Federal Register Vol. 82, No.158,

Table of Contents I. Background II. Overview of the Proposed LFI Rating System A. LFI Rating Components B. LFI Rating Scale III. Transition from the RFI Rating System to the LFI Rating System IV. Consequences of LFI Ratings V. Applicability VI. Timing and Implementation VII. Related Proposed Guidance A. Management of Core Business Lines and Independent Risk Management and Controls 1. Senior Management 2. Management of Core Business Lines 3. Independent Risk Management and Controls B. Board Effectiveness VIII. Other Related Developments IX. Proposed Changes to Existing Regulations X. Comparison of the RFI and LFI Rating Systems XI. Request for Comments XII. Regulatory Analysis A. Paperwork Reduction Act B. Regulatory Flexibility Analysis C. Solicitation of Comments on Use of Plain Language Appendix A. Text of Proposed Large Financial Institution Rating System I. Background

The 2007-2009 financial crisis demonstrated the risks that large financial institutions (LFIs) pose to U.S. financial stability. As a group, these institutions were overleveraged, had insufficient capital to support their risks, and relied heavily on short-term wholesale funding that was susceptible to runs. This excessive risk-taking, combined with similar behavior outside the regulated financial sector, left the U.S. economy vulnerable. The ensuing financial crisis led to a deep recession and the loss of nearly nine million jobs.

In response, since the financial crisis, the Federal Reserve has placed materially heightened supervisory expectations on LFIs. The Federal Reserve has developed a supervisory program specifically designed to address the risks posed by such firms to U.S. financial stability. The Federal Reserve established the Large Institution Supervision Coordinating Committee (LISCC) in 2010 to coordinate its supervisory oversight for the systemically important firms that pose the greatest risk to U.S. financial stability.1 The LISCC supervisory program conducts annual horizontal reviews of LISCC firms and firm-specific examination work focused on evaluating a firm's (i) capital adequacy under normal and stressed conditions; (ii) liquidity positions and risk management practices; (iii) recovery and resolution preparedness; and (iv) governance and controls. For LFIs that are not LISCC firms, the Federal Reserve performs horizontal reviews and firm-specific supervisory work focused on capital, liquidity, and governance and control practices, which are tailored to reflect the risk characteristics of these institutions.2

In 2012, the Federal Reserve implemented a new consolidated supervisory program for LFIs (referred to as the “LFI supervision framework”) described in SR letter 12-17.3 The LFI supervision framework is intended to (i) enhance each LFI's financial and operational strength and resilience to reduce the likelihood of an LFI's failure or material financial or operational distress, and (ii) reduce the risk to U.S. financial stability overall if an LFI were to fail.4

The LFI supervision framework includes heightened expectations regarding capital and liquidity, including both the amount of capital and liquidity and the related planning and risk management practices. The LFI supervision framework also outlined expectations for a firm's maintenance of operational strength and resilience and its compliance with laws and regulations, as provided by effective governance and control practices.

The Federal Reserve has not modified its supervisory rating system for bank holding companies since the 2007-2009 financial crisis. Since 2004, the Federal Reserve has used the “RFI/C(D)” rating system (referred to as the “RFI rating system”) to communicate its supervisory assessment of every bank holding company (BHC) regardless of its asset size, complexity, or systemic importance.5 The RFI rating system focuses on the risk management practices (R component) and financial condition (F component) of the consolidated organization, and assesses the potential impact (I component) of a BHC's nondepository entities on its subsidiary depository institution(s).

Given the systemic risks posed by LFIs and the corresponding changes to the Federal Reserve's supervisory expectations and oversight of those firms, the Federal Reserve believes that a new rating system would be more effective than the RFI rating system for evaluating LFIs. The RFI rating system remains a relevant and effective tool for developing and communicating supervisory assessments for community and regional holding companies. Therefore, the RFI rating system will continue to be used in the supervision of these organizations.

The proposed LFI rating system provides a supervisory evaluation of whether a firm possesses sufficient financial and operational strength and resilience to maintain safe and sound operations through a range of conditions. The proposed LFI rating system is designed to:

• Fully align with the Federal Reserve's current supervisory programs and practices, which are based upon the LFI supervision framework's core objectives of reducing the probability of LFIs failing or experiencing material distress and reducing the risk to U.S. financial stability;

• Enhance the clarity and consistency of supervisory assessments and communications of supervisory findings and implications; and

• Provide appropriate incentives for LFIs to maintain financial and operational strength and resilience, including compliance with laws and regulations, by more clearly defining the supervisory consequences of a given rating.

Under the proposed LFI rating system, the Federal Reserve would evaluate and assign ratings for the following three components: 6

• Capital Planning and Positions

• Liquidity Risk Management and Positions

• Governance and Controls

The Capital Planning and Positions component rating would encompass assessments of (i) the effectiveness of the governance and planning processes used by a firm to determine the amount of capital necessary to cover risks and exposures, and to support activities through a range of conditions; and (ii) the sufficiency of a firm's capital positions to comply with applicable regulatory requirements and to support the firm's ability to continue to serve as a financial intermediary through a range of conditions. Findings from CCAR for LISCC firms and certain other large and complex LFIs,7 and from similar supervisory activities for other LFIs,8 represent a material portion of the work that would be conducted to determine the Capital Planning and Positions component rating.

The Liquidity Risk Management and Positions component rating would encompass assessments of (i) the effectiveness of a firm's governance and risk management processes used to determine the amount of liquidity necessary to cover risks and exposures, and to support activities through a range of conditions; and (ii) the sufficiency of a firm's liquidity positions to comply with applicable regulatory requirements and to support the firm's ongoing obligations through a range of conditions.9 The Liquidity Risk Management and Positions component rating would be based on findings of coordinated examinations of liquidity positions and risk management practices conducted across several firms (horizontal examinations), as well as ongoing assessments of an individual firm's liquidity positions and risk management practices conducted through the supervisory process.

Horizontal examinations help to ensure that the liquidity positions and risk management practices of firms with similar liquidity risk profiles are evaluated in a consistent manner. LISCC firms are subject to the Comprehensive Liquidity Analysis and Review (CLAR), which is an annual horizontal exercise that assesses both liquidity positions and risk management. Other LFI firms are subject to more narrow horizontal examinations depending on their risk profile. The Federal Reserve also conducts targeted examinations of specific areas that are of high risk to an individual firm or have not been covered by a recent horizontal examination.

The Federal Reserve evaluates each firm's risk management practices by reviewing the processes that firms use to identify, measure, monitor, and manage liquidity risk and make funding decisions. The Federal Reserve evaluates a firm's liquidity positions against applicable regulatory requirements, and assesses the firm's ability to support its obligations through other means, such as its funding concentrations.

The Governance and Controls component rating would evaluate the effectiveness of a firm's (i) board of directors, (ii) management of core business lines and independent risk management and controls, and (iii) recovery planning (for domestic LISCC firms only).10 This rating would assess a firm's effectiveness in aligning strategic business objectives with the firm's risk tolerance 11 and risk management capabilities; maintaining strong, effective, and independent risk management and control functions, including internal audit; promoting compliance with laws and regulations, including those related to consumer protection; and otherwise providing for the ongoing resiliency of the firm. Firm-specific and horizontal examination work focused on a firm's corporate governance, independent risk management, controls, and lines of business, among other areas, would provide the basis for determining the Governance and Controls component rating.

Unlike other supervisory rating systems, including the RFI rating system, the Federal Reserve would not assign a standalone composite rating under the proposed LFI rating system. The Federal Reserve believes assigning a standalone composite rating is not necessary because the three proposed LFI component ratings are designed to clearly communicate supervisory assessments and associated consequences for each of the core areas (capital, liquidity, and governance and controls) considered critical to a firm's strength and resilience. It is unlikely that the assignment of a standalone composite rating would convey new or additional information regarding supervisory assessments, and a standalone composite rating could dilute the clarity and impact of the component ratings.

Each LFI component rating would be assigned using a multi-level scale (Satisfactory/Satisfactory Watch, Deficient-1, and Deficient-2). A “Satisfactory” rating indicates that the firm is considered safe and sound and broadly meets supervisory expectations.12 A “Satisfactory Watch” rating is a conditional “Satisfactory” rating, and is discussed in greater detail below. A “Deficient-1” rating indicates that although the firm's current condition is not considered to be materially threatened, there are financial and/or operational deficiencies that put its prospects for remaining safe and sound through a range of conditions at significant risk. A “Deficient-2” rating indicates that financial and/or operational deficiencies materially threaten the firm's safety and soundness, or have already put the firm in an unsafe and unsound condition.

Supervisors may assign a “Satisfactory Watch” component rating which indicates that the firm is generally considered safe and sound; however certain issues are sufficiently material that, if not resolved in a timely manner in the normal course of business, would put the firm's prospects for remaining safe and sound through a range of conditions at risk. This would be consistent with existing supervisory practice where supervisors generally indicate to a firm that a rating downgrade is a strong possibility if the firm fails to resolve identified weaknesses in a timely manner. The “Satisfactory Watch” rating may also be used for firms previously rated “Deficient” when circumstances warrant.

In considering whether supervisory issues are likely to be resolved in the normal course of business, the Federal Reserve will assess the firm's ability to remediate or mitigate these issues (through compensating controls and/or a reduced risk profile) in a timely manner without material changes to, or investments in, a firm's governance, risk management or internal control structures, practices, or capabilities.

A “Satisfactory Watch” rating is not intended to be used for a prolonged period. Firms that receive a “Satisfactory Watch” rating would have a specified timeframe to fully resolve issues leading to that rating (as is the case with all supervisory issues), generally no longer than 18 months.13 If the firm successfully resolved the issues leading to the “Satisfactory Watch” rating, the firm would typically be upgraded to “Satisfactory” as it has demonstrated an ability to successfully remediate or mitigate these issues in a timely manner in the normal course of business. However, if the firm failed to timely remediate or mitigate those issues, that failure would generally be viewed as evidence that the firm lacked sufficient financial and/or operational capabilities to remain safe and sound through a range of conditions. In these instances, the firm would typically be downgraded to a “Deficient” rating.

When a firm is rated “Satisfactory Watch,” supervisors would focus on determining whether a firm's issues are related to each other, similar in nature or root cause, or constitute a pattern reflecting deeper governance or risk management weaknesses, warranting a downgrade to a “Deficient” rating.

As noted above, the LFI supervision framework—as described in SR 12-17 and accompanied by the issuance of enhanced regulatory requirements, supervisory expectations and practices—has been established over recent years to enhance the ability of large systemically important firms to sustain operations through a range of stressful conditions and events. Introduction of a new rating system that is comprehensively aligned with the LFI supervision framework represents the natural next step in the build-out of this program. As such, transition to the proposed LFI rating system is intended to be evolutionary and expected to be routine in most respects for affected firms.

Approaches to assessing an LFI's financial strength and resilience via effective capital and liquidity governance and planning, and sufficiency of related positions, are more prominent in the proposed LFI rating system versus the RFI rating system, and are fully reflective of current supervisory practices and expectations. Key conclusions of LFI supervision activities, including CCAR and CLAR, will be directly reflected within the Capital and Liquidity component rating assignments. By contrast, the RFI rating system was not designed to readily accommodate the results of these activities.

Similarly, the key elements within the Governance and Controls component rating, which underlie a firm's operational resilience and overall risk management, are also consistent with current practices. Most of these elements can be traced to supervisory expectations for risk management and internal controls first introduced in 1995, and subsequently carried forth into the RFI rating system in 2004.14 These foundational aspects of a firm's governance and control framework, including expectations relating to the effectiveness of boards of directors and emphasis on sound risk management, remain present in the proposed LFI rating system, albeit with some changes in emphasis and nomenclature.

The Governance and Controls component rating also provides an updated approach to assessing the effectiveness of risk management and control activities as conducted (i) directly within a firm's business line operations (where risk-taking activities are initiated and implemented), and (ii) throughout a firm's independent risk management and controls. More recently, key expectations regarding the alignment of a firm's strategy with its risk tolerance and risk management capabilities were included in SR letter 12-17, and are also reflected within capital planning guidance issued in 2015.15

The chart included below in Section X, “Comparison of the RFI and LFI Rating Systems,” broadly compares and illustrates the structural differences between the two rating systems.

Statutes and regulations applicable to LFIs grant a number of privileges to well managed firms.16 Under the RFI rating system, a firm's composite rating and Risk Management rating determine whether a holding company is considered to be “well managed” for purposes of these privileges.17 Under the proposed LFI rating system, a firm must be rated “Satisfactory” or “Satisfactory Watch” for each of its three component ratings in order to be considered “well managed.” 18 A rating of “Deficient-1” or lower for any component would result in the firm not being deemed “well managed.” This reflects the judgment that an LFI is not in satisfactory condition overall unless it is considered sound in each of the key areas of capital, liquidity, and governance and controls.

A “Deficient-1” component rating could be a barrier for a firm seeking the Federal Reserve's approval to engage in new or expansionary activities, unless the firm can demonstrate that (i) it is making meaningful, sustained progress in resolving identified deficiencies and issues; (ii) the proposed new or expansionary activities would not present a risk of exacerbating current deficiencies or issues or lead to new concerns; and (iii) the proposed activities would not distract the board or senior management from remediating current deficiencies or issues.

The Federal Reserve would be extremely unlikely to approve any proposal seeking to engage in new or expansionary activities from a firm with a “Deficient-2” component rating.

Under the Bank Holding Company Act (BHC Act) and the Home Owners' Loan Act,19 companies that have elected to be treated as financial holding companies (FHCs) and that do not remain well managed face restrictions on commencement or expansion of certain activities. In addition, a firm with less than satisfactory ratings may be subject to restrictions or higher charges in attempting to access the Federal Reserve's discount window or in gaining access to intraday credit.

A “Deficient-1” component rating would often be an indication that the firm should be subject to either an informal or formal enforcement action, and may also result in the designation of the firm as being in “troubled condition.” 20 A firm with a “Deficient-2” component rating should expect to be subject to a formal enforcement action and deemed to be in “troubled condition.”

The Federal Reserve would use the proposed LFI rating system to evaluate and communicate the supervisory condition of all bank holding companies that have total consolidated assets of $50 billion or more; all non-insurance, non-commercial savings and loan holding companies that have total consolidated assets of $50 billion or more; and all U.S. intermediate holding companies (IHCs) of foreign banking organizations established pursuant to section 252.153 of the Federal Reserve's Regulation YY.21 In the future, the Federal Reserve plans to use the LFI rating system to assess systemically important nonbank financial companies designated by the Financial Stability Oversight Council (FSOC) for supervision by the Federal Reserve; however, this would be done through a separate rulemaking.

Until final adoption of a LFI rating system, the Federal Reserve will continue to evaluate firms using the existing RFI rating system. Holding companies with less than $50 billion in total consolidated assets would continue to be evaluated using the RFI rating system.

The Federal Reserve proposes to assign initial LFI ratings to all applicable firms during 2018. Due to differences in the timing of supervisory cycles across the portfolios that comprise the LFI supervisory program, firms in one portfolio may receive their initial LFI ratings at different times during the year than firms in another portfolio.

During the initial LFI rating supervisory cycle, each applicable firm would receive all three component ratings under the LFI rating system concurrently. Consistent with current Federal Reserve practice on the assignment and communication of supervisory ratings by examiners, ratings under the proposed LFI rating system would be assigned and communicated to firms on at an annual basis, and more frequently as warranted. After the initial LFI rating supervisory cycle, examiners may assign and communicate individual component ratings on a rolling basis to the firms. Under the proposed LFI rating system, the Federal Reserve would continue to generally rely to the fullest extent possible on the information and assessments developed by other relevant supervisors and functional regulators. In accordance with the Federal Reserve's regulations governing confidential supervisory information,22 ratings assigned under the LFI rating system would be communicated by the Federal Reserve to the firm but not disclosed publicly.

The proposed LFI rating system would apply if a firm reports total consolidated assets of $50 billion or more, calculated based on the average of the firm's total consolidated assets in the four (4) most recent quarters as reported on the firm's quarterly financial reports filed with the Federal Reserve. A firm that meets this criteria would generally receive the three LFI component ratings within one year of becoming subject to the LFI rating system. A firm would continue to be rated under the LFI rating system until it has less than $45 billion in total consolidated assets, based on the average total consolidated assets as reported on the firm's four (4) most recent quarterly financial reports filed with the Federal Reserve. The Federal Reserve may determine to apply the RFI rating system or another applicable rating system in certain limited circumstances.23

Concurrent with issuing this proposal, the Board is issuing another proposal for public comment addressing supervisory expectations for boards of directors of all Federal Reserve-supervised institutions.24 That proposal includes proposed guidance concerning the effectiveness of boards of directors of large financial institutions, which is an element of the Governance and Controls component rating. The Board also plans to separately release additional proposed guidance seeking comment on supervisory expectations relating to a firm's management of core business lines and independent risk management and controls, which is also an element of the Governance and Controls component rating. The Federal Reserve expects to release this additional guidance in the near future. However, if the LFI rating system is finalized before the additional governance and controls guidance is finalized, firms would be evaluated using existing supervisory guidance until such time that the additional governance and controls guidance is finalized.25

The following section provides a summary of the planned guidance relating to a firm's management of core business lines and independent risk management and controls, as well as a summary of the proposed guidance relating to the effectiveness of a firm's board of directors.26

The supervisory assessment of a firm's management of core business lines and independent risk management and controls would have three components: (1) Expectations for senior management with respect to both core business lines and independent risk management and controls; (2) expectations for the management of core business lines (CBLs); and (3) expectations for independent risk management (IRM) and controls.

Senior management oversees both the management of core business lines and independent risk management and controls. The supervisory assessment of the effectiveness of senior management would include senior management's role in managing the firm's day-to-day operations, promoting safety and soundness and compliance with internal policies and procedures, laws, and regulations, including those related to consumer protection.27

Senior management is responsible for implementing the firm's strategy and risk tolerance as approved by the firm's board. Senior management should implement the strategic and risk objectives across the firm such that they support the firm's long-term resiliency and safety and soundness, including the firm's resilience to a range of stressed conditions. Senior management should ensure that the firm's infrastructure, staffing, and resources are sufficient to carry out the firm's strategic objectives.

Senior management should maintain and implement an effective risk management framework and ensure the firm can appropriately manage risk consistent with its strategy and risk tolerance. This should include establishing clear responsibilities and accountability for the identification, management, and control of risk. Senior management should also develop and maintain the firm's policies and procedures and system of internal controls to ensure compliance with laws and regulations.

Senior management is responsible for ensuring the resolution of key issues and effective firm-wide communication, including to and from the board of directors. Senior management should have in place robust mechanisms for keeping apprised of, among other things, current and emerging risks to the firm and other material issues, including by maintaining robust management information systems.

Senior management should have in place succession and contingency staffing plans for key positions and have compensation and performance management programs that promote and enforce prudent risk-taking behaviors and business practices.

The Federal Reserve would consider the effectiveness of the management of core business lines in meeting its supervisory expectations.28 For LISCC firms, all business lines would be considered CBLs. For other firms, CBLs would be defined as those business lines where a significant control disruption, failure, or loss event would result in a material loss of revenue, profit, or franchise value, or result in significant consumer harm.29 The Federal Reserve is reserving discretion to identify other business lines or functions as core business lines, based on their size, risk profile, or other supervisory considerations.

CBL management should establish for each core business line specific business and risk objectives that align with the firm-wide strategy and risk tolerance.30 CBL management should inform senior management when the risk management capabilities are insufficient to align those business and risk objectives. CBL management should also clearly present to senior management the risks emanating from the business line's activities and explain how those risks are managed and align with the firm's risk tolerance.

CBL management should identify, measure, and manage current and emerging risks that stem from CBL activities and external factors. CBL management should also incorporate appropriate feedback from independent risk management (IRM) on business line risk positions, implementation of the risk tolerance, and risk management practices, including risk mitigation.

CBL management should manage the CBL's activities so they remain within risk limits established by IRM, consult with senior management before permitting any breaches of the limits, and follow appropriate procedures for obtaining exceptions to limits. CBL management should also adhere to the firm's policies and procedures for vetting new business products and initiatives, and escalate to senior management any required changes or modifications to risk management systems or internal control policies and procedures arising from the adoption of a new business or initiative.

CBL management should provide a CBL with sufficient resources and infrastructure to meet financial goals and strategic objectives while maintaining operational and financial resilience in a range of operating conditions, including stressful ones. Resources and infrastructure include sufficient personnel with appropriate training and expertise and management information systems.

CBL management should develop and maintain an effective system of sound and appropriate internal controls for its CBL that ensures compliance with laws and regulations.31 CBL management should regularly test to ensure the effectiveness of controls within the business lines and ensure that deficiencies are remediated, and should escalate material deficiencies and systematic control violations to senior management, as well as provide periodic reports. Finally, CBL management should reassess controls periodically to ensure relevancy and alignment with current approved policies.

CBL management should establish policies and guidelines that delineate accountability, set forth clear lines of management authority within the CBL, and align desired behavior with the firm's performance management incentives. CBL management should hold employees accountable for conduct that is inconsistent with the firm's policies or board and senior management directives or that could result in violations of law. CBL management should inform senior management of improper conduct when appropriate, including individual instances and when there are identified patterns of misconduct. CBL management should have ongoing and effective means to prevent, detect, and remediate risk management and compliance failures.

The Federal Reserve would assess whether the firm's independent risk management and controls meet supervisory expectations. This assessment would focus on three related areas: The independent risk management function, internal controls, and internal audit.

A CRO must have sufficient capability and experience in identifying, assessing, and managing risk exposures of large, complex financial institutions.32 The CRO should guide IRM to establish and monitor compliance with enterprise-wide risk limits, identify and aggregate the firm's risks, assess the firm's risk positions relative to the parameters of the firm's risk tolerance, and provide relevant risk information to senior management and the board of directors.

The CRO should inform the board of directors if his or her stature, independence, or authority is not sufficient or is at risk of being insufficient to provide unbiased and independent assessments of the firm's risks, risk management activities, and system of internal controls.33 Further, the CRO should be included in discussions with other senior management and the board related to key decisions, such as strategic planning and capital and liquidity planning, and provide input to the board on incentive compensation.

The CRO should notify senior management and the board of directors when activities or practices at the firm-wide, risk-specific, or CBL level do not align with the firm's overall risk tolerance. As appropriate, the CRO should recommend constraints on risk taking and enhancements to risk management practices to senior management and the board of directors.

The CRO should support the independence of IRM from the business lines by establishing clearly defined roles and responsibilities and reporting lines.

The firm should have a CAE, appointed by the board, with sufficient capability, experience, independence, and stature to manage the internal audit function's responsibilities.34 Under the direction of the CAE, the internal audit function performs an independent assessment of the effectiveness of the firm's system of internal controls and the risk management framework. The CAE should manage effectively all aspects of internal audit work on an ongoing basis, including any internal audit work that is outsourced. The CAE should have the authority to oversee all internal audit activities and to hire internal audit staff with sufficient capability and stature. The CAE should report findings, issues, and concerns to the board's audit committee and senior management.

IRM should evaluate whether the firm's risk tolerance appropriately captures the firm's material risks, whether it aligns with the firm's strategic plan and the corresponding business activities, and whether it is consistent with the capacity of the risk management framework. IRM, including through the CRO, should provide input to both senior management and the board to assist in the development, evaluation, and approval of the firm's risk tolerance. IRM should also determine whether the firm's risk profile is consistent with the firm's risk tolerance and assess whether the firm's risk management framework has the capacity to manage the risks outlined in the risk tolerance.

Under direction of the CRO, IRM should establish enterprise-wide risk limits as well as more granular risk limits, as appropriate, that are consistent with the firm's risk tolerance for the firm's full set of risks. IRM should monitor and update risk limits as appropriate, especially as the firm's risk tolerance, risk profile, or external conditions change. IRM should identify significant trends in risk levels to evaluate whether risk-taking and risk management practices are consistent with the firm's strategic objectives. IRM should escalate to senior management material breaches to the firm's risk tolerance and enterprise-wide risk limits, as well as instances where IRM's conclusions differ from those of CBLs.

IRM should identify and measure under both normal and stressful operating conditions, where possible, current and emerging risks within and across business lines and risk types, as well as any other relevant perspective. Common risk types include credit, market, operational, liquidity, interest rate, legal, and compliance (such as consumer protection and Bank Secrecy Act/anti-money laundering).

IRM should aggregate risks across the entire firm and assess those risks relative to the firm's risk tolerance. IRM should identify material or critical concentrations of risks and assess the likelihood and potential impact of those risks on the firm. IRM should identify information gaps, uncertainties, or limitations in risk assessments for the board of directors and senior management, as appropriate.

Risk reporting should cover current and emerging risk, risk exposure and adherence to risk limits and risk concentrations as well as the firm's ongoing strategic, capital, and liquidity planning processes. Risk reporting should enable prompt escalation and remediation of material problems; enhance appropriate and timely responses to identified problems; provide current and forward-looking perspectives; and support or influence strategic decision-making.

Developing and maintaining effective internal controls are the responsibility of senior management, IRM, and CBL management. Accordingly, a firm should appropriately assign management responsibilities for the establishment and maintenance of internal controls. To foster an appropriate control culture within the firm, adequate control activities should be integrated into the daily functions of all relevant personnel.

A firm should have mechanisms to monitor and test internal controls and to identify and escalate issues that appear to compromise the effectiveness of internal controls. The scope, frequency, and depth of testing should consider the complexity of the firm, the results of risk assessments, and the number and significance of the deficiencies identified during prior testing. A firm should test and monitor internal controls using a risk-based approach, prioritizing efforts on controls in areas of highest risk and less effective controls.

A firm should evaluate and communicate internal control deficiencies in a timely manner to those parties responsible for taking corrective action, including senior management.

The internal audit function should examine, evaluate, and perform an independent assessment of the effectiveness of the firm's risk management framework and internal control systems and report findings to senior management and the firm's audit committee. The Federal Reserve would assess the extent to which a firm complies with existing guidance on internal audit.35

Concurrent with this proposal, the Board is issuing a related proposal for public comment addressing supervisory expectations for boards of directors of all Federal Reserve-supervised institutions. The Federal Reserve conducted a multi-year review of the practices of boards of directors, particularly at the largest financial institutions, which considered the factors that make boards effective, the challenges boards face, how boards influence the safety and soundness of their firms, and the impact of the Federal Reserve's expectations for boards of directors in existing supervisory guidance. The proposed guidance relating to boards of directors and its accompanying notice published in the Federal Register constitute the results of the review. The review identified three key issues that could potentially reduce a board's ability to be effective. First, supervisory expectations for boards of directors and senior management have become increasingly difficult to distinguish. Second, boards typically spend a significant amount of time focused on supervisory expectations that do not directly relate to the board's core responsibilities, which include guiding the development of the firm's strategy and risk tolerance, overseeing senior management and holding them accountable, supporting the stature and independence of the firm's independent risk management and internal audit functions, and adopting effective governance practices. Third, boards of large financial institutions often face significant challenges managing the overwhelming quantity of information provided by senior management in advance of board meetings.

The proposal would refocus existing supervisory expectations on a board's core responsibilities by more clearly distinguishing the roles and responsibilities of the board from those of senior management; eliminating redundant, outdated, or irrelevant supervisory expectations for boards; and ensuring that supervisory guidance is more closely aligned.

The proposal contains three parts, the first of which includes proposed supervisory guidance addressing effective boards of directors (proposed BE guidance), which would apply to the largest depository institution holding companies supervised by the Federal Reserve. The proposed BE guidance identifies five key attributes of effective boards of directors and would provide the framework the Federal Reserve would use to assess a firm's board of directors. The proposed BE guidance also would clarify supervisory expectations for boards as distinct from expectations for senior management.

The second part of the proposal would revise certain supervisory expectations for boards to ensure they are aligned with the Federal Reserve's supervisory framework, and would eliminate redundant, outdated, or irrelevant supervisory expectations. These changes reflect the Federal Reserve's review of approximately 170 existing supervisory expectations contained in 27 Supervision and Regulation letters (SR letters), and would apply to bank and savings and loan holding companies of all sizes.

The third part of the proposal includes proposed supervisory guidance that would replace Federal Reserve SR letter 13-13 36 and clarify expectations for communicating supervisory findings to an institution's board of directors and senior management. This proposed guidance, like the existing guidance, would apply to all financial institutions supervised by the Federal Reserve. The proposed guidance would facilitate the execution of boards' core responsibilities by clarifying expectations for communicating supervisory findings to an institution's board of directors and senior management. The proposed guidance would indicate that Federal Reserve examiners and supervisory staff would direct most Matters Requiring Immediate Attention (MRIAs) and Matters Requiring Attention (MRAs) to senior management for corrective action. MRIAs and MRAs would only be directed to the board for corrective action when the board needs to address its corporate governance responsibilities or when senior management fails to take appropriate remedial action. The board would remain responsible for holding senior management accountable for remediating supervisory findings.

Upon finalizing the LFI rating system, the Federal Reserve expects to issue supervisory guidance to update and align the consolidated supervisory framework, including SR letter 12-17, to be fully consistent with any modifications made through the final adoption of the LFI rating system as well as supervisory guidance relating to governance and controls.

In the future, the Federal Reserve may propose to revise the LFI rating system to include an additional rating component to assess the sufficiency of resolution planning efforts undertaken by LISCC firms (and perhaps other select LFIs) to reduce the impact on the U.S. financial system in the event of the firm's failure. This proposed revision to the LFI rating system would be issued for notice and comment.

References to holding company ratings are included in a number of the Federal Reserve's existing regulations. In certain cases, the regulations are narrowly constructed such that they contemplate only the assignment of a standalone composite rating using a numerical rating scale. This is consistent with the current RFI rating system but is not compatible with the proposed LFI rating system. Three provisions in the Federal Reserve's existing regulations are written in this manner, including two in Regulation K and one in Regulation LL. In Regulation K, section 211.2(z) of Regulation K includes a definition of “well managed” which in part requires a bank holding company to have received a composite rating of 1 or 2 at its most recent examination or review; and section 211.9(a)(2) requires an investor (which by definition can be a bank holding company) to have received a composite rating of at least 2 at its most recent examination in order to make investments under the general consent or limited general consent procedures contained in sections 211.9(b) and (c). In Regulation LL, section 238.54(a)(1) restricts savings and loan holding companies from commencing certain activities without the Federal Reserve's prior approval unless the company received a composite rating of 1 or 2 at its most recent examination.

To ensure that the Federal Reserve's regulations are consistent and compatible with all aspects of both the RFI rating system as well as the proposed LFI rating system, the Federal Reserve proposes to amend those three regulatory provisions so they would apply to entities which receive numerical composite ratings as well as to entities which do not receive numerical composite ratings (including firms subject to the proposed LFI rating system).37 To satisfy the requirements of those provisions, firms that do not receive numerical composite ratings would have to be considered satisfactory under the proposed LFI rating system. To be considered satisfactory, a firm would have to be rated “Satisfactory” or “Satisfactory Watch” for each component of the proposed LFI rating system; a firm which is rated “Deficient-1” or lower for any component would not be considered satisfactory. This standard would apply to any provision contained in the Federal Reserve's regulations which requires or refers to a firm having a satisfactory composite rating.

The proposed LFI rating system includes several structural changes from the RFI rating system. The following table provides a broad comparison between the two rating systems.

The Board invites comments on all aspects of the proposed LFI rating system, including responses to the following questions:

(1) Are there specific considerations beyond those outlined in this proposal that should be considered in the Federal Reserve's assessment of whether an LFI has sufficient financial and operational strength and resilience to maintain safe and sound operations?

(2) Does the proposal clearly describe the firms that would be subject to the LFI rating system, and those firms that would continue to be subject to the RFI rating system?

(3) Does the proposal clearly describe the supervisory expectations for senior management in the evaluation of a firm's governance and controls under the proposed LFI rating system?

(4) Does the proposal clearly describe how and under what circumstances a “Satisfactory Watch” rating would or would not be assigned? Does that rating provide appropriate messaging and incentives to firms to correct identified deficiencies?

(5) Should the LFI rating system be revised at a future date to assess the sufficiency of a firm's resolution planning efforts undertaken to reduce the impact on the financial system in the event of the firm's failure? If yes, what should the Federal Reserve specifically consider in conducting that assessment?

(6) Are there options that should be considered to enhance the transparency of LFI ratings in order to incent more timely and comprehensive remediation of supervisory deficiencies or issues?

(7) What specific issues should the Federal Reserve consider when using the LFI rating system to inform future revisions to other supervisory rating systems used to assess the U.S. operations of foreign banking organizations?

There is no collection of information required by this proposal that would be subject to the Paperwork Reduction Act of 1995, 44 U.S.C. 3501 et seq.

The Board is providing an initial regulatory flexibility analysis with respect to this proposed rule. The Regulatory Flexibility Act, 5 U.S.C. 601 et seq. (RFA), generally requires an agency to assess the impact a rule is expected to have on small entities. The RFA requires an agency either to provide an initial regulatory flexibility analysis with a proposed rule for which a general notice of proposed rulemaking is required or to certify that the proposed rule will not have a significant impact on a substantial number of small entities. Based on the Board's analysis and for the reasons stated below, the Board believes that neither the proposed LFI rating system nor the proposed rule will have a significant economic impact on a substantial number of small entities. A final regulatory flexibility analysis will be conducted after comments received during the public comment period have been considered.

Under regulations issued by the Small Business Administration, a small entity includes a depository institution, bank holding company, or savings and loan holding company with assets of $550 million or less (small banking organizations). As of June 1, 2017, there were approximately 3,539 small banking organizations. As described above, the proposed LFI rating system would apply only to all bank holding companies with total consolidated assets of $50 billion or more; all non-insurance, non-commercial savings and loan holding companies with total consolidated assets of $50 billion or more; and U.S. intermediate holding companies of foreign banking organizations established pursuant to section 252.153 of the Federal Reserve's Regulation YY. Small banking organizations would therefore not be subject to the proposed LFI rating system. Similarly, the proposed rule would make conforming changes to several regulations to reflect certain aspects of the proposed LFI rating system, but would not change the operation of those regulations for any entity that would not be subject to the proposed LFI rating system. As a result, neither the proposed LFI rating system nor the proposed rule should have any impact on small banking organizations. In light of the foregoing, the Board believes that the proposed LFI rating system will not have a significant economic impact on small banking organizations supervised by the Board.

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

• Has the Board organized the material to suit your needs? If not, how could the proposal be more clearly stated?

• Does the proposal contain technical language or jargon that is not clear? If so, what language requires clarification?

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

• Would more, but shorter, sections be better? If so, what sections should be changed?

• What else could the Board do to make the proposal easier to understand?

For the reasons stated in the preamble, the Board proposes to amend 12 CFR parts 211 and 238 as follows:

Comments Invited

We invite you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under the ADDRESSES section. Include “Docket No. FAA-2017-0770; Product Identifier 2017-NM-030-AD” at the beginning of your comments. We specifically invite comments on the overall regulatory, economic, environmental, and energy aspects of this proposed AD. We will consider all comments received by the closing date and may amend this proposed AD because of those comments.

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

On January 21, 2014, we issued AD 2014-03-07, Amendment 39-17744 (79 FR 9392, February 19, 2014) (“AD 2014-03-07”), for certain The Boeing Company Model MD-11 and MD-11F airplanes. AD 2014-03-07 superseded AD 2009-26-16, Amendment 39-16155 (74 FR 69249, December 31, 2009). AD 2014-03-07 requires inspecting certain locations of the wire bundles of the center upper auxiliary fuel tank for damage, and corrective action if necessary. AD 2014-03-07 also requires installing nonmetallic barrier/shield sleeving, new clamps, new attaching hardware, and a new extruded channel. AD 2014-03-07 resulted from reports that identified additional locations where inspections and corrective actions of the center upper auxiliary fuel tank are needed. We issued AD 2014-03-07 to reduce the potential of ignition sources inside fuel tanks, which, in combination with flammable fuel vapors, could result in fuel tank explosions and consequent loss of the airplane.

Since we issued AD 2014-03-07, we determined that, for certain airplanes, it is necessary to inspect the wire bundles at additional center upper auxiliary fuel tank locations for damage. We have also expanded the applicability to add one airplane (Line Number 579) that is also affected by the identified unsafe condition.

We reviewed Boeing Service Bulletin MD11-28-126, Revision 6, dated July 1, 2016. This service information describes procedures for inspecting certain wire bundles of the center auxiliary fuel tank for damage, and repairing or replacing damaged wires. This service information also describes procedures for installing barrier/shield sleeving, clamping, and an extruded channel. This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the ADDRESSES section.

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

This proposed AD would retain all requirements of AD 2014-03-07. This proposed AD would add inspection requirements for certain airplanes and expand the applicability. This proposed AD would require accomplishing the actions specified in the service information described previously, except as discussed under “Difference between this Proposed AD and Service Information.” For information on the procedures and compliance times, see this service information at http://www.regulations.gov by searching for and locating Docket No. FAA-2017-0770.

Boeing Service Bulletin MD11-28-126, Revision 6, dated July 1, 2016, specifies to contact the manufacturer for certain instructions, but this proposed AD would require using repair methods, modification deviations, and alteration deviations in one of the following ways:

• In accordance with a method that we approve; or

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

We estimate that this proposed AD affects 125 airplanes of U.S. registry. We estimate the following costs to comply with this proposed AD:

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

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

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

This proposed AD is issued in accordance with authority delegated by the Executive Director, Aircraft Certification Service, as authorized by FAA Order 8000.51C. In accordance with that order, issuance of ADs is normally a function of the Compliance and Airworthiness Division, but during this transition period, the Executive Director has delegated the authority to issue ADs applicable to transport category airplanes to the Director of the System Oversight Division.

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

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

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

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

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

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

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

The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This proposed rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it would establish Class E airspace extending upward from 700 feet above the surface at Deblois Flight Strip, Deblois, ME, to support IFR operations in standard instrument approach procedures at the airport.

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

Communications should identify both docket numbers (FAA Docket No. FAA-2015-2891 and Airspace Docket No. 15-ANE-1) and be submitted in triplicate to DOT Docket Operations (see ADDRESSES section for address and phone number). You may also submit comments through the Internet at http://www.regulations.gov.

Persons wishing the FAA to acknowledge receipt of their comments on this action must submit with those comments a self-addressed stamped postcard on which the following statement is made: “Comments to Docket No. FAA-2015-2891; Airspace Docket No. 15-ANE-1.” The postcard will be date/time stamped and returned to the commenter.

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

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

You may review the public docket containing the proposal, any comments received, and any final disposition in person in the Dockets Office (see the ADDRESSES section for address and phone number) between 9:00 a.m. and 5:00 p.m., Monday through Friday, except federal holidays. An informal docket may also be examined between 8:00 a.m. and 4:30 p.m., Monday through Friday, except federal holidays at the office of the Eastern Service Center, Federal Aviation Administration, room 350, 1701 Columbia Avenue, College Park, Georgia 30337.

This document proposes to amend FAA Order 7400.11A, Airspace Designations and Reporting Points, dated August 3, 2016, and effective September 15, 2016. FAA Order 7400.11A is publicly available as listed in the ADDRESSES section of this document. FAA Order 7400.11A lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

The FAA is considering an amendment to Title 14, Code of Federal Regulations (14 CFR) part 71 to establish Class E airspace extending upward from 700 feet above the surface within a 7-mile radius of Deblois Flight Strip, Deblois, ME, providing the controlled airspace required to support the new RNAV (GPS) standard instrument approach procedures for IFR operations at the airport.

Class E airspace designations are published in Paragraph 6005 of FAA Order 7400.11A, dated August 3, 2016, and effective September 15, 2016, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document will be published subsequently in the Order.

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

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

In consideration of the foregoing, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:

The authority for this rulemaking is 5 U.S.C. 552a, the Privacy Act of 1974, as amended, which requires the implementation of the Act by Federal agencies.

This action ensures that ABMC's collection, use, maintenance, or dissemination of information about individuals for purposes of discharging its statutory responsibilities will be performed in accordance with the Privacy Act of 1974 and applicable OMB guidance. This rule:

• Establishes rules of conduct for ABMC personnel and ABMC contractors involved in the design, development, operation, or maintenance of any system of records.

• Establishes appropriate administrative, technical, and physical safeguards to ensure the security and confidentiality of records and to protect against any anticipated threats or hazards to their security or integrity that could result in substantial harm, embarrassment, inconvenience, or unfairness to any individual about whom information is maintained.

• Ensures that guidance, assistance, and subject matter expert support are provided ABMC staff, contractors and the public as needed in the implementation and execution of and compliance with the ABMC Privacy Program.

• Ensures that laws, policies, procedures, and systems for protecting individual privacy rights are implemented throughout ABMC.

Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rule benefits the public and the United States Government by providing clear procedures for members of the public, contractors, and employees to follow with regard to the ABMC privacy program. This rule has been designated a not significant regulatory action.

Section 202 of the Unfunded Mandates Reform Act of 1995 (UMRA) (2 U.S.C. 1532) requires agencies to assess anticipated costs and benefits before issuing any rule whose mandates require spending in any 1 year of $100 million in 1995 dollars, updated annually for inflation. In 2016, that threshold is approximately $146 million. This rule will not mandate any requirements for State, local, or tribal governments, nor will it affect private sector costs.

The ABMC certifies this proposed rule is not subject to the Regulatory Flexibility Act (5 U.S.C. Ch. 6) because it would not, if promulgated, have a significant economic impact on a substantial number of small entities. Therefore, the Regulatory Flexibility Act, as amended, does not require ABMC to prepare a regulatory flexibility analysis.

Executive Order 13132 establishes certain requirements that an agency must meet when it promulgates a proposed rule (and subsequent final rule) that imposes substantial direct requirement costs on State and local governments, preempts State law, or otherwise has Federalism implications. This rule will not have a substantial effect on the States; the relationship between the National Government and the States; or the distribution of power and responsibilities among the various levels of Government.

It has been determined that this rule does not impose reporting or record keeping requirements under the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35).

I. Summary

EPA is proposing to approve the portions of the October 26, 2015, and May 19, 2017, SIP revisions from Alabama concerning CSAPR 1 allowance trading programs for ozone season emissions of NOX. Large EGUs in Alabama are currently subject to CSAPR FIPs that require the units to participate in the federal CSAPR NOX Group 2 Ozone Season Trading Program. The CSAPR regulations provide a process for the submission and approval of SIP revisions to replace the requirements of CSAPR FIPs with SIP requirements under which a state's units participate in CSAPR state trading programs that are integrated with and, with certain permissible exceptions, substantively identical to the CSAPR federal trading programs.

The portions of the SIP revisions proposed for approval would incorporate into Alabama's SIP state allowance trading program regulations for ozone season NOX emissions that would replace EPA's federal trading program regulations for those emissions from Alabama units. EPA is proposing to approve these portions of the SIP revisions, as clarified in a letter provided on August 4, 2017, because they meet the requirements of the CAA and EPA's regulations for approval of a CSAPR full SIP revision replacing a federal trading program with a state trading program that is integrated with and substantively identical to the federal trading program except for permissible differences with respect to emission allowance allocation provisions. Under the CSAPR regulations, approval of these portions of the SIP revisions would automatically eliminate the obligations of EGUs in Alabama (but not any units in Indian country within Alabama's borders) to participate in CSAPR's federal trading programs for ozone season NOX emissions under the corresponding CSAPR FIPs. EPA proposes to find that approval of these portions of the SIP revisions would satisfy Alabama's obligation pursuant to CAA section 110(a)(2)(D)(i)(I) to prohibit emissions which will significantly contribute to nonattainment or interfere with maintenance of the 1997 8-hour Ozone NAAQS in any other state. EPA also proposes to find that approval of these portions of the SIP revisions would partially satisfy Alabama's obligation pursuant to CAA section 110(a)(2)(D)(i)(I) to prohibit emissions which will significantly contribute to nonattainment or interfere with maintenance of the 2008 8-hour Ozone NAAQS in any other state.

Section II of this document summarizes relevant aspects of the CSAPR federal trading programs and FIPs as well as the range of opportunities states have to submit SIP revisions to modify or replace the FIP requirements while continuing to rely on CSAPR's trading programs to address the states' obligations to mitigate interstate air pollution. Section III describes the specific conditions for approval of such SIP revisions. Section IV contains EPA's analysis of Alabama's SIP submittal. Section V addresses incorporation by reference. Section VI sets forth EPA's proposed action on the submittal. Section VII addresses statutory and Executive Order reviews.

EPA issued CSAPR in July 2011 and the CSAPR Update 2 in 2016 to address the requirements of CAA section 110(a)(2)(D)(i)(I) concerning interstate transport of air pollution for specific NAAQS. As amended (including by the 2016 CSAPR Update), CSAPR requires 27 eastern states to limit their statewide emissions of sulfur dioxide (SO2) and/or NOX in order to mitigate transported air pollution unlawfully impacting other states' ability to attain or maintain four NAAQS: the 1997 annual PM2.5 NAAQS, the 2006 24-hour PM2.5 NAAQS, the 1997 8-hour Ozone NAAQS, and the 2008 8-hour Ozone NAAQS. The CSAPR emissions limitations are defined in terms of maximum statewide “budgets” for emissions of annual SO2, annual NOX, and/or ozone season NOX by each covered state's large EGUs. The CSAPR state budgets are implemented in two phases of generally increasing stringency: The Phase 1 budgets apply to emissions in 2015 and 2016; and the Phase 2 and CSAPR Update budgets apply to emissions in 2017 and later years. As a mechanism for achieving compliance with the emissions limitations, CSAPR establishes five federal emissions trading programs: a program for annual NOX emissions; two geographically separate programs for annual SO2 emissions; and two geographically separate programs for ozone season NOX emissions. CSAPR also establishes FIP requirements applicable to the large EGUs in each covered state.3 Currently, the CSAPR FIP provisions require each state's units to participate in up to three of the five CSAPR trading programs.

CSAPR includes provisions under which states may submit and EPA will approve SIP revisions to modify or replace the CSAPR FIP requirements while allowing states to continue to meet their transport-related obligations using either CSAPR's federal emissions trading programs or state emissions trading programs integrated with the federal programs, provided that the SIP revisions meet all relevant criteria.4 Through such a SIP revision, a state may replace EPA's default provisions for allocating emission allowances among the state's units, employing any state-selected methodology to allocate or auction the allowances, subject to timing conditions and limits on overall allowance quantities. In the case of CSAPR's federal trading programs for ozone season NOX emissions (or an integrated state trading program), a state may also expand trading program applicability to include certain smaller EGUs.5 If a state wants to replace the CSAPR FIP requirements with SIP requirements under which the state's units participate in a state trading program that is integrated with and identical to the federal trading program even as to the allocation and applicability provisions, the state may submit a SIP revision for that purpose as well. However, no emissions budget increases or other substantive changes to the trading program provisions are allowed. A state whose units are subject to multiple CSAPR federal trading programs may submit SIP revisions to modify or replace either some or all of those FIP requirements.

States can submit two basic forms of CSAPR-related SIP revisions effective for emissions control periods in 2017 or later years.6 Specific conditions for approval of each form of SIP revision are set forth in the CSAPR regulations, as described in section III below. Under the first alternative—an “abbreviated” SIP revision—a state may submit a SIP revision that upon approval replaces the default allowance allocation and/or applicability provisions of a CSAPR federal trading program for the state.7 Approval of an abbreviated SIP revision leaves the corresponding CSAPR FIP and all other provisions of the relevant federal trading program in place for the state's units.

Under the second alternative—a “full” SIP revision—a state may submit a SIP revision that upon approval replaces a CSAPR federal trading program for the state with a state trading program integrated with the federal trading program, so long as the state trading program is substantively identical to the federal trading program or does not substantively differ from the federal trading program except as discussed above with regard to the allowance allocation and/or applicability provisions.8 For purposes of a full SIP revision, a state may either adopt state rules with complete trading program language, incorporate the federal trading program language into its state rules by reference (with appropriate conforming changes), or employ a combination of these approaches.

The CSAPR regulations identify several important consequences and limitations associated with approval of a full SIP revision. First, upon EPA's approval of a full SIP revision as correcting the deficiency in the state's SIP that was the basis for a particular set of CSAPR FIP requirements, the obligation to participate in the corresponding CSAPR federal trading program is automatically eliminated for units subject to the state's jurisdiction without the need for a separate EPA withdrawal action, so long as EPA's approval of the SIP revision as meeting the requirements of the CSAPR regulations is full and unconditional.9 Second, approval of a full SIP revision does not terminate the obligation to participate in the corresponding CSAPR federal trading program for any units located in any Indian country within the borders of the state, and if and when a unit is located in Indian country within a state's borders, EPA may modify the SIP approval to exclude from the SIP, and include in the surviving CSAPR FIP instead, certain trading program provisions that apply jointly to units in the state and to units in Indian country within the state's borders.10 Finally, if at the time a full SIP revision is approved EPA has already started recording allocations of allowances for a given control period to a state's units, the federal trading program provisions authorizing EPA to complete the process of allocating and recording allowances for that control period to those units will continue to apply, unless EPA's approval of the SIP revision provides otherwise.11

Each CSAPR-related abbreviated or full SIP revision must meet the following general submittal conditions:

• Timeliness and completeness of SIP submittal. If a state wants to replace the default allowance allocation or applicability provisions of a CSAPR federal trading program, the complete SIP revision must be submitted to EPA by December 1 of the year before the deadlines described below for submitting allocation or auction amounts to EPA for the first control period for which the state wants to replace the default allocation and/or applicability provisions.12 This SIP submission deadline is inoperative in the case of a SIP revision that seeks only to replace a CSAPR FIP and federal trading program with a SIP and a substantively identical state trading program integrated with the federal trading program. The SIP submittal completeness criteria in section 2.1 of appendix V to 40 CFR part 51 also apply.

In addition to the general submittal conditions, a CSAPR-related abbreviated or full SIP seeking to address the allocation or auction of emission allowances must meet the following further conditions:

• Methodology covering all allowances potentially requiring allocation. For each federal trading program addressed by a SIP revision, the SIP revision's allowance allocation or auction methodology must replace both the federal program's default allocations to existing units 13 at 40 CFR 97.411(a), 97.511(a), 97.611(a), 97.711(a), or 97.811(a), as applicable, and the federal trading program's provisions for allocating allowances from the new unit set-aside (NUSA) for the state at 40 CFR 97.411(b)(1) and 97.412(a), 97.511(b)(1) and 97.512(a), 97.611(b)(1) and 97.612(a), 97.711(b)(1) and 97.712(a), or 97.811(b)(1) and 97.812(a), as applicable.14 In the case of a state with Indian country within its borders, while the SIP revision may neither alter nor assume the federal program's provisions for administering the Indian country NUSA for the state, the SIP revision must include procedures addressing the disposition of any otherwise unallocated allowances from an Indian country NUSA that may be made available for allocation by the state after EPA has carried out the Indian country NUSA allocation procedures.15

• Assurance that total allocations will not exceed the state budget. For each federal trading program addressed by a SIP revision, the total amount of allowances auctioned or allocated for each control period under the SIP revision (prior to the addition by EPA of any unallocated allowances from any Indian country NUSA for the state) generally may not exceed the state's emissions budget for the control period less the sum of the amount of any Indian country NUSA for the state for the control period and any allowances already allocated to the state's units for the control period and recorded by EPA.16 Under its SIP revision, a state is free to not allocate allowances to some or all potentially affected units, to allocate or auction allowances to entities other than potentially affected units, or to allocate or auction fewer than the maximum permissible quantity of allowances and retire the remainder. Under the CSAPR NOX Ozone Season Group 2 Trading Program only, additional allowances may be allocated if the state elects to expand applicability to non-EGUs that would have been subject to the NOX Budget Trading Program established for compliance with the NOX SIP Call.17

• Timely submission of state-determined allocations to EPA. The SIP revision must require the state to submit to EPA the amounts of any allowances allocated or auctioned to each unit for each control period (other than allowances initially set aside in the state's allocation or auction process and later allocated or auctioned to such units from the set-aside amount) by the following deadlines.18 Note that the submission deadlines differ for amounts allocated or auctioned to units considered existing units for CSAPR purposes and amounts allocated or auctioned to other units.

• No changes to allocations already submitted to EPA or recorded. The SIP revision must not provide for any change to the amounts of allowances allocated or auctioned to any unit after those amounts are submitted to EPA or any change to any allowance allocation determined and recorded by EPA under the federal trading program regulations.19

• No other substantive changes to federal trading program provisions. The SIP revision may not substantively change any other trading program provisions, except in the case of a SIP revision that also expands program applicability as described below.20 Any new definitions adopted in the SIP revision (in addition to the federal trading program's definitions) may apply only for purposes of the SIP revision's allocation or auction provisions.21

In addition to the general submittal conditions, a CSAPR-related abbreviated or full SIP revision seeking to expand applicability under the CSAPR NOX Ozone Season Group 1 or CSAPR NOX Ozone Season Group 2 Trading Programs (or an integrated state trading program) must meet the following further conditions:

• Only electricity generating units with nameplate capacity of at least 15 MWe. The SIP revision may expand applicability only to additional fossil fuel-fired boilers or combustion turbines serving generators producing electricity for sale, and only by lowering the generator nameplate capacity threshold used to determine whether a particular boiler or combustion turbine serving a particular generator is a potentially affected unit. The nameplate capacity threshold adopted in the SIP revision may not be less than 15 MWe.22 In addition or alternatively, applicability under the CSAPR NOX Ozone Season Group 2 Trading Program may be expanded to non-EGUs that would have been subject to the NOX Budget Trading Program established for compliance with the NOX SIP Call.23

• No other substantive changes to federal trading program provisions. The SIP revision may not substantively change any other trading program provisions, except in the case of a SIP revision that also addresses the allocation or auction of emission allowances as described above.24

In addition to the general submittal conditions and the other applicable conditions described above, a CSAPR-related full SIP revision must meet the following further conditions:

• Complete, substantively identical trading program provisions. The SIP revision must adopt complete state trading program regulations substantively identical to the complete federal trading program regulations at 40 CFR 97.402 through 97.435, 97.502 through 97.535, 97.602 through 97.635, 97.702 through 97.735, or 97.802 through 97.835, as applicable, except as described above in the case of a SIP revision that seeks to replace the default allowance allocation and/or applicability provisions.25

• Only non-substantive substitutions for the term “State.” The SIP revision may substitute the name of the state for the term “State” as used in the federal trading program regulations, but only to the extent that EPA determines that the substitutions do not substantively change the trading program regulations.26

• Exclusion of provisions addressing units in Indian country. The SIP revision may not impose requirements on any unit in any Indian country within the state's borders and must not include the federal trading program provisions governing allocation of allowances from any Indian country NUSA for the state.27

In the Final Rules Section of this Federal Register, EPA is approving the State's implementation plan revision as a direct final rule without prior proposal because the Agency views this as a noncontroversial submittal and anticipates no adverse comments. A detailed rationale for the approval is set forth in the direct final rule. If no adverse comments are received in response to this rule, no further activity is contemplated. If EPA receives adverse comments, the direct final rule will be withdrawn and all public comments received will be addressed in a subsequent final rule based on this proposed rule. EPA will not institute a second comment period on this document. Any parties interested in commenting on this document should do so at this time.

I. Background

Each state is required to submit a progress report in the form of a SIP revision during the first implementation period that evaluates progress towards the RPGs for each mandatory Class I federal area (Class I area) 1 within the state and in each mandatory Class I area outside the state that may be affected by emissions from within the state. See 40 CFR 51.308(g). In addition, the provisions under 40 CFR 51.308(h) require states to submit, at the same time as the progress report, a determination of the adequacy of the state's existing regional haze plan. The first progress report is due five years after submittal of the initial regional haze plan.

SC DHEC submitted its first regional haze plan on December 17, 2007, and submitted its Progress Report on December 28, 2012. The Progress Report and accompanying cover letter included a determination that South Carolina's existing regional haze plan requires no substantive revision to achieve the established regional haze visibility improvement and emissions reduction goals for 2018. EPA proposed to find that the State's Progress Report satisfied the requirements of 40 CFR 51.308(g) and (h) in a notice of proposed rulemaking (NPRM) published on January 17, 2014 (79 FR 3147). Today's notice supplements that 2014 NPRM by more fully explaining and soliciting comment on the basis for the Agency's proposed approval as it relates to the Clean Air Interstate Rule (CAIR) and CSAPR.

In accordance with requirements in EPA's Regional Haze Rule (RHR), South Carolina's Progress Report describes the progress made towards the RPGs of Class I areas in and outside South Carolina that are affected by emissions from South Carolina's sources.2 See 40 CFR 51.308(g). This Progress Report also included an assessment of whether South Carolina's existing regional haze plan is sufficient to allow it and other nearby states with Class I areas to achieve their RPGs by the end of the first implementation period. See 40 CFR 51.308(h). In the 2014 NPRM, EPA proposed to approve the State's Progress Report as adequately addressing 40 CFR 51.308(g) and (h). EPA's proposed conclusions in the 2014 NPRM regarding South Carolina's Progress Report are briefly summarized below.

South Carolina's Progress Report included a description of the status of measures in its regional haze plan; a summary of the emissions reductions achieved; an assessment of the visibility conditions for Cape Romain Wilderness Area, the only Class I area in the State; an analysis of the changes in emissions from sources and activities within the State; an assessment of any significant changes in anthropogenic emissions within or outside the State that have limited or impeded visibility improvement progress in Class I areas impacted by the State's sources; an assessment of the sufficiency of the regional haze plan to enable South Carolina and states affected by South Carolina's sources to meet the RPGs for their Class I areas; and a review of the State's visibility monitoring strategy. As explained in the 2014 NPRM, EPA proposed to find that South Carolina's Progress Report adequately addressed the applicable provisions under 40 CFR 51.308(g).

In addition, South Carolina simultaneously submitted a determination pursuant to 40 CFR 51.308(h) that its regional haze plan is sufficient to enable the State and states affected by South Carolina's sources to achieve the RPGs for Class I areas affected by South Carolina's sources. The State also declared that further revision of the existing regional haze plan was not needed at that time. As explained in detail in the 2014 NPRM, EPA proposed to determine that South Carolina had adequately addressed 40 CFR 51.308(h) because visibility has improved at Cape Romain; sulfur dioxide (SO2) emissions from the State's sources have decreased beyond original projections; 3 additional electric generating unit (EGU) control measures not relied upon in the State's regional haze plan have occurred or will occur in the implementation period; and the SO2 emissions from EGUs in South Carolina are already below the levels projected for 2018 in the regional haze plan and are expected to continue to trend downward, as will the SO2 emissions from EGUs in the other VISTAS states. In the 2014 NPRM, EPA proposed to approve South Carolina's Progress Report SIP as meeting the requirements of 40 CFR 51.308(g) and (h).

Decisions by the courts regarding EPA rules addressing the interstate transport of pollutants have had a substantial impact on EPA's review of the regional haze plans of many states. In 2005, EPA issued regulations allowing states to rely on CAIR to meet certain requirements of the RHR. See 70 FR 39104 (July 6, 2005).4 Like many other states subject to CAIR, South Carolina relied on CAIR in its regional haze plan to meet certain requirements of the RHR, including the criteria for alternatives to the best available retrofit technology (BART) requirements for emissions of SO2 and nitrogen oxides (NOX) from certain EGUs in the State. This reliance was consistent with EPA's regulations. See 70 FR 39104 (July 6, 2005). However, in 2008, the D.C. Circuit remanded CAIR to EPA without vacatur to preserve the environmental benefits provided by the rule. North Carolina v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008). On August 8, 2011 (76 FR 48208), acting on the D.C. Circuit's remand, EPA promulgated CSAPR to replace CAIR and issued Federal Implementation Plans (FIPs) to implement the rule in CSAPR-subject states.5 Implementation of CSAPR was scheduled to begin on January 1, 2012, when CSAPR would have superseded the CAIR program. However, numerous parties filed petitions for review of CSAPR, and at the end of 2011, the D.C. Circuit issued an order staying CSAPR pending resolution of the petitions and directing EPA to continue to administer CAIR. Order of December 30, 2011, in EME Homer City Generation, L.P. v. EPA, D.C. Cir. No. 11-1302.

On June 28, 2012 (77 FR 38509), EPA finalized a limited approval of South Carolina's regional haze plan addressing the first implementation period for regional haze. In a separate action, published on June 7, 2012 (77 FR 33642), EPA finalized a limited disapproval of regional haze plans from South Carolina and several other states because these plans relied on CAIR to meet certain regional haze requirements, and also amended the Regional Haze Rule to provide that participation by a state's EGUs in a CSAPR trading program for a given pollutant—either a CSAPR federal trading program implemented through a CSAPR FIP or an integrated CSAPR state trading program implemented through an approved CSAPR SIP revision—qualifies as a BART alternative for those EGUs for that pollutant.6 See 40 CFR 51.308(e)(4). In that same June 7, 2012, action, EPA also finalized FIPs to replace reliance on CAIR with reliance on CSAPR to address deficiencies in CAIR-dependent regional haze plans of several states, including South Carolina's regional haze plan.

Following these EPA actions, however, the D.C. Circuit issued a decision in EME Homer City Generation, L.P. v. EPA, 696 F.3d 7 (D.C. Cir. 2012), vacating and remanding CSAPR to EPA and ordering continued implementation of CAIR pending the promulgation of a valid replacement. On April 29, 2014, the Supreme Court reversed the D.C. Circuit's decision on CSAPR and remanded the case to the D.C. Circuit to resolve remaining issues in accordance with the high court's ruling.7 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 (2014). On remand, the D.C. Circuit affirmed CSAPR in most respects, but invalidated without vacating some of the CSAPR budgets for a number of states. EME Homer City Generation, L.P. v. EPA, 795 F.3d 118 (D.C. Cir. 2015). The remanded budgets include the Phase 2 SO2 emissions budget and ozone-season NOX budget for South Carolina. The CSAPR litigation ultimately delayed implementation of the rule for three years, from January 1, 2012, when CSAPR's cap-and-trade programs were originally scheduled to replace the CAIR cap-and-trade programs, to January 1, 2015. Thus, the rule's Phase 2 budgets, originally promulgated to begin on January 1, 2014, took effect on January 1, 2017.

On May 26, 2017, South Carolina submitted a draft SIP revision for parallel processing that adopts provisions for participation in the CSAPR annual NOX and annual SO2 trading programs, including annual NOX and annual SO2 budgets that are equal to the budgets for South Carolina in EPA's CSAPR FIP. EPA signed a NPRM on July 28, 2017 proposing to approve the SIP revision. As approval of that SIP revision would eliminate South Carolina's remanded federally-established Phase 2 SO2 budget, it is EPA's opinion that finalization of approval of that action would address the judicial remand of South Carolina's federally-established Phase 2 SO2 budget.8

CAIR was in effect at the time that South Carolina submitted its Progress Report on December 28, 2012, and the State included an assessment of the emission reductions from the implementation of CAIR in its report. South Carolina's Progress Report discussed the status of the litigation concerning CAIR and CSAPR, but because CSAPR was not at that time in effect, South Carolina did not take actual emissions reductions from CSAPR into account in assessing its regional haze plan. For the same reason, in the 2014 NPRM, EPA did not assess at that time the impact of CSAPR nor the CSAPR FIP on the abilities of South Carolina and its neighbors to meet their RPGs.

The purpose of this supplemental proposal is to seek comment on the effect of the D.C. Circuit's 2015 decision on the Agency's assessment of South Carolina's Progress Report and the State's determination that its existing regional haze plan need not be revised at this time. Given the complex background summarized above, EPA is proposing to determine that South Carolina appropriately took CAIR into account in its Progress Report. CAIR was in effect during the 2007-2011 period addressed by South Carolina's Progress Report. EPA approved South Carolina's regulations implementing CAIR as part of the South Carolina SIP on October 16, 2009 (74 FR 53167), and at the time of submission of its Progress Report, neither South Carolina nor EPA had taken any action to remove CAIR from the South Carolina SIP. See 40 CFR 52.2120(c). Therefore, EPA proposes to find that South Carolina appropriately evaluated and relied on CAIR reductions to demonstrate the State's progress towards meeting its RPGs.

The State's Progress Report also demonstrated that Class I areas in other states impacted by South Carolina sources were on track to meet their RPGs as discussed in the 2014 NPRM. See 79 FR 3151. EPA's intention in requiring the progress reports pursuant to 40 CFR 51.308(g) was to ensure that emission management measures in the regional haze plans are being implemented on schedule and that visibility improvement appears to be consistent with the RPGs. See 64 FR 35713, 35747 (July 1, 1999). CAIR was in effect in South Carolina through 2014, providing the emission reductions relied upon in South Carolina's regional haze plan. Thus, EPA is proposing to determine that South Carolina appropriately took into account CAIR reductions in assessing the implementation of measures in the regional haze plan for the 2007-2011 timeframe, and EPA believes that it is appropriate to rely on CAIR emission reductions for purposes of assessing the adequacy of South Carolina's Progress Report demonstrating progress during this timeframe because CAIR remained effective and provided the requisite emission reductions.

In addition, EPA also believes that reliance upon CAIR reductions to show South Carolina's progress towards meeting its RPGs from 2007-2011 is consistent with the Agency's prior actions. During the continued implementation of CAIR per the direction of the D.C. Circuit through October 2014, EPA approved redesignations of areas to attainment of the 1997 PM2.5 NAAQS in which states relied on CAIR as an “enforceable measure.” See 77 FR 76415 (December 28, 2012) (redesignation of Huntingdon-Ashland, West Virginia); 78 FR 59841 (September 30, 2013) (redesignation of Wheeling, West Virginia); and 78 FR 56168 (September 12, 2013) (redesignation of Parkersburg, West Virginia). While EPA did previously state in a rulemaking action on the Florida regional haze plan that a five-year progress report may be the appropriate time to address changes, if necessary, for RPG demonstrations and long term strategies, EPA does not believe that the implementation of CSAPR impacts the adequacy of the South Carolina regional haze plan to address reasonable progress from 2007 through 2011 or to meet requirements in 40 CFR 51.308(g) and (h) because CAIR was implemented during the time period evaluated by South Carolina for its Progress Report. See generally 77 FR 73369, 73371 (December 10, 2012) (proposed action on the Florida regional haze plan).

EPA's December 3, 2014, interim final rule sunset CAIR compliance requirements on a schedule coordinated with the implementation of CSAPR compliance requirements. Because CSAPR should result in greater emissions reductions of SO2 and NOX than CAIR throughout the affected region, including in South Carolina and neighboring states, EPA expects South Carolina to maintain and continue its progress towards its RPGs for 2018 through continued, and additional, SO2 and NOX reductions. See generally August 8, 2011 (76 FR 48208) (promulgating CSAPR). Although the implementation of CSAPR was tolled for three years, the Rule is now being implemented, and by 2018, the endpoint for calculating RPGs for the first regional haze implementation period, CSAPR will reduce emissions of SO2 and NOX from EGUs in South Carolina by the same amount assumed by EPA when it issued the CSAPR FIP for South Carolina in June 2012. See 76 FR 48208 (CSAPR promulgation), and 77 FR 33642 (limited disapproval of South Carolina regional haze plan and FIP for South Carolina for certain regional haze requirements).

At the present time, the requirements of CSAPR apply to sources in South Carolina under the terms of a FIP. If EPA approves South Carolina's May 26, 2017, SIP revision that incorporates the CSAPR requirements into its SIP, the requirements of CSAPR for annual NOX and SO2 emissions will apply to sources in the State through its SIP at budget levels equal to those in the CSAPR FIP. The RHR requires an assessment of whether the current “implementation plan” is sufficient to enable the states to meet all established RPGs under 40 CFR 51.308(g). The term “implementation plan” is defined for purposes of the RHR to mean “any [SIP], [FIP], or Tribal Implementation Plan.” See 40 CFR 51.301. EPA is, therefore, proposing to determine that the Agency may consider measures in any issued FIP as well as those in a state's regional haze plan in assessing the adequacy of the “existing implementation plan” under 40 CFR 51.308(g)(6) and (h). Because CSAPR will ensure the control of SO2 and NOX emissions reductions relied upon by South Carolina and other states in setting their RPGs beginning in January 2015 at least through the remainder of the first implementation period in 2018, EPA is proposing to approve South Carolina's finding that there is no need for revision of the existing implementation plan for South Carolina to achieve the RPGs for Cape Romain and the Class I areas impacted by South Carolina sources.

EPA notes that the RHR provides for periodic evaluation and assessment of a state's reasonable progress towards achieving the national goal of natural visibility conditions under the CAA section 169A(b). The regional haze regulations at 40 CFR 51.308 required states to submit initial SIPs in 2007 providing for reasonable progress towards the national goal for the first implementation period from 2008 through 2018. See 40 CFR 51.308(b). Pursuant to 40 CFR 51.308(f), SIP revisions reassessing each state's reasonable progress towards the national visibility goal are due by July 31, 2021, July 31, 2028, and every ten years thereafter. For such subsequent regional haze plans, 40 CFR 51.308(f) requires each state to reassess its reasonable progress and all the elements of its regional haze plan required by 40 CFR 51.308(d), taking into account improvements in monitors and control technology, assessing the state's actual progress and effectiveness of its long term strategy, and revising RPGs as necessary. See 40 CFR 51.308(f)(1)-(3). Therefore, South Carolina has the opportunity to reassess its RPGs and the adequacy of its regional haze plan, including its reliance first upon CAIR and now upon CSAPR for emission reductions from EGUs, when it prepares and submits its second regional haze plan to cover the implementation period from 2018 through 2028. As discussed in the 2014 NPRM and in South Carolina's Progress Report, emissions of SO2 from EGUs are below original projections for 2018. In addition, the visibility data provided by South Carolina show that Cape Romain is currently on track to achieve its RPGs.

In summary, EPA proposes to approve South Carolina's Progress Report. EPA solicits comments on this supplemental proposal, but only with respect to the specific issues raised in this notice concerning the Agency's interpretation of the term “implementation plan” in the RHR, and EPA's proposed agreement with South Carolina's assessment that the current regional haze plan for South Carolina, in combination with EPA's CSAPR FIP or an approved CSAPR SIP, need not be revised at this time to achieve the established RPGs for South Carolina and other impacted states in light of the status of CAIR through 2014 and CSAPR starting in 2015. EPA is not reopening the comment period on any other aspect of the January 17, 2014, NPRM as an adequate opportunity to comment on those issues has already been provided. The purpose of this supplemental proposal is limited to review of South Carolina's Progress Report in light of the D.C. Circuit's 2015 ruling on CSAPR. This supplemental proposal reflects EPA's desire for public input into how it should proceed in light of this decision when acting on the State's pending Progress Report, in particular the requirements that the State assess whether the current implementation plan is sufficient to ensure that RPGs are met. See 40 CFR 51.308(g) and (h).9

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 Act. Accordingly, this proposed 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);

• 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 mandates 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 Act; and

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

In addition, this proposed rule for South Carolina does not have Tribal implications as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), because it does not have substantial direct effects on an Indian Tribe. The Catawba Indian Nation Reservation is located within the state of South Carolina. Pursuant to the Catawba Indian Claims Settlement Act, S.C. Code Ann. 27-16-120, “all state and local environmental laws and regulations apply to the [Catawba Indian Nation] and Reservation and are fully enforceable by all relevant state and local agencies and authorities.” EPA notes this action will not impose substantial direct costs on Tribal governments or preempt Tribal law.

On October 1, 2007, July 18, 2011, June 17, 2013, August 8, 2014, January 20, 2016, and July 27, 2016, SC DHEC submitted SIP revisions to EPA for approval that involve changes to South Carolina's minor source permitting regulations to clarify and streamline the State's federally-approved preconstruction and operating permitting program. This program requires minor stationary sources planning to construct or modify sources of air pollutants to first obtain a construction permit and to obtain and maintain operating permits in accordance with the South Carolina Code of Regulations Annotated (S.C. Code Ann. Regs.) at Regulation 61-62.1, Section II—“Permit Requirements.” The portion of the SIP-approved permitting program covering construction permits is generally referred to as the minor source permitting program or the minor NSR program to distinguish it from additional permitting requirements for major sources of air pollutants.1 The portion of the SIP-approved permitting program covering minor source operating permits is referred to as the federally enforceable state operating permit (FESOP) program. The changes made in these submittals clarify the applicability, streamline the permitting process, provide more options for the minor source permitting program, and generally reduce the overall burden on the state permitting program and the regulated community. The changes addressed in this proposed rulemaking also correct typographical errors, make internal references consistent, and recodify sections of the existing rules. In this action, EPA is proposing to approve certain portions of these SIP submissions that make changes to South Carolina's minor NSR regulations and FESOP requirements.

EPA is not acting on a portion of the revisions to Regulation 61-62.1, Section II—“Permit Requirements.” Specifically, EPA is not acting on the renumbering and minor administrative language changes to paragraph G.6.—“Emergency Provisions,” in the October 1, 2007, submittal, nor the minor additional language changes to this portion of the minor source permitting regulations included in the August 8, 2014, submittal.2

At this time, EPA is not acting on the following changes included in the October 1, 2007, submittal: Regulation 61-62.5, Standard No. 4—“Emissions from Process Industries”; and Regulation 61-62.5, Standard No. 5.2—“Control of Oxides of Nitrogen (NOX).”

EPA is also not acting on changes in the July 18, 2011, submittal to the following regulations in South Carolina's SIP: Regulation 61-62.1, Section I—“Definitions”; Regulation 61-62.3—“Air Pollution Episodes”; Regulation 61-62.5, Standard No. 1—“Emissions from Fuel Burning Operations”; Regulation 61-62.5, Standard No. 4—“Emissions from Process Industries”; Regulation 61-62.5, Standard No. 6—“Alternative Emission Limitation Options (Bubble)”; Regulation 61-62.5, Standard No. 7—“Prevention of Significant Deterioration”; and Regulation 61-62.5, Standard No. 7.1—“Nonattainment New Source Review.” EPA approved the changes to Regulation 61-62.5, Standard No. 2—“Ambient Air Quality Standards,” included in the July 18, 2011, submittal, on April 3, 2013 (78 FR 19994).

EPA is not acting on the changes included in the June 17, 2013, submittal to the following regulations: Regulation 61-62.1, Section I—“Definitions”; Regulation 61-62.1, Section IV—“Source Tests”; Regulation 61-62.3—“Air Pollution Episodes”; Regulation 61-62.5, Standard No. 4—“Emissions from Process Industries”; and Regulation 61-62.5, Standard No. 5—“Volatile Organic Compounds.”

Additionally, EPA is not acting on the changes included in the August 8, 2014, submittal to the following regulations: Regulation 61-62.1, Section I—“Definitions”; Regulation 61-62.1, Section IV—“Source Tests”; Regulation 61-62.1, Section V—“Credible Evidence”; Regulation 61-62.5, Standard No. 1—“Emissions from Fuel Burning Equipment”; and Regulation 61-62.5, Standard No. 4—“Emissions from Process Industries.” EPA approved the changes to Regulation 61-62.1, Section III—“Emissions Inventory and Emissions Statement,” included in the August 8, 2014, submittal, on June 12, 2015 (80 FR 33413) and May 31, 2017 (82 FR 24851).

EPA is also not acting on the changes included in the January 20, 2016, submittal to the following regulations: Regulation 61-62.5, Standard No. 5—“Volatile Organic Compounds”; Regulation 61-62.5, Standard No. 7.1—“Nonattainment New Source Review”; and Regulation 61-62.6—“Control of Fugitive Particulate Matter.”

Finally, EPA is not acting on the changes included in the July 27, 2016, submittal to the following regulations: Regulation 61-62.1, Section I—“Definitions”; Regulation 61-62.5, Standard No. 4—“Emissions from Process Industries”; and Regulation 61-62.5, Standard No. 5.2—“Control of Oxides of Nitrogen (NOX).” EPA will address these remaining changes to the South Carolina SIP in separate actions.

South Carolina has a SIP-approved minor source permitting program at Regulation 61-62.1, Section II—“Permit Requirements.” These regulations include requirements for obtaining preconstruction and operating permits for different types of minor sources. The program covers “true minor” sources, which have the potential to emit (PTE) of certain pollutants below major sources thresholds for new sources and modifications. The SIP-approved minor source permitting program also includes provisions for issuing permits that establish federally enforceable emission limits to restrict the PTE of certain pollutants below major source and major modification applicability thresholds: “synthetic minor” permits establish these limits for sources obtaining construction permits, and “conditional major” permits establish these emission limits in the corresponding operating permits. South Carolina initially revised its minor NSR and FESOP rules in the October 1, 2007, submittal to clarify and streamline requirements for obtaining minor source construction and operating permits. The July 18, 2011, June 17, 2013, August 8, 2014, January 20, 2016, and July 27, 2017, submittals make other clarifying and administrative changes, which are discussed for each subsection of the regulation below.

EPA has reviewed the proposed changes to the minor source construction and operating permitting regulations and preliminarily finds them to be consistent with CAA sections 110(a)(2)(C) and 110(l), EPA's minor NSR regulations found at 40 CFR 51.160—164, and the criteria applicable to an approvable State FESOP program.

Regulation 61-62.1, Section II.A—“Construction Permits” specifies applicability and certain requirements for obtaining permits for sources seeking to construct or modify emissions units. The October 1, 2007, submittal makes several changes to paragraph A. as follows: (1) Adds allowed preconstruction activities at subparagraph A.1.d. for true minor sources (i.e., minor sources that are not synthetic minor sources); (2) adds the requirement that written notification be provided to the Department marking the commencement of construction and initial startup; (3) adds language requiring compliance with all terms, limits, and conditions of Department-issued construction permits; (4) adds time constraints for the validity of issued construction permits; and (5) removes the descriptions of permit application requirements from former paragraph A.2. to create a standalone subsection C. for construction permits, and to detail more specific requirements for other types of permits in other paragraphs.

The July 18, 2011, submittal makes subsequent clarifying and administrative changes to Section II.A., consolidating former subparagraph A.1.a. and paragraph A.5. into an introductory paragraph applicable to the entirety of Regulation 61-62.1, Section II. The submittal also makes other renumbering and administrative edits to the remaining subparagraphs.

The language moved to an introductory paragraph for Section II states: (1) The regulation will not supersede any state or federal requirements nor special permit conditions unless it imposes a more restrictive limit; (2) sources must comply with all terms, conditions, and limitations of any permit issued by SC DHEC for sources or activities at its facility; and (3) a source's permit status may change if new regulatory requirements become applicable. The effect of moving this language from subsection A. is to clarify that it is applicable to all of Section II—meaning it applies to any types of permits issued by the SC DHEC rather than only construction permits.

The August 8, 2014, submittal further modifies Section II.A. by making administrative edits and adding additional allowed preconstruction activities for true minor sources at subparagraph A.1.c, originally added in the October 1, 2007, submittal as subparagraph A.1.d.

The revision to subparagraph A.1.c.—added to the Regulation as A.1.d. in the October 1, 2007, submittal, renumbered in the July 18, 2011, submittal, and updated in the August 8, 2014, submittal—allows certain preconstruction activities prior to obtaining a final construction permit, provided that specific conditions are met. EPA has preliminarily determined that the preconstruction activities provision is consistent with the requirements of CAA sections 110(a)(2)(C) and 110(l), and federal regulations at 40 CFR 51.160—51.164.

Section 110(a)(2)(C) of the CAA requires that state SIPs include a program for regulating the construction and modification of stationary sources as necessary to ensure that the NAAQS are maintained. Federal regulations at 40 CFR 51.160(b) require states to have legally enforceable procedures to prevent construction or modification of a source if it would violate any SIP control strategies or interfere with attainment or maintenance of the NAAQS. Federal regulations limit the types of allowed preconstruction activities for new and modified major sources at 40 CFR 51.165(a)(1)(xv), 51.166(b)(11), and 52.21(b)(11) and, as discussed below, South Carolina has adopted these provisions into its SIP. But federal regulations do not impose a corresponding limitation on preconstruction activities for minor sources. SC DHEC provided additional clarification of its allowed minor source preconstruction activities in a December 30, 2016, letter, which is included in the Docket for this proposed action. In this letter, SC DHEC first explains that “[a]llowed preconstruction activities are extremely limited in nature and do not include construction of that actual process unit itself.” The State also points to a requirement under Section II.C.3.n. that sources applying for construction permits demonstrate emissions will not interfere with attainment or maintenance of the NAAQS. This requirement corresponds to Section II.A.2. of the Regulation, which states that permits will not be issued if emissions interfere with any state or federal standard.

SC DHEC also points to its memorandum regarding allowed preconstruction activities for major sources prior to obtaining PSD permits.3 SC DHEC notes that its minor source preconstruction activities provisions mirror the federal limits on major source preconstruction activities, with the exception of one additional activity: Allowing a facility to pour concrete foundation prior to obtaining a construction permit. This activity is only prohibited for major sources or major modifications prior to obtaining a permit in accordance with the definition of “begin actual construction” in the federal PSD regulations at 40 CFR 51.166(b)(11) and 52.21(b)(11), and the NNSR regulations at 51.165(a)(1)(xv). As SC DHEC explains in its clarifying letter, Section II.A.1.c.—which specifies which sources may engage in preconstruction activities—explicitly excludes “sources not requesting to use federally enforceable construction permit conditions to limit potential to emit, sources not subject to regulations with more stringent start of construction limitations, or sources not otherwise exempt from permit requirements.” In other words, the regulation excludes, among other sources, major sources subject to PSD regulations or CAA section 112 requirements for hazardous air pollutants (i.e., major sources and modifications).

In its December 30, 2016 letter, SC DHEC references Section II.A.1.d., which clearly states that the owners or operators of any sources that would not qualify for the issuance of a construction permit assume the financial risk of commencing the preconstruction activities listed in Section II.A.1.c. SC DHEC also notes that a source could be subject to an enforcement action under Section II.F.2. and Section II.J.1.e.—or subject to permit revocation under Section II.J.1.b—if the source either did not comply with the regulations during construction or would not have qualified for the preconstruction activities undertaken.

Because SC DHEC does not allow for the construction of process units, there are no increased emissions associated with any of the preconstruction activities allowed at Section II.A.1.c.i.-xvii. The gatekeeping applicability language at Section II.A.1.c. and major NSR applicability provisions at Regulation 61-62.5, Standard No. 7(a)(2) and Standard No. 7.1(a)(1), provide that no major sources or modifications may engage in the preconstruction activities allowed under Section II.A.1.c.i.-xvii. Additionally, SC DHEC does not allow synthetic minor sources to conduct the preconstruction activities. Finally, SC DHEC has legally enforceable procedures to prevent construction or modification of a source if it would violate SIP control strategies or interfere with attainment or maintenance of the NAAQS, as required by 40 CFR 51.160(b).

The changes to South Carolina's minor NSR program are not inconsistent with the requirements of the CAA and EPA's regulations, and are therefore approvable as part of the SIP. EPA is therefore proposing to approve the aforementioned changes to subsection A. and the introductory portion of Section II pursuant to the CAA and 40 CFR 51.160-164.

Regulation 61-62.1, Section II.B.—“Exemptions from the Requirement to Obtain a Construction Permit” specifies which types of minor sources are exempt from obtaining minor source construction permits. The October 1, 2007, submittal makes several changes to subsection II.B. as follows: (1) Renumbers existing Section II.F. to Section II.B. and modifies the title to clarify that the paragraph applies only to construction permits; (2) adds language specifying that future source modifications or new regulatory requirements may trigger the need to obtain a permit for exempted facilities; (3) clarifies that the exemption for boilers and space heaters applies to those firing virgin solid and liquid fuels; (4) adds an exemption for boilers and space heaters firing only virgin gas fuels rated 10 million British thermal units per hour or less; (5) modifies the number of hours for testing and maintenance for exempted emergency generators; (6) modifies subparagraph B.2.h. to exempt additional sources with emissions less than the threshold of 1 pound per hour (lb/hr) PTE of sulfur dioxide, nitrogen oxides, and carbon monoxide; (7) adds the requirement for SC DHEC to periodically publish a list of sources exempted from the construction permit requirement under subparagraphs B.2.a.-g.—and any other sources determined to qualify for permit exemptions based on subparagraph B.2.h.—in the South Carolina State Register; (8) adds procedures for sources requesting exemption from obtaining a construction permit under paragraph B.2. or paragraph B.4.; (9) adds paragraph B.6. to provide that exemptions under Section II.B. do not relieve the owner or operator of any source from any obligation to comply with any other applicable requirements; and (10) makes other administrative changes and adds references throughout subsection B.

The July 18, 2011, submittal makes subsequent revisions to clarify requirements and qualifications at Section II.B., as follows: (1) Adds language to subparagraph B.2.h. to require that emissions calculations or other information necessary to demonstrate a source qualifies for the exemption must be kept on site and provided to SC DHEC upon request; (2) revises language in paragraph B.3. to clarify that source types which are added to the list of exempted sources will be determined not to interfere with attainment or maintenance of any state or federal standard; (3) adds language stating that SC DHEC reserves the right to require a construction permit on a case-by-case basis, and that case-by-case determinations will consider, but not be limited to, “the nature and amount of the pollutants, location, proximity to residences and commercial establishments, etc.”; and (4) makes administrative edits to existing language.

Finally, the August 8, 2014, submittal makes additional changes to paragraph II.B., including: (1) Administrative edits to the title of the paragraph and to references and subparagraphs throughout; (2) revises the PTE criteria in subparagraph B.2.h. to a 5 ton per year (tpy) threshold rather than 1 lb/hr, and adds language to state that sources with higher PTE may be exempted under this subparagraph if they demonstrate that they are not subject to any applicable state or federal limits or requirements; (3) amends paragraph B.3. to include language asserting that SC DHEC may develop emission thresholds for exemption that are determined will not interfere with attainment or maintenance of state or federal standards to include in the list maintained pursuant to this paragraph, and that SC DHEC could be petitioned to consider adding additional sources to this list; and (4) adds paragraph B.5. stating that sources of volatile organic compounds (VOCs) with a PTE greater than the emission threshold listed in subparagraph B.2.h. may be exempted from the requirement to obtain a construction permit on a case-by-case basis, and that exempt sources may later be required to be included in construction or operating permits.

Section 110(a)(2)(C) of the CAA requires that SIPs include a program for regulating the construction and modification of stationary sources as necessary to ensure that the NAAQS are maintained. Federal regulations at 40 CFR 51.160(e) require that states identify the types and sizes of sources subject to review and the basis for determining which sources are subject. Additionally, CAA section 110(l) provides that EPA shall not approve a revision to 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 CAA. SC DHEC has determined that specific sources listed at paragraphs B.1. and B.2. do not require permits because their size is not such that they are expected to interfere with attainment or maintenance of state or federal standards, including reasonable further progress.

SC DHEC's December 30, 2016, letter provides additional clarification for certain changes made to Section II.B. Subparagraph B.2.f. extends the testing and maintenance operation threshold for exempting emergency generators from 250 hours to 500 hours per year. SC DHEC considered CAA section 110(l), and asserts that the state expects no increase in actual emissions as a result of raising this exemption threshold. SC DHEC explains that the 500 hours per year threshold is commonly used to determine the PTE for title V and other major source applicability determinations, consistent with an EPA guidance memorandum.4 These sources are still restricted to emergency conditions, meaning that other types of non-emergency activities—such as peak shaving—would not qualify for the exemption under paragraph II.B. Additionally, SC DHEC points to applicable federal requirements for emergency generators at 40 CFR part 63 at subpart ZZZZ and 40 CFR part 60 at subparts IIII and JJJJ to restrict non-emergency use of these sources to 100 hours per year. Therefore, this change to subparagraph B.2.f. will not result in any real increase in emissions and therefore will not affect the state's ability to attain or maintain state or federal standards or reasonable further progress. The State also has the discretion to define the scope of its minor NSR program pursuant to 40 CFR 51.160(e).

SC DHEC in its letter also addresses changes made to subparagraph II.B.h. potentially allowing certain sources with PTE exceeding the thresholds of this subparagraph to be exempt from the requirement to obtain a construction permit. SC DHEC asserts that this provision is primarily intended to apply to sources with PTE only slightly above the thresholds in subparagraph II.B.h. SC DHEC notes the safeguards built into the language that sources subject to any applicable requirements are not exempt from obtaining construction permits. The letter then steps through an example of the process that small sources of VOC emissions would undergo, including an assessment of any potentially applicable requirements related to NAAQS, toxics, or hazardous air pollutants; consideration of the PTE relative to major source thresholds; and any other special considerations. SC DHEC determines the applicability of construction permits for these sources under close scrutiny on a case-by-case basis. This process in determining which types and sizes of sources need to undergo preconstruction review and permitting, afforded the State pursuant 40 CFR 51.160(e), is sufficient to protect the NAAQS and prevent interference with reasonable further progress, consistent with CAA sections 110(a)(2)(C) and 110(l).

SC DHEC's change to paragraph II.B.3. notes that SC DHEC may develop emission thresholds for exemptions that are not determined not to interfere with attainment or maintenance or any state or federal standard. EPA understands this language to reflect SC DHEC's flexibility for determining which types and sizes of sources need to undergo preconstruction review and permitting pursuant 40 CFR 51.160(e), and understands that these thresholds would need to be in the SIP, similar to Subparagraph II.B.h. The compiled list is available on SC DHEC's Web site.5 EPA preliminarily agrees that SC DHEC clearly lays out the types and sizes of sources of interest for preconstruction review, and also the reasonable process by which case-by-case determinations are made to exempt sources with emissions above the thresholds in subparagraph B.2.h., but less than any thresholds for other applicable requirements like major NSR. EPA also preliminarily agrees that this portion of South Carolina's minor NSR program does not interfere with attainment or maintenance of the NAAQS, reasonable further progress, or other applicable CAA requirements. Therefore, we are proposing to approve changes to the SIP made to Section II.B. pursuant to CAA sections 110(a)(2)(C) and 110(l), as well as 40 CFR 51.160-164.

Regulation 61-62.1, Section II.C—“Construction Permit Applications,” specifies the requirements for sources applying for and obtaining construction permits. The October 1, 2007, submittal makes several changes to subsection C. as follows: (1) Renumbers former paragraph A.2. to standalone subsection C and changes the title to specify that the requirements apply to construction permit applications; (2) makes administrative edits, including renumbering; (3) adds paragraph C.3. to reference SC DHEC forms which were created to ease the permit application process; and (4) renumbers former subparagraphs B.2.a.-g. to C.3.a.-p., reformatting and clarifying what information may be required in addition to the SC DHEC forms, including more specific process, chemical, and emissions information used to determine PTE, an air quality analysis demonstrating protection of the NAAQS, and a regulatory applicability determination.

The July 18, 2011, submittal further modifies Section II.C. at subparagraphs C.3.c.-d. to make administrative edits. South Carolina's August 8, 2014, submittal makes additional administrative and clarifying edits. The January 20, 2016, submittal also makes minor administrative edits. Finally, the July 27, 2016, submittal makes one change to subparagraph C.2.m. to clarify that scale drawings of the facility must include buildings that might affect dispersion of emissions.

EPA has reviewed the changes made to the construction permit application requirements and is proposing to approve them into the SIP, pursuant to CAA sections 110(a)(2)(C) and 110(l).

Regulation 61-62.1, Section II.D.—“General Construction Permits” provides regulations by which SC DHEC can issue general construction permits for similar sources. South Carolina's October 1, 2007, submittal adds these provisions to the minor NSR program for construction permits to facilitate the permitting process for similar sources qualifying for and applying for coverage under permits with general terms and conditions. The purpose of this general permitting minor NSR program is to protect the NAAQS while simplifying the permitting process for similar sources. The general construction permits paragraph provides for the following: (1) General permits will incorporate all applicable requirements for construction of similar sources and identify the criteria by which sources can qualify for the permit; (2) sources can submit construction permit applications to SC DHEC that include requests for coverage under the general permit, and sources later determined not to qualify for the general permit are subject to enforcement; (3) approval to operate under a permit is a final permit action for the purposes of judicial review; (4) the permit application can deviate from the provisions of Section II.C. if enough information is included to determine the source's qualification for the general permit; and (5) sources qualifying for general permits are able to apply for individual construction permits in lieu of coverage under the general permit.

The August 8, 2014, submittal makes administrative and clarifying edits to subsection II.D. throughout. EPA has reviewed the changes made to the minor NSR permitting program and is proposing to approve them into the SIP, pursuant to CAA sections 110(a)(2)(C) and 110(l).

Regulation 61-62.1, Section II.E.—“Synthetic Minor Construction Permits” specifies requirements for obtaining construction permits with federally enforceable emissions limits to restrict PTE for sources. South Carolina's October 1, 2007, submittal revises the paragraph for synthetic minor sources as follows: (1) Renumbers subsection II.H. to subsection II.E.; (2) makes administrative and clarifying amendments to the title and throughout the paragraph to clearly indicate that this paragraph pertains to construction permits and to update references; (3) removes former subparagraphs II.2.c.-f. as these requirements are now redundant and covered by other portions of subsection E. or Section II; (4) adds paragraph E.3. to list required synthetic minor permit conditions; (5) adds administrative language to make applications for general synthetic minor construction permits consistent with other construction permit applications; and (6) adds paragraph E.5. to list additional requirements for synthetic minor construction permit applications relative to other minor construction permit applications.

The August 8, 2014, submittal makes changes to subsection II.E. to update administrative language and references throughout the paragraph. The July 27, 2016, submittal also makes administrative edits to subparagraph E.2.b. EPA has reviewed the changes made to the requirements covering synthetic minor construction permits and is proposing to approve them into the SIP, pursuant to CAA sections 110(a)(2)(C) and 110(l), and 40 CFR 51.160-164.

Regulation 61-62.1, Section II.F.—“Operating Permits” specifies requirements for obtaining minor source operating permits. South Carolina's October 1, 2007, submittal makes several changes to subsection II.F. to clarify and add requirements, including: (1) Renumbering subsection II.B. to II.F.; (2) adding paragraph F.1. to require sources to record the actual date of initial startup and submit it to SC DHEC; (3) adding paragraph F.2. to require certification that construction was completed in accordance with the specifications of the construction permit, to require any variances from the construction permit to be addressed, and to assert that construction variances which would trigger new requirements will be considered construction without a permit; (4) adding language to clarify that title V sources may comply with the Section II.F operating permit requirements by submitting a permit modification request under 61-62.70.7(e) ; (5) adding language to clarify that the existing requirement to provide a written request to SC DHEC for a new or revised operating permit applies to minor sources and those major sources not yet covered by a title V permit; (6) adding subparagraph F.3.c. to specify that the written request for a new or revised operating permit must include a list of sources put into operation and the actual initial startup dates for those sources; (7) making other administrative edits throughout the paragraph; and (8) moving paragraph B.2. regarding permit renewals to a standalone subsection II.H.

The August 8, 2014 and July 27, 2016, submittals make administrative changes to Section II.F.—“Operating Permits.” EPA has reviewed the changes made to the existing SIP requirements for applying for an operating permit and is proposing to approve them into the SIP, pursuant to CAA sections 110(a)(2)(C) and 110(l).

Regulation 61-62.1, Section II.G.—“Conditional Major Operating Permits” specifies requirements for obtaining operating permits with federally enforceable emissions limits to restrict PTE for sources. South Carolina's October 1, 2007, submittal makes several changes to subsection II.G. to clarify applicability and requirements as follows: (1) Adds language to specify that paragraph II.G. applies to sources requesting federally enforceable limits to restrict PTE below major source thresholds; (2) adds language to specify that sources which received synthetic minor construction permits and that are not subject to title V will receive conditional major operating permits; (3) adds permit shield language to note that if the renewal request is submitted pursuant to paragraph II.H., conditional major sources can operate under the most recent conditional major permit until SC DHEC processes the renewal request; (4) adds language to note that the written request provided by new sources needs to include any additional information specified in subparagraph G.5.; (5) adds language and clarifies existing language to note that the permit conditions, including special conditions to verify compliance with operational and emissions limits, are located at subsection II.J.; (6) modifies existing language to specify additional requirements for conditional major operating permit applications only; (7) removes requirements pertaining to construction permit application requirements because subsections II.C. and II.E. otherwise cover these requirements; (8) removes requirements pertaining to standard operating permit applications because those are otherwise covered by subsection II.F.; (9) adds language to specify that the general information requirements in construction permit applications at paragraph C.3. also apply to conditional major operating permits; and (10) makes other administrative language changes throughout the paragraph.

The July 18, 2011, August 8, 2014, and July 27, 2016, submittals make additional administrative changes to subsection II.G. EPA has reviewed the changes made to SC DHEC's conditional major source program, which is a portion of the FESOP minor source program, and agrees that the revisions made to subsection II.G. clarify the requirements for obtaining conditional major operating permits. Further, EPA has determined that the conditional operating permit program remains consistent with the criteria for approving FESOP programs.6 Therefore, EPA is proposing to approve these changes into the SIP pursuant to CAA sections 110(a)(2)(C) and 110(l).

Regulation 61-62.1, Section II.H.—“Operating Permit Renewal Request” specifies requirements for renewing operating permits for minor sources. South Carolina's October 1, 2007, submittal makes several changes to subsection II.H. to clarify applicability and requirements as follows: (1) Renumbers former paragraph B.2. to make a standalone subsection at II.H.; (2) adds paragraph H.1. to clarify that operating permits must be renewed through a written request; (3) adds paragraph H.2. to clarify that subsection II.H does not apply to title V sources; (4) adds language to specify that sources must submit permit renewal requests no later than 90 days prior to expiration of the existing operating permit; (5) revises language to expand the type of information needed to verify special permit conditions; (6) adds language to require more specific information in the renewal request, including changes in the source information required for construction permits under paragraph C.3.; and (7) makes administrative language changes throughout the paragraph.

The July 18, 2011, June 17, 2013, August 8, 2014, and July 27, 2016, submittals make several administrative edits and correct typographical errors throughout subsection II.H. EPA has reviewed the changes made to the operating permit renewal requirements and believes these changes are more specific and help to ensure SC DHEC has the best information possible when evaluating renewal requests. EPA has also preliminarily determined that the changes will not interfere with attainment or maintenance of the NAAQS, reasonable further progress, or other applicable CAA requirements. EPA is therefore proposing to approve these changes into the SIP, pursuant to CAA sections 110(a)(2)(C) and 110(l).

Regulation 61-62.1, Section II.I.—“Registration Permits” provides regulations by which SC DHEC can issue registration permits, covering the construction and operation of similar sources. South Carolina's October 1, 2007, submittal adds these provisions to the minor source construction and operating permitting program to facilitate the permitting process for similar true minor sources qualifying for and applying for coverage permits for specific source categories. The purpose of this registration permitting minor source program is to protect the NAAQS while simplifying the permitting process for similar true minor sources. The difference between registration permits and general construction permits or general operating permits is that this program develops permits for specific source categories exclusively for true minor sources.

The October 1, 2007, submittal provides the following requirements for registration permits under paragraph II.I: (1) Registration permits will be developed by SC DHEC and will specify all applicable requirements for construction and operation of similar true minor sources; (2) registration permits will be developed only for true minor sources; (3) sources can submit applications for coverage by certifying qualification for, and agreeing to the conditions of, registration permits, and sources later determined not to qualify for the registration permit are subject to enforcement; (4) approval to operate under a permit is a final permit action for the purposes of judicial review; and (5) sources will adhere to general requirements under paragraph II.J.1., and any other special permit conditions necessary to verify compliance with operational and emission limits.

The July 18, 2011, submittal makes subsequent changes to subsection II.I. as follows: (1) Makes administrative edits; (2) adds language to assert that regardless of qualification for registration permits, SC DHEC reserves the right to require construction and operating permits, as determined on a case-by-case basis; and (3) changes language to clarify that registration permits shall contain any applicable permit conditions under subsection II.J., rather than all permit conditions listed in paragraph II.J., as SC DHEC finds appropriate.

The August 8, 2014, submittal includes other changes to paragraph II.I., including administrative edits throughout and adding language to assert that SC DHEC can reopen registration permits for cause or to include new standards or regulations that become applicable during the lifetime of the permit. The August 8, 2014, submittal also removes language at subparagraph I.1.a. requiring SC DHEC to provide notice and opportunity for public participation prior to developing new registration permits. However, the State withdrew this change from EPA's consideration in a letter dated August 7, 2017.7 In the letter, SC DHEC explained that its intent in withdrawing the change was to require the Department to comply with the public participation procedures at subsection II.N. when developing registration permits.

EPA has reviewed the changes made to the registration permit requirements, as clarified by the State's August 7, 2017, letter, and is proposing to approve them into the SIP, pursuant to CAA sections 110(a)(2)(C) and 110(l), and 40 CFR part 51, subpart I.

Regulation 61-62.1, Section II.J.—“Permit Conditions” specifies required standard and special permit conditions. The October 1, 2007, submittal combines the standard and special permit conditions into a standalone section for required permit conditions. This submittal makes the following changes at paragraph J.: (1) Renumbers former subsection II.C. to II.J. and modifies the title to reflect that the subsection applies to all permit types; (2) requires sources to submit reports as specified in applicable permits, laws, regulations, or standards; (3) adds language to assert that a source may be subject to enforcement if it fails to construct in accordance with the application and any issued construction permit, or constructs without applying for approval; (4) adds language to clarify the time period over which construction permits are valid; (5) renumbers paragraph G.4. to paragraph J.2. and modifies the title to clarify that what follows are special permit conditions; (6) adds language stating that SC DHEC will require special permit conditions as it finds appropriate, such as operational limits or reporting and recordkeeping requirements; (7) removes former subparagraph G.4.g., which states conditions to limit PTE must be federally enforceable, because the State otherwise imposes this requirement for synthetic minor construction permits at subparagraph E.3. and conditional major operating permits at subparagraph G.5.; and (8) makes administrative language changes throughout subsection II.J.

One change made to subparagraph J.1.d., formerly C.4., in the October 1, 2007, submittal regards when emissions reports need to be made. In the place of a specific quarterly timeframe, the change directs sources to comply with reporting requirements derived from applicable permit requirements, laws and regulations, or standards. There are no specific reporting requirements for minor sources specified in federal regulations at 40 CFR 51.160-164, so these reporting schedules can be developed as SC DHEC deems necessary.8 Moreover, subparagraph J.1.a. states that “[n]o applicable law, regulation or standard will be contravened.” Thus, if there is a prescriptive state or federal requirement for reporting of emissions that applies to any of these minor sources, the permits will set the necessary reporting schedule accordingly. Therefore, EPA has determined that this change does not interfere with attainment or maintenance of the NAAQS, reasonable further progress, or any other applicable CAA requirements.

The July 18, 2011, submittal makes further revisions to subsection II.J., including: (1) Adding language stating that false information or misrepresentation in a permit application is grounds for permit revocation; (2) adding language stating that the issued construction or operating permit must be kept at the facility and that records must be kept as prescribed on site for at least five years; and (3) making administrative and clarifying edits. The August 8, 2014, submittal makes additional administrative changes.

EPA has reviewed the changes to standard and special permit requirements for the minor source construction and operating permit program and is proposing to approve them into the SIP pursuant to CAA section 110(a)(2)(C) and 110(l).

Regulation 61-62.1, Section II.K.—“Exceptions” sets forth factors that SC DHEC shall consider in determining whether to impose alternative emissions limits, compliance schedules, or other restrictions. The October 1, 2007, submittal makes non-substantive changes to this subsection, including renumbering this existing subsection from II.D. to II.K., and making administrative language changes. EPA is therefore proposing to approve the aforementioned changes into the SIP pursuant to CAA sections 110(a)(2)(C) and 110(l).

Regulation 61-62.1, Section II.M.—“Transfer of Ownership/Operation” specifies procedures for owners or operators of sources to undertake if the ownership or operation is transferred to another party. The October 1, 2007, submittal makes minor changes to this regulation to renumber existing subsection II.E. to subsection II.M. and to add more specific requirements for the written request to transfer ownership or operation of a source. The August 8, 2014, submittal makes only administrative changes to language in this subsection.

EPA has reviewed the changes to this existing portion of the minor source permitting regulations and is proposing to approve the aforementioned changes into the SIP pursuant to CAA section 110(a)(2)(C) and 110(l).

Regulation 61-62.1, Section II.N.—“Public Participation Procedures,” specifies the public participation requirements for sources applying for and obtaining federally enforceable minor source construction and operating permits. The October 1, 2007, submittal makes several changes to subsection N. as follows: (1) Renumbers existing paragraph G.5. to create a standalone paragraph for public participation and clarify that these procedures can apply to other types of permit requests rather than only conditional major source operating permits; (2) adds language providing SC DHEC with discretion to require notice of permitting activity, even when not otherwise required by the State's regulations; (3) adds language stating that SC DHEC can use means other than publishing in newspapers, the State Register, and mailing lists to notify the public of minor source permitting; and (5) makes administrative language edits for consistency.

The July 18, 2011, submittal makes one clarifying edit to reflect that an approved construction permit is required prior to the commencement of construction. The August 8, 2014, submittal makes administrative and clarifying edits to subsection II.N., including: (1) Adding language to subparagraph N.1. to identify the SC DHEC Web site as another method of notifying the public of permitting activity; (2) reformatting and revising paragraph N.2. to list the required elements of the public notice; (3) revising language to identify how SC DHEC will address and record comments, and broadening the SC DHEC procedures to note that the State will respond to all comments rather than only those received in writing or at the public hearing; (4) removing language requiring SC DEHC to respond to all comments in writing; and (5) making administrative edits.

The changes in the October 1, 2007, submittal to allow for other methods of public notice, and in the August 8, 2014, submittal to explicitly list the SC DHEC Web site as a possible method of public notice are consistent with the minor source permitting regulations at 40 CFR 51.161. EPA has existing policy asserting that the public notice requirement for minor source permitting activities at 40 CFR 51.161(b)(3) is media-neutral, meaning that the public notice requirement can be met as long as the State interprets the method to be “prominent advertising.” 9 SC DHEC can therefore make use of its Web site, mailing lists, and other methods in lieu of publication in a newspaper. The provisions at subsection II.N. pertain only to minor sources, and any major source public notice requirements are contained in the major source PSD, NNSR, and title V regulations.10

EPA has reviewed the public notice requirements and preliminarily finds that the changes currently before the Agency are not inconsistent with the CAA and EPA's implementing regulations, including the criteria for approving FESOP programs. See 54 FR 27274 (June 28, 1989). Therefore, EPA is proposing to approve the changes to the existing public notice requirements for the minor NSR and FESOP programs, pursuant to CAA section 110(a)(2)(C) and 40 CFR 51.160-164.

Regulation 61-62.1, Section II.O.—“Inspection and Entry,” specifies requirements to allow SC DHEC officials to enter and inspect facilities. South Carolina's July 18, 2011, submittal adds these provisions to the minor source construction and operating permitting program to allow for verification of adherence to permit conditions. The August 8, 2014, submittal makes one additional administrative change to the introductory language at subsection II.O. The ability for SC DHEC to enter and inspect facilities enables the State to oversee the minor source permitting program, including assisting in potential enforcement actions. EPA is therefore proposing to approve this subsection and its updated provisions into the SIP, pursuant to CAA section 110(a)(2)(C).

In this rule, EPA is proposing to include in a final EPA rule regulatory text that includes incorporation by reference. In accordance with the requirements of 1 CFR 51.5, EPA is proposing to incorporate by reference South Carolina Regulation 61-62.1, Section II—“Permit Requirements,” effective June 24, 2016,11 which revises the federally enforceable minor source construction and operating permit program. EPA has made, and will continue to make, these materials generally available through www.regulations.gov and/or 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 revisions to the South Carolina SIP submitted by SC DHEC to EPA on October 1, 2007, July 18, 2011, June 17, 2013, August 8, 2014, January 20, 2016, and July 27, 2016. Specifically, EPA is proposing to approve the changes to S.C. Code Ann. Regs. 61-62.1, Section II—“Permit Requirements,” as discussed above, pursuant to CAA section 110(a)(2)(C), section 110(l), and 40 CFR 51.160—164.

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

• 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).

Section 169A(b)(2)(A) of the Clean Air Act (CAA or Act) requires states to submit regional haze SIPs that contain such measures as may be necessary to make reasonable progress towards the natural visibility goal, including a requirement that certain categories of existing major stationary sources built between 1962 and 1977 procure, install, and operate BART as determined by the state. Under the RHR, states are directed to conduct BART determinations for such “BART-eligible” sources that may be anticipated to cause or contribute to any visibility impairment in a Class I area. Rather than requiring source-specific BART controls, states also have the flexibility to adopt an emissions trading program or other alternative program as long as the alternative provides greater reasonable progress towards improving visibility than BART. See 40 CFR 51.308(e)(2). EPA provided states with this flexibility in the RHR, adopted in 1999, and further refined the criteria for assessing whether an alternative program provides for greater reasonable progress in two subsequent rulemakings. See 64 FR 35714 (July 1, 1999); 70 FR 39104 (July 6, 2005); 71 FR 60612 (October 13, 2006).

EPA demonstrated that CAIR would achieve greater reasonable progress than BART in revisions to the regional haze program made in 2005.1 See 70 FR 39104. In those revisions, EPA amended its regulations to provide that states participating in the CAIR cap-and-trade programs pursuant to an EPA-approved CAIR SIP or states that remain subject to a CAIR Federal Implementation Plan (FIP) need not require affected BART-eligible electric generating units (EGUs) to install, operate, and maintain BART for emissions of SO2 and nitrogen oxides (NOX). As a result of EPA's determination that CAIR was “better-than-BART,” a number of states in the CAIR region, including Alabama, relied on the CAIR cap-and-trade programs as an alternative to BART for EGU emissions of SO2 and NOX in designing their regional haze SIPs. These states also relied on CAIR as an element of a long-term strategy (LTS) for achieving their reasonable progress goals (RPGs) for their regional haze programs. However, in 2008, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) remanded CAIR to EPA without vacatur to preserve the environmental benefits provided by CAIR. North Carolina v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008). On August 8, 2011 (76 FR 48208), acting on the D.C. Circuit's remand, EPA promulgated CSAPR to replace CAIR and issued FIPs to implement the rule in CSAPR-subject states.2 Implementation of CSAPR was scheduled to begin on January 1, 2012, when CSAPR would have superseded the CAIR program.

Due to the D.C. Circuit's 2008 ruling that CAIR was “fatally flawed” and its resulting status as a temporary measure following that ruling, EPA could not fully approve regional haze SIPs to the extent that they relied on CAIR to satisfy the BART requirement and the requirement for a LTS sufficient to achieve the state-adopted RPGs. On these grounds, EPA finalized a limited disapproval of Alabama's regional haze SIP on June 7, 2012, triggering the requirement for EPA to promulgate a FIP unless Alabama submitted and EPA approved a SIP revision that corrected the deficiency. See 77 FR 33642. EPA finalized a limited approval of Alabama's regional haze SIP on June 28, 2012, as meeting the remaining applicable regional haze requirements set forth in the CAA and the RHR. See 77 FR 38515.

In the June 7, 2012, limited disapproval action, EPA also amended the RHR to provide that participation by a state's EGUs in a CSAPR trading program for a given pollutant—either a CSAPR federal trading program implemented through a CSAPR FIP or an integrated CSAPR state trading program implemented through an approved CSAPR SIP revision—qualifies as a BART alternative for those EGUs for that pollutant.3 See 40 CFR 51.308(e)(4). Since EPA promulgated this amendment, numerous states covered by CSAPR have come to rely on the provision through either SIPs or FIPs.4

Numerous parties filed petitions for review of CSAPR in the D.C. Circuit, and on August 21, 2012, the court issued its ruling, vacating and remanding CSAPR to EPA and ordering continued implementation of CAIR. EME Homer City Generation, L.P. v. EPA, 696 F.3d 7, 38 (D.C. Cir. 2012). The D.C. Circuit's vacatur of CSAPR was reversed by the United States Supreme Court on April 29, 2014, and the case was remanded to the D.C. Circuit to resolve remaining issues in accordance with the high court's ruling. EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 (2014). On remand, the D.C. Circuit affirmed CSAPR in most respects, but invalidated without vacating some of the CSAPR budgets as to a number of states. EME Homer City Generation, L.P. v. EPA, 795 F.3d 118 (D.C. Cir. 2015). The remanded budgets include the Phase 2 SO2 emissions budgets for Alabama, Georgia, South Carolina, and Texas and the Phase 2 ozone-season NOX budgets for 11 states. This litigation ultimately delayed implementation of CSAPR for three years, from January 1, 2012, when CSAPR's cap-and-trade programs were originally scheduled to replace the CAIR cap-and-trade programs, to January 1, 2015. Thus, the rule's Phase 2 budgets that were originally promulgated to begin on January 1, 2014, began on January 1, 2017.

On November 10, 2016, EPA published a notice of proposed rulemaking (NPRM) explaining the Agency's belief that the potentially material changes to the scope of CSAPR coverage resulting from the D.C. Circuit's remand will be limited to the withdrawal of the FIP provisions providing SO2 and annual NOX budgets for Texas and ozone-season NOX budgets for Florida. This is due, in part, to EPA's approval of the portion of Alabama's October 26, 2015, SIP submittal adopting Phase 2 annual NOX and SO2 budgets equivalent to the federally-developed budgets and to commitments from Georgia and South Carolina to submit SIP revisions adopting Phase 2 annual NOX and SO2 budgets equal to or more stringent than the federally-developed budgets. See 81 FR 78954. Since publication of the NPRM, Georgia and South Carolina have submitted these SIP revisions to EPA.5 In the NPRM, EPA also proposed to determine that the limited changes to the scope of CSAPR coverage do not alter EPA's conclusion that CSAPR remains “better-than-BART;” that is, that participation in CSAPR remains available as an alternative to BART for EGUs covered by the trading program. At this time, EPA has not finalized this proposed determination.

Alabama's October 26, 2015, SIP submittal also seeks to correct the deficiencies identified in the June 7, 2012, limited disapproval of its regional haze SIP by replacing reliance on CAIR with reliance on CSAPR.6 Specifically, Alabama requests that EPA amend the State's regional haze SIP by replacing its reliance on CAIR with CSAPR to satisfy SO2 and NOX BART requirements and SO2 reasonable progress requirements for EGUs formerly subject to CAIR,7 and to support the RPGs for the Sipsey Wilderness Area in Alabama for the first planning period. EPA is proposing to take these actions in this action.

By statute, SIPs meeting the requirements of sections 110(a)(1) and (2) of the CAA are to be submitted by states within three years (or less, if the Administrator so prescribes) after promulgation of a new or revised NAAQS to provide for the implementation, maintenance, and enforcement of the new or revised NAAQS. EPA has historically referred to these SIP submissions made for the purpose of satisfying the requirements of sections 110(a)(1) and 110(a)(2) as “infrastructure SIP” submissions. Sections 110(a)(1) and (2) require states to address basic SIP elements such as for monitoring, basic program requirements, and legal authority that are designed to assure attainment and maintenance of the newly established or revised NAAQS. More specifically, section 110(a)(1) provides the procedural and timing requirements for infrastructure SIPs. Section 110(a)(2) lists specific elements that states must meet for the infrastructure SIP requirements related to a newly established or revised NAAQS. The contents of an infrastructure SIP submission may vary depending upon the data and analytical tools available to the state, as well as the provisions already contained in the state's implementation plan at the time in which the state develops and submits the submission for a new or revised NAAQS.

Section 110(a)(2)(D) has two components: 110(a)(2)(D)(i) and 110(a)(2)(D)(ii). Section 110(a)(2)(D)(i) includes four distinct components, commonly referred to as “prongs,” that must be addressed in infrastructure SIP submissions. The first two prongs, which are codified in section 110(a)(2)(D)(i)(I), are provisions that prohibit any source or other type of emissions activity in one state from contributing significantly to nonattainment of the NAAQS in another state (prong 1) and from interfering with maintenance of the NAAQS in another state (prong 2). The third and fourth prongs, which are codified in section 110(a)(2)(D)(i)(II), are provisions that prohibit emissions activity in one state from interfering with measures required to prevent significant deterioration of air quality in another state (prong 3) or from interfering with measures to protect visibility in another state (prong 4). Section 110(a)(2)(D)(ii) requires SIPs to include provisions ensuring compliance with sections 115 and 126 of the Act, relating to interstate and international pollution abatement.

Through this action, EPA is proposing to approve the prong 4 portion of Alabama's infrastructure SIP submissions for the 2010 1-hour NO2, 2010 1-hour SO2, and 2012 annual PM2.5 NAAQS, and to convert EPA's disapproval of the prong 4 portion of Alabama's infrastructure SIP submission for the 2008 8-hour Ozone NAAQS to an approval, as discussed in section IV of this notice.8 All other applicable infrastructure SIP requirements for these SIP submissions have been or will be addressed in separate rulemakings. A brief background regarding the NAAQS relevant to this proposal is provided below. For comprehensive information on these NAAQS, please refer to the Federal Register notices cited in the following subsections.

On June 2, 2010, EPA revised the 1-hour primary SO2 NAAQS to an hourly standard of 75 parts per billion (ppb) based on a 3-year average of the annual 99th percentile of 1-hour daily maximum concentrations. See 75 FR 35520 (June 22, 2010). States were required to submit infrastructure SIP submissions for the 2010 1-hour SO2 NAAQS to EPA no later than June 2, 2013. Alabama submitted an infrastructure SIP submission for the 2010 1-hour SO2 NAAQS on April 23, 2013. This proposed action only addresses the prong 4 element of that submission.9

On January 22, 2010, EPA promulgated a new 1-hour primary NAAQS for NO2 at a level of 100 ppb, based on a 3-year average of the 98th percentile of the yearly distribution of 1-hour daily maximum concentrations. See 75 FR 6474 (February 9, 2010). States were required to submit infrastructure SIP submissions for the 2010 1-hour NO2 NAAQS to EPA no later than January 22, 2013. Alabama submitted infrastructure SIP submissions for the 2010 1-hour NO2 NAAQS on April 23, 2013, and December 9, 2015. This proposed action only addresses the prong 4 element of those submissions.10

In the Final Rules section of this Federal Register, EPA is approving the State's SIP revision as a direct final rule without prior proposal because the Agency views this as a noncontroversial submittal and anticipates no adverse comments. A detailed rationale for the approval is set forth in the direct final rule. If no adverse comments are received in response to this rule, no further activity is contemplated. If EPA receives adverse comments, the direct final rule will be withdrawn and all public comments received will be addressed in a subsequent final rule based on this proposed rule. EPA will not institute a second comment period on this document. Any parties interested in commenting on this document should do so at this time.

For further information, please see the information provided in the direct final action, with the same title, that is located in the “Rules and Regulations” section of this Federal Register publication. Please note that if EPA receives adverse comment on an amendment, paragraph, or section of this rule and if that provision may be severed from the remainder of the rule, EPA may adopt as final those provisions of the rule that are not the subject of an adverse comment.

The contents of this preamble are listed in the following outline:

Entities potentially affected by this proposed rule are fuel producers and distributors involved in the supplying of gasoline to Shelby County, TN.

The above table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. The table lists the types of entities of which EPA is aware that potentially could be affected by this proposed rule. Other types of entities not listed on the table could also be affected. To determine whether your organization could be affected by this proposed rule, you should carefully examine the regulations in 40 CFR 80.27. If you have questions regarding the applicability of this action to a particular entity, call the person listed in the FOR FURTHER INFORMATION CONTACT section of this preamble.

The statutory authority for this action is granted to EPA by sections 211(h) and 301(a) of the CAA, as amended; 42 U.S.C. 7545(h) and 7601(a).

EPA will not hold a public hearing on this matter unless a request is received by the person identified in the FOR FURTHER INFORMATION CONTACT section of this preamble by September 1, 2017. If EPA receives such a request, we will publish information related to the timing and location of the hearing and a new deadline for public comment.

EPA is proposing to approve a request from Tennessee to change the summertime Federal RVP standard for Shelby County from 7.8 psi to 9.0 psi by amending EPA's regulations at 40 CFR 80.27(a)(2). In a separate rulemaking, noted below, EPA has already approved a CAA section 110(l) non-interference demonstration which concludes that relaxing the Federal RVP requirement from 7.8 psi to 9.0 psi for gasoline sold from June 1 to September 15 of each year in Shelby County would not interfere with the maintenance of the ozone national ambient air quality standards (NAAQS) and the maintenance of the other NAAQS, or with any other applicable CAA requirement. When Tennessee previously requested that Shelby County be redesignated to attainment for the 2008 ozone standard, Tennessee took a conservative approach for the maintenance plan demonstration by modeling 9.0 psi for the RVP requirements as opposed to 7.8 psi. Tennessee did not, at that time, request the relaxation of the Federal RVP requirements for Shelby County. More recently, Tennessee requested a relaxation of the Federal RVP requirements. This has necessitated a demonstration that relaxing the Federal RVP requirement from 7.8 psi to 9.0 psi for gasoline sold from June 1 to September 15 of each year in Shelby County would not interfere with maintenance of any NAAQS, including the 2008 and 2015 ozone NAAQS, or any other applicable CAA requirement, under CAA section 110(l). Therefore, by a subsequent rulemaking, EPA approved Tennessee's non-interference demonstration for its already approved maintenance plan for the 2008 ozone NAAQS.2

The preamble for this rulemaking is organized as follows: Section III.B. provides the history of the Federal gasoline volatility regulation. Section III.C. describes the policy regarding relaxation of gasoline volatility standards in ozone nonattainment areas that are redesignated as attainment areas. Section III.D. provides information specific to Tennessee's request for Shelby County.

On August 19, 1987 (52 FR 31274), EPA determined that gasoline nationwide was becoming increasingly volatile, causing an increase in evaporative emissions from gasoline-powered vehicles and equipment. Evaporative emissions from gasoline, referred to as volatile organic compounds (VOC), 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 and 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 CAA section 211(c), EPA promulgated regulations on March 22, 1989 (54 FR 11868) that set maximum limits for the RVP of gasoline sold during the regulatory control periods that were established on a state-by-state basis in that final rule. The regulatory control periods addressed the portion of the year when peak ozone concentrations were expected. These regulations constituted Phase I of a two-phase nationwide program, which was designed to reduce the volatility of gasoline during the high ozone season. 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).

The 1990 CAA Amendments established new CAA section 211(h) to address fuel volatility. CAA 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 an RVP level in excess of 9.0 psi during the high ozone season. CAA section 211(h) also 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 CAA section 211(h). The modified regulations prohibited the sale of gasoline with an RVP above 9.0 psi in all areas designated attainment for ozone, effective January 13, 1992. For areas designated as nonattainment, the regulations retained the original Phase II standards published on June 11, 1990 (55 FR 23658), which included the 7.8 psi ozone season limitation for certain areas. As stated in the preamble to the Phase II volatility controls and reiterated in the proposed change to the volatility standards published in 1991, EPA will rely on states to initiate changes to their respective volatility programs. EPA's policy for approving such changes is described below in Section III.C.

As stated in the preamble for EPA's amended Phase II volatility standards (56 FR 64706), any change in the gasoline volatility standard for a nonattainment area that was subsequently redesignated as an attainment area must be accomplished through a separate rulemaking that revises the applicable standard for that area. Thus, for former 1-hour ozone nonattainment areas where EPA mandated a Phase II volatility standard of 7.8 psi RVP in the December 12, 1991 rulemaking, the federal 7.8 psi gasoline RVP requirement remains in effect, even after such an area is redesignated to attainment, until a separate rulemaking is completed that relaxes the Federal gasoline RVP standard in that area from 7.8 psi to 9.0 psi.

As explained in the December 12, 1991 rulemaking, EPA believes that relaxation of an applicable gasoline 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, CAA section 107(d)(3) requires the state to make a showing, pursuant to CAA section 175A, that the area is capable of maintaining attainment for the ozone NAAQS for ten years. Depending on the area's circumstances, this maintenance plan will either demonstrate that the area is capable of maintaining 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 gasoline volatility standard unless the state requests a relaxation and the maintenance plan demonstrates that the area will maintain attainment for ten years without the need for the more stringent volatility standard. Similarly, a maintenance plan may be revised to relax the gasoline volatility standard if the state requests a relaxation and the maintenance plan demonstrates that the area will maintain attainment for the duration of the maintenance plan.

On April 12, 2017, Tennessee, through the Tennessee Department of Environment and Conservation (TDEC or State), submitted a request to relax the Federal gasoline RVP requirement in Shelby County. The State also submitted a CAA section 110(l) non-interference demonstration for approval by EPA. The non-interference demonstration shows that the relaxation would not interfere with maintenance of the 2008 ozone NAAQS or any other applicable CAA requirement including the 2015 ozone NAAQS. Tennessee did not request relaxation of the Federal RVP standard from 7.8 psi to 9.0 psi when TDEC originally submitted the CAA section 175A maintenance plan for the 2008 ozone NAAQS that was approved on June 23, 2016 (81 FR 40816).

On July 7, 2017, EPA approved Tennessee's April 12, 2017 request for approval of the CAA section 110(l) non-interference demonstration. In that rulemaking, EPA included an evaluation of Tennessee's CAA section 110(l) non-interference demonstration for Shelby County.3

In this action, EPA is proposing to approve Tennessee's request to relax the summertime ozone season gasoline RVP standard for Shelby County from 7.8 psi to 9.0 psi. Specifically, EPA is proposing to amend the applicable gasoline RVP standard to allow the gasoline RVP requirements at 40 CFR 80.27(a)(2) for Shelby County to change from 7.8 psi to 9.0 psi. This proposal is based on EPA's separate approval of Tennessee's April 12, 2017 request for a non-interference demonstration approval and EPA's June 23, 2016 approval of the redesignation request and maintenance plan for the 2008 ozone NAAQS as described above.

This action is not a “significant regulatory action” under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and therefore was not submitted to the Office of Management and Budget (OMB) for review.

This action is not expected to be an Executive Order 13771 regulatory action because this action is not significant under Executive Order 12866.

This action does not impose any new information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq., and therefore is not subject to these requirements.

I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule. The small entities subject to the requirements of this action are refiners, importers or blenders of gasoline that choose to produce or import low RVP gasoline for sale in Tennessee, and gasoline distributers and retail stations in Tennessee. This action, if finalized, would relax the Federal RVP standard for gasoline sold in Shelby County, Tennessee during the summertime ozone season (June 1 to September 15 of each year) to allow the RVP for gasoline sold in this county to rise from 7.8 psi to 9.0 psi. This rule does not impose any requirements or create impacts on small entities beyond those, if any, already required by or resulting from the CAA section 211(h) Volatility Control program. Therefore, this action would have no net regulatory burden for all directly regulated small entities.

This proposed rule does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. The action would implement mandates that are specifically and explicitly set forth in CAA section 211(h) without the exercise of any policy discretion by EPA.

This action does not have federalism implications. It would not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government.

This action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). This proposed rule would affect only those refiners, importers or blenders of gasoline that choose to produce or import low RVP gasoline for sale in Shelby County and gasoline distributers and retail stations in the Area. Thus, Executive Order 13175 does not apply to this action.

EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that EPA has reason to believe may disproportionately affect children, per the definition of “covered regulatory action” in section 2-202 of the Executive Order. EPA has no reason to believe that this action may disproportionately affect children since Tennessee has provided evidence that a relaxation of the gasoline RVP will not interfere with its attainment of the ozone NAAQS for Shelby County, or any other applicable CAA requirement. By separate action, EPA has approved Tennessee's non-interference demonstration regarding its maintenance plan for the 2008 ozone NAAQS, and that Tennessee's relaxation of the gasoline RVP standard in Shelby County to 9.0 RVP will not interfere with any other NAAQS or CAA requirement.

This action is not subject to Executive Order 13211 because it is not a significant regulatory action under Executive Order 12866.

This rulemaking does not involve technical standards.

EPA believes the human health or environmental risk addressed by this action would not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because it does not affect the applicable ozone NAAQS which establish the level of protection provided to human health or the environment. This rule would relax the applicable volatility standard of gasoline during the summer, possibly resulting in slightly higher mobile source emissions. However, Tennessee has demonstrated in its non-interference demonstration that this action will not interfere with maintenance of the ozone NAAQS in Shelby County for the 2008 ozone NAAQS, or with any other applicable requirement of the CAA. Therefore, disproportionately high and adverse human health or environmental effects on minority or low-income populations are not an anticipated result. The results of this evaluation are contained in EPA's proposed and final rules for Tennessee's non-interference demonstration. A copy of Tennessee's April 12, 2017 letter requesting that EPA relax the gasoline RVP standard, including the technical analysis demonstrating that the less stringent gasoline RVP would not interfere with continued maintenance of the 2008 ozone NAAQS in Shelby County, or with any other applicable CAA requirement, has been placed in the public docket for this action.

The statutory authority for this action is granted to EPA by sections 211(h) and 301(a) of the Clean Air Act, as amended; 42 U.S.C. 7545(h) and 7601(a).

For further information about the proposed update to TRI's covered NAICS codes, please see the information provided in the direct final action, with the same title, that is located in the “Rules and Regulations” section of this issue of the Federal Register. To comment on this proposed rule, and by extension the direct final rule, you must reference docket ID No. EPA-HQ-OPPT-2007-0197 in one of the manners described above in the ADDRESSES section.