With some exceptions, the Federal Election Campaign Act, 52 U.S.C. 30101-45, and Commission regulations require disclaimers for public communications that are made by a political committee, that expressly advocate the election or defeat of a clearly identified federal candidate, or that solicit contributions. See 52 U.S.C. 30120(a); 11 CFR 110.11(a). 1 The information those disclaimers must include vary depending on whether the communications were authorized or paid for by a candidate, an authorized committee, or an agent of either. See 52 U.S.C. 30120(d); 11 CFR 110.11(b) and (c). All disclaimers must be presented in a clear and conspicuous manner to give the readers, observers, or listeners, adequate notice of who paid for or authorized the communication. 52 U.S.C. 30120(c) and (d); 11 CFR 110.11(c).

Disclaimers on communications transmitted via television or through any broadcast, cable or satellite transmission are subject to certain additional requirements. Among those requirements, such communications made by political committees (whether or not authorized or paid for by a candidate) must carry a written disclaimer in letters equal to or greater than four percent of the communication's vertical picture height. See 52 U.S.C. 30120(d); 11 CFR 110.11(c)(3)(iii)(A), (4)(iii)(A).

On December 4, 2018, the Commission received a Petition for Rulemaking from Extreme Reach (“Petition”) asking the Commission to amend 11 CFR 110.11(c)(3)(iii)(A). The Petition contends that the current standard for TV ads is outdated due to the fact that it was promulgated during a period when television was broadcast in standard definition, rather than the current high definition.

The Petition cites a publication of the International Telecommunication Union, Petition at 13-31, to support its assertion that high definition is the current standard for television broadcasts. The Petition also includes the disclaimer portions of advertising guidelines from the ABC, CBS, and NBC television networks. Petition at 44-47. According to the Petition, these guidelines support the contention that the current industry guidelines for a normal disclaimer size is 22 pixels (approximately two percent of the vertical picture height) using high definition resolution. Petition at 2. The Petition also includes screen shots purporting to show how a disclaimer appears in high definition under the four percent standard, and how a disclaimer appears in high definition using the proposed two percent standard. In light of this, the Petition asks the Commission to open a rulemaking to revise “[the Commission's regulation] to add a separate requirement for [high definition] where letters must be equal to or greater than two (2) percent of the vertical picture height and specify that the four (4) percent of the vertical picture height requirement only applies to [standard definition].”

The Commission seeks comments on the Petition. The public may inspect the Petition on the Commission's website at http://sers.fec.gov/fosers/, or in the Commission's Public Records Office, 1050 First Street NE, 12th Floor, Washington, DC 20463, Monday through Friday, from 9 a.m. to 5 p.m.

The Commission will not consider the Petition's merits until after the comment period closes. If the Commission decides that the Petition has merit, it may begin a rulemaking proceeding. The Commission will announce any action that it takes in the Federal Register .

I. Background

Section 165(i) of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (Dodd-Frank Act), 1 as initially enacted, required a national bank or Federal savings association (FSA) (collectively, banks) with total consolidated assets of more than $10 billion to conduct and report an annual stress test. In addition, section 165 required these banks to provide a report to the Office of the Comptroller of the Currency (OCC) at such time, in such form, and containing such information as the OCC may require. 2 In addition, section 165 required the OCC to issue regulations that establish methodologies for banks conducting their stress test and required the methodologies to include at least three different stress-testing scenarios: “baseline,” “adverse,” and “severely adverse.”  3 In October 2012, the OCC published in the Federal Register its rule implementing the Dodd-Frank Act stress testing requirement. 4 The OCC's rule established two subgroups for covered institutions—“$10 to $50 billion covered institutions” and “$50 billion or over covered institutions”—and subjected the two subgroups to different stress test requirements and deadlines for reporting and disclosures. In February 2018, the OCC published a second rule making additional technical and conforming changes to the OCC's company-run stress testing regulations. 5

The Economic Growth, Regulatory Relief, and Consumer Protection Act (EGRRCPA), enacted on May 24, 2018, amended certain aspects of the company-run stress testing requirement in section 165(i)(2) of the Dodd-Frank Act. 6 Specifically, section 401 of EGRRCPA raises the minimum asset threshold for financial companies covered by the company-run stress testing requirement from $10 billion to $250 billion in total consolidated assets; revises the requirement for banks to conduct stress tests “annually” and instead require them to conduct stress tests “periodically”; and no longer requires the OCC to provide an “adverse” stress-testing scenario, thus reducing the number of required stress test scenarios from three to two. The amendments made by section 401 of EGRRCPA applicable to financial companies become effective eighteen months after EGRRCPA's enactment. 7

The OCC is proposing to revise the OCC's stress testing rule, at 12 CFR part 46, consistent with the amendments made by section 401 of the EGRRCPA (the proposed rule or proposal). 8 The proposal would also make a few additional technical and facilitating changes to the stress testing rule.

As described above, section 401 of EGRRCPA amends section 165 of the Dodd-Frank Act by raising the minimum asset threshold for banks required to conduct stress tests from $10 billion to $250 billion. The proposed rule implements this change by eliminating the two existing subcategories of “covered institution”—“$10 to $50 billion covered institution” and “$50 billion or over covered institution”—and revising the term “covered institution” to mean a national bank or FSA with average total consolidated assets, calculated as required under this part, that are greater than $250 billion. In addition, the proposal makes certain technical and conforming changes to the rule in order to consolidate requirements that were applied differently to $10 to $50 billion covered institutions and $50 billion or over covered institutions.

EGRRCPA eliminates the requirement under section 165 of the Dodd-Frank Act for covered institutions to conduct stress tests on an “annual” basis and, instead, requires that they be “periodic.” The term “periodic” is not defined in EGRRCPA, and the OCC is proposing that, in general, a covered institution would be required to conduct, report, and publish a stress test once every two years, beginning on January 1, 2020, and continuing every even-numbered year thereafter ( i.e., 2022, 2024, 2026, etc.). However, a covered institution that is consolidated under a holding company that is required to conduct a stress test at least once every calendar year (pursuant to regulations of the Board of Governors of the Federal Reserve (Board) at 12 CFR part 252) would be required to conduct, report, and publish its stress test annually. The proposal also adds a new defined term, “reporting year,” to the definitions at § 46.2. A covered institution's reporting year is the year in which a covered institution must conduct, report, and publish its stress test.

Subsequent to these changes, some covered institutions would have a biennial reporting year (biennial stress testing covered institutions) while others would have an annual reporting year (annual stress testing covered institutions). In either case, the dates and deadlines in the OCC's stress testing rule would be interpreted relative to the covered institution's reporting year. For example, if a biennial stress testing covered institution is preparing its 2022 stress test, the covered institution would rely on financial data available as of December 31, 2021; use stress test scenarios that would be provided by the OCC no later than February 15, 2022; provide its report of the stress test to the OCC by April 5, 2022; and publish a summary of the results of its stress test in the period starting June 15 and ending July 15 of 2022.

Based on the OCC's experience overseeing and reviewing the results of company-run stress testing over more than five years, the OCC believes that a biennial stress testing cycle would be appropriate for most covered institutions. For covered institutions that would stress test on a biennial cycle, the OCC expects this level of frequency to provide the OCC and the covered institution with information that is sufficient to satisfy the purposes of stress testing, including: Assisting in an overall assessment of a covered institution's capital adequacy, identifying risks and the potential impact of adverse financial and economic conditions on the covered institution's capital adequacy, and determining whether additional analytical techniques and exercises are appropriate for a covered institution to employ in identifying, measuring, and monitoring risks to the soundness of the covered institution. In addition, the OCC would continue to review the covered intuition's stress testing processes and procedures. Under the proposed rule, all covered institutions that would conduct stress tests on a biennial basis would be required to conduct stress tests in the same reporting year. By requiring these covered institutions to conduct their stress tests in the same year, the proposal would continue to allow the OCC to make comparisons across banks for supervisory purposes and assess macroeconomic trends and risks to the banking industry.

Under the proposal, certain covered institutions would be required to conduct annual stress tests. This subset would be limited to covered institutions that are consolidated under holding companies that are required to conduct stress tests more frequently than once every other year. This requirement reflects the OCC's expectation that covered institutions that would be required to stress test on an annual basis would be subsidiaries of the largest and most systemically important banking organizations ( i.e., subsidiaries of global systemically important bank holding companies or bank holding companies that have $700 billion or more in total assets or $75 billion or more in cross-border activity). This treatment aligns with the agencies' long-standing policy of applying similar standards to holding companies and their subsidiary banks.

Section 165(i) of the Dodd-Frank Act requires the OCC to establish methodologies for covered institutions conducting a stress test and requires the methodologies to include at least three different stress-testing scenarios: “baseline,” “adverse,” and “severely adverse.” EGRRCPA amends section 165 to no longer require the OCC to include an “adverse” stress-testing scenario and reduces the number of required stress test scenarios from three to two. Accordingly, this proposal removes references to the “adverse” stress test scenario in the OCC's stress testing rule. In the OCC's experience, the “adverse” stress-testing scenario has provided limited incremental information to the OCC and market participants beyond what the “baseline” and “severely adverse” stress-testing scenarios provide. The proposal would maintain the requirement for the OCC to conduct supervisory stress tests under both a “baseline” and “severely adverse” stress-testing scenario.

Section 46.3 of the OCC's current rule provides a transition period between when a bank becomes a covered institution and when the bank must report its first stress test. The OCC is amending the transition period in § 46.3(b) to conform to the other changes in this proposal, including the establishment of annual and biennial stress testing covered institutions. Under the proposal, “A national bank or Federal savings association that becomes a covered institution shall conduct its first stress test under this part in the first reporting year that begins more than three calendar quarters after the date the national bank or Federal savings association becomes a covered institution, unless otherwise determined by the OCC in writing.” For example, if a covered institution that conducts stress tests on a biennial basis becomes a covered institution on March 31 of a non-reporting year ( e.g., 2023), the bank must report its first stress test in the subsequent calendar year ( i.e., 2024), which is its first reporting year. If the same bank becomes a covered institution on April 1 of a non-reporting year, it skips the subsequent calendar year and reports its first stress test in the next reporting year ( i.e., 2026). As with other aspects of the stress test rule, the OCC may change the transition period for particular covered institutions, as appropriate in light of the nature and level of the activities, complexity, risks, operations, and regulatory capital of the covered institutions, in addition to any other relevant factors.

The proposal would not establish a transition period for covered institutions that move from a biennial stress testing requirement to an annual stress testing requirement. Accordingly, a covered institution that becomes an annual stress testing covered institution would be required to begin stress testing annually as of the next reporting year. The OCC expects covered institutions to anticipate and make arrangements for this development. To the extent that particular circumstances warrant the extension of a transition period, the OCC would do so based on its reservation of authority and supervisory discretion.

The current § 46.6 of the stress testing rule requires the board of directors of a covered institution, or a committee thereof, to review and approve the covered institution's stress testing policies and procedures as frequently as economic conditions or the condition of the institution may warrant, but no less than annually. The proposal would revise the frequency of this requirement from “annual” to “once every reporting year” in order to make review by the board of directors consistent with the covered institution's stress testing cycle.

Section 46.5 of the stress testing rule states the OCC's reservation of the authority, pursuant to which the OCC may revise the frequency and methodology of the stress testing requirement as appropriate for particular covered institutions. The OCC is proposing to add the following sentence to paragraph (a)(2) of § 46.5 to further clarify its reservation of authority: “The OCC may also exempt one or more covered institutions from the requirement to conduct a stress test in a particular reporting year.”

The proposal would remove certain transition language present in the current stress testing rule that is no longer current. For example, the proposal would strike the following sentence from paragraph (a)(2) of § 46.6: “Until December 31, 2015, or such other date specified by the OCC, a covered institution is not required to calculate its risk-based capital requirements using the internal ratings-based and advanced measurement approaches as set forth in 12 CFR part 3, subpart E.”

The OCC invites comment on all aspects of this proposed rule, including the following questions:

1. The proposal would require a covered institution that is consolidated under a holding company that is required to conduct a stress test at least once every calendar year to treat every calendar year as a reporting year, unless otherwise determined by the OCC. Is this the appropriate frequency for this group of banks? What are the advantages and disadvantages of requiring a covered institution to conduct a stress test at the same frequency as, or at a different frequency than, its holding company?

2. As an alternative to the requirement that a covered institution be required to stress test annually based on the stress testing requirements of its holding company, should the OCC establish separate criteria to capture certain large banks ( e.g., banks above a specified asset threshold), regardless of whether they are consolidated under a holding company?

3. All other covered institutions that are not required to stress test annually would be required to stress test biennially. Is this the appropriate frequency for this category of banks? Should the OCC further subdivide covered institutions into additional categories that would be subject to different frequency requirements?

4. Is the length of the grace period for new covered institutions appropriate? Should the proposal establish a transition period for covered institutions that are already required to stress test and that move from a biennial stress testing requirement to an annual stress testing requirement?

The RCDRIA requires that the OCC, in determining the effective date and administrative compliance requirements of new regulations that impose additional reporting, disclosure, or other requirements on insured depository institutions (“IDIs”), consider, consistent with principles of safety and soundness and the public interest, any administrative burdens that such regulations would place on depository institutions, including small depository institutions, and customers of depository institutions, as well as the benefits of such regulations. 12 U.S.C. 4802. In addition, in order to provide an adequate transition period, new regulations that impose additional reporting, disclosures, or other new requirements on IDIs generally must take effect on the first day of a calendar quarter that begins on or after the date on which the regulations are published in final form.

The proposed rule imposes no additional reporting, disclosure, or other requirements on IDIs, including small depository institutions, nor on the customers of depository institutions. The proposed rule would reduce the frequency of company-run stress tests for a subset of banks, raise the threshold for covered institutions from $10 billion to $250 billion, and reduce the number of required stress test scenarios from three to two for all banks. Nonetheless, in connection with determining an effective date for the proposed rule, the OCC invites comment on any administrative burdens that the proposed rule would place on depository institutions, including small depository institutions, and customers of depository institutions.

The Regulatory Flexibility Act, 5 U.S.C. 601 et seq. (“RFA”), requires an agency, in connection with a proposed rule, to prepare an Initial Regulatory Flexibility Analysis describing the impact of the proposed rule on small entities (defined by the Small Business Administration (“SBA”) for purposes of the RFA to include banking entities with total assets of $550 million or less) or to certify that the proposed rule would not have a significant economic impact on a substantial number of small entities.

As of December 31, 2017, the OCC supervised approximately 886 small entities. 9 Because the proposed rule would only cover OCC-supervised banks with more than $250 billion in consolidated assets, the OCC anticipates that it would not impose additional costs on any OCC-supervised institutions. Therefore, the OCC certifies that the proposed rule would not have a significant economic impact on a substantial number of OCC-supervised small entities.

The Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3521) states that no agency may conduct or sponsor, nor is the respondent required to respond to, an information collection unless it displays a currently valid Office of Management and Budget (OMB) control number. The information collection requirements in the proposal are found in §§ 46.6 through 46.8.

Currently, § 46.6(c) requires that each covered institution establish and maintain a system of controls, oversight, and documentation, including policies and procedures, describing the covered institution's stress test practices and methodologies, and processes for validating and updating the covered institution's stress test practices. The board of directors of the covered institution must approve and review these policies at least annually. Section 46.7(a) requires each covered institution to report the results of their stress tests to the OCC annually. Section 46.8(a) requires that a covered institution publish a summary of the results of its annual stress tests on its website or in any other forum that is reasonably accessible to the public.

Under the proposal, the increase in the applicability threshold for these requirements under the proposal would reduce the estimated number of respondents. In addition the frequency of these reporting, recordkeeping, and disclosure requirements for some institutions would be decreased to biennial.

Estimated number of respondents: 8 (biennial testing: 4; annual testing: 4).

Estimated total annual burden: 6,240 hours.

Comments are requested on:

(a) Whether the information collections are necessary for the proper performance of the OCC's functions, including whether the information has practical utility;

(b) The accuracy of the OCC's estimates of the burden of the information collections, including the validity of the methodology and assumptions used;

(c) Ways to enhance the quality, utility, and clarity of the information to be collected;

(d) Ways to minimize the burden of information collections on respondents, including through the use of automated collection techniques or other forms of information technology; and

(e) Estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.

The OCC analyzed the proposed rule under the factors set forth in the Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1532). Under this analysis, the OCC considered whether the proposed rule includes a federal mandate that may result in the expenditure by state, local, and Tribal governments, in the aggregate, or by the private sector, of $100 million or more in any one year (adjusted annually for inflation).

The proposed rule does not impose new mandates. Therefore, the OCC concludes that implementation of the proposed rule would not result in an expenditure of $100 million or more annually by state, local, and tribal governments, or by the private sector.

Section 722 of the Gramm-Leach-Bliley Act requires the OCC to use plain language in all proposed and final rules published after January 1, 2000. The OCC invites comment on how to make this proposed rule easier to understand.

For example:

• Has the OCC organized the material to inform your needs? If not, how could the OCC present the proposed rule more clearly?

• Are the requirements in the proposed rule clearly stated? If not, how could the proposal be more clearly stated?

• Does the proposed regulation contain technical language or jargon that is not clear? If so, which language requires clarification?

• Would a different format (grouping and order of sections, use of headings, paragraphing) make the proposed regulation easier to understand? If so, what changes would achieve that?

• Is this section format adequate? If not, which of the sections should be changed and how?

• What other changes can the OCC incorporate to make the proposed regulation easier to understand?

For the reasons stated in the preamble, the OCC proposes to amend 12 CFR part 46 as follows:

The additions and revisions read as follows:

The revisions and addition read as follows:

The revision reads as follows:

iii. Redesignating paragraphs (a)(1)(i) and (a)(1)(ii) as paragraphs (a)(1) and (a)(2), respectively; and

The revision reads as follows:

The FAA published a notice of meeting in the Federal Register (83 FR 66646; December 27, 2018) holding an informal airspace meeting to discuss plans for modifying the Miami, FL, Class B Airspace, and the Fort Lauderdale, FL, Class C Airspace areas. The meeting was to be held on Wednesday, February 27, 2019, at Broward College, Pembroke Pines, FL. In light of the recent federal government shutdown, the FAA has decided to postpone the meeting to provide additional time for planning and preparation.

Once arrangements for a new meeting are finalized, the details will be announced in the Federal Register .

On November 6, 2018, the Commission approved for publication in the Federal Register the SEF NPRM. The SEF NPRM was published in the Federal Register on November 30, 2018, with a 75-day comment period scheduled to close on February 13, 2019. 2 Based on the broad range of topics addressed in the SEF NPRM and the number of questions posed, the Commission has determined to extend the comment period. Accordingly, the comment period for the SEF NPRM is open through March 15, 2019.

On November 6, 2018, the Commodity Futures Trading Commission (“Commission”) approved a request for public comment regarding the practice of “post-trade name give-up” on swap execution facilities (the “Name Give-Up Request for Comment”). The Name Give-Up Request for Comment was published in the Federal Register on November 30, 2018, with a 60-day comment period closing on January 29, 2019 (83 FR 61571). On November 6, 2018, the Commission also approved a notice of proposed rulemaking regarding swap execution facilities and the trade execution requirement (the “SEF NPRM”). Like the Name Give-Up Request for Comment, the SEF NPRM was published in the Federal Register on November 30, 2018 (83 FR 61946). However, the SEF NPRM was published with a 75-day comment period that is scheduled to conclude on February 13, 2019. By a separate Federal Register release also published today, the Commission has determined to extend the comment period for the SEF NPRM until March 15, 2019. The Commission anticipates that there will be a large degree of overlap between the group of commenters on the SEF NPRM and the group of commenters on the Name Give-Up Request for Comment, as well as certain overlaps in the issues raised by the two matters. In light of these factors, the Commission believes that it would be sensible for the comment periods for the two matters to conclude on the same date. Accordingly, the comment period for the Name Give-Up Request for Comment is open through March 15, 2019.

PVOS applying for the Limited Excess Property Program (LEPP), the Ocean Freight Reimbursement Program (OFR), or to other agencies under Section 607(a) of the Foreign Assistance Act must complete and submit to USAID a self-certification form indicating that the organization meets the conditions to register as a PVO. The self-certification form requires that the PVO confirm whether it is registered as a U.S.-based organization or an international PVO and must be signed by an authorized representative of the applicant organization. Rescission of this rule is expected to significantly reduce the burden on the public and produce an estimated annual cost savings of $779,000 to USAID and significant projected savings for the PVO community, ranging from $2 million to $11.2 million per year.

All comments must be in writing and submitted through one of the methods specified in the ADDRESSES section above. All submissions must include the title of the action and RIN for this rulemaking. Please include your name, title, organization, postal address, telephone number, and email address in the text of the message. Please note that USAID recommends sending all comments to the Federal eRulemaking Portal because security screening precautions have slowed the delivery and dependability of surface mail to USAID/Washington. At the end of the comment period and until finalization of the action, all comments will be made available at http://www.regulations.gov for public review without change, including any personal information provided. We recommend you do not submit information that you consider Confidential Business Information (CBI) or any information that is otherwise protected from disclosure by statute. USAID will only address substantive comments on the rule. Comments that are insubstantial or outside the scope of the rule may not be considered.

USAID is issuing this proposed rule to rescind 22 CFR part 203. The regulation codifies the rules for PVO registration with USAID. More specifically, 22 CFR part 203 provides the registration process for PVOs, including the conditions for registration and documentation required to be submitted to USAID to complete a registration, as well as the annual renewals and termination processes.

The rule is being rescinded because the current PVO registration process is not needed for the majority of programs open to PVOs across the Agency and therefore has been streamlined to apply only to the Agency programs that require registration by statute (Limited Excess Property Program, Ocean Freight Reimbursement Program, and U.S. Government agencies seeking to provide foreign assistance in accordance with Section 607(a) of the Foreign Assistance Act).

USAID's PVO Registration process was originally created for purposes of designating that an organization met the definition of a PVO and specific organizational standards. Today, USAID examines all potential partner organizations, PVOs or otherwise, via a pre-award assessment in accordance with Agency policy (ADS 303: Grants and Cooperative Agreements to Non- Governmental Organizations; and ADS 302: USAID Direct Contracting), and as required by relevant regulations ( i.e. 2 CFR 200.205 for assistance, and FAR Part 9 for contracts). This process is carried out by warranted USAID Agreement/Contract Officers. The 22 CFR part 203 due diligence process for PVO registration process is duplicative of these pre-award assessments. In addition, PVOs invest a substantial amount of time and money to obtain and maintain registration.

Only three USAID activities are required by statute to have PVOs register with USAID as a condition of eligibility: The Limited Excess Property Program (LEPP), the Ocean Freight Reimbursement Program (OFR) (see FAA section 123 generally and FAA section 607(a)), and granting approval to U.S. Government agencies seeking to provide foreign assistance under FAA Section 607(a). Combined, these programs serve fewer than 50 organizations. USAID has established a simplified registration process for users of the three activities (consisting of self-certification) to save considerable time and resources.

Finally, USAID's PVO registration has historically played the role that private rating organizations now play—publishing data on PVOs and other types of non-governmental organizations. The extensive information publicly available through other providers has eliminated the need for the Agency to produce information on the sector through the maintenance and publication of a registry.

Under E.O. 12866, USAID must determine whether a regulatory action is “significant” and therefore subject to the requirements of the E.O. and subject to review by the Office of Management and Budget (OMB). USAID has determined that this rule is not an “economically significant regulatory action” under Section 3(f)(1) of E.O. 12866. This proposed rule is not a major rule under 5 U.S.C. 804.

E.O.s 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). E.O. 13563 emphasizes the importance of quantifying both costs and benefits, reducing costs, harmonizing rules, and promoting flexibility. Streamlining the duplicative Agency-wide registration program eliminates thousands of labor hours and saves hundreds of thousands of dollars for USAID and the estimated 550 PVOs currently registered with USAID.

USAID utilizes a contractor to manage the PVO registration process, costing the Agency approximately $700,000 per year. In addition, internal USAID labor costs related to the registration process amount to $79,406 in burdened salary and benefit expenses (50% of a GS-13 FTE). With the proposed deregulation, USAID anticipates that it would save $779,406 in government costs per year.

Moreover, USAID estimates that the deregulation will generate significant cost savings for PVOs affected. USAID recently surveyed all PVO registrants (550 in total) to quantify the burden associated with the registration process. Within the past ten years, the number of PVOs registering with USAID on an annual basis has been consistent, ranging from 550 to 553 PVOs per year. Based on survey results, USAID estimates that all 550 PVO registrants spent 4,378 hours to prepare and file registration forms. Using market research, USAID estimates that the burdened labor cost for PVO staff to conduct tasks related to registration ranges from $40 to $80 per hour. 1 Applying those rates to the total 4,378 personnel-hours yields an estimated cost ranging from $175,120 to $350,240 for PVO staff to register.

In addition, with rescission of the rule, USAID concludes that PVOs would achieve significant further cost savings since a component of the PVO registration process is the conduct of a financial audit. USAID estimated the total amount of audits that were conducted for PVO registration purposes but not used to range from 183 (low estimate) to 363 (high estimate). This estimated range refers to PVOs that obtained audits for PVO registration only but did not receive an award from USAID. Based on market research, 2 past experience, and consultations with registered PVOs, the average cost of an audit ranges from $10,000 to $30,000. USAID then calculated a low estimate and high estimate of cost savings. For the high estimate, USAID applied the rate of $30,000 to 363 registrants (two-thirds of the 550 total registrants) that do not receive an award. This yields an annual total of $10,890,000 in expenses avoided. For the low estimate, we applied the $10,000 rate as the audit cost and added the assumption that half of registrants without awards would have procured financial audits, even in absence of the rule. Multiplying $10,000 by 183 (one-third of 550 total registrants) yields a total of $1,830,000 for our low cost estimate of cost savings associated with avoided audit expenses. When estimates for PVO staff time and financial audits are combined, the cost savings for affected PVOs ranges from $2,005,120 to $11,240,240. When added to the expected costs internal to USAID of $779,406, this yields an annual total of incremental cost savings as a result of the rescission from $2,784,526 to $12,019,646. Rescission of our PVO registration rule benefits USAID and our PVOS by streamlining processes and achieving significant cost savings.

This proposed rule is considered an E.O. 13771 deregulatory action. Details on the estimated cost savings of this rule can be found in the rule's economic analysis.

Because the rescission of this regulation removes rather than imposes collection of information, USAID certifies that the proposed rescission will not have a significant economic impact on a substantial number of small entities.

The Paperwork Reduction Act (44 U.S.C. Chapter 3507) applies to this rule since this rule removes information collection requirements formerly approved by the Office of Management and Budget (OMB). Rescission of this rule will significantly reduce paperwork and eliminate information collection requirements on the 550 PVOs that register with the Agency. USAID collects information from all registered PVOs as part of the registration requirement, such as data on their organization, including financial information and provision of a costly financial audit, in order to determine whether the PVO meets the conditions of registration. Under the revised approach, only organizations applying for the Agency's LEPP, OFR awards, or are working with other U.S. government agencies seeking to provide foreign assistance (about 50 organizations in total) would be required to certify that they meet USAID's PVO requirements through the new certification process described earlier. No other data or financial audits would be collected.

USAID previously collected information for PVO registration purposes under the OMB-approved AID Form 1550-2 (OMB Approval Number 0412-0035) but inadvertently operated in non-compliance with the Paperwork Reduction Act (PRA) when OMB approval of this form expired, and USAID did not seek extension of the OMB approval when the Agency moved to an online system for PVO registration. USAID's online PVO registration system required that PVOs provide the same information requested on AID Form 1550-2, including financial data. As such, the public reporting burden for collection of information remained the same under the online system.

The Agency plans to issue this deregulatory action since the purpose of the rule is to remove an unneeded hurdle to doing business with the Agency that imposes unnecessary and excessive costs on the private sector with no value to the Government. The rule proposed for rescission originally called for the collection of information, such as a company's volunteer make-up—a requirement for PVOs that has since been obviated once the volunteer requirement was removed by law. Apart from that requirement, statutory references to registration of PVOs (such as those in FAA sections 123 or 607) provide no further guidance or requirements to the Agency on what such registration should entail. By rescinding this rule, the Agency is free to simplify and streamline registration to remove costly barriers to doing business with the Agency.

The Agency also conducted surveys of the primary stakeholders to the registration process—that of Agency internal stakeholders and the PVO community. Surveys of registered PVOs in 2012 and in 2017 showed that the PVO community did not see significant value in the registration program delineated by the rule at issue, and internal stakeholders for the Agency determined that the information collected in accordance with the rule at issue served no purpose for the Agency. These findings contributed to the decision to remove both the registration program and the rule that required such a rigorous registration process. Additionally, no new rule is being put in place in lieu of the present rule.

For the Limited Excess Property Program, the Ocean Freight Reimbursement Program, and PVOs who are affiliated with U.S. Government agencies seeking to provide foreign assistance under FAA Section 607(a), which all still require registration due to legislative requirements, as provided above, the Agency has developed a simplified registration process to be implemented as part of the application process.

The Alcohol and Tobacco Tax and Trade Bureau (TTB) published Notice No. 177 in the Federal Register on December 6, 2018 (83 FR 62750) proposing the establishment of the West Sonoma Coast American viticultural area (AVA) in Sonoma County, California. The proposed AVA lies entirely within the established Sonoma Coast AVA (27 CFR 9.116) and the North Coast AVA (27 CFR 9.30). In Notice No. 177, TTB described the characteristics of the proposed West Sonoma Coast AVA and solicited public comment on the proposal. In Notice No. 177, the comment period closing date was erroneously listed as January 7, 2019. A correction to the comment period closing date was published in the Federal Register on December 17, 2018, (83 FR 64495) and showed the correct comment period closing date of February 4, 2019.

TTB has received two requests to extend the comment period for Notice No. 177. The first comment, from Lester Schwartz of the Fort Ross Vineyard, requested a 60-day extension of the comment period to allow for “sufficient time to present factually and legally accurate information * * *.” The second comment, from Daniel and Marion Schoenfeld of Wild Hog Vineyard, requested a 30-day extension so that “interested parties are given sufficient time and opportunity to investigate the facts [and] analyze the proposed rule * * *.” These comments are posted as comments 27 and 28 within Docket No. TTB-2018-0008 on the Regulations.gov website at http://www.regulations.gov .

In response to these requests, TTB is reopening the comment period for Notice No. 177 for an additional 60 days. Therefore, TTB will be accepting comments on Notice No. 177 through April 15, 2019.

See the ADDRESSES section above for instructions on how and where to comment on Notice No. 177 and for instructions on how to view or obtain copies of documents and comments associated with Notice No. 177.

Karen A. Thornton of the Regulations and Rulings Division drafted this document.

VA is correcting its proposed rule, Schedule for Rating Disabilities: Infectious Diseases, Immune Disorders, and Nutritional Deficiencies, that published February 5, 2019, in the Federal Register at 84 FR 1678.

In proposed rule FR Doc. 2019-00636 beginning on page 1678 in the issue of February 5, 2019, make the following corrections.

1. On page 1689, beginning in the first column, correct amendatory instruction number 5 to read as follows:

The revisions and additions read as follows:

2. On page 1689, in the amendatory text for Appendix B to Part 4, remove the diagnostic code “6351 HIV-related infection” and correct the diagnostic code “6356” to read “6354”.

3. On page 1690, in the amendatory table for Appendix C to Part 4, the entry “Nontuberculosis mycobacterial infection-Diagnostic code 6312 should be listed before Nontyphoid salmonella infection Diagnostic code 6333”.

On April 11, 2003, GA EPD submitted a SIP revision to EPA for approval that involves changes to Georgia's SIP regulations. In this action, EPA is proposing to approve the portions of the Georgia submission that make changes to Georgia's Rule 391-3-1-.02(2)(nnn)— NO X Emissions from Large Stationary Gas Turbines and Rule 391-3-1-.02(5)— Open Burning . 1 EPA is not acting on the following three other portions of GA EPD's April 11, 2003, submittal at this time. On October 21, 2009, GA EPD submitted a letter withdrawing from the submittal a proposed revision to Georgia Rule 391-3-1-.02(2)(qqq)— Volatile Organic Compound From Extruded Polystyrene Products Manufacturing Utilizing a Blowing Agent . 2 On January 5, 2017 (82 FR 1206), EPA approved changes to Rule 391-3-1-.01— Definitions that were included in the April 11, 2003, submittal. On April 16, 2018 (83 FR 16276), EPA published a proposed rulemaking for Rule 391-3-1-.03(11)(b)— Permit by Rule Standards that was included in the April 11, 2003, submittal.

EPA is proposing to approve a change to Rule 391-3-1-.02(2)(nnn)— NO X Emissions from Large Stationary Gas Turbines (henceforth, Rule (nnn)), which applies to stationary gas turbines with a maximum potential output of greater than 25 megawatts. This rule was originally approved into the Georgia SIP on July 10, 2001 (66 FR 35906), as one of several rules adopted as part of GA EPD's 1-hour ozone attainment demonstration for the Atlanta nonattainment area (Atlanta Area).

Paragraph 1 of Rule (nnn) establishes nitrogen oxides (NO X ) emission limits for the subject gas turbines in a 45-county area that includes and extends beyond the thirteen counties of the previous Atlanta, Georgia, 1979 1-hour ozone maintenance area. 3 Paragraph 2 of the rule provides that these limits apply during the “ozone season” period of May 1 through September 30 of each year.

For existing units, paragraph 5 of Rule (nnn) allowed a source owner or operator to petition the Director, by May 1, 2003, for a change to the rule in case a source is unable to meet the NO X emission limits of paragraph 1 through combustion modifications. Georgia Power, in a 2002 letter to GA EPD, 4 specified certain combustion turbine units at four sources that would not be able to meet the emission limits in paragraph 1 because either emission reduction technologies failed to achieve compliance with the NO X limit of the rule or because compliance proved to be prohibitively expensive. Those units are Unit 6 at Plant Bowen, Units 3A and 3B at Plant McDonough, Units 5A and 5B at Plant Atkinson, and Unit 5A at Plant Wansley. As a result, GA EPD's April 11, 2003, SIP revision adds to Rule (nnn) a new paragraph 7, which provides an exemption from the rule for the units that Georgia Power determined were unable to comply with the NO X limits of paragraph 1 and were therefore taken out of normal service during ozone season. On April 10, 2018, GA EPD informed EPA that only two sources remain affected by this exemption. 5

Paragraph 7 of Rule (nnn) provides that units are exempt from the provisions of the rule if they only operate up to three hours per month for maintenance purposes or under emergency conditions. Thus, such units are to be maintained in an operational condition for the purpose of being available to operate during emergency situations and for normal operation outside of ozone season. If an owner or operator were to choose to operate in excess of the paragraph 7 limitations, the unit would be required to comply with the NO X emission limits of paragraph 1 and could no longer avail itself of the exemption provided by paragraph 7.

EPA is proposing to find that the revisions to paragraph 7 to Rule (nnn) are consistent with the CAA, including Section 110(l) of the Act, because the changes will result in reduced overall emissions from the exempted units. This is because the rule restricts the operation of the subject units during ozone season to only limited circumstances—for short periods of time for the purposes of maintenance and for emergency situations—rather than being able to operate continuously for the generation of electricity for sale. Under the existing approved rule, these units are allowed to operate, in compliance with the NO X emission limits of paragraph 1, for up to 3,672 hours during the ozone season (153 ozone season days multiplied by 24 hours per day). Under the paragraph 7 exemption from the NO X emissions limits, these units are allowed to operate only up to 15 hours during ozone season (3 hours per month multiplied by 5 ozone season months) for maintenance purposes, and only temporarily for emergency purposes.

On December 14, 2006, GA EPD submitted supplemental information with an evaluation of emission rates under the new subparagraph 7. That correspondence, which is included in the docket for this rulemaking, shows Georgia's analysis of the maximum allowable NO X emission rate based on the existing paragraph 1 in comparison to the maximum allowable emissions for maintenance purposes under paragraph 7. As shown in the table on page 3 of GA EPD's analysis, the allowable NO X emissions based on operation for maintenance purposes under paragraph 7 are significantly less than the allowable NO X emissions under the existing paragraph 1—less than two percent of previously allowable emissions. Indeed, since 2008, data from EPA's Air Markets Program Data ( https://ampd.epa.gov/ampd/ ) shows the highest annual NO X emissions reported for these units is less than 0.5 ton.

Paragraph 7 limits the use of these units to two types of emergency situations. First, the units may be used “For the purpose of restarting the steam-electric generating units when all steam-electric generating units at a facility are down and off-site power is not available (also known as a `Black Start').” A “Black Start” occurs in the rare circumstance that there is a system-wide power failure and these combustion turbine units are temporarily started up to provide the necessary power within the facility to re-start other units for the purposes of electricity production for the grid. In an April 10, 2018 email, GA EPD informed EPA that, since the time that Georgia adopted paragraph 7, these combustion turbine units have not been started up for the emergency purpose of a Black Start. 6

Second, paragraph 7 allows these units to be used “When power problems on the grid would necessitate implementing manual load shedding procedures for retail customers.” “Manual load shedding,” as described by GA EPD, is a procedure used when Georgia Power directs power consumers to minimize or stop electric consumption, which can occur in conjunction with brownouts. 7 Such a procedure could be used in an attempt to rebalance power in the grid and avoid a system-wide power failure. Under paragraph 7, these combustion turbine units could be used in this emergency situation to ensure continued power production at a level sufficient to meet grid demand, thus obviating the need to reduce or stop power to consumers through manual load shedding procedures. Since the time that Georgia adopted paragraph 7, manual load shedding procedures have occurred infrequently, 8 and such events do not necessarily require the start-up of an emergency combustion turbine in all cases.

Section 110(l) provides that “the Administrator shall not approve a revision of a plan if the revision would interfere with any applicable requirement concerning attainment and reasonable further progress (as defined in section 171), or any other applicable requirement of this Act.” This proposed SIP revision is consistent with these requirements because potential NO X emissions for maintenance under the new paragraph 7 are significantly less than potential emissions of a unit generating electricity for sale continuously during the 153-day ozone season. In addition, based upon the limited types of emergency use allowed under the rule and the actual operational history and emissions of these units, 9 EPA believes that start-up of these units for emergency purposes is unlikely during any particular ozone season and that any such use that might occur would be brief. Accordingly, EPA is proposing to approve the amendment to Rule (nnn) from GA EPD's April 11, 2003, submittal.

GA EPD's April 11, 2003, submittal makes several changes to the State's Open Burning rule at Rule 391-3-1-.02(5). This rule bans open burning in the State of Georgia with the exception of several specific types of open burning listed at subsection (5)(a). 10 In its submittal, GA EPD explains that the purpose of the changes is to make the rule consistent with current interpretation, implementation, and enforcement.

GA EPD's submittal revises paragraph (5)(a)6, which provides an exclusion from the open burning ban for “Fires set for purposes of training fire-fighting personnel when authorized by the appropriate governmental entity and the guidelines set forth by the Director are strictly observed.” The submittal revises this exclusion from the open burning ban by deleting the ending phrase, “and the guidelines set forth by the Director are strictly observed.” However, the State's “guidelines set forth by the Director” apply to acquired structure burns, which as discussed below, are now part of the authorization process for the new standalone exclusion from the open burning ban at paragraph (5)(a)7. Therefore, the State has removed this phrase from paragraph (5)(a)6.

The submittal adds a standalone exemption from the open burning ban at paragraph (5)(a)7 for “[a]cquired structure burn,” which is defined as “the burning of a house, building or structure for the exclusive purpose of providing training to the fire-fighting personnel or arson investigators.”  11 See Georgia Rule 391-3-1-.02(5)(e)(3). Under the rule, an acquired structure burn may only be conducted after an Authorization to Burn certificate has been issued by the Division. EPA notes that acquired structure burn activities were previously exempted from the open burning ban throughout the State, with some limitations, under Rule 391-3-1-.02(5)(a)(6) (previously (a)(7)). However, GA EPD has pulled “acquired structure burns” out as a standalone exemption to further restrict them during ozone season in the 45 counties encompassing and surrounding the (former) Atlanta ozone 1-hour nonattainment area. 12 EPA is proposing to approve the addition of “acquired structure burns” as a standalone exemption from the open burning ban because it was already exempted under the existing SIP-approved rule as part of training to the fire-fighting personnel under paragraph (5)(a)6. As a standalone exemption, it is now specifically banned during ozone season in the 45 counties of the Atlanta Area under Rule 391-3-1-.02(5)(b). Also, conducting an acquired structure burn requires an Authorization to Burn certificate, which includes the “guidelines set forth by the Director” that were also previously included in paragraph (5)(a)6. 13 In addition, EPA notes that because acquired structure burns are no longer allowed in the 45-county area surrounding the Atlanta Area during ozone season, this change will prevent them from having an adverse impact on the seven counties of the only current nonattainment area in the State. 14 Taken together, the exclusions at paragraphs (5)(a)6 and (5)(a)7 retain the exemption for fires set for purposes of training fire-fighting personnel, provided that proper authorization has been obtained, but now prohibit acquired structure burns during the ozone season in 45 counties of the Atlanta Area.

The submittal also removes the following two types of open burning from the list of activities at subsection (5)(a) that are excluded from the open burning ban: (1) “Destruction of combustible demolition or construction materials either on site or transported to a burning facility upon approval by the Director, unless prohibited by local ordinance and/or regulation” (subparagraph (5)(a)3); and (2) “Setting and maintenance by contractors and tradesmen of miscellaneous small fires necessary to such activities as street-paving work installation or repair of utilities, provided that such fires are kept small in size, no smoke emissions exceed 40 percent opacity, and that local ordinances and regulations do not prohibit such actions” (subparagraph (5)(a)11). Since these two types of open burning would no longer be excluded from the State's open burning ban, they would be prohibited in the State, and this strengthens protection of air quality.

GA EPD's submittal revises another existing exclusion at paragraph (5)(a)8, where the exclusion for “Disposal of tree limbs from storm damage” is changed to “Disposal of vegetative debris from storm damage.” EPA believes the change from “tree limbs” to “vegetative debris” is minimal and will have no impact on air quality.

Paragraph (5)(a)11 (previously (5)(a)12) provides an exception to the open burning ban in “other than predominantly residential areas for the purpose of land clearing or construction or right-of-way maintenance provided the following [five] conditions are met.” The second condition that must be met for this type of open burning to be allowed is that “[t]he location of the burning is at least 1,000 feet from any dwelling located in a predominately residential area.” Two changes are made here. The revised language (1) removes the limitation of this exception to “other than predominantly residential areas,” and (2) changes the second condition that must be met such that rather than requiring this type of burning occur at least 1,000 feet from any “dwelling located in a predominantly residential area,” the rule requires it to occur at least 1,000 feet from any “occupied structure, or lesser distance if approved by the Division.” Thus, the revised rule establishes a minimum distance required from all occupied structures ( e.g., schools, work places and shops), not just residential area dwellings, and provides that the GA EPD Director may approve lesser distances as evaluated and deemed appropriate. The revised language is more protective of air quality because it requires that burning for the purpose of land clearing, construction or right-of-way maintenance must be conducted at least 1,000 feet away from all occupied structures, not just residential dwellings. Any distance less than 1,000 feet must be specifically reviewed and, if deemed appropriate, approved by the Director. EPA believes the amount of distance required is unrelated to attainment or maintenance of the NAAQS, and thus is appropriately left to the State's discretion.

Paragraph (5)(a)13 (previously (5)(a)14) provides seven conditions that must all be met before anyone may conduct “[o]pen burning of vegetative material for the purpose of land clearing using an air curtain destructor.” The revision removes the “Georgia Forestry Office” as one of the entities that may be required to authorize such burning under the first condition at subparagraph (5)(a)13(i). As revised, authorization for such burning must be obtained, if required, from the fire department having local jurisdiction but is not required from the Georgia Forestry Office. EPA believes this revision is within the State's discretion. The revision also adds a new condition, subparagraph (5)(a)13(viii), stating that “[t]he air curtain destructor cannot be fired before 10:00 a.m. and the fire must be completely extinguished, using water or by covering with dirt, at least one hour before sunset.” Thus, the burning of vegetative material for the purpose of land clearing using an air curtain destructor must be limited to daytime hours. This approach is more protective of air quality because it allows less time each day for the burning of vegetative material and enables better oversight by enforcement personnel.

Subsection 391-3-1-.02(5)(b) provides specific county restrictions to implement more stringent limitations on open burning in the counties that were previously part of the Atlanta nonattainment area for the 1997 8-hour ozone NAAQS. GA EPD's April 11, 2003, revision moves the counties of Bartow, Carroll, Hall, Newton, Spalding, and Walton from paragraph (b)2 to paragraph (b)1 (and thus deletes paragraph (b)2) and makes administrative edits to reflect the adopted changes in the allowed types of open burning listed in subsection (5)(a). This is an administrative change that will not impact air quality. The SIP revision also deletes from paragraph (b)4 (renumbered as (b)3) a statement which provides the Division with authority to allow additional types of open burning if it can be demonstrated that adequate disposal facilities are not reasonably available. EPA proposes to approve this revision because it strengthens the SIP by disallowing additional types of open burning currently allowed in some circumstances under the specific county open burning restrictions of subsection (5)(b).

The submittal also includes a revision that would delete the following provision from subsection (5)(c): “A written notification to a person of a violation at one site shall be considered adequate notice of the rules and regulations and subsequently observed violations by the same person at the same or different site will result in immediately appropriate legal action by the Director.” EPA is not proposing to act on this deletion because the provision was never approved into the SIP.

The SIP revision also removes subsection (5)(e) of the State's Open Burning Rule, which prohibits open burning during an “air pollution episode,” defined at Rule 391-3-1-.04 as a condition that could “lead to a substantial threat to the health of persons in the specific area affected.” Georgia has separate state-adopted regulations establishing three levels of an air pollution episode: “Alert,” “Warning,” and “Emergency.” The lowest level, “Alert,” occurs at 0.17 parts per million (ppm) over an 8-hour average for ozone; 150 micrograms per cubic meter (μg/m 3 ) over a 24-hour average for PM 2.5 ; and 350 μg/m 3 over a 24-hour average for PM 10 . 15

In this action, EPA is proposing to approve removal of the prohibition on open burning during an air pollution episode at Rule 391-3-1-.02(5)(e), which currently states: “During an air pollution episode declared by the proper authorities, no open burning of any kind shall be permitted unless open burning is required in the performance of an official duty of any public office, or a fire is necessary to thwart or prevent a hazard which cannot be properly managed by any other means, or is necessary for the protection of public health.” In comparison with the NAAQS, the “Alert” levels under the State's Air Pollution Episode rule are 2.3 times the ozone and PM NAAQS levels or greater. In other words, an exceedance of the NAAQS would occur well before the concentration of air contaminants gets high enough for an air pollution episode declaration, meaning a ban on open burning during an episode, by definition, cannot impact attainment or maintenance of the NAAQS. Further, there have been only a few instances of pollutant levels above the Alert threshold in Georgia, 16 and no recorded declaration of an air pollution episode. And as discussed below, EPA notes the State has ample authority to implement an open burning ban to the extent needed to protect public health. For these reasons, EPA believes that removal of Rule 391-3-1-.02(5)(e) from the SIP is consistent with the CAA, including section 110(l) of the Act, and its implementing regulations.

EPA also notes that removal of this provision will not impact the State's separate “emergency powers” authority under section 110(a)(2)(G) of the Act. That provision requires the SIP to include “emergency powers” to restrain pollution sources presenting an imminent and substantial endangerment to public health or welfare, or the environment. EPA has previously approved Georgia Air Quality Act § 12-9-14 as satisfying the State's section 110(a)(2)(G) obligations. Thus, removal of Rule 391-3-1-.02(d) will not impact this separate applicable requirement.

In this rule, 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, EPA is proposing to incorporate by reference the GA EPD Rule 391-3-1-.02(2)(nnn)— NO X Emissions from Large Stationary Gas Turbines which revises emissions limits for some large stationary gas turbines and Rule 391-3-1-.02(5)— Open Burning, which revises the State's open burning rules, state effective March 26, 2003. EPA has made, and will continue to make, these materials generally available through www.regulations.gov and at the EPA Region 4 office (please contact the person identified in the FOR FURTHER INFORMATION CONTACT section of this preamble for more information).

EPA is proposing to approve portions of Georgia's April 11, 2003, submittal. Specifically, EPA is proposing to approve the changes to GA EPD Rule 391-3-1-.02(2)(nnn)— NO X Emissions from Large Stationary Gas Turbines and Rule 391-3-1-.02(5)— Open Burning . EPA believes that these proposed changes to the regulatory portion of the SIP are consistent with section 110 of the CAA and meet the regulatory requirements pertaining to SIPs. EPA also believes that these proposed changes are specifically consistent with CAA section 110(l), which states that the Administrator shall not approve a revision of a plan if the revision would interfere with any applicable requirement concerning attainment and reasonable further progress (as defined in CAA section 171), or any other applicable requirement of the Act.

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

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

• Is not an Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory action because SIP approvals are exempted under Executive Order 12866;

• 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 (Public Law 104-4);

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

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

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

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

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

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 as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), nor will it impose substantial direct costs on tribal governments or preempt tribal law.

This rulemaking proposes to approve Georgia's SIP revision for the maintenance plan, submitted on August 15, 2018, that would support the State's request that EPA relax the federal RVP requirement from 7.8 psi to 9.0 psi for gasoline sold between June 1 and September 15 of each year (high ozone season) in the Atlanta fuel volatility Area. EPA is also proposing to find that Georgia has demonstrated that changing the federal RVP requirements in the Atlanta fuel volatility Area will not interfere with attainment or maintenance of any NAAQS or with any other applicable requirement of the CAA.

On July 18, 2016, Georgia submitted a 2008 8-hour ozone redesignation request and maintenance plan for the 15-county 2008 8-hour ozone Atlanta maintenance Area, which EPA approved on June 2, 2017 (82 FR 25523). With its redesignation request, Georgia included a maintenance plan demonstration that estimated emissions through 2030 and modeled the federal 7.8 psi RVP summer gasoline volatility limit in the emissions calculations. The August 15, 2018, submittal updates Georgia's 2008 8-hour ozone maintenance plan mobile emissions inventory, associated MVEBs, and includes measures to offset the emissions increases resulting from any relaxation of the federal RVP requirements. The offset measures are described in Section V, below. The updates are summarized in Georgia's submittal which can be viewed at http://www.regulations.gov.

To support the August 15, 2018, SIP revision Georgia evaluated whether changing the 7.8 psi RVP to 9.0 psi RVP federal requirement would interfere with air quality in the 15-county Atlanta maintenance Area. To make this demonstration of noninterference, Georgia completed a technical analysis, including using the current version of EPA's Motor Vehicle Emissions Simulator (MOVES2014a) to project the change in emissions that would result from the RVP relaxation of 7.8 psi to 9.0 psi in the 15-county Atlanta maintenance Area.

In this noninterference demonstration, Georgia used MOVES2014a to develop its projected emissions inventory according to EPA's guidance for on-road and nonroad mobile sources. Georgia used the NONROAD 2008 model within MOVES2014a to develop the nonroad emissions inventory to reflect the emissions changes from relaxing the RVP of 7.8 psi to 9.0 psi in the Atlanta fuel volatility Area.

The 2014 attainment base year mobile emissions were taken directly from the 2008 maintenance SIP and future-year on-road mobile source emissions estimates for 2018, 2020, 2030, and 2040 were modeled using a RVP input parameter of 10.0 psi. 1 Georgia interpolated years 2025 and 2035 to further illustrate the downward trend in emissions. Georgia selected years 2020, 2030 and 2040 because these years are used by the Atlanta Regional Commission in Atlanta's transportation conformity determinations. The 2008 8-hour maintenance plan showed compliance with and maintenance of the 2008 8-hour ozone NAAQS until the 2030 outyear by providing information to support the demonstration that current and future emissions of nitrogen oxides (NOx) and volatile organic compounds (VOC) remained at or below the 2014 base year emissions inventory. For more detailed information on the current approved maintenance plan, see EPA's December 23, 2016 (81 FR 94283), proposed approval of Georgia's maintenance plan for the 2008 8-hour ozone NAAQS.

In this action, EPA is proposing to approve the State's technical demonstration that the 15-county Atlanta maintenance Area can continue to attain and maintain the 2008 ozone NAAQS, as well as other NAAQS, and meet all other CAA requirements after changing to the sale of gasoline with a RVP of 9.0 psi during the high ozone season in the 13-county Atlanta fuel volatility Area. EPA is also proposing to approve the revised mobile emissions inventory, the associated MVEBs, and the measures to offset the emissions increases due to relaxation of the federal RVP requirements. EPA's section 110(l) analysis of the noninterference demonstration included as a part of Georgia's August 15, 2018, SIP revision is provided below. Consistent with CAA section 211(h) and the Phase II volatility regulations, EPA will initiate a separate rulemaking to relax the current federal requirement to use gasoline that complies with the federal RVP limit from 7.8 psi to 9.0 psi in the 13-county Atlanta fuel volatility Area.

On November 6, 1991 (56 FR 56694), EPA designated and classified the following counties in and around the Atlanta, Georgia metropolitan area as a Serious ozone nonattainment area for the 1-hour ozone NAAQS: Cherokee, Clayton, Cobb, Coweta, DeKalb, Douglas, Fayette, Forsyth, Fulton, Gwinnett, Henry, Paulding, and Rockdale. This 13-county 1-hour ozone area is the “Atlanta fuel volatility Area.” The nonattainment designation triggered various requirements for the Atlanta 1-hour ozone nonattainment area. One of those requirements for the 1-hour ozone nonattainment area was the federal 7.8 psi RVP limit for gasoline sold between June 1 and September 15, which is the subject of this action.

Because the Atlanta 1-hour ozone nonattainment area failed to attain the 1-hour ozone NAAQS by November 15, 1999, EPA issued a final rulemaking action on September 26, 2003, to reclassify or “bump up,” the area to a Severe ozone nonattainment area. This reclassification became effective on January 1, 2004 (68 FR 55469). EPA redesignated the Atlanta 1-hour ozone nonattainment area to attainment for the 1-hour ozone NAAQS, effective June 14, 2005 (70 FR 34660).

On April 30, 2004 (69 FR 23858), EPA designated the following 20 counties in and around metropolitan Atlanta as a Marginal nonattainment area for the 1997 8-hour ozone NAAQS: Barrow, Bartow, Carroll, Cherokee, Clayton, Cobb, Coweta, DeKalb, Douglas, Fayette, Forsyth, Fulton, Gwinnett, Hall, Henry, Newton, Paulding, Rockdale, Spalding, and Walton. The Atlanta fuel volatility Area is a sub-set of this 20-county area. Subsequently, EPA reclassified the Atlanta 1997 8-hour ozone nonattainment area as a Moderate nonattainment area on March 6, 2008 (73 FR 12013), because the area failed to attain the 1997 8-hour ozone NAAQS by the required attainment date of June 15, 2007. Subsequently, the Atlanta 1997 8-hour ozone nonattainment area attained the 1997 8-hour ozone standard, and on December 2, 2013 (78 FR 72040), EPA redesignated the area to attainment for the 1997 8-hour ozone NAAQS.

Effective July 20, 2012, EPA designated the following 15-counties Marginal nonattainment for the 2008 8-hour ozone NAAQS: Bartow, Cherokee, Clayton, Cobb, Coweta, DeKalb, Douglas, Fayette, Forsyth, Fulton, Gwinnett, Henry, Paulding, and Rockdale. As mentioned before, the Atlanta fuel volatility Area is sub-set of this 15-county area. The 15-county Atlanta 2008 8-hour ozone nonattainment area did not attain the 2008 8-hour ozone NAAQS by the attainment date of July 20, 2015, and therefore on May 4, 2016, EPA published a final rule reclassifying the area from a Marginal nonattainment area to a Moderate nonattainment area for the 2008 8-hour ozone standard (81 FR 26697). Moderate areas were required to attain the 2008 8-hour ozone NAAQS no later than July 20, 2018, six years after the effective date of the initial nonattainment designations. See 40 CFR 51.1103.

Under the provisions of EPA's ozone implementation rule for the 2008 8-hour ozone NAAQS (40 CFR part 51, subpart AA), EPA can issue a determination that an area is attaining the relevant standard, also known as a Clean Data Determination (40 CFR 51.1118). On July 14, 2016 (81 FR 45419), EPA determined that the Atlanta 2008 8-hour ozone nonattainment area attained the 2008 8-hour ozone NAAQS based on complete, quality-assured, and certified ozone monitoring data for years 2013 through 2015. On July 18, 2016, Georgia submitted a 2008 8-hour ozone redesignation request and maintenance plan for the area (hereafter the “Atlanta maintenance Area), which EPA approved on June 2, 2017 (82 FR 25523).

At the time of all of the redesignations to attainment noted above (for the 1979 1-hour ozone NAAQS, the 1997 8-hour ozone NAAQS, and the 2008 8-hour ozone NAAQS), Georgia did not request relaxation of the federal 7.8 psi RVP requirement for the Atlanta fuel volatility Area. Georgia is now requesting relaxation of the federal 7.8 psi RVP requirement to 9.0 psi for the Atlanta fuel volatility Area.

On October 1, 2015, EPA revised the 8-hour ozone standard from 0.075 ppm to 0.070 ppm (80 FR 65292). Subsequently, on June 4, 2018, EPA published a final rule (effective date August 3, 2018) designating the following 7 Atlanta counties Marginal nonattainment for the 2015 8-hour ozone NAAQS: Bartow, Clayton, Cobb, Dekalb, Fulton, Gwinnett and Henry (83 FR 25776). The 7 counties comprising the 2015 8-hour ozone nonattainment area are also part of the 13-county Atlanta fuel volatility Area. Areas designated Marginal nonattainment must attain the standard by August 3, 2021.

On August 19, 1987 (52 FR 31274), EPA determined that gasoline nationwide had become increasingly volatile, causing an increase in evaporative emissions from gasoline-powered vehicles and equipment. Evaporative emissions from gasoline, referred to as VOCs, are precursors to the formation of tropospheric ozone and contribute to the nation's ground-level ozone problem. Exposure to ground-level ozone can reduce lung function (thereby aggravating asthma or other respiratory conditions), increase susceptibility to respiratory infection, and may contribute to premature death in people with heart and lung disease.

The most common measure of fuel volatility that is useful in evaluating gasoline evaporative emissions is RVP. Under section 211(c) of CAA, EPA promulgated regulations on March 22, 1989 (54 FR 11868), that set maximum limits for the RVP of gasoline sold during the high ozone season. These regulations constituted Phase I of a two-phase nationwide program, which was designed to reduce the volatility of commercial gasoline during the summer ozone control season. 40 CFR 80.27(a)(1). On June 11, 1990 (55 FR 23658), EPA promulgated more stringent volatility controls as Phase II of the volatility control program. These requirements established maximum RVP standards of 9.0 psi or 7.8 psi (depending on the state, the month, and the area's initial ozone attainment designation with respect to the 1-hour ozone NAAQS during the high ozone season).

The 1990 CAA Amendments established a new section, 211(h), to address fuel volatility. Section 211(h) requires EPA to promulgate regulations making it unlawful to sell, offer for sale, dispense, supply, offer for supply, transport, or introduce into commerce gasoline with a RVP level in excess of 9.0 psi during the high ozone season. Section 211(h) prohibits EPA from establishing a volatility standard more stringent than 9.0 psi in an attainment area, except that EPA may impose a lower (more stringent) standard in any former ozone nonattainment area redesignated to attainment.

On December 12, 1991 (56 FR 64704), EPA modified the Phase II volatility regulations to be consistent with section 211(h) of the CAA. 40 CFR 80.27(a)(2). The modified regulations prohibited the sale of gasoline with a RVP above 9.0 psi in all areas designated attainment for ozone, beginning in 1992. For areas designated as nonattainment, the regulations retained the original Phase II standards published on June 11, 1990 (55 FR 23658). A current listing of the federal RVP requirements for states can be found on EPA's website at: https://www.epa.gov/gasoline-standards.

As explained in the December 12, 1991 (56 FR 64704), Phase II rulemaking, EPA believes that relaxation of an applicable federal RVP standard is best accomplished in conjunction with the redesignation process. In order for an ozone nonattainment area to be redesignated as an attainment area, section 107(d)(3) of the Act requires the state to make a showing, pursuant to section 175A of the Act, that the area is capable of maintaining attainment for the ozone NAAQS for ten years after redesignation. Depending on the area's circumstances, this maintenance plan will either demonstrate that the area can maintain attainment for ten years without the more stringent volatility standard or that the more stringent volatility standard may be necessary for the area to maintain its attainment with the ozone NAAQS. Therefore, in the context of a request for redesignation, EPA will not relax the volatility standard unless the state requests a relaxation and the maintenance plan demonstrates, to the satisfaction of EPA, that the area will maintain attainment without the need for the more stringent volatility standard. As mentioned before, under the initial 1-hour ozone nonattainment designation, the 13-county Atlanta fuel volatility Area was required to sell gasoline that complied with the federal 7.8 psi RVP limit from June 1 to September 15 of each year.

Additionally, to comply with the 1-hour ozone NAAQS, Georgia adopted a state fuel program through Georgia Rule 391-3-1-.02(2)(bbb), Gasoline Marketing, (hereafter “Georgia Rule”), which required the sale of low sulfur gasoline with an RVP of 7.0 psi during the high ozone season in a 45-county Georgia Fuel Area. The Georgia Fuel Area included the 20-county 1997 8-hour ozone maintenance and the 15-county 2008 8-hour nonattainment areas (the 15-county area being a subset of the 20-county area) with the remaining counties considered “counties of influence.” The Georgia Rule was implemented through a waiver under section 211(c)(4)(C) of the CAA, which allowed the adoption of a state fuel program more stringent than the Federal requirement. EPA incorporated the Georgia Rule into the Georgia SIP on July 19, 2004 (69 FR 33862). The Georgia Rule was removed from the Georgia SIP effective October 1, 2015 (80 FR 52627).

Again, Georgia did not request relaxation of the applicable 7.8 psi federal RVP standard for the 13-county Atlanta fuel volatility Area when the Area was redesignated to attainment for the 1979 1-hour ozone NAAQS, the 1997 8-hour ozone NAAQS, and the 2008 8-hour ozone NAAQS. Georgia is therefore now submitting a revision to the 2008 8-hour ozone NAAQS maintenance plan and a non-interference demonstration concluding that relaxing the federal RVP requirement from 7.8 psi to 9.0 psi for gasoline sold between June 1st and September 15th of each year in the Atlanta fuel volatility Area would not interfere with attainment or maintenance of the any of the NAAQS.

The modeling associated with Georgia's maintenance plan for the 2008 8-hour ozone NAAQS, approved on June 2, 2017, was premised upon the future-year emissions estimates for 2018, 2022, 2026, and 2030, which include the federal 7.8 psi RVP requirement in the Atlanta fuel volatility Area. To approve Georgia's request to relax the federal RVP requirement in the Atlanta fuel volatility Area, EPA must conclude that requested change will satisfy section 110(l) of the CAA. Section 110(l) requires that a revision to the SIP not interfere with any applicable requirement concerning attainment and reasonable further progress (as defined in section 171), or any other applicable requirement of the Act. In this submittal, Georgia's modeling includes the same future years but is based on the federal 9.0 psi RVP limit. EPA is proposing approval of the noninterference demonstration based on an evaluation of current air quality monitoring data and the information provided in the noninterference demonstration.

Additionally, in the absence of an attainment demonstration, to demonstrate no interference with any applicable NAAQS or requirement of the CAA under section 110(l), EPA believes it is appropriate to allow states to substitute equivalent emissions reductions to compensate for any change to a SIP-approved program, as long as actual emissions in the air are not increased. “Equivalent” emissions reductions are reductions that are equal to or greater than those reductions achieved by the control measure approved in the SIP. To show that compensating emissions reductions are equivalent, adequate justification must be provided. The compensating, equivalent reductions should represent actual emissions reductions achieved in a contemporaneous time frame to the change of the existing SIP control measure order to preserve the status quo level of emission in the air. If the status quo is preserved, noninterference is demonstrated. In addition to being contemporaneous, the equivalent emissions reductions should also be permanent, enforceable, quantifiable, and surplus.

EPA evaluates each section 110(l) noninterference demonstration on a case-by-case basis considering the circumstances of each SIP revision. EPA interprets 110(l) as applying to all NAAQS that are in effect, including those for which SIP submissions have not been made. The degree of analysis focused on any particular NAAQS in a noninterference demonstration varies depending on a number of relevant factors, including the nature of the emissions associated with the proposed SIP revision. EPA's section 110(l) analysis of the noninterference demonstration included as part of Georgia's August 15, 2018, SIP revision is provided below.

On August 15, 2018, Georgia submitted a noninterference demonstration to support the State's request to relax the federal summertime gasoline RVP limit from 7.8 psi to 9.0 psi for the Atlanta fuel volatility Area. This noninterference demonstration evaluates the 15-county Atlanta maintenance Area, which encompasses the smaller Atlanta fuel volatility Area, and the 7-county 2015 8-hour ozone nonattainment area. This demonstration includes an evaluation of the impact that the relaxation of the 7.8 psi RVP requirement would have on Atlanta's ability to maintain the 1997 and 2008 ozone standards. It also evaluates whether the relaxation of the federal RVP requirement would interfere with the ability of the 7-county 2015 8-hour ozone nonattainment area to attain the ozone standard by August 3, 2021, which is the attainment date for areas classified as Marginal, or with any of the other applicable NAAQS. Although the attainment date is August 3, 2021, Marginal areas must show attainment using air quality data for years 2018 through 2020. The 2015 8-hour ozone NAAQS and other NAAQS are addressed later in this notice.

Georgia EPD focused its analysis on the impact of the relaxed federal RVP limit of 9.0 psi to attainment and maintenance of the ozone standards and its precursors NO X and VOC. RVP requirements do not affect lead (Pb), sulfur dioxide (SO 2 ), or carbon monoxide (CO) emissions. Because VOC and NO X emissions are also precursors for PM, and NO X is a precursor for nitrogen dioxide (NO 2 ), these pollutants will be discussed later in this Section. Georgia is currently in attainment for all PM NAAQS, SO 2 , NO 2 , CO, and Pb. The relaxation of the RVP requirement will have little to no impact on emissions of these pollutants or their related precursors.

In this noninterference demonstration, Georgia used EPA's MOVES2014a model to develop its projected mobile (on-road and nonroad) emissions inventory according to EPA's guidance for on-road and nonroad mobile sources. As mentioned before, the future-year on-road mobile source emissions estimates for 2018, 2020, 2025 and 2030, 2035 and 2040 were generated with MOVES2014a using a RVP input parameter of 10.0 psi. This noninterference demonstration modeled year 2018 to align with the 2008 8-hour ozone maintenance plan. Therefore, the year 2018 serves as a surrogate for the year 2019 when Georgia projects the relaxation of the federal RVP requirement would take place. The maintenance plan showed compliance with and maintenance of the 2008 8-hour ozone NAAQS by providing information to support this demonstration that current and future emissions of NO X and VOC remained at or below the 2014 2008 8-hour ozone attainment base year emissions inventory. 2 The analysis in this proposal will primarily refer to the years 2018 and 2030 to stay in alignment with the 2008 8-hour ozone maintenance plan. The emissions trend for year 2020 will be discussed later in the notice because attainment for the 2015 8-hour ozone NAAQS will be based on years 2018 through 2020. Also, based on modeling data from EPA's Cross State Air Pollution Rule, the entire State of Georgia is showing attainment for the 2015 8-hour ozone NAAQS through 2023. 3  

Tables 1 and 2, below, show the direct impact on the on-road mobile source emissions due to a relaxation of the federal RVP requirements from 7.8 psi to 9.0 psi for the Atlanta fuel volatility Area. As summarized below, on-road NO X and VOC emissions increase when the requirement is relaxed to 9.0 psi. NO X emissions increased by 0.29 and 0.05 tons per day (tpd) in 2018 and 2030, respectively in the 15-county Atlanta maintenance Area. VOC emissions also increased by 0.75 and 0.14 tpd in 2018 and 2030, respectively in the same area. While emissions of both precursors increase with a RVP relaxation to 9.0 psi, the increases decrease over time from 0.27 percent in 2018 to 0.13 percent in 2030 for NO X emissions and from 1.11 percent in 2018 down to 0.39 percent in 2030 for VOC emissions in the 15-county Atlanta maintenance Area. Even with the small increases in emissions for the 15-county Atlanta maintenance Area, the overall on-road emissions for NO X decrease from 106.23 tpd in 2018 to 39.60 tpd in 2030. Similarly, the overall on-road emissions for VOC decrease from 68.35 tpd in 2018 to 35.96 tpd in 2030 in the 15-county Atlanta maintenance Area. This indicates that changes in on-road emissions due to a relaxation of the federal RVP limit from 7.8 psi to 9.0 psi will not interfere with continued maintenance of the 2008 8-hour NAAQS in the 15-county Atlanta maintenance Area.

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

On August 25, 2017, the Maryland Department of the Environment (MDE) submitted a revision to its SIP. This SIP submittal consists of Maryland's revised Stage II requirement regulations, at COMAR 26.11.24, Vapor Recovery at Gasoline Dispensing Facilities, which have been revised to allow the decommissioning of existing Stage II vapor recovery systems and which allows newly constructed GDFs (or those undergoing major modifications) the option not to install Stage II equipment. The SIP submittal also includes a demonstration that removal of Stage II vapor recovery systems in Maryland will not interfere with any requirement concerning attainment or reasonable progress of any National Ambient Air Quality Standard (NAAQS), or any other applicable requirement of the CAA. Maryland's SIP demonstration is also intended to show that removal of Stage II requirements is consistent with all relevant EPA guidance.

Stage II vapor recovery is an emission control system that is installed on gasoline dispensing equipment at GDFs for the purpose of capturing fuel vapor that would otherwise be released from vehicle gas tanks into the atmosphere during vehicle refueling. Stage II vapor recovery systems installed on dispensing equipment capture these refueling emissions at the dispenser and route the refueling vapors back to the GDF's underground storage tank, preventing volatile organic compounds (VOCs) that comprise these vapors from escaping to the atmosphere.

Beginning in 1998, newly manufactured gasoline-burning cars and trucks have been equipped with on-board vapor recovery (ORVR) systems that utilize carbon canisters installed directly on the vehicle to capture refueling vapors in the vehicle to be later routed to the vehicle's engine for combustion during engine operation.

Stage II vapor recovery systems and ORVR systems were initially both required by the 1990 amendments to the CAA. Section 182(b)(3) of the CAA requires areas classified as moderate and above ozone nonattainment to implement Stage II vapor recovery programs. Also, under CAA section 184(b)(2), states in the Northeast 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 cars and trucks (passenger vehicles). EPA adopted these requirements in a final action published in the April 6, 1994 Federal Register (59 FR 16262 (hereafter referred to as the ORVR rule). Upon the effective date of that final rule, moderate ozone nonattainment areas were no longer subject to CAA section 182(b)(3) Stage II vapor recovery requirements. Under the ORVR rule, new passenger cars built in model year 1998 and later were required to be equipped with ORVR systems, followed by model year 2001 and later light-duty trucks. ORVR equipment has been installed on nearly all new gasoline-powered light-duty cars, light- duty trucks, and heavy-duty vehicles manufactured since 2006. 1

During the phase-in of ORVR controls, Stage II has provided VOC emission reductions in ozone nonattainment areas and in certain areas of the OTR. Congress recognized that ORVR systems and Stage II vapor recovery systems would over time become largely redundant technologies acting to capture the same pollutants. Therefore, Congress provided authority in the 1990 amendments to the CAA for EPA to allow states to remove Stage II vapor recovery programs from their SIPs upon EPA making a finding that ORVR is in “widespread use.” EPA issued a widespread use finding in a final rule published in the May 16, 2012 Federal Register (77 FR 28772), in which EPA determined that ORVR was in widespread use on a nationwide basis. EPA estimated that as of the end of 2016, more than 88 percent of gasoline refueling nationwide would occur with ORVR-equipped vehicles. 2 Thus, Stage II vapor recovery programs have become largely redundant control systems (for ORVR-equipped vehicles) and as a result, Stage II vapor recovery systems achieve ever declining emissions benefits as more ORVR-equipped vehicles continue to enter the on-road motor vehicle fleet. 3 In areas where certain types of vacuum-assist Stage II vapor recovery systems are used, the interaction between ORVR systems and certain configurations of Stage II vapor recovery systems results in the reduction of overall control system efficiency in capturing VOC refueling emissions compared to what would otherwise be achieved by ORVR or Stage II acting in the absence of the other. In its May 16, 2012 widespread use 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, which among other things, exempted 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 program may submit SIP revisions that would allow for the phase-out of Stage II vapor recovery systems.

The Maryland portion of the Philadelphia-Wilmington-Trenton, PA-NJ-DE-MD metropolitan area (hereafter referred to as the Maryland portion of the Philadelphia area or the Philadelphia area) and the Baltimore, MD metropolitan area were designated by the CAA as severe nonattainment for the 1979 1-hour ozone NAAQS. 4 At the same time, the Maryland portion of the Washington, DC-MD-VA metropolitan area (hereafter referred to as the Maryland portion of the Washington area, or the Washington area) was designated as serious nonattainment under the 1-hour ozone NAAQS. As a result, Maryland adopted Stage II vapor recovery regulations (COMAR 26.11.24) for the Maryland portion of the Washington area, the Maryland portion of the Philadelphia area, and for the Baltimore, MD area on January 18, 1993 (Maryland Register, February 5, 1993, Vol. 20, Issue 3). Maryland submitted a revision to EPA on January 18, 1993 to request the addition of Maryland Stage II requirements to the Maryland SIP, which EPA approved in a final action published in the June 9, 1994 Federal Register (59 FR 29730). Maryland submitted a revised version of this regulation to EPA as a SIP revision on May 23, 2002, which EPA approved in a final action published in the May 7, 2003 Federal Register (68 FR 24363). Maryland further amended its Stage II regulation on January 26, 2005, and EPA approved that revised rule as a revision to the Maryland SIP in a final rule published in the May 8, 2006 Federal Register (71 FR 26688).

Maryland was also required to adopt Stage II, or comparable measures, on a statewide basis under the Stage II OTR provisions of CAA section 184(b)(2). Maryland submitted a comparable measures demonstration to satisfy the Stage II comparability requirement to EPA on November 5, 1997. EPA approved Maryland's November 1997 Stage II comparability SIP in a final rule published in the December 9, 1998 Federal Register (63 FR 67780). Maryland's OTR Stage II comparability demonstration relied on five area source VOC control rules as comparable measures to Stage II.

On August 25, 2017, Maryland submitted a SIP revision to EPA consisting of revised Stage II requirements (COMAR26.11.24) adopted by MDE on November 2, 2015 (state effective November 23, 2015), along with a demonstration of the emission impacts of removal of the Stage II requirements on affected Maryland areas. The revised rule removes the requirements for new Stage II vapor recovery systems in Maryland Stage II areas, while allowing GDFs with installed Stage II systems the option to decommission their equipment or to retain it. Maryland's revised Stage II vapor recovery requirements rule incorporates by reference requirements and procedures for stations opting to decommission Stage II vapor recovery equipment, based on Section 14 of the Petroleum Equipment Institute's Recommended Practices for Installation and Testing of Vapor Recovery Systems at Vehicle-Fueling Sites, 2009 edition, PEI/RP300-09.

Under Maryland's revised rule, GDFs opting to continue to operate Stage II vapor recovery equipment, as well as those opting to decommission Stage II vapor recovery equipment, are subject to continued testing requirements (at specified intervals) and recordkeeping and reporting requirements related to testing. Maryland's revised rule incorporates by reference several test methods applicable to GDFs that opt to decommission or to continue to operate Stage II vapor recovery systems ( Leak Rate and Cracking Pressure of Pressure/Vacuum Valves, TP-201.1E, California EPA Air Resources Board) and ( Determination of Vapor Piping Connections to Underground Gasoline Storage Tanks (Tie-Tank Test), TP-201.3C, California EPA Air Resources Board). For GDFs opting to continue Stage II operation (in addition to prior Stage II test requirements), new tests are added to include a periodic leak rate and cracking pressure test (per TP-201.1E), as well as a tie tank test (per TP-201.3C). GDFs opting to decommission will be subject only to the newly added periodic leak rate and cracking pressure test (TP-201.1E) and the tie tank test (TP-201.3C). Copies of test results must be forwarded to MDE within 30 days of the test.

The August 25, 2017 SIP revision also includes a demonstration supporting the discontinuation of the Maryland Stage II vapor recovery program. This demonstration, discussed in greater detail below, consists of an analysis that after the year 2016, the overall emissions benefits associated with the Stage II program (operated in conjunction with ORVR) are overwhelmed by an emissions disbenefit caused by an ORVR incompatibility with certain vacuum-assist type Stage II equipment. MDE's analysis shows that continued operation of the Stage II vapor recovery program beyond 2016 actually increases VOC emissions due to the incompatibility between certain Stage II and ORVR equipment, coupled with the increasing prevalence of ORVR-equipped vehicles. While Maryland is not requiring every Stage II-equipped GDF to decommission their equipment, it is assumed a majority of existing stations will do so upon the removal of state and federal Stage II mandates. Even if all stations do no decommission their equipment (or delay doing so), overall emission benefits will be improved by the shift to primarily ORVR use in current Stage II subject areas.

EPA has reviewed Maryland's revised COMAR 26.11.24, Vapor Recovery at Gasoline Dispensing Facilities, and accompanying SIP narrative, and has concluded that Maryland's August 25, 2017 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 Plan and Assessing Comparable Measures” (EPA-457/B-12-001; August 7, 2012), hereafter referred to as EPA's Stage II Removal Guidance.

Maryland's August 25, 2017 SIP revision includes a demonstration supporting the discontinuation of the Maryland Stage II vapor recovery program, in compliance with the requirements of the CAA sections 110(l) requirement that revision of the SIP will not interfere with attainment of or reasonable further progress towards attainment of any NAAQS or any other applicable CAA requirement. This demonstration was prepared by MDE based on relevant equations provided in EPA's Stage II Removal Guidance. From this analysis, Maryland determined that by 2016 the emissions benefits from the Stage II vapor recovery program (in conjunction with ORVR) will be overwhelmed by the emission disbenefits stemming from an incompatibility between certain Stage II vacuum-assist based systems and ORVR. Beyond 2016, the continuation of Stage II vapor recovery requirements would increase emissions in the Maryland portions of all analyzed areas, as summarized in Table 1. Based on this analysis, Maryland elected to allow decommissioning of Stage II vapor recovery systems beginning in October 2016.

In evaluating whether a given SIP revision would interfere with attainment of a NAAQS, EPA generally considers whether the SIP revision will allow for an increase in actual emission into the air over what is allowed under the existing EPA-approved SIP. EPA has not required that states produce a new complete attainment demonstration for every SIP revision, provided that the status quo air quality is preserved. See e.g., Kentucky Resources Council, Inc. v. EPA, 467 F.3d 986 (6th Cir. 2006). 5 EPA believes that a planned Stage II decommissioning that is shown not to result in an increase in areawide VOC emissions would be consistent with the conditions of CAA section 110(l), and would not jeopardize attainment or maintenance of an area that formerly relied upon Stage II emission reductions in the approved SIP. Maryland has demonstrated that Stage II vapor recovery will no longer provide emission reductions when compared to ORVR without Stage II vapor recovery in all Maryland ozone nonattainment areas. Since 2016, Stage II vapor recovery (operated in conjunction with ORVR) has been shown by Maryland to result in increased VOC emissions in Maryland's three ozone nonattainment areas—due to incompatibilities between certain types of Stage II equipment and vehicle ORVR systems. Therefore, EPA believes discontinuance of Stage II in Maryland's three ozone nonattainment areas will not interfere with those areas' ability to attain or maintain the NAAQS, or to provide reasonable further progress in meeting the NAAQS.

Throughout this document, wherever “we”, “us” or “our” is used, it is intended to refer to the EPA.

On October 17, 2006 (71 FR 61144), the EPA revised the level of the 24-hour PM 2.5 NAAQS, lowering the primary and secondary standards from the 1997 standard of 65 micrograms per cubic meter (µg/m 3 ) to 35 µg/m 3 . The EPA retained the form of the 1997 24-hour standard, that is, the 98th percentile of the annual 24-hour concentrations at each population-oriented monitor within an area, averaged over 3 years. See 71 FR 61164-5 (October 17, 2006).

On November 13, 2009 (74 FR 58688), the EPA designated a number of areas as nonattainment for the 24-hour PM 2.5 NAAQS of 35 µg/m 3 , including the Provo, UT NAA. The EPA originally designated these areas under the general provisions of CAA title I, part D, subpart 1 (“subpart 1”), under which attainment plans must provide for the attainment of a specific NAAQS (in this case, the 2006 PM 2.5 standards) as expeditiously as practicable, but no later than 5 years from the date the areas were designated nonattainment.

Subsequently, on January 4, 2013, the U.S. Court of Appeals for the District of Columbia Circuit held in NRDC v. EPA   1 that the EPA should have implemented the 2006 24-hour PM 2.5 standard based on both the general NAA requirements in subpart 1 and the PM-specific requirements of CAA title I, part D, subpart 4 (“subpart 4”). In response to the Court's decision in NRDC v. EPA, on June 2, 2014 (79 FR 31566), the EPA finalized the “Identification of Nonattainment Classification and Deadlines for Submission of State Implementation Plan (SIP) Provisions for the 1997 Fine Particulate (PM 2.5 ) NAAQS and 2006 PM 2.5 NAAQS.” This rule classified the areas that were designated in 2009 as nonattainment to Moderate and set the attainment SIP submittal due date for those areas at December 31, 2014. After the court's decision and the EPA's June 2, 2014 rule, on December 16, 2014 the Utah Division of Air Quality (UDAQ) withdrew all prior Provo, UT PM 2.5 SIP submissions and submitted a new SIP to address both the general requirements of subpart 1 and the PM-specific requirements of subpart 4 for Moderate areas.

On August 24, 2016, the EPA finalized the Fine Particulate Matter National Ambient Air Quality Standards: State Implementation Plan Requirements (“PM 2.5 SIP Requirements Rule”), 81 FR 58010, which addressed the January 4, 2013, court ruling. The final PM 2.5 SIP Requirements Rule provides the EPA's interpretation of the requirements applicable to PM 2.5 NAAs and explains how air agencies can meet the statutory SIP requirements that apply under subparts 1 and 4 to areas designated nonattainment for any PM 2.5 NAAQS.

The EPA has previously acted on portions of Utah's Moderate area attainment plan for the Provo, UT NAA. Specifically, we approved certain area source rules and related reasonably available control measure (RACM) analyses on February 25, 2016 (81 FR 9343), October 19, 2016 (81 FR 71988) and September 14, 2017 (82 FR 43205). We have not disapproved any portions of the plan; as a result, the clocks for sanctions under 179(a) and for a Federal Implementation Plan (FIP) under 110(c) are not in effect for the Provo, UT NAA.

Finally, on May 10, 2017 (82 FR 21711), the EPA determined that the Provo, UT NAA failed to attain the 2006 24-hour PM 2.5 NAAQS by the Moderate attainment date of December 31, 2015. With this determination, the Provo, UT NAA was reclassified as a “Serious” area for the 2006 24-hour PM 2.5 NAAQS, with a new attainment date of December 31, 2019. This reclassification triggered an obligation for Utah to submit a new, Serious area attainment plan consisting of several elements, including a control strategy and demonstration of attainment by the new attainment date. See 40 CFR 51.1003(b)(1).

Over the past two decades, the EPA has consistently applied its “Clean Data Policy” interpretation to attainment related provisions of Part D of the CAA. The EPA codified the Clean Data Policy in the PM 2.5 SIP Requirements Rule (40 CFR 51.1015(a)) for the implementation of current and future PM 2.5 NAAQS. See 81 FR 58010, 58161 (August 24, 2016). For a complete discussion of the Clean Data Policy's history and the EPA's longstanding interpretation under the CAA, please refer to the PM 2.5 SIP Requirements Rule.

As codified at 40 CFR 51.1015(a) in the PM 2.5 SIP Requirements Rule, upon a determination by the EPA that a Moderate PM 2.5 NAA has attained the PM 2.5 NAAQS, the requirements for the State to submit an attainment demonstration, provisions demonstrating timely implementation of RACM (including reasonably available control technology (RACT)), a reasonable further progress (RFP) plan, quantitative milestones and quantitative milestone reports, and contingency measures shall be suspended. Additionally, under 40 CFR 51.1015(b), upon determination by the EPA that a Serious PM 2.5 NAA has attained the PM 2.5 NAAQS, the requirements for the State to submit an attainment demonstration, RFP, quantitative milestones and quantitative milestone reports, and contingency measures for the area will be suspended. However, the EPA's longstanding policy for the best available control measure (BACM)/best available control technology (BACT) requirement of CAA section 189(b)(1)(B) is that the requirement is independent of attainment. Thus, a CDD would not suspend the obligation for UDAQ to submit any applicable outstanding BACM/BACT requirements or other requirements that are independent of attainment.

By extension, the requirement to submit a motor vehicle emission budget (MVEB) for the attainment year (both for a Moderate and Serious NAA) for the purposes of transportation conformity is also suspended. A MVEB is that portion of the total allowable emissions defined in the submitted or approved control strategy implementation plan revision or maintenance plan for a certain date for the purpose of meeting RFP milestones or demonstrating attainment or maintenance of the NAAQS, for any criteria pollutant or its precursors, allocated to highway and transit vehicle use and emissions. 2 For the purposes of the transportation conformity regulations, the control strategy implementation plan revision is the implementation plan which contains specific strategies for controlling the emissions of and reducing ambient levels of pollutants in order to satisfy CAA requirements for demonstrations of RFP and attainment. 3 Given that MVEBs are required to support the RFP and attainment demonstration requirements in the attainment plan, suspension of the RFP and attainment demonstration requirements through a CDD also suspends the requirement to submit MVEBs for the attainment and RFP years. The suspension of planning requirements pursuant to 40 CFR 51.1015 does not preclude the State from submitting suspended elements of its Moderate and Serious area attainment plans for the EPA approval for the purposes of strengthening the State's SIP.

The planning elements under subpart 1 and subpart 4 generally include RFP, attainment demonstrations, RACM/RACT, NAA contingency measures, and other state planning requirements related to attaining the NAAQS. 4 The suspension of the obligation to submit such requirements applies regardless of when the plan submissions are due. The CDD does not suspend CAA requirements that are independent of helping the area achieve attainment, such as the requirements to submit an emissions inventory, nonattainment new source review (NNSR), and BACM/BACT requirements. The determination of attainment is not equivalent to a redesignation, and the State must still meet the statutory requirements for redesignation in order to be redesignated to attainment.

In accordance with 40 CFR 51.1015(a) and (b), the CDD suspends the aforementioned SIP obligations until such time as the area is redesignated to attainment, after which such requirements are permanently discharged; or the EPA determines that the area has re-violated the PM 2.5 NAAQS, at which time the State shall submit such attainment plan elements for the Moderate and Serious NAA plans by a future date to be determined by the EPA and announced through publication in the Federal Register at the time the EPA determines the area is violating the PM 2.5 NAAQS.

Determining whether an area has attained the NAAQS is based on monitored air quality data; thus, the validity of a determination of attainment depends in part on whether the monitoring network adequately measures ambient PM 2.5 levels in the NAA. The UDAQ is the governmental agency with the authority and responsibilities under the State's laws for collecting ambient air quality data for the Provo, UT NAA and submitting the data to AQS. UDAQ annually certifies that the data they submit to AQS are quality assured. UDAQ also submits an annual monitoring network plan (AMNP) to the EPA. These plans discuss the status of the air monitoring network, as required under 40 CFR part 58. With respect to PM 2.5 monitoring in the Provo, UT NAA, the EPA found that UDAQ's annual network plans met the applicable requirements under 40 CFR part 58 for the relevant period, 2015-2017, with the exception (discussed below) of UDAQ's 2015 network plan. 5 The UDAQ operated three PM 2.5 State and Local Air Monitoring Station (SLAMS) monitors during the 2015-2017 period within the Provo, UT PM 2.5 NAA: North Provo, Lindon and Spanish Fork.

UDAQ submitted the 2015 AMNP and 5-Year Network Assessment in June 2015. UDAQ's submissions were not reviewed and acted on by Region 8 because the Region was conducting a Technical Support Audit (TSA) of UDAQ's ambient air monitoring program at the time. The TSA was completed in August 2015 and found major and minor/observation issues with the monitoring program. The objective of a TSA is to review a monitoring program's quality assurance (QA) system, in this case the reporting of valid data to the EPA's AQS database. See 40 CFR part 58, appendices A through E. A major finding may indicate that invalid data have been loaded in AQS or that future operations may result in the collection of invalid data. A minor/observation finding will not necessarily lead to data loss or invalidation, but warrants investigation, appropriate follow-up, and audit response. Additional details pertaining to the major and minor findings can be found in the August 2015 TSA, available in the docket.

Due to these monitoring issues, the EPA did not approve UDAQ's 2015 AMNP and a large number of samples from the filter-based Federal Reference Method (FRM) monitors in the Provo, UT NAA were invalidated. 6 The EPA worked with UDAQ to correct the deficiencies found in the August 2015 TSA and after their review of the PM 2.5 data for 2015, UDAQ removed the invalid samples for the Provo, UT FRM monitors and left the valid samples in the AQS database. However, some continuous sampler data from the Provo, UT co-located Federal Equivalent Method (FEM) monitors were determined to have sufficient QA to meet NAAQS comparison requirements. Data from these co-located monitors were used to fill in some of the missing days in 2015, adding to the total number of samples that can be used to determine a 98th percentile value for that year and providing for a complete 2015 monitoring year. Utah used the methodology found in 40 CFR part 50, appendix N 3.0(d)(2) and 3.0(e) to substitute FEM data for the days without FRM data.

The EPA has reviewed the Provo, UT monitoring sites and, using the criteria found in 40 CFR part 58, appendix A, has determined that the QA for the continuous FEM monitors is acceptable. We therefore agree that the data from the FEM monitors can be substituted for the days for which the FRM monitor data was invalid. The data from the FEM monitor at the Spanish Fork monitoring site was used to substitute for invalid FRM data; however, 2015 was still incomplete. Further discussion on the Spanish Fork monitoring site can be found below.

On November 29, 2016, UDAQ submitted a letter that contained the Air Monitoring Program (AMP) 430, AMP 450, AMP 256, and AMP 450NC reports required to certify the 2015 air quality data in Utah. UDAQ completed the data certification process in AQS and with the November 29, 2016 letter, certified that the 2015 air quality data is accurate. Additional information related to these monitors can be found in the November 23, 2016 memoranda found in the docket for this proposed action. Additional details and evaluation of the 2015-2017 AMNPs can be found in our notice proposing to issue a CDD for the Logan, UT-ID Moderate PM 2.5 nonattainment area. See 83 FR 33886 (July 18, 2018). The Logan, UT-ID CDD was subsequently finalized on October 19, 2018 (83 FR 52983).

The EPA's evaluation of whether the Provo, UT PM 2.5 NAA has attained the 2006 24-hour PM 2.5 NAAQS is based on our review of all valid monitoring data “produced by suitable monitors that are required to be submitted to AQS, or otherwise available to EPA . . . .” See Appendix N, 3.0(a). Based on our review, the PM 2.5 monitoring network for the Provo, UT NAA meets the requirements stated above and is therefore adequate for use in determining whether the area attained the 2006 24-hour PM 2.5 NAAQS.

The EPA reviewed the PM 2.5 ambient air monitoring data from the North Provo (AQS site 49-049-0002), Lindon (AQS site 49-049-4001), and Spanish Fork (AQS site 49-049-5010) monitoring sites consistent with the requirements contained in 40 CFR part 50, as recorded in the EPA AQS database for the Provo, UT NAA. As shown in Table 1 below, the North Provo monitor in the Provo, UT NAA has collected complete data since 2011 and is trending downward overall. The Lindon monitor had incomplete data in 2012; however, all other years have been complete and the monitor shows a downward trend too.

The Spanish Fork monitor had incomplete data during the first quarter of 2015 and 2016 and is not eligible for the high value data substitution test in 40 CFR part 50, appendix N. However, based upon the analysis detailed in the monitoring memorandum located in the docket for today's action, 7 the EPA has preliminarily determined that the upper end of the probable range for the 2015-2017 design value at the Spanish Fork monitor (30 µg/m 3 ) is well below the NAAQS. As a result, the EPA has preliminarily concluded that the Provo, UT NAA continues to meet the 2006 24-hour PM 2.5 NAAQS of 35 µg/m 3 for the period 2015-2017, the most recent 3-year period of certified data availability. Should there be a subsequent violation of the 2006 PM 2.5 standards in the Provo, UT NAA, the EPA will withdraw the CDD.

Based on the monitoring data for the period 2015-2017, the EPA is proposing to determine that the area has clean data for demonstrating attainment of the 2006 24-hr PM 2.5 NAAQS. In accordance with 40 CFR 51.1015, a CDD can be made upon a determination by the EPA that a Moderate or Serious PM 2.5 NAA is attaining the PM 2.5 NAAQS. As provided in 40 CFR 51.1015, so long as this area continues to meet the standard, finalization of this determination suspends the requirements for this area to submit an attainment demonstration, associated RACM/RACT, RFP plan, contingency measures, and any other planning SIP requirements related to the attainment of the 2006 PM 2.5 NAAQS. For purposes of this NAAQS, the requirements to submit a projected attainment inventory as part of an attainment demonstration or RFP as well as a MVEB are also suspended by this determination.

As discussed in the PM 2.5 SIP Requirements Rule, the nonattainment base emissions inventory required by section 172(c)(3) is not suspended by this determination because the base inventory is a requirement independent of planning for an area's attainment. See 81 FR 58009 at 58028 and 58127-8 and 80 FR 15340 at 15441-2. Additionally, NNSR requirements are discussed in the PM 2.5 SIP Requirements Rule and required by CAA sections 110(a)(2)(C); 172(c)(5); 173; 189(a); and 189(e), as not being suspended by a CDD because this requirement is independent of the area's attainment planning. See 81 FR 58010 at 58107 and 58127. Furthermore, the BACM/BACT requirements found in CAA section 189(b)(1)(B) are not suspended with a CDD for a Serious NAA due to this requirement being independent of attainment. See 81 FR 58010 at 58128.

Under the proposed CDD, the planning requirements noted above (for both Moderate and Serious areas) shall be suspended, until such time as the area is redesignated to attainment, after which such requirements are permanently discharged. This proposed action, if finalized, will not constitute a redesignation to attainment under CAA section 107(d)(3)(E), because the State must have an approved maintenance plan for the area as required under section 175A of the CAA, and the EPA must determine that the area has met the other requirements for redesignation in order to be redesignated to attainment. The designation status of the area will remain nonattainment for the 2006 PM 2.5 NAAQS until such time as the EPA determines that the area meets the CAA requirements for redesignation to attainment under CAA section 107(d)(3)(E).

It is possible, although not expected, that the Provo, UT area could violate the 24-hour PM 2.5 NAAQS before a maintenance plan is adopted, submitted, and approved, and the area is redesignated to attainment. Under 40 CFR 51.1015(a)(2) and (b)(2), if the EPA determines that the area has re-violated the 24-hour PM 2.5 NAAQS, the EPA will rescind the CDD and the State shall be required to submit the suspended attainment plan elements. Even so, submission of the suspended elements may be insufficient to eliminate future violations. Therefore, the issuance of a SIP call under section 110(k)(5) could be an appropriate response. This SIP call could require the State to submit, by a reasonable deadline not to exceed 18 months, a revised plan demonstrating expeditious attainment and complying with other requirements applicable to the area at the time of this finding. Under CAA section 172(d), the EPA may reasonably adjust the dates applicable to these requirements.

The EPA is proposing to make a CDD for the 2006 24-hour PM 2.5 Provo, Utah (UT) NAA based on the area's current attainment of the standard. Pursuant to 40 CFR 51.1015(a) and (b), the EPA proposes to determine that the obligation to submit any remaining attainment-related SIP revisions arising from classification of the Provo, UT area as a Moderate NAA and subsequent reclassification as a Serious NAA under subpart 4 of part D (of title I of the Act) for the 2006 24-hour PM 2.5 NAAQS is not applicable for so long as the area continues to attain the 2006 24-hour PM 2.5 NAAQS. However, the CDD does not suspend UDAQ's obligation to submit non-attainment-related requirements, which includes the base-year emission inventory, NNSR revisions, and BACM/BACT. This proposed action, if finalized, would not constitute a redesignation to attainment under CAA section 107(d)(3).

This action proposes to issue a determination of attainment based on air quality and to suspend certain federal requirements, and thus, would not impose additional requirements beyond those imposed by state law. For this 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);

• Is not an Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory action because SIP approvals are exempted under Executive Order 12866;

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

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

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

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

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

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

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

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

In addition, this proposed action does not 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 proposed 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).

Throughout this document, whenever “we,” “us,” or “our” is used, we mean EPA. This supplementary information section is arranged as follows:

On March 27, 2008, EPA promulgated a revised 8-hour ozone NAAQS of 0.075 parts per million (ppm). 1 Promulgation of a revised NAAQS triggers a requirement for EPA to designate areas of the country as nonattainment, attainment, or unclassifiable for the standard. For the ozone NAAQS, this also involves classifying any nonattainment areas at the time of designation. 2 Ozone nonattainment areas are classified based on the severity of their ozone levels (as determined based on the area's “design value,” which represents air quality in the area for the most recent 3 years). The classifications for ozone nonattainment areas are marginal, moderate, serious, severe, and extreme. 3

Areas that EPA designates nonattainment for the ozone NAAQS are subject to the general nonattainment area planning requirements of CAA section 172 and also to the ozone-specific planning requirements of CAA section 182. Ozone nonattainment areas in the lower classification levels have fewer and/or less stringent mandatory air quality planning and control requirements than those in higher classifications. For marginal areas, a state is required to submit a baseline emissions inventory, adopt provisions into the SIP requiring emissions statements from stationary sources, and implement a NNSR program for the relevant ozone NAAQS. 4 For moderate areas, a state needs to comply with the marginal area requirements, plus additional moderate area requirements, including the requirement to submit a modeled demonstration that the area will attain the NAAQS as expeditiously as practicable but no later than 6 years after designation, the requirement to submit a reasonable further progress (RFP) plan, the requirement to adopt and implement certain emissions controls, such as RACT and I/M, and the requirement for greater emissions offsets for new or modified major stationary sources under the state's NNSR program. 5

On June 11, 2012, 6 EPA designated the Chicago area as a marginal nonattainment area for the 2008 ozone NAAQS. The Chicago area includes Cook, DuPage, Kane, Lake, McHenry, and Will Counties and part of Grundy and Kendall Counties in Illinois; Lake and Porter Counties in Indiana; and part of Kenosha County in Wisconsin. On May 4, 2016, 7 pursuant to section 18l(b)(2) of the CAA, EPA determined that the Chicago area failed to attain the 2008 ozone NAAQS by the July 20, 2015 marginal area attainment deadline and thus reclassified the area from marginal to moderate nonattainment. In that action, EPA established January 1, 2017, as the due date for all moderate area nonattainment plan SIP requirements applicable to newly reclassified areas. Pleasant Prairie and Somers townships in Kenosha County are part of the Chicago area nonattainment area. The remainder of Kenosha County is designated as unclassifiable/attainment.

On May 21, 2012, 8 EPA designated Sheboygan County in Wisconsin as a marginal nonattainment area for the 2008 ozone NAAQS. On December 19, 2016, 9 pursuant to section 18l(b) of the CAA, EPA determined that Sheboygan County failed to attain the 2008 ozone NAAQS by the July 20, 2016 marginal area attainment deadline and thus reclassified the area from marginal to moderate nonattainment. In that action, EPA established January 1, 2017, as the due date for all moderate area nonattainment plan SIP requirements applicable to newly reclassified areas.

Effective March 6, 2017, EPA found that 15 states and the District of Columbia failed to submit SIP revisions in a timely manner to satisfy certain requirements for the 2008 ozone NAAQS. 10 This finding established certain deadlines for the imposition of sanctions if a state does not submit a timely SIP revision addressing the requirements for which the finding was made and for EPA to promulgate a FIP to address any outstanding SIP requirements. As part of that action, EPA made a finding that Wisconsin failed to submit a marginal NNSR SIP for the Wisconsin portion of the Chicago area and for Sheboygan County.

I. What action is the EPA taking today?

Through letters dated April 4, 2017, August 22, 2017, and September 28, 2018, the State of North Carolina, through NCDEQ, submitted three SIP revisions for EPA approval. 1 These SIP revisions include structural amendments to 15A North Carolina Administrative Code (NCAC) 02D Section .0501— Compliance with Emission Control Standards, and typographical amendments to 15A NCAC 02D Section .0536— Particulate Emissions from Electric Utility Boilers. 2 Additionally, the SIP revisions incorporate, for primarily structural, organizational reasons, four new rules: 15A NCAC 02D Sections .2609— Particulate Testing Method, .2610— Opacity, .2611— Sulfur Dioxide Testing Methods, and .2617— Total Reduced Sulfur. EPA has preliminarily determined that a number of these changes to the North Carolina SIP are either structural or minor and ministerial and do not alter the meaning of any SIP provisions, that others are SIP-strengthening, and that all are consistent with federal regulations regarding source testing and are approvable pursuant to section 110 of the CAA. The changes that are the subject of this proposed rulemaking are described in further detail in section III below.

On November 19, 2008, North Carolina submitted to EPA for approval a SIP revision which restructured the way the SIP identified source testing methods. The November 19, 2008, SIP revision removed all references to required source testing methods from the source-category rules of the SIP and compiled them into a new section: Subchapter 2D Section .2600, Source Testing. This new rule section consolidated North Carolina's testing protocols with federal air source testing methods formerly located throughout DEQ's rules and amended existing source-category standards to add cross-references to the applicable testing rules in the new section, 2D Section .2600. EPA partially approved the November 19, 2008, SIP revision, together with several other SIP revisions, but did not act on some of the proposed amendments at the time. See 78 FR 27065 (May 9, 2013).

Through a letter dated April 4, 2017, North Carolina submitted a request to withdraw some of the proposed changes from the November 19, 2008, SIP revision and to resubmit these changes for EPA's approval. In its request, North Carolina withdrew amendments to 2D Sections .0501— Compliance with Emission Control Standards, .0536— Particulate Emissions from Electric Utility Boilers, and .2609— Particulate Testing Methods, as well as one rule under Subchapter 2Q, Section .0523— Changes Not Requiring Permit Revisions and resubmitted these changes with an updated redline strikeout of each section.

Similarly, through a letter dated August 22, 2017, North Carolina withdrew from the November 19, 2008, SIP revision, new provisions found at 2D Sections .2610— Opacity, .2611— Sulfur Dioxide Testing Methods, and .2617— Total Reduced Sulfur, and resubmitted these new provisions with an updated redline strikeout of each new section.

Lastly, in letters dated September 28, 2018, North Carolina submitted: (1) An additional SIP withdrawal and revision, and (2) a separate withdrawal. Specifically, the September 28, 2018, SIP revision withdrew the changes to 2D Sections .0501 and addition of .2609 from the April 4, 2017, SIP revision, and concurrently resubmitted these for incorporation into the SIP with updated redline strikeouts. In the separate withdrawal letter, also dated September 28, 2018, North Carolina withdrew 2Q Section .0523 from the April 4, 2017, SIP revision. 3 North Carolina decided not to resubmit 2Q Section .0523 because this provision applies to North Carolina's Title V permitting program and is not appropriate for approval into the SIP.

The changes proposed for approval herein are a part of North Carolina's strategy to attain and maintain the national ambient air quality standards (NAAQS), and EPA has preliminarily determined that they are approvable pursuant to section 110 of the CAA. The changes that are the subject of this proposed rulemaking and EPA's rationale for proposing to approve them are described in further detail below.

EPA is proposing to approve into the North Carolina SIP amendments to Subchapter 2D Sections .0501— Compliance with Emission Control Standards, and .0536— Particulate Emissions from Electric Utility Boilers, as well as the addition of four new rules, Sections .2609— Particulate Testing Methods, .2610— Opacity, .2611— Sulfur Dioxide Testing Methods, and .2617— Total Reduced Sulfur. Below is a description of these changes and our rationale for proposing to approve them.

Section .0501 is amended by removing all language regarding testing methods for determining compliance with emission control standards, which was previously found in paragraphs (b) and (c)(1) through (c)(18). As mentioned in Section II, above, North Carolina's November 19, 2008, SIP revision included a new set of rules at 2D Section .2600, Source Testing. As described in more detail below, the operative portions of the deleted language from Section .0501 have all been relocated to the appropriate subsections of 2D Section .2600, some of which were previously approved into the SIP in 2013. See 78 FR 27065 (May 9, 2013). Other subsections of 2D Section .2600 are now being proposed for SIP approval through the April 4, 2017, August 22, 2017, and September 28, 2018, SIP revisions. In addition, all of the corresponding deletions of Section .0501 language are now being proposed for SIP approval. Further details on the proposed deletions of the Section .0501 testing methods and their current or new locations are presented below.

1. Whereas the relocation of Section .0501's testing methods to Section .2600 was previously approved in the 2013 final rule for the November 19, 2008, SIP revision, the corresponding deletion of the paragraphs from Section .0501 now being proposed for approval is as follows  4 :

• Paragraphs (b), (c)(14), and (c)(18) language is found in current Section .2602— General Provisions on Test Methods and Procedures.

• Paragraph (c)(1) language is found in current Section .2604— Number of Test Points.

• Paragraph (c)(2) language is found in current Section .2605— Velocity and Volume Flow Rate.

• Paragraph (c)(7) language is found in current Section .2612— Nitrogen Oxide Testing Methods.

• Paragraph (c)(12) language is found in current Section .2608— Number of Runs and Compliance Determination.

• Paragraph (c)(13) language is found in current Section .2606— Molecular Weight.

• Paragraph (c)(15) language is found in current Section .2621— Determination of Fuel Heat Content Using F-Factor.

• Paragraph (c)(17) language is found in current Section .2613— Volatile Organic Compound Testing Methods.

2. Deletion being proposed for approval through the April 4, 2017, SIP revisions:

• Paragraph (c)(3) and (c)(16) language is found in new Section .2609— Particulate Testing Methods.

3. Deletion being proposed for approval through the August 22, 2017, SIP revision:

• Paragraph (c)(4), (c)(5), and (c)(6) language is found in new Section .2611— Sulfur Dioxide Testing Methods.

• Paragraph (c)(8) language is found in new Section .2610— Opacity.

• Paragraph (c)(10) language is found in new Section .2617— Total Reduced Sulfur.

If EPA finalizes this proposed approval, all of the necessary testing methods will have been deleted from Section .0501 and relocated to one of the current or new subsections in Section .2600. EPA has reviewed these changes to Section .0501 and has preliminarily determined that they are approvable pursuant to section 110 of the CAA because they are structural in nature and the deleted language is relocated and retained in 2D Section .2600 of the North Carolina SIP.

Section .0536 is amended by updating cross-references that identify the location of the testing method procedures and requirements. Previously, Section .0536 referred to Section .0501 to identify the applicable procedures and requirements for stack testing when measuring emission rates for electric utility boilers. Because North Carolina has relocated all language regarding testing methods to Section .2600, amendments to Section .0536 substitute all cross-references to Section .0501 with cross-references to Section .2600.

Additionally, North Carolina is adding a reference in Section .0536 to its quality assurance program found in Section .0613 and making a minor typographical change by substituting the word “director” with “Director” throughout Section .0536.

EPA has reviewed these changes and has preliminarily determined that the amendments to Section .0536 are minor ministerial changes that do not result in a change to the existing source testing requirements in the North Carolina SIP and are approvable pursuant to section 110 of the Act.

As noted in Section III.A.2, above, most of the language of new Section .2609 was previously found in paragraphs (c)(3) and (c)(16) of Section .0501, which are now being proposed for deletion. Section .2609 adopts the federal testing Method 5 of Appendix A of 40 CFR part 60, and Method 202 of Appendix M of 40 CFR part 51, which are meant to demonstrate compliance with particulate matter (PM) emission standards. As an alternative to Method 5, Section .2609 also adopts Method 17 of Appendix A of 40 CFR part 60, which can be used under certain testing conditions. For steam generators that use soot blowing as a routine method of cleaning heat transfer surfaces, Section .2609 also establishes specific testing requirements to account for the soot's contribution to particulate emissions. Lastly, paragraph (f) of Section .2609 establishes requirements for sources to use Method 201 or 201A, in combination with Method 202, to demonstrate compliance specifically for PM 10 emission standards.

Method 5 and Method 17, which are meant to measure filterable PM, were testing method options previously found in Section .0501 that are now relocated to new Section .2609. A source's total particulate emissions, however, also includes condensable PM, and is measured using different testing methods. The additional requirement in .2609 to use Method 202 to demonstrate compliance with particulate emission standards, as well as the option to use a combination of Methods 201 or 201A in conjunction with Method 202 for PM 10 compliance, are new provisions to this rule that require testing of condensable PM as well as filterable PM. North Carolina requires the use of testing methods for both filterable and condensable PM to capture total particulate emissions.

EPA has reviewed this change and has preliminarily determined that the addition of Section .2609, including the additional test methods, is consistent with federal regulations. The addition of new Section .2609 both retains and strengthens the existing source testing requirements of the North Carolina SIP.

As noted in Section III.A.3, above, most of the language of new Section .2610 was previously found in paragraph (c)(8) of Section .0501, which is being proposed for deletion. Section .2610 adopts the federal Method 9 of Appendix A of 40 CFR part 60, which is meant to determine compliance with opacity standards by visual observation, and Method 22 of Appendix A of 40 CFR part 60, which is meant to determine compliance with opacity standards when they are based upon the frequency of fugitive emissions from stationary sources as specified in an applicable rule.

The requirement to use Method 9 when determining opacity by visual observation was previously found in Section .0501 and is now relocated to new Section .2610. A new provision not found in Section .0501 is the option to use Method 22 for determining compliance with opacity standards based upon the frequency of fugitive emissions from stationary sources. The use of Method 22, as described in Section .2609, is allowed only in cases where this method is required by a permit condition or another applicable regulation.

EPA has reviewed this change and has preliminarily determined that the addition of new Section .2610, including the option to use Method 22, is consistent with federal regulations. The addition of new Section .2610 both retains and strengthens the existing source testing requirements of the North Carolina SIP.

As noted in Section III.A.3, above, the language of this new provision, Section .2611, was previously found in paragraphs (c)(4), (5), and (6) of Section .0501, which are being proposed for deletion. Section .2611 establishes testing methods and methodologies for sulfur dioxide in different types of sources, specifically:

a. If compliance is to be demonstrated for a combustion source through stack sampling, the procedures described in Method 6 or Method 6C of Appendix A of 40 CFR part 60 shall be used. When using Method 6 procedures to demonstrate compliance, compliance shall be determined by averaging six 20-minute samples taken over such a period of time that no more than 20 minutes elapses between any two consecutive samples. The 20-minute run requirement applies to Method 6 only, not to Method 6C. Method 6C is an instrumental method and the sampling is done continuously.

b. Fuel burning sources not required to use continuous emissions monitoring to demonstrate compliance with sulfur dioxide emission standards may determine compliance with sulfur dioxide emission standards by stack sampling or by analyzing the sulfur content of the fuel.

c. For stationary gas turbines, Method 20 of 40 CFR part 60 shall be used to demonstrate compliance with applicable sulfur dioxide emissions standards.

d. When compliance is to be demonstrated for a combustion source by analysis of sulfur in fuel, sampling, preparation, and analysis of fuels shall be according to American Society of Testing and Materials (ASTM) methods. The Director may approve ASTM methods different from those described in the regulation if they will provide equivalent or more reliable results. The Director may prescribe alternate ASTM methods on an individual basis if that action is necessary to secure reliable test data. Paragraph (d)(1) of Section .2611 outlines specific ASTM methods for Coal Sampling, and paragraph (d)(2) outlines specific ASTM methods for Oil Sampling.

e. When compliance is shown for sulfuric acid manufacturing plants or spodumene ore roasting plants through stack sampling using the methods provided in Sections .0517 and .0527, respectively, the procedures described in Method 8 of Appendix A of 40 CFR part 60 shall be used. When Method 8 of Appendix A of 40 CFR part 60 is used to determine compliance, compliance shall be determined by averaging emissions measured by three one-hour test runs unless otherwise specified in the applicable rule or subpart of 40 CFR part 60.

f. When compliance is shown for a combustion source emitting sulfur dioxide not covered under paragraphs (a) through (e) of Section .2611 through stack sampling, the procedures described in Method 6 or Method 6C of Appendix A of 40 CFR part 60 shall be used. When using Method 6 procedures to demonstrate compliance, compliance shall be determined by averaging six 20-minute samples taken over such a period of time that no more than 20 minutes elapses between any two consecutive samples. The 20-minute run requirement applies to Method 6 only, not to Method 6C. Method 6C is an instrumental method and the sampling is done continuously.

All of the above the testing methods identified in Section .2611 were previously found in Section .0501, with the exception of Method 6C. This new alternative method allows for the use of a sampling instrument that tests continuously rather than periodically.

EPA has reviewed this change and has preliminarily determined that the addition of new Section .2611, including the addition of Method 6C as an alternative method, is consistent with federal regulations. The addition of new Section .2611 both retains and strengthens the existing source testing requirements of the North Carolina SIP.

As noted in Section III.A.3, above, the language of this new provision, Section .2617, was previously found in paragraph (c)(10) of Section .0501, which is being proposed for deletion. Section .2617 adopts the use of federal testing Method 16 of Appendix A of 40 CFR part 60 or Method 16A of Appendix A of 40 CFR part 60 to demonstrate compliance with total reduced sulfur emissions standards. The rule also adopts the federal testing Method 15 of Appendix A of 40 CFR part 60 to be used as an alternative to determine total reduced sulfur emissions from tail gas control units of sulfur recovery plants, hydrogen sulfide in fuel gas for fuel gas combustion devices, and where specified in other applicable subparts of 40 CFR part 60.

The requirement to use Method 16 or 16A was previously found in Section .0501 and is now relocated to new Section .2617. The option to use Method 15 in certain circumstances is a new provision to this rule. Although Method 15 has a slightly different process of testing for reduced sulfur, the resulting conclusions are the same. Additionally, consistent with section 1.2.1 of Method 15 in the CFR, Section .2617 provides that Method 15 may be used only as an alternative in certain specified sources, as described in the paragraph above, or where specified in other applicable federal subparts.

EPA has reviewed this change and has preliminarily determined that the addition of Section .2617, including the addition of Method 15 for certain sources, is consistent with federal regulations. EPA is proposing to approve all changes in this section of this rulemaking pursuant to section 110 of the Act.

In this rule, 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, EPA is proposing to incorporate by reference under Subchapter 2D, of the North Carolina SIP, Sections .0501— Compliance with Emission Control Standards, .0536— Particulate Emissions from Electric Utility Boilers, .2609— Particulate Testing Methods, .2610— Opacity, .2611— Sulfur Dioxide Testing Methods, and .2617— Total Reduced Sulfur, state effective June 1, 2008. EPA has made, and will continue to make, these materials generally available through www.regulations.gov and at the EPA Region 4 office (please contact the person identified in the For Further Information Contact section of this preamble for more information).

EPA is proposing to approve North Carolina's April 4, 2017, August 22, 2017, and September 28, 2018, SIP revisions. Specifically, EPA is proposing to approve under Subchapter 2D of the North Carolina SIP, the adoption of new Sections .2609, .2610, .2611, and .2617, as well as amendments to existing Sections .0501 and .0536. EPA is proposing to approve these revisions under section 110 of the CAA, including section 110(l), for the reasons stated above. 5

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

• Are not significant regulatory actions 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);

• Are not Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory actions because SIP approvals are exempted under Executive Order 12866;

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

• Are 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. );

• Do 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);

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

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

• Are not significant regulatory actions subject to Executive Order 13211 (66 FR 28355, May 22, 2001);

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

• Do 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).

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 as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), nor will it impose substantial direct costs on tribal governments or preempt tribal law.

On May 25, 2018, the State of Delaware, through the Department of Natural Resources and Environmental Control (DNREC), formally submitted a SIP revision requesting that the definition of VOC in the Delaware SIP be updated to conform to several EPA rulemakings that exempted compounds from the regulatory definition of VOC in 40 CFR 51.100(s). The May 25, 2018 SIP revision requested that the definition of VOC in the Delaware SIP be updated to add the following compounds to the list of compounds excluded from the definition of VOC: t-butyl acetate (also known as tertiary butyl acetate or TBAC), HFE-7000 (1,1,1,2,2,3,3-heptafluoro-3-methoxy-propane), HFE-7500 [3-ethoxy-1,1,1,2,3,4,4,5,5,6,6,6-dodecafluoro-2-(trifluoromethyl) hexane], HFC-227ea (1,1,1,2,3,3,3-heptafluoropropane), methyl formate, HFE-7300 (1,1,1,2,2,3,4,5,5,5-decafluoro-3-methoxy-4-trifluoromethyl-pentane), propylene carbonate and dimethyl carbonate. These compounds were excluded from the regulatory definition of VOC in 40 CFR 51.100(s) by EPA in several rulemakings, which are discussed in more detail later in this notice of proposed rulemaking (NPRM). Delaware's May 25, 2018 SIP revision also requested minor changes to the format of some of the chemical formulas for VOCs that are already excluded from the definition of VOC in the Delaware SIP. 1

VOCs are organic compounds of carbon that, in the presence of sunlight, react with sources of oxygen molecules, such as nitrogen oxides (NO X ) and carbon monoxide (CO), in the atmosphere to produce tropospheric ozone, commonly known as smog. Common sources that may emit VOCs include paints, coatings, housekeeping and maintenance products, and building and furnishing materials. Outdoor emissions of VOCs are regulated by EPA primarily to prevent the formation of ozone.

VOCs have different levels of volatility, depending on the compound, and react at different rates to produce varying amounts of ozone. VOCs that are non-reactive or of negligible reactivity to form ozone react slowly and/or form less ozone; therefore, reducing their emissions has limited effects on local or regional ozone pollution. Section 302(s) of the CAA specifies that EPA has the authority to define the meaning of VOC and what compounds shall be treated as VOCs for regulatory purposes. It is EPA's policy that organic compounds with a negligible level of reactivity should be excluded from the regulatory definition of VOC in order to focus control efforts on compounds that significantly affect ozone concentrations. EPA uses the reactivity of ethane as the threshold for determining whether a compound has negligible reactivity. Compounds that are less reactive than, or equally reactive to, ethane under certain assumed conditions may be deemed negligibly reactive and, therefore, suitable for exemption by EPA from the regulatory definition of VOC. The policy of excluding negligibly reactive compounds from the regulatory definition of VOC was first laid out in the “Recommended Policy on Control of Volatile Organic Compounds” (42 FR 35314, July 8, 1977) and was supplemented subsequently with the “Interim Guidance on Control of Volatile Organic Compounds in Ozone State Implementation Plans” (70 FR 54046, September 13, 2005). The regulatory definition of VOC as well as a list of compounds that are designated by EPA as negligibly reactive can be found at 40 CFR 51.100(s).

On September 30, 1999, EPA proposed to revise the regulatory definition of VOC in 40 CFR 51.100(s) to exclude TBAC as a VOC (64 FR 52731). In most cases, when a negligibly reactive VOC is exempted from the definition of VOC, emissions of that compound are no longer recorded, collected, or reported to states or the EPA as part of VOC emissions. However, EPA's final rule excluded TBAC from the definition of VOC for purposes of VOC emissions limitations or VOC content requirements but continued to define TBAC as a VOC for purposes of all recordkeeping, emissions reporting, photochemical dispersion modeling, and inventory requirements that apply to VOC (69 FR 69290, November 29, 2004) (2004 Final Rule). 2

I. Background

On May 8, 2018, the Allegheny County Health Department (ACHD) through the Pennsylvania Department of Environmental Protection (PADEP) submitted a formal revision to the Pennsylvania SIP. The SIP revision consists of an amendment to ACHD regulations under Article XXI (Air Pollution Control) which adds sections to implement the use of low sulfur fuel oils used in combustion units in Allegheny County, adding sampling and testing methods, and amending associated definitions.

Sulfur dioxide (SO 2 ) emissions contribute to the formation of fine particulate matter (PM 2.5 ) and sulfates in the atmosphere, and subsequently to the formation of regional haze. Regional haze is visibility impairing pollution that scatters and absorbs light. The pollutants that cause visibility impairment come from sources and activities that emit fine particles and their precursors, SO 2 , PM 2.5 , nitrogen oxides (NO X ), and volatile organic compounds (VOCs).

The May 8, 2018 SIP revision included revisions to Article XXI to implement low sulfur fuel oil provisions in Allegheny County that align with the state-wide low sulfur fuel oil provisions in 25 Pa Code Section 123.22 (Section 123.22), which is part of the Pennsylvania SIP. The SIP revision seeks to add Sections 2104.10 (Commercial Fuel Oil) and 2107.16 (Sulfur in Fuel Oil) of Article XXI to the Pennsylvania SIP and amend, within the SIP, Section 2101.20 (Definitions) of Article XXI. 1

EPA previously approved amendments to Pennsylvania's low sulfur fuel oil regulation in July 2014. The regulations in 25 Pa Code Section 123.22 specified and established SO 2 emission levels and maximum allowable sulfur contents for certain fuel oil types by specific air basins through June 30, 2016, and consistent state-wide maximum allowable sulfur contents for certain fuel oil types beginning July 1, 2016. 79 FR 39330 (July 10, 2014). The July 2014 regulation established maximum allowable sulfur-content in fuels prior to June 30, 2016 in all Pennsylvania air basins except Allegheny County, Lower Beaver Valley, and Monongahela Valley. It also established a statewide maximum allowable sulfur content in fuel oil, including Allegheny County, beginning on July 1, 2016.

Through the May 2018 SIP revision submittal, Pennsylvania seeks to add Sections 2104.10 and 2107.16 of ACHD's Article XXI to the Pennsylvania SIP. Section 2104.10 implements low sulfur fuel oil provisions that will reduce the amount of sulfur in fuel oils that are offered for sale, delivered for use, exchanged in trade or permitted to use in Allegheny County, Pennsylvania. Section 2104.10(a) establishes maximum allowable sulfur content for commercial fuel oil, expressed as parts per million (ppm) by weight or percentage by weight, for number 2 and lighter distillate oil to 0.05 percent sulfur content by weight (500 ppm), number 4 residual oil to 0.25 percent sulfur content by weight (2,500 ppm), and 0.5 percent sulfur content by weight (5,000 ppm) for number 5 and number 6 and heavier commercial fuel oils by no later than July 1, 2016. Commercial fuel oil stored by the ultimate consumer in the County prior to the applicable compliance date may be used after the applicable compliance date if the fuel oil met the applicable maximum allowable sulfur content at the time it was stored.

The provision in Section 2104.10(a)(2) of Article XXI allows for a temporary suspension or increase to the maximum allowable sulfur content for a commercial fuel oil according to provisions set forth in 25 Pa Code Section 123.22(d)(2)(iii) and (iv). In the event that compliant fuel is not reasonably available in the air basin, and a written waiver request is appropriately filed, and subsequently approved by PADEP, a suspension of these sulfur levels can be granted for the shortest duration in which adequate supplies can be made reasonably available, but for no more than 60 days.

Section 2104.10(c) and (d) of Article XXI establish sampling, testing, recordkeeping, and reporting requirements. Recordkeeping and reporting requirements in Section 2104.10(d) apply to transferors and transferees in the manufacture and distribution chain for commercial fuel oil from the refinery owner or operator to the ultimate consumer. If any transferor accepts a shipment of commercial fuel oil of a shipment that lacks the required records specified in Section 2104.10(d), they are required to test for sulfur content under Section 2104.10(c)(3).

Definitions for terminology which relate to reporting and recordkeeping requirements were added. Pennsylvania's May 2018 SIP revision submittal also seeks to amend Section 2101.20 (Definitions) to add the following new terms: (1) “Commercial fuel oil;” (2) “Noncommercial fuel;” (3) “Transferee;” (4) “Transferor;” and (5) “Ultimate consumer.” Additionally, the revision to Section 2101.20 (Definitions) of Article XXI seeks to amend the definition of the following terms to provide clarity and support the amendments to Section 2104.10 and Section 2107.16: (1) “Carrier;” (2) “Distributor;” (3) “Retail outlet;” and (4) “Terminal.”

Section 2107.16 of Article XXI establishes the sampling methods that must be used. Refinery owners and operators who produce commercial fuel oil intended for use or used in Allegheny County are required to sample, test and calculate the actual sulfur content of each batch of the commercial fuel oil according to the methods established in Section 2107.16. The regulations ACHD seeks to add to the Pennsylvania SIP require the use of various American Standards of Testing Materials (ASTM) methods for the sampling of petroleum and for the determination of sulfur content in fuel oil, including updates and revisions to those methods. These methods match those cited in 25 Pa Code Section 123.33(f), which is part of the Pennsylvania SIP.

Pennsylvania asserts that lowering the maximum allowable sulfur content in commercial fuel oils combusted or sold in Allegheny County will aid in reducing SO 2 emissions that are a cause of regional haze. EPA proposes to approve these regulations to strengthen Pennsylvania's SIP.

EPA has determined that the revisions made to Article XXI of ACHD's rules and regulations, Sections 2101.20, 2104.10 and 2107.16, meet the requirements of the CAA and is proposing to approve the amendments to ACHD's regulations for commercial fuel oil sulfur limits for combustion units into the Pennsylvania SIP. EPA is soliciting public comments on the issues discussed in this document. These comments will be considered before taking final action.

In this document, 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, EPA is proposing to incorporate by reference ACHD's maximum allowable sulfur content regulation. EPA has made, and will continue to make, these materials generally available through http://www.regulations.gov and at the EPA Region III Office (please contact the person identified in the For Further Information Contact section of this preamble for more information).

Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the CAA and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this action merely 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);

• Is not an Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory action because SIP approvals are exempted under Executive Order 12866.

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

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

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

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

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

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

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

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

In addition, this SIP revision for commercial fuel oil sulfur limits for combustion units in Allegheny County, Pennsylvania, does not have tribal implications as specified in Executive Order 13175, because the SIP is not approved to apply in Indian Country located in the state, and EPA notes that it will not impose substantial direct costs on tribal governments or preempt tribal law. Thus, Executive Order 13175 does not apply to this action.

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

On March 12, 2008, the EPA revised the levels of the primary and secondary 8-hour ozone NAAQS to 0.075 parts per million (ppm). 73 FR 16436 (Mar. 27, 2008). The 2008 ozone NAAQS are met at an ambient air quality monitoring site when the 3-year average of the annual fourth-highest daily maximum 8-hour average ozone concentration is less than or equal to the NAAQS, as determined in accordance with Appendix P to 40 CFR part 50. Under Appendix P, digits to the right of the third decimal place are truncated.

Section 110(a)(1) of the CAA requires states to submit, within 3 years after promulgation of a new or revised NAAQS, SIPs meeting the applicable “infrastructure” elements of sections 110(a)(1) and (2). One of these applicable infrastructure elements, CAA section 110(a)(2)(D)(i), requires SIPs to address the “good neighbor” provision which requires states to prohibit certain adverse air quality effects on other states due to interstate transport of pollution.

Specifically, section 110(a)(2)(D)(i)(I) requires SIPs to contain adequate 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 any other state. The two provisions of this section are referred to as prong 1 (significant contribution to nonattainment) and prong 2 (interfere with maintenance). Section 110(a)(2)(D)(i)(II) requires SIPs to contain adequate provisions to prohibit emissions that will interfere with measures required to be included in the applicable implementation plan for any other state under part C to prevent significant deterioration of air quality (prong 3) or to protect visibility (prong 4).

The EPA has established a four-step interstate transport framework to address the prong 1 and 2 requirements for ozone and fine particulate matter (PM 2.5 ) NAAQS through the development and implementation of several previous rulemakings. 1 The four steps of this framework are as follows: (1) Identify downwind air quality problems; (2) identify upwind states that impact those downwind air quality problems enough to warrant further review and analysis; (3) identify the emissions reductions, if any, necessary to prevent an identified upwind state from contributing significantly or interfering with maintenance with respect to those downwind air quality problems; and (4) adopt permanent and enforceable measures needed to achieve those emissions reductions. The EPA has applied this framework in various actions addressing prongs 1 and 2 for the PM 2.5 and ozone NAAQS. 2

On August 4, 2015, the EPA issued a Notice of Data Availability (NODA) containing air quality modeling to assist states with meeting section 110(a)(2)(D)(i)(I) requirements for the 2008 ozone NAAQS within the context of the four-step framework. 3 Specifically, the air quality modeling helped states address steps 1 and 2 of the framework by (1) identifying locations in the United States where the EPA anticipated nonattainment or maintenance issues in 2017 for the 2008 ozone NAAQS, and (2) quantifying the projected contributions from emissions from upwind states to downwind ozone concentrations at the receptors in 2017. The EPA also used this modeling to support the Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS (“CSAPR Update”) proposed rule (80 FR 75706, December 3, 2015); we updated the modeling in 2016 to support the CSAPR Update final rule (81 FR 74504, October 26, 2016). The projections in this updated version of the modeling (hereon referred to as the “CSAPR Update modeling”) were part of the technical record for the EPA's February 3, 2017 final action on the prongs 1 and 2 portions of the Wyoming 2008 Ozone Infrastructure SIP, which is discussed in more detail later in this notice. 82 FR 9153.

In the CSAPR Update, the EPA used the CSAPR Update modeling to identify downwind nonattainment and maintenance receptors at step 1 of the four-step framework ( see 81 FR 74530-74532, October 26, 2016). Specifically, the EPA identified nonattainment receptors as those monitoring sites with current measured design values exceeding the NAAQS that also have projected ( i.e., in 2023) average design values exceeding the NAAQS. The EPA identified maintenance receptors as those monitoring sites with projected maximum design values exceeding the NAAQS. The EPA considered all nonattainment receptors to also be maintenance receptors because a monitoring site with a projected average design value above the standard necessarily also has a projected maximum design value above the standard. Monitoring sites with projected maximum design values that exceed the standard and which are not also nonattainment receptors are thus referred to as maintenance- only receptors.

To address step 2 of the framework for the CSAPR Update, the EPA used the CSAPR Update modeling to determine whether an eastern state's impact on each projected downwind air quality problem would be at or above a specific threshold. The EPA's modeling projected ozone concentrations and contributions in 2017, which would be the last ozone season before the then-upcoming July 2018 attainment date for nonattainment areas classified as Moderate for the 2008 ozone NAAQS. Consistent with the original CSAPR rulemaking (76 FR 48208, August 8, 2011), the EPA applied a threshold of one percent of the 2008 ozone NAAQS of 75 ppb (0.75 ppb) to identify linkages between upwind states and downwind nonattainment and maintenance receptors in the CSAPR Update. 81 FR 74518 (October 26, 2016). If a state's impact on identified downwind nonattainment and maintenance receptors did not exceed 0.75 ppb, the state was not considered “linked” to those receptors and was therefore not considered to significantly contribute to nonattainment or interfere with maintenance of the standard in those downwind areas. If a state's impact exceeded the 0.75 ppb threshold, that state was considered “linked” to the downwind nonattainment or maintenance receptor(s) and the state's emissions were evaluated further, taking into account both air quality and cost considerations, to determine what, if any, emissions reductions might be necessary to address the state's obligation pursuant to CAA section 110(a)(2)(D)(i)(I).

On February 6, 2014, the Wyoming Department of Environmental Quality (WDEQ) submitted a certification that the approved Wyoming SIP adequately addressed the “good neighbor” provision for the 2008 ozone NAAQS. See 81 FR 71712, 71713 (Nov. 18, 2016). On November 18, 2016, the EPA proposed to approve Wyoming's submission for prong 1 and disapprove Wyoming's submission for prong 2 of the good neighbor provision (81 FR 81712), and on February 3, 2017, the EPA finalized the proposed approval and disapproval. 82 FR 9153. This disapproval established a 2-year deadline, under CAA section 110(c), for the EPA to promulgate a federal implementation plan (FIP) or approve a SIP that meets the requirements of prong 2 of the good neighbor provision for the 2008 ozone NAAQS for Wyoming. The EPA acted on the portions of the submission addressing prongs 1, 3 and 4 of the good neighbor provision for the 2008 ozone NAAQS. 4

The EPA based its February 3, 2017 disapproval for prong 2 in the first instance on a determination that the February 6, 2014 submission lacked an analysis to support the conclusion that the Wyoming SIP contained adequate provisions prohibiting emissions that will interfere with maintenance of the 2008 ozone NAAQS in any other state. 81 FR 81714 (proposal); 82 FR 9147 (final). As explained in the notices for the proposed and final action, in accordance with the decision of the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in North Carolina v. EPA, 531 F.3d 896, 910-11 (2008), states and the EPA are required to give “independent significance” to prong 2 by considering the potential impacts of emissions on areas that may have issues maintaining the standards. 82 FR 9145.

However, if the EPA's supplemental analysis supports the state's conclusion that the SIP is adequate to address the statutory requirements, we may approve the state's submittal. 82 FR 9149. In this case, the EPA evaluated the CSAPR Update modeling, described above. That modeling showed that emissions from Wyoming were not linked to any nonattainment receptors for the 2008 ozone NAAQS in the 2017 analytic year. However, the modeling also showed that emissions from Wyoming were projected to contribute above the 1% threshold to one maintenance receptor at the Chatfield Reservoir in Douglas County, Colorado (monitor I.D. # 80350004). 5 The CSAPR Update modeling identified two other maintenance receptors in the Denver Metro/North Front Range (DMNFR) 2008 Ozone Moderate nonattainment area, but emissions from Wyoming were projected to impact those receptors below the 0.75 ppb threshold. For the purpose of our action on the Wyoming SIP submission, we determined that a 1% screening threshold was appropriate to use for the Douglas County maintenance receptor because the air quality problem in that area resulted in part from the relatively small individual contributions of upwind states that collectively contribute a large portion of the ozone concentrations (9.7%), comparable to some eastern receptors addressed in the CSAPR Update. 82 FR 9149-50. The CSAPR Update modeling projected that Wyoming emissions would contribute 1.18 ppb, or approximately 1.57% of the 2008 ozone NAAQS, at the Douglas County maintenance receptor in 2017. 6 As this contribution was above the screening threshold, we could not conclude on the basis of the CSAPR Update modeling that Wyoming's SIP contained sufficient provisions to prohibit emissions that will interfere with maintenance of the 2008 ozone NAAQS at the Douglas County maintenance receptor. As a result, the EPA disapproved the February 6, 2014 submittal for prong 2.

WDEQ submitted a new interstate transport SIP on October 17, 2018, providing additional information to demonstrate that the State meets the prong 2 requirement for the 2008 ozone NAAQS. In this submittal, WDEQ addressed the prong 2 requirements of section 110(a)(2)(D)(i)(I) using a weight of evidence analysis and concluded that emissions from Wyoming will not interfere with maintenance of the 2008 ozone NAAQS in any other state. The submittal states that weight of evidence analyses are a valid approach to assessing ozone transport in western states and have been used by the EPA and in submittals by other western states, specifically California. Consistent with the CSAPR Update modeling, which only found one potential linkage with the Douglas County maintenance receptor, WDEQ focused its analysis on the potential impacts of Wyoming emissions on that receptor. WDEQ's analysis included information about recent and forthcoming emission reductions at sources in Wyoming; ozone modeling for the 2023 analytic year from the EPA's October 27, 2017 memorandum “Supplemental Information on the Interstate Transport State Implementation Plan Submissions for the 2008 Ozone National Ambient Air Quality Standards under Clean Air Act Section 110(a)(2)(D)(i)(I)” (hereon “October 2017 Memo”); and the EPA's proposed approval (since finalized) of the “Colorado Attainment Demonstration for the 2008 8-Hour Ozone Standard for the DMNFR Moderate nonattainment area” (hereon “DMNFR attainment demonstration”). 83 FR 14807 (April 6, 2018).

WDEQ indicated that the Douglas County monitor was projected to be a maintenance receptor for the year 2017 in the CSAPR Update modeling. However, WDEQ stated that it is unclear whether it should still consider the Douglas County monitor to be maintenance for this NAAQS, given its review of information available subsequent to the CSAPR Update modeling. Specifically, WDEQ cited the EPA's October 2017 Memo and the State of Colorado's attainment demonstration for the 2008 8-Hour Ozone Standard for the DMNFR nonattainment area to argue that the Douglas County receptor should not be considered a maintenance receptor for the 2008 ozone NAAQS.

First, WDEQ referenced the EPA's October 2017 Memo. As described in further detail in Section III of this notice, the EPA performed air quality modeling, released in the October 2017 Memo, to project 2008 ozone nonattainment and maintenance receptors for the analytic year 2023 to assist the states in addressing remaining prong 1 or prong 2 obligations for the 2008 ozone NAAQS. This modeling projected a maximum design value of 73.2 ppb (below the 75 ppb NAAQS) for the Douglas County receptor in the 2023 analytic year. October 2017 Memo atA-7. WDEQ also cited language from the October 2017 Memo which states that “no areas in the United States, outside of California, are expected to have problems attaining and maintaining the 2008 ozone NAAQS in 2023.” Id. at 4.

WDEQ then referenced modeling performed by the State of Colorado as part of its DMNFR attainment demonstration. 7 Specifically, WDEQ referenced modeling from Colorado's weight of evidence attainment demonstration in which Colorado removed monitoring data for certain days during 2010-2013 from the calculation of the 2011 baseline ozone design value because these data were likely influenced by atypical events such as stratospheric intrusions or wildfires. Colorado's modeling, which will be discussed in further detail in Section III of this notice, projected the Douglas County monitor would have a maximum modeled design value below the 2008 NAAQS in 2017 when the adjusted 2011 baseline was used. 83 FR 14813 (April 6, 2018). As noted by WDEQ, in the EPA's proposed approval of Colorado's DMNFR attainment demonstration, we concurred with Colorado's assessment that this modeling was properly configured, met EPA performance requirements, and was appropriately used in its application. Id. The EPA has since finalized our proposed approval of Colorado's DMNFR attainment demonstration. 83 FR 31068 (July 3, 2018).

In its October 17, 2018 submission, WDEQ asserted that the modeling from both the EPA's October 2017 Memo and Colorado's DMNFR attainment demonstration indicate that all future design values for the Douglas County receptor are below the 2008 ozone NAAQS. Therefore, WDEQ asserts that this receptor should no longer be considered a maintenance receptor, as it was identified in the CSAPR Update modeling, but should instead be considered to be attainment.

WDEQ also included information about recent and forthcoming emission reductions at sources in Wyoming in its weight-of-evidence analysis. Specifically, WDEQ provided information about nitrogen oxide (NO X ) and volatile organic compounds (VOC) emissions reductions that occurred between 2011 and 2017, and NO X reductions that will occur before 2023. WDEQ focused on these pollutants as both are precursors to ozone. WDEQ calculated that permitting actions, including Title V permit rescissions for sources that have reduced their emissions from major to minor source levels, accounted for a statewide reduction of 12,392.5 tons per year (tpy) of NO X and 905.6 tpy of VOC between 2011 and 2017. WDEQ noted that regulations covering nonpoint sources and reductions from leak detection and repair or fugitive emissions monitoring programs had led to additional VOC reductions, though WDEQ had not quantified the reductions from these regulations. WDEQ also calculated a 21,525 tpy NO X reduction between 2017 and 2023, concluding NO X emissions would decrease by nearly 18% from those reported in the 2011 Emission Inventory (the inventory used in the CSAPR Update modeling and October 2017 Memo modeling) by 2023 through permitting actions alone. WDEQ also asserted that the emissions reductions listed in its submission do not appear to have been accounted for in the CSAPR Update modeling.

WDEQ concludes that all elements of its weight-of-evidence analysis combined demonstrate that emissions from the State of Wyoming will not interfere with maintenance of the 2008 8-hour ozone NAAQS in any other state, including at the Douglas County, Colorado receptor.

The EPA has reviewed all elements of WDEQ's weight-of-evidence analysis and additional relevant technical information to determine whether the SIP has adequate provisions to ensure emissions from the state will not interfere with maintenance of the 2008 ozone NAAQS in any other state. The EPA conducted this review within the four-step interstate transport framework. Therefore, the EPA's first step in reviewing WDEQ's submission is to identify downwind air quality problems.

The EPA first reviewed WDEQ's information about modeling conducted by the State of Colorado that projected attainment of the 2008 ozone NAAQS at the Douglas County receptor and all other ozone monitors in the DMNFR Moderate ozone nonattainment area in 2017. Based on Colorado's DMNFR attainment demonstration modeling results, WDEQ asserts that the Douglas County receptor should not be considered a maintenance receptor at step 1 of the four-step interstate transport framework. As noted, the Douglas County receptor was the only maintenance receptor to which emissions from Wyoming contributed above 1% of the 2008 ozone NAAQS in the EPA's 2016 CSAPR Update modeling.

The EPA's review of Colorado's DMNFR attainment demonstration modeling, provided below, begins with an overview of the modeling analysis in the attainment planning context for which it was originally generated. Then, we expand on Wyoming's analysis by considering Colorado's modeling in the context of interstate transport. Specifically, we consider how Colorado's removal of atypical event-influenced monitor data in 2010, 2011 and 2012 from the 2011 baseline ozone design value would impact the CSAPR Update modeling results with regard to the Colorado receptor to which Wyoming was linked.

In Colorado's primary modeling for the DMNFR attainment demonstration, the State calculated relative response factors (RRFs) using the maximum modeled ozone in a 3x3 matrix of grid cells around each ozone receptor to model a 2017 projected concentration of 76.2 ppb at the Douglas County receptor. See 83 FR 14811 (April 6, 2018). Because this projection was close to the 75 ppb NAAQS, Colorado developed its DMNFR attainment demonstration using a weight-of-evidence analysis, as recommended by EPA guidance. Id. at 14812. Colorado's weight-of-evidence analysis included two modeling analyses in addition to the primary (3x3 matrix) analysis. The first was performed using a 7x7 matrix of grid cells around each receptor. Colorado contended that this model performed better than the 3x3 matrix in simulating the 2011 period when monitored concentrations were compared to model results in the 7x7 matrix, potentially as a result of challenges in accurately simulating meteorological data in Colorado's complex terrain combined with the use of a high resolution 4-km grid in the Colorado modeling platform. In this modeling analysis, Colorado modeled the Douglas County receptor as attaining the NAAQS in 2017 with a projected concentration of 75 ppb. Id. All other receptors in the Denver ozone moderate nonattainment area were also projected as attainment in the modeling analysis using the 7x7 matrix.

In the second modeling analysis, Colorado evaluated high ozone days from 2009 to 2013 that were likely influenced by atypical, extreme, or unrepresentative events (collectively, “atypical events”) such as wildfire or stratospheric intrusion, but were included in the calculation of the 2011 baseline ozone design value. 8 Colorado did not submit formal demonstrations under the Exceptional Events Rule (40 CFR 50.14) for these days because they do not affect the DMNFR's attainment status and thus do not have regulatory significance under the Exceptional Events Rule. However, these days do affect the baseline design value and thus affect the model projected future design value for 2017. After removing the data that were likely influenced by atypical events, Colorado modeled attainment in 2017 at the Douglas County receptor using both the 3x3 (74 ppb) and 7x7 (73 ppb) matrices for calculating the model RRF. Id. at 14813. All other receptors in the DMNFR ozone Moderate nonattainment area were also projected as attainment in 2017 when atypical event-influenced data were removed from the baseline calculation, with the highest projection at any receptor in the area at 74 ppb. As noted in Section II, the EPA concurred with Colorado's assessment that this modeling was appropriate for Colorado's weight of evidence attainment demonstration, and subsequently finalized our approval of Colorado's attainment demonstration. 83 FR 31068 (July 3, 2018).

While Wyoming listed the DMNFR attainment demonstration modeling results as evidence that the Douglas County receptor should not be considered a maintenance receptor as of 2017, the EPA did not reach the same conclusion based on these results alone. This is because the Colorado modeling results, while appropriate in an attainment planning context, were calculated from a baseline design value that is the weighted average of three3-year design values. In an interstate transport modeling context, EPA evaluates the transport contribution for both the weighted average design value and individually for each of the three3-year average design values. As noted in Section I of this proposed action, in the CSAPR Update the EPA identified as “nonattainment receptors” monitoring sites with a current measured value exceeding the NAAQS that also have a projected average design value exceeding the NAAQS and identified maintenance receptors as those monitoring sites with a projected maximum design value exceeding the NAAQS. Colorado's DMNFR attainment demonstration modeling results calculated the 2011 baseline by averaging the three relevant design values (2009-2011, 2010-2012, and 2011-2013). Therefore, the 2017 modeled projections presented in the DMNFR attainment demonstration (and referenced by Wyoming) would only have some relevance with regard to whether the Douglas County receptor should be identified as a nonattainment receptor in an interstate transport context. However, the determination of whether the Douglas County receptor should continue to be identified as a maintenance receptor, as it was in the CSAPR Update modeling, is based on the 2017 projection of the maximum of the three base year design values (in this case, 2011-2013).

Nonetheless, the information regarding atypical event-influenced data in the DMNFR attainment demonstration is relevant to the determination of whether the Douglas County monitor should continue to be identified as a maintenance receptor in the EPA's 2017 modeling for the 2008 ozone NAAQS. Because the CSAPR Update modeling was conducted in 2016, the EPA did not consider Colorado's “Analyses in Support of Exceptional Event Flagging and Exclusion for the Weight of Evidence Analysis” in the CSAPR Update modeling. 9 After reviewing this document, the EPA finds it appropriate to consider the impact of removing atypical event-influenced data from the CSAPR Update modeling baseline as part of our review of Wyoming's prong 2 weight-of-evidence analysis. After removal of the atypical event-influenced data from the 2009-2013 baseline, listed in Table 1 below, the baseline maximum design value at the Douglas County receptor (2011-2013) decreases from 83 ppb to 81 ppb, as shown in Table 2.

We then applied the RRF from the CSAPR Update Modeling to this adjusted design value, and the results are shown in Table 3 below. 10