatory action subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);

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

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

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

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

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

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

• Is not subject to requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the Clean Air Act; 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, the SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).