In recent years, however, the FDIC typically has not determined that notices must be filed with the FDIC when the FRB accepts a passivity commitment in lieu of a notice. For the reasons described below, developments involving institutional investors and FDIC-supervised institutions have prompted the FDIC to reconsider its procedures regarding transactions exempt from notice requirements pursuant to subpart E, the facts and circumstances under which it will require a notice, and how to monitor compliance with passivity commitments entered into to rebut the presumption of control.

Passive investment vehicles such as index mutual funds and exchange-traded funds (ETFs) that aim to replicate the performance of a third-party index such as the S&P 500 Index (collectively, “index funds”) have grown in popularity in recent decades. Index funds do not hand-pick stocks like actively managed funds do in order to provide a return greater than the market; rather, index funds seek to match market returns by investing proportionally across stocks in the desired index or sector of the national economy. To the extent multiple index funds have the same company or related companies that sponsor, manage, or advise them, these companies are called “fund complexes.” By the end of December 2023, according to data released by Morningstar, passive funds exceeded active funds in total assets under management for the first time, with approximately $13.3 trillion in total assets to active funds' $13.2 trillion. 21 For comparison, when the first ETF was listed in 1993, passive funds represented less than 1 percent of total fund assets. 22 Index funds have grown in popularity due to lower management fees relative to active funds, the belief that index funds match or outperform active funds more frequently and consistently, and the growth of target-date funds in retirement plans. 23 Investments in index funds have pulled in more dollars on a net basis than active funds every year since 2013, and if fund flows continue to follow current trends, then they will further exceed total assets in active funds in the future. 24

The exponential growth of index funds necessarily implicates the statutory and regulatory schemes of the CBCA and other banking laws that are based on ownership thresholds and control of banking organizations. 25 As investments in index funds grow, asset management companies and other institutional investors engaging in similar strategies must continue to invest those funds in the universe of stocks that comprise the index, purchasing ever-greater shares of those companies and increasing their ownership stakes. The FDIC has observed that fund complexes have acquired 10 percent or more of the voting securities at FDIC-supervised institutions or their controlling affiliates and have continued to increase their ownership percentages at more institutions. Additionally, the FDIC in recent years has observed a general pattern of more frequent requests for relief to rebut the presumptions of control under subpart E.

These developments have prompted the FDIC to reconsider its policies under the CBCA and implementing regulations so that the FDIC may more appropriately assess the effects of any control exerted over the management and policies of FDIC-supervised institutions. The FDIC is concerned that fund complexes will continue to increase their ownership percentage of FDIC-supervised institutions to potentially significant amounts as investments in their respective index funds grow. Fund complexes owning such high percentages of voting securities of FDIC-supervised institutions may create situations where the investor can have an outsized influence over the management or policies of an institution. 26 Such outsized influence may flow naturally from exercise of their votes as large shareholders over matters such as mergers, or through other indicia of control, such as engagements with portfolio companies whereby investors meet with directors or management to influence the direction of the company. 27 Fund complexes may seek board representation or management interlocks depending on the nature of existing passivity commitments.

Additionally, there have been changes to proxy access  28 and discretionary broker voting  29 that have given fund complexes more potential for control over the companies in which they hold a large equity stake in voting securities. The potential for fund complexes to exercise significant influence or control over management, business strategies, or major policy decisions at publicly traded FDIC-supervised institutions could increase the risk profile at such institutions and lead to excessive risk-taking to enhance profits, investor returns, or stock price. Finally, as fund complexes continue to purchase more shares of banking organizations across the market to match the growth of investments in index funds, there is the potential to create a concentration of ownership that may result in such investors having excessive influence or control over the banking industry as a whole.

In light of these changes to the economic landscape and ownership of FDIC-supervised institutions, the FDIC reviewed its policies under the CBCA and implementing regulations and believes it is appropriate to amend its current regulations to allow it to review certain transactions under the CBCA to address the concerns and potential risks outlined above. The FDIC also recognizes the interest in and need for collaboration among the Federal banking agencies on these issues to ensure consistency in the review of transactions implicating the CBCA. Accordingly, the FDIC is committed to engaging in dialogue and coordination with the FRB and the Office of the Comptroller of the Currency to develop an interagency approach to the issues discussed in this proposal and seeks public comment regarding further interagency coordination in this area.

As noted above, the defined term “covered institution” excludes a holding company that is the subject of an exemption described in either § 303.84(a)(3) or (a)(8). 30 In accordance with the FDIC's proposal to remove the exemption at § 303.84(a)(8), as described below, the FDIC proposes to remove the reference to holding companies and associated exemptions in the definition of “covered institution.” Therefore, as shown in the proposed regulatory text, the definition of “covered institution” would eliminate the reference to holding companies subject to the regulatory exemptions in § 303.84(a)(3) or (a)(8).

As described below, the FDIC proposes to remove the exemption at § 303.84(a)(8). The FDIC is not proposing to remove the exemption at § 303.84(a)(3), which refers to transactions that are statutorily exempt from the CBCA's notice requirements. However, because the reference to § 303.84(a)(3) in the definition of “covered institution” refers to statutorily exempt transactions and not to holding companies themselves, the FDIC believes it is appropriate to remove this reference in the definition of covered institution as well. Some depository institution holding companies may be considered covered institutions.

Section 303.84(a) currently contains eight transactions that are exempt from providing prior notice to the FDIC. The FDIC proposes to remove the exemption at § 303.84(a)(8), acquisitions of depository institution holding company voting securities for which the Board of Governors of the Federal Reserve System reviews a notice pursuant to the CBCA.

The current regulatory exemption only applies when the FRB actually reviews a notice under the CBCA, as described above. 31 Under this proposal, investors that propose to acquire voting securities of a depository institution holding company in transactions for which the FRB reviews a notice would no longer automatically be exempt from providing the FDIC prior notice. A change in control at the holding company level conveys indirect control over the IDI for which the FDIC is the AFBA under the CBCA. The proposal to remove the exemption solely because a notice is being reviewed by the FRB would allow the FDIC to exercise its authority under the CBCA to require and approve or disapprove such a notice at the IDI level.

The FDIC has determined that the original purpose of the current exemption, which was to avoid duplicate regulatory review of the same transaction by both the FRB and the FDIC, 32 is no longer warranted in light of the widespread impacts resulting from growth in, and changes to the nature of, passive investment strategies. As described above, fund complexes' increasingly large ownership of voting securities of FDIC-supervised institutions or companies that control FDIC-supervised institutions, and the evolution of the economic landscape over the past few decades, present new risks. Accordingly, the FDIC has determined that this proposal is necessary in light of the risks created by possible outsized control over and concentration of ownership of FDIC-supervised institutions. The FDIC must have the ability to require a notice so that, as the AFBA for the underlying IDI, it may independently review and determine whether the proposed acquisition satisfies the statutory factors enumerated in the CBCA for the institutions it supervises. 33 While an acquisition may be disapproved if one or more statutory factors in the CBCA are not met, as the Federal agency that also administers the DIF, the FDIC has a particular interest in reviewing whether a proposed acquisition could result in an adverse effect on the DIF.

While this proposal would allow the FDIC to require a notice to the FDIC when the FRB reviews a notice to acquire voting securities of a depository institution holding company, the FDIC would consider the facts and circumstances when deciding whether to exercise this authority for notices filed with the FRB. The FDIC believes it is appropriate to review proposed acquisitions under the CBCA more closely in order to fully address risks regarding outsized influence and increased concentration of ownership, though the FDIC may not do so for every proposed acquisition. Rather, the FDIC's proposal would allow it to consider the full range of options provided for under the CBCA.

Under the FDIC's current regulations, when the FRB accepts a passivity commitment in lieu of a notice, the FDIC evaluates the facts and circumstances of the case to determine whether a notice is required to be filed with the FDIC for the indirect acquisition of control of an FDIC-supervised institution. Similarly, in cases where the FRB accepts a notice, the FDIC under the proposed rule will evaluate the facts and circumstances to determine whether to require a notice to be filed with the FDIC as well.

The proposed rule would mean that for transactions resulting in the acquiring person owning, controlling, or holding with power to vote 10 percent or more of any class of voting securities of a depository institution holding company with an FDIC-supervised subsidiary institution, the FDIC may exercise one of the following options: (1) based on the facts and circumstances, require prior written notice to the FDIC under the CBCA for the indirect acquisition of control of an FDIC-supervised institution; or (2) allow the acquiring person an opportunity to rebut the presumption of control in writing. 34

As previously discussed, the proposed rule would remove an existing regulatory exemption that only applies when the FRB reviews a notice under the CBCA. As of the quarter ending March 31, 2024, the FDIC supervised 2,920 insured depository institutions. 35 This proposed rule, if promulgated, would likely increase the number of change-in-control notices submitted by entities seeking to acquire voting securities of FDIC-supervised institutions or their parent companies, and associated costs. Over the first three months of 2024, the FRB received 13 filings from 11 unique entities to indirectly acquire voting securities of FDIC-supervised institutions by acquiring voting securities of the entity that controls an FDIC-supervised institution. 36 The FDIC expects to receive 52 notices annually as a result of the proposed rule and one request to rebut the presumption of control annually. 37 The FDIC estimates that each notice would require 30.5 labor hours at an hourly cost of $142.40  38 and that each request to rebut the presumption of control would require 15 labor hours at an hourly cost of $111.40. 39 Therefore, the FDIC estimates that the proposed rule could result in average annual recordkeeping, reporting, and disclosure compliance costs of up to $227,517.40. 40 However, the FDIC believes that this estimate likely is conservative because, as previously stated, the FDIC may not exercise this authority for every notice filed with the FRB.

If adopted, the FDIC believes that the proposed rule would facilitate appropriate review of transactions resulting in control of FDIC-supervised institutions and, thereby, would reduce the likelihood of outsized influence or control over FDIC-supervised institutions and any associated costs. As previously discussed, recent developments in equity markets in concert with the FDIC's current practice of exempting entities from a notification requirement when the FRB reviews a notice under the CBCA may be contributing to elevated risk of excessive or indirect control or concentration of ownership of FDIC-supervised institutions. The proposed rule would facilitate the FDIC's review of certain transactions, thereby increasing the likelihood that all the statutory factors in the CBCA are met, and reducing the likelihood that certain transactions would result in an adverse effect on the DIF. The FDIC does not have the information necessary to quantify such effect.

The primary alternative to this proposed rule that the FDIC considered was maintaining the existing regulatory structure in which an entity is exempt from submitting a notice to the FDIC when the FRB actually reviews a notice to acquire voting securities of a depository institution holding company. The FDIC believes that the proposed rule is more appropriate because recent developments in the equity markets, in concert with the FDIC's current policy of not requiring a notice, may be contributing to an elevated risk of excessive indirect control of FDIC-supervised institutions. The FDIC also considered the alternative of compelling an entity to file a notice with the FDIC in each case where the FRB actually reviews a notice to acquire voting securities of a depository institution holding company under the CBCA. However, the FDIC believes that the proposed rule is more appropriate because it would balance the costs associated with duplicate regulatory review of the same transaction with the elevated risks associated with excessive control or concentration of ownership of FDIC-supervised institutions.

The FDIC is seeking comment on all aspects of the proposed rule and existing regulatory framework that applies to the role played by asset managers and other institutional investors with FDIC-supervised institutions in the context of the CBCA and passivity agreements. While the FDIC continues to perform a comprehensive review of its overall regulatory and supervisory approach to issues that arise under the CBCA, this proposed rule asks a number of questions and seeks public comment regarding monitoring of change in control-related issues, the use of passivity commitments, and specific terms and conditions that may be appropriate to incorporate into such commitments or non-objections in the future. In responding to the following questions, the FDIC asks that commenters please include quantitative as well as qualitative support for their responses, as applicable. The FDIC will consider comments submitted anonymously.

Question 1. Should the FDIC require prior written notice at the bank level when a change of control occurs at the holding company level? Why or why not?

Question 2. If the FDIC should require prior written notice when a change of control occurs at the holding company level, what steps should the FDIC take to avoid duplication of regulatory reviews and reduce regulatory burden? What would be the negative impacts of inconsistent approaches across the Federal banking agencies?

Question 3. Should the FDIC and other AFBAs consider an approach whereby a notice would be required at either the bank level or holding company based on specific criteria, such as the percentage of assets of the insured depository institution in relation to the consolidated assets of the holding company?

Question 4. Does the existing and proposed regulatory and supervisory framework properly consider all aspects of the role played by investors with FDIC-supervised institutions in the context of the CBCA? If not, what areas should be addressed?

Question 5. What, if any, additional requirements or criteria should be included in the existing regulatory framework to address the concerns of passive investors exerting control, direct and indirect, over FDIC-supervised institutions?

As previously explained in the 2021 Clarifications Memo, EPA intends the second implementation period of the regional haze program to secure meaningful reductions in visibility impairing pollutants that build on the significant progress States have achieved to date. The Agency also recognizes that analyses regarding reasonable progress are State-specific and that, based on States' and sources' individual circumstances, what constitutes reasonable reductions in visibility impairing pollutants will vary from state-to-state. While there exist many opportunities for States to leverage both ongoing and upcoming emission reductions under other CAA programs, the Agency expects States to undertake rigorous reasonable progress analyses that identify further opportunities to advance the national visibility goal consistent with the statutory and regulatory requirements. See generally 2021 Clarifications Memo. This is consistent with Congress' determination that a visibility protection program is needed in addition to the CAA's National Ambient Air Quality Standards and Prevention of Significant Deterioration programs, as further emission reductions may be necessary to adequately protect visibility in Class I Areas throughout the country. 12

Because the air pollutants and pollution affecting visibility in Class I Areas can be transported over long distances, successful implementation of the regional haze program requires long-term, regional coordination among multiple jurisdictions and agencies that have responsibility for Class I Areas and the emissions that impact visibility in those areas. In order to address regional haze, States need to develop strategies in coordination with one another, considering the effect of emissions from one jurisdiction on the air quality in another. Five regional planning organizations (RPOs), 13 which include representation from State and Tribal governments, EPA, and FLMs, were developed in the lead-up to the first implementation period to address regional haze. RPOs evaluate technical information to better understand how emissions from State and Tribal land impact Class I Areas across the country, pursue the development of regional strategies to reduce emissions of particulate matter and other pollutants leading to regional haze, and help States meet the consultation requirements of the RHR.

The Mid-Atlantic/Northeast Visibility Union (MANE-VU), one of the five RPOs described above, is a collaborative effort of State governments, Tribal governments, and various Federal agencies established to initiate and coordinate activities associated with the management of regional haze, visibility, and other air quality issues in the Mid-Atlantic and Northeast corridor of the United States. Member States and Tribal governments (listed alphabetically) include: Connecticut, Delaware, the District of Columbia, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Penobscot Indian Nation, Rhode Island, St. Regis Mohawk Tribe, and Vermont. The Federal partner members of MANE-VU are EPA, U.S. National Parks Service (NPS), U.S. Fish and Wildlife Service (FWS), and U.S. Forest Service (USFS).

Under the CAA and EPA's regulations, all 50 States, the District of Columbia, and the U.S. Virgin Islands are required to submit regional haze SIPs satisfying the applicable requirements for the second implementation period of the regional haze program by July 31, 2021. Each State's SIP must contain a long-term strategy for making reasonable progress toward meeting the national goal of remedying any existing and preventing any future anthropogenic visibility impairment in Class I Areas. CAA 169A(b)(2)(B). To this end, 40 CFR 51.308(f) lays out the process by which States determine what constitutes their long-term strategies, with the order of the requirements in 40 CFR 51.308(f)(1) through (3) generally mirroring the order of the steps in the reasonable progress analysis  14 and paragraphs (f)(4) through (6) containing additional, related requirements. Broadly speaking, a State first must identify the Class I Areas within the State and determine the Class I Areas outside the State in which visibility may be affected by emissions from the State. These are the Class I Areas that must be addressed in the State's long-term strategy. See 40 CFR 51.308(f), (f)(2). For each Class I Area within its borders, a State must then calculate the baseline, current, and natural visibility conditions for that area, as well as the visibility improvement made to date and the URP. See 40 CFR 51.308(f)(1). Each State having a Class I Area and/or emissions that may affect visibility in a Class I Area must then develop a long-term strategy that includes the enforceable emission limitations, compliance schedules, and other measures that are necessary to make reasonable progress in such areas. A reasonable progress determination is based on applying the four factors in CAA section 169A(g)(1) to sources of visibility-impairing pollutants that the State has selected to assess for controls for the second implementation period. See 40 CFR 51.308(f)(2). A State evaluates potential emission reduction measures for those selected sources and determines which are necessary to make reasonable progress. Those measures are then incorporated into the State's long-term strategy. After a State has developed its long-term strategy, it then establishes RPGs for each Class I Area within its borders by modeling the visibility impacts of all reasonable progress controls at the end of the second implementation period, i.e., in 2028, as well as the impacts of other requirements of the CAA. The RPGs include reasonable progress controls not only for sources in the State in which the Class I Area is located, but also for sources in other States that contribute to visibility impairment in that area. The RPGs are then compared to the baseline visibility conditions and the URP to ensure that progress is being made towards the statutory goal of preventing any future and remedying any existing anthropogenic visibility impairment in Class I Areas. 40 CFR 51.308(f)(2) and (3).

In addition to satisfying the requirements at 40 CFR 51.308(f) related to reasonable progress, the regional haze SIP revisions for the second implementation period must address the requirements in 40 CFR 51.308(g)(1) through (5) pertaining to periodic reports describing progress towards the RPGs, 40 CFR 51.308(f)(5), as well as requirements for FLM consultation that apply to all visibility protection SIPs and SIP revisions. 40 CFR 51.308(i).

A State must submit its regional haze SIP and subsequent SIP revisions to EPA according to the requirements applicable to all SIP revisions under the CAA and EPA's regulations. See CAA 169A(b)(2); CAA 110(a). Upon EPA approval, a SIP is enforceable by the Agency and the public under the CAA. If EPA finds that a State fails to make a required SIP revision, or if EPA finds that a State's SIP is incomplete or disapproves the SIP, the Agency must promulgate a Federal implementation plan (FIP) that satisfies the applicable requirements. CAA 110(c)(1).

The first step in developing a regional haze SIP is for a State to determine which Class I Areas, in addition to those within its borders, “may be affected” by emissions from within the State. In the 1999 RHR, EPA determined that all States contribute to visibility impairment in at least one Class I Area, 64 FR 35714 at 35720-22 (July 1, 1999), and explained that the statute and regulations lay out an “extremely low triggering threshold” for determining “whether States should be required to engage in air quality planning and analysis as a prerequisite to determining the need for control of emissions from sources within their State.” Id. at 35721.

A State must determine which Class I Areas must be addressed by its SIP by evaluating the total emissions of visibility impairing pollutants from all sources within the State. While the RHR does not require this evaluation to be conducted in any particular manner, EPA's 2019 Guidance provides recommendations for how such an assessment might be accomplished, including by, where appropriate, using the determinations previously made for the first implementation period. 2019 Guidance at 8-9. In addition, the determination of which Class I Areas may be affected by a State's emissions is subject to the requirement in 40 CFR 51.308(f)(2)(iii) to “document the technical basis, including modeling, monitoring, cost, engineering, and emissions information, on which the State is relying to determine the emission reduction measures that are necessary to make reasonable progress in each mandatory Class I Federal Area it affects.”

As part of assessing whether a SIP submission for the second implementation period is providing for reasonable progress towards the national visibility goal, the RHR contains requirements in 40 CFR 51.308(f)(1) related to tracking visibility improvement over time. The requirements of this section apply only to States having Class I Areas within their borders; the required calculations must be made for each such Class I Area. EPA's 2018 Visibility Tracking Guidance  15 provides recommendations to assist States in satisfying their obligations under 40 CFR 51.308(f)(1); specifically, in developing information on baseline, current, and natural visibility conditions, and in making optional adjustments to the URP to account for the impacts of international anthropogenic emissions and prescribed fires. See 82 FR 3078 at 3103-05 (January 10, 2017).

The RHR requires tracking of visibility conditions on two sets of days: the clearest and the most impaired days. Visibility conditions for both sets of days are expressed as the average deciview index for the relevant five-year period (the period representing baseline or current visibility conditions). The RHR provides that the relevant sets of days for visibility tracking purposes are the 20% clearest (the 20% of monitored days in a calendar year with the lowest values of the deciview index) and 20% most impaired days (the 20% of monitored days in a calendar year with the highest amounts of anthropogenic visibility impairment). 16 40 CFR 51.301. A State must calculate visibility conditions for both the 20% clearest and 20% most impaired days for the baseline period of 2000-2004 and the most recent five-year period for which visibility monitoring data are available (representing current visibility conditions). 40 CFR 51.308(f)(1)(i) and (iii). States must also calculate natural visibility conditions for the clearest and most impaired days, 17 by estimating the conditions that would exist on those two sets of days absent anthropogenic visibility impairment. 40 CFR 51.308(f)(1)(ii). Using all these data, States must then calculate, for each Class I Area, the amount of progress made since the baseline period (2000-2004) and how much improvement is left to achieve in order to reach natural visibility conditions.

Using the data for the set of most impaired days only, States must plot a line between visibility conditions in the baseline period and natural visibility conditions for each Class I Area to determine the URP—the amount of visibility improvement, measured in deciviews, that would need to be achieved during each implementation period in order to achieve natural visibility conditions by the end of 2064. The URP is used in later steps of the reasonable progress analysis for informational purposes and to provide a non-enforceable benchmark against which to assess a Class I Area's rate of visibility improvement. 18 Additionally, in the 2017 RHR Revisions, EPA provided States the option of proposing to adjust the endpoint of the URP to account for impacts of anthropogenic sources outside the United States and/or impacts of certain types of wildland prescribed fires. These adjustments, which must be approved by EPA, are intended to avoid any perception that States should compensate for impacts from international anthropogenic sources and to give States the flexibility to determine that limiting the use of wildland-prescribed fire is not necessary for reasonable progress. See 82 FR 3078 at 3107, January 10, 2017, footnote 116.

EPA's 2018 Visibility Tracking Guidance can be used to help satisfy the 40 CFR 51.308(f)(1) requirements, including in developing information on baseline, current, and natural visibility conditions, and in making optional adjustments to the URP. In addition, the 2020 Data Completeness Memo provides recommendations on the data completeness language referenced in 40 CFR 51.308(f)(1)(i) and provides updated natural conditions estimates for each Class I Area.

The core component of a regional haze SIP submission is a long-term strategy that addresses regional haze in each Class I Area within a State's borders and each Class I Area that may be affected by emissions from the State. The long-term strategy “must include the enforceable emissions limitations, compliance schedules, and other measures that are necessary to make reasonable progress, as determined pursuant to (f)(2)(i) through (iv).” 40 CFR 51.308(f)(2). The amount of progress that is “reasonable progress” is based on applying the four statutory factors in CAA section 169A(g)(1) in an evaluation of potential control options for sources of visibility impairing pollutants, which is referred to as a “four-factor” analysis. The outcome of that analysis is the emission reduction measures that a particular source or group of sources needs to implement in order to make reasonable progress towards the national visibility goal. See 40 CFR 51.308(f)(2)(i). Emission reduction measures that are necessary to make reasonable progress may be either new, additional control measures for a source, or they may be the existing emission reduction measures that a source is already implementing. See 2019 Guidance at 43; 2021 Clarifications Memo at 8-10. Such measures must be represented by “enforceable emissions limitations, compliance schedules, and other measures” ( i.e., any additional compliance tools) in a State's long-term strategy in its SIP. 40 CFR 51.308(f)(2).

Section 51.308(f)(2)(i) provides the requirements for the four-factor analysis. The first step of this analysis entails selecting the sources to be evaluated for emission reduction measures; to this end, the RHR requires States to consider “major and minor stationary sources or groups of sources, mobile sources, and area sources” of visibility impairing pollutants for potential four-factor control analysis. 40 CFR 51.308(f)(2)(i). A threshold question at this step is which visibility impairing pollutants will be analyzed. As EPA previously explained, consistent with the first implementation period, EPA generally expects that each State will analyze at least SO 2 and NO X in selecting sources and determining control measures. See 2019 Guidance at 12, 2021 Clarifications Memo at 4. A State that chooses not to consider at least these two pollutants should demonstrate why such consideration would be unreasonable. 2021 Clarifications Memo at 4.

While States have the option to analyze all sources, the 2019 Guidance explains that “an analysis of control measures is not required for every source in each implementation period,” and that “[s]electing a set of sources for analysis of control measures in each implementation period is . . . consistent with the Regional Haze Rule, which sets up an iterative planning process and anticipates that a State may not need to analyze control measures for all its sources in a given SIP revision.” 2019 Guidance at 9. However, given that source selection is the basis of all subsequent control determinations, a reasonable source selection process “should be designed and conducted to ensure that source selection results in a set of pollutants and sources the evaluation of which has the potential to meaningfully reduce their contributions to visibility impairment.” 2021 Clarifications Memo at 3.

EPA explained in the 2021 Clarifications Memo that each State has an obligation to submit a long-term strategy that addresses the regional haze visibility impairment that results from emissions from within that State. Thus, source selection should focus on the in-State contribution to visibility impairment and be designed to capture a meaningful portion of the State's total contribution to visibility impairment in Class I Areas. A State should not decline to select its largest in-State sources on the basis that there are even larger out-of-State contributors. 2021 Clarifications Memo at 4. 19

Thus, while States have discretion to choose any source selection methodology that is reasonable, whatever choices they make should be reasonably explained. To this end, 40 CFR 51.308(f)(2)(i) requires that a State's SIP submission include “a description of the criteria it used to determine which sources or groups of sources it evaluated.” The technical basis for source selection, which may include methods for quantifying potential visibility impacts such as emissions divided by distance metrics, trajectory analyses, residence time analyses, and/or photochemical modeling, must also be appropriately documented, as required by 40 CFR 51.308(f)(2)(iii).

Once a State has selected the set of sources, the next step is to determine the emissions reduction measures for those sources that are necessary to make reasonable progress for the second implementation period. 20 This is accomplished by considering the four factors—“the costs of compliance, the time necessary for compliance, and the energy and nonair quality environmental impacts of compliance, and the remaining useful life of any existing source subject to such requirements.” CAA 169A(g)(1). EPA has explained that the four-factor analysis is an assessment of potential emission reduction measures ( i.e., control options) for sources; “use of the terms `compliance' and `subject to such requirements' in section 169A(g)(1) strongly indicates that Congress intended the relevant determination to be the requirements with which sources would have to comply in order to satisfy the CAA's reasonable progress mandate.” 82 FR 3078 at 3091 (January 10, 2017). Thus, for each source it has selected for four-factor analysis, 21 a State must consider a “meaningful set” of technically feasible control options for reducing emissions of visibility impairing pollutants. Id. at 3088. The 2019 Guidance provides that “[a] state must reasonably pick and justify the measures that it will consider, recognizing that there is no statutory or regulatory requirement to consider all technically feasible measures or any particular measures. A range of technically feasible measures available to reduce emissions would be one way to justify a reasonable set.” 2019 Guidance at 29.

EPA's 2021 Clarifications Memo provides further guidance on what constitutes a reasonable set of control options for consideration: “A reasonable four-factor analysis will consider the full range of potentially reasonable options for reducing emissions.” 2021 Clarifications Memo at 7. In addition to add-on controls and other retrofits ( i.e., new emission reduction measures for sources), EPA explained that States should generally analyze efficiency improvements for sources' existing measures as control options in their four-factor analyses, as in many cases such improvements are reasonable given that they typically involve only additional operation and maintenance costs. Additionally, the 2021 Clarifications Memo provides that States that have assumed a higher emission rate than a source has achieved or could potentially achieve using its existing measures should also consider lower emission rates as potential control options. That is, a State should consider a source's recent actual and projected emission rates to determine if it could reasonably attain lower emission rates with its existing measures. If so, the State should analyze the lower emission rate as a control option for reducing emissions. 2021 Clarifications Memo at 7. EPA's recommendations to analyze potential efficiency improvements and achievable lower emission rates apply to both sources that have been selected for four-factor analysis and those that have forgone a four-factor analysis on the basis of existing “effective controls.” See 2021 Clarifications Memo at 5, 10.

After identifying a reasonable set of potential control options for the sources it has selected, a State then collects information on the four factors with regard to each option identified. EPA has also explained that, in addition to the four statutory factors, States have flexibility under the CAA and RHR to reasonably consider visibility benefits as an additional factor alongside the four statutory factors. 22 The 2019 Guidance provides recommendations for the types of information that can be used to characterize the four factors (with or without visibility), as well as ways in which States might reasonably consider and balance that information to determine which of the potential control options is necessary to make reasonable progress. See 2019 Guidance at 30-36. The 2021 Clarifications Memo contains further guidance on how States can reasonably consider modeled visibility impacts or benefits in the context of a four-factor analysis. 2021 Clarifications Memo at 12-13, 14-15. Specifically, EPA explained that while visibility can reasonably be used when comparing and choosing between multiple reasonable control options, it should not be used to summarily reject controls that are reasonable given the four statutory factors. 2021 Clarifications Memo at 13. Ultimately, while States have discretion to reasonably weigh the factors and to determine what level of control is needed, 40 CFR 51.308(f)(2)(i) provides that a State “must include in its implementation plan a description of . . . how the four factors were taken into consideration in selecting the measure for inclusion in its long-term strategy.”

As explained above, 40 CFR 51.308(f)(2)(i) requires States to determine the emission reduction measures for sources that are necessary to make reasonable progress by considering the four factors. Pursuant to 40 CFR 51.308(f)(2), measures that are necessary to make reasonable progress towards the national visibility goal must be included in a State's long-term strategy and in its SIP. 23 If the outcome of a four-factor analysis is a new, additional emission reduction measure for a source, that new measure is necessary to make reasonable progress towards remedying existing anthropogenic visibility impairment and must be included in the SIP. If the outcome of a four-factor analysis is that no new measures are reasonable for a source, continued implementation of the source's existing measures is generally necessary to prevent future emission increases and thus to make reasonable progress towards the second part of the national visibility goal: preventing future anthropogenic visibility impairment. See CAA 169A(a)(1). That is, when the result of a four-factor analysis is that no new measures are necessary to make reasonable progress, the source's existing measures are generally necessary to make reasonable progress and must be included in the SIP. However, there may be circumstances in which a State can demonstrate that a source's existing measures are not necessary to make reasonable progress. Specifically, if a State can demonstrate that a source will continue to implement its existing measures and will not increase its emission rate, it may not be necessary to have those measures in the long-term strategy in order to prevent future emission increases and future visibility impairment. EPA's 2021 Clarifications Memo provides further explanation and guidance on how States may demonstrate that a source's existing measures are not necessary to make reasonable progress. See 2021 Clarifications Memo at 8-10. If the State can make such a demonstration, it need not include a source's existing measures in the long-term strategy or its SIP.

As with source selection, the characterization of information on each of the factors is also subject to the documentation requirement in 40 CFR 51.308(f)(2)(iii). The reasonable progress analysis, including source selection, information gathering, characterization of the four statutory factors (and potentially visibility), balancing of the four factors, and selection of the emission reduction measures that represent reasonable progress, is a technically complex exercise, but also a flexible one that provides States with bounded discretion to design and implement approaches appropriate to their circumstances. Given this flexibility, 40 CFR 51.308(f)(2)(iii) plays an important function in requiring a State to document the technical basis for its decision making so that the public and EPA can comprehend and evaluate the information and analysis the State relied upon to determine what emission reduction measures must be in place to make reasonable progress. The technical documentation must include the modeling, monitoring, cost, engineering, and emissions information on which the State relied to determine the measures necessary to make reasonable progress. This documentation requirement can be met through the provision of and reliance on technical analyses developed through a regional planning process, so long as that process and its output has been approved by all State participants. In addition to the explicit regulatory requirement to document the technical basis of their reasonable progress determinations, States are also subject to the general principle that those determinations must be reasonably moored to the statute. 24 That is, a State's decisions about the emission reduction measures that are necessary to make reasonable progress must be consistent with the statutory goal of remedying existing and preventing future visibility impairment.

The four statutory factors (and potentially visibility) are used to determine what emission reduction measures for selected sources must be included in a State's long-term strategy for making reasonable progress. Additionally, the RHR at 40 CFR 51.308(f)(2)(iv) separately provides five “additional factors”  25 that States must consider in developing their long-term strategies: (1) emission reductions due to ongoing air pollution control programs, including measures to address reasonably attributable visibility impairment; (2) measures to reduce the impacts of construction activities; (3) source retirement and replacement schedules; (4) basic smoke management practices for prescribed fire used for agricultural and wildland vegetation management purposes and smoke management programs; and (5) the anticipated net effect on visibility due to projected changes in point, area, and mobile source emissions over the period addressed by the long-term strategy. The 2019 Guidance provides that a State may satisfy this requirement by considering these additional factors in the process of selecting sources for four-factor analysis, when performing that analysis, or both, and that not every one of the additional factors needs to be considered at the same stage of the process. See 2019 Guidance at 21. EPA provided further guidance on the five additional factors in the 2021 Clarifications Memo, explaining that a State should generally not reject cost-effective and otherwise reasonable controls merely because there have been emission reductions since the first planning period owing to other ongoing air pollution control programs or merely because visibility is otherwise projected to improve at Class I Areas. Additionally, States should not rely on these additional factors to summarily assert that the State has already made sufficient progress and, therefore, no sources need to be selected or no new controls are needed regardless of the outcome of four-factor analyses. 2021 Clarifications Memo at 13.

Because the air pollution that causes regional haze crosses State boundaries, 40 CFR 51.308(f)(2)(ii) requires a State to consult with other States that also have emissions that are reasonably anticipated to contribute to visibility impairment in a given Class I Area. Consultation allows for each State that impacts visibility in an area to share whatever technical information, analyses, and control determinations may be necessary to develop coordinated emission management strategies. This coordination may be managed through inter- and intra-RPO consultation and the development of regional emissions strategies; additional consultations between States outside of RPO processes may also occur. If a State, pursuant to consultation, agrees that certain measures ( e.g., a certain emission limitation) are necessary to make reasonable progress at a Class I Area, it must include those measures in its SIP. 40 CFR 51.308(f)(2)(ii)(A). Additionally, the RHR requires that States that contribute to visibility impairment at the same Class I Area consider the emission reduction measures the other contributing States have identified as being necessary to make reasonable progress for their own sources. 40 CFR 51.308(f)(2)(ii)(B). If a State has been asked to consider or adopt certain emission reduction measures, but ultimately determines those measures are not necessary to make reasonable progress, that State must document in its SIP the actions taken to resolve the disagreement. 40 CFR 51.308(f)(2)(ii)(C). EPA will consider the technical information and explanations presented by the submitting State and the State with which it disagrees when considering whether to approve the State's SIP. See id.; 2019 Guidance at 53. Under all circumstances, a State must document in its SIP submission all substantive consultations with other contributing States. 40 CFR 51.308(f)(2)(ii)(C).

Reasonable progress goals “measure the progress that is projected to be achieved by the control measures States have determined are necessary to make reasonable progress based on a four-factor analysis.” 82 FR 3078 at 3091 (January 10, 2017). Their primary purpose is to assist the public and EPA in assessing the reasonableness of States' long-term strategies for making reasonable progress towards the national visibility goal. See 40 CFR 51.308(f)(3)(iii) and (iv). States in which Class I Areas are located must establish two RPGs, both in deciviews—one representing visibility conditions on the clearest days and one representing visibility on the most anthropogenically impaired days—for each area within their borders. 40 CFR 51.308(f)(3)(i). The two RPGs are intended to reflect the projected impacts, on the two sets of days, of the emission reduction measures the State with the Class I Area, as well as all other contributing States, have included in their long-term strategies for the second implementation period. 26 The RPGs also account for the projected impacts of implementing other CAA requirements, including non-SIP based requirements. Because RPGs are the modeled result of the measures in States' long-term strategies (as well as other measures required under the CAA), they cannot be determined before States have conducted their four-factor analyses and determined the control measures that are necessary to make reasonable progress. See 2021 Clarifications Memo at 6.

For the second implementation period, the RPGs are set for 2028. Reasonable progress goals are not enforceable targets, 40 CFR 51.308(f)(3)(iii); rather, they “provide a way for the states to check the projected outcome of the [long-term strategy] against the goals for visibility improvement.” 2019 Guidance at 46. While States are not legally obligated to achieve the visibility conditions described in their RPGs, 40 CFR 51.308(f)(3)(i) requires that “[t]he long-term strategy and the reasonable progress goals must provide for an improvement in visibility for the most impaired days since the baseline period and ensure no degradation in visibility for the clearest days since the baseline period.” Thus, States are required to have emission reduction measures in their long-term strategies that are projected to achieve visibility conditions on the most impaired days that are better than the baseline period and show no degradation on the clearest days compared to the clearest days from the baseline period. The baseline period for the purpose of this comparison is the baseline visibility condition—the annual average visibility condition for the period 2000-2004. See 40 CFR 51.308(f)(1)(i), 82 FR 3078 at 3097-98 (January 10, 2017).

So that RPGs may also serve as a metric for assessing the amount of progress a State is making towards the national visibility goal, the RHR requires States with Class I Areas to compare the 2028 RPG for the most impaired days to the corresponding point on the URP line (representing visibility conditions in 2028 if visibility were to improve at a linear rate from conditions in the baseline period of 2000-2004 to natural visibility conditions in 2064). If the most impaired days RPG in 2028 is above the URP ( i.e., if visibility conditions are improving more slowly than the rate described by the URP), each State that contributes to visibility impairment in the Class I Area must demonstrate, based on the four-factor analysis required under 40 CFR 51.308(f)(2)(i), that no additional emission reduction measures would be reasonable to include in its long-term strategy. 40 CFR 51.308(f)(3)(ii). To this end, 40 CFR 51.308(f)(3)(ii) requires that each State contributing to visibility impairment in a Class I Area that is projected to improve more slowly than the URP provide “a robust demonstration, including documenting the criteria used to determine which sources or groups [of] sources were evaluated and how the four factors required by paragraph (f)(2)(i) were taken into consideration in selecting the measures for inclusion in its long-term strategy.” The 2019 Guidance provides suggestions about how such a “robust demonstration” might be conducted. See 2019 Guidance at 50-51.

The 2017 RHR, 2019 Guidance, and 2021 Clarifications Memo also explain that projecting an RPG that is on or below the URP based on only on-the-books and/or on-the-way control measures ( i.e., control measures already required or anticipated before the four-factor analysis is conducted) is not a “safe harbor” from the CAA's and RHR's requirement that all States must conduct a four-factor analysis to determine what emission reduction measures constitute reasonable progress. The URP is a planning metric used to gauge the amount of progress made thus far and the amount left before reaching natural visibility conditions. However, the URP is not based on consideration of the four statutory factors and therefore cannot answer the question of whether the amount of progress being made in any particular implementation period is “reasonable progress.” See 82 FR 3078 at 3093, 3099-3100 (January 10, 2017); 2019 Guidance at 22; 2021 Clarifications Memo at 15-16.

Section 51.308(f)(6) requires States to have certain strategies and elements in place for assessing and reporting on visibility. Individual requirements under this section apply either to States with Class I Areas within their borders, States with no Class I Areas but that are reasonably anticipated to cause or contribute to visibility impairment in any Class I Area, or both. A State with Class I Areas within its borders must submit with its SIP revision a monitoring strategy for measuring, characterizing, and reporting regional haze visibility impairment that is representative of all Class I Areas within the State. SIP revisions for such States must also provide for the establishment of any additional monitoring sites or equipment needed to assess visibility conditions in Class I Areas, as well as reporting of all visibility monitoring data to EPA at least annually. Compliance with the monitoring strategy requirement may be met through a State's participation in the Interagency Monitoring of Protected Visual Environments (IMPROVE) monitoring network, which is used to measure visibility impairment caused by air pollution at the 156 Class I Areas covered by the visibility program. 40 CFR 51.308(f)(6), (f)(6)(i) and (iv). The IMPROVE monitoring data is used to determine the 20% most anthropogenically impaired and 20% clearest sets of days every year at each Class I Area and tracks visibility impairment over time.

All States' SIPs must provide for procedures by which monitoring data and other information are used to determine the contribution of emissions from within the State to regional haze visibility impairment in affected Class I Areas. 40 CFR 51.308(f)(6)(ii) and (iii). S ection 51.308(f)(6)(v) further requires that all States' SIPs provide for a statewide inventory of emissions of pollutants that are reasonably anticipated to cause or contribute to visibility impairment in any Class I Area; the inventory must include emissions for the most recent year for which data are available and estimates of future projected emissions. States must also include commitments to update their inventories periodically. The inventories themselves do not need to be included as elements in the SIP and are not subject to EPA review as part of the Agency's evaluation of a SIP revision. 27 All States' SIPs must also provide for any other elements, including reporting, recordkeeping, and other measures, that are necessary for States to assess and report on visibility. 40 CFR 51.308(f)(6)(vi). Per the 2019 Guidance, a State may note in its regional haze SIP that its compliance with the Air Emissions Reporting Rule (AERR) in 40 CFR part 51, subpart A satisfies the requirement to provide for an emissions inventory for the most recent year for which data are available. To satisfy the requirement to provide estimates of future projected emissions, a State may explain in its SIP how projected emissions were developed for use in establishing RPGs for its own and nearby Class I Areas. 28

Separate from the requirements related to monitoring for regional haze purposes under 40 CFR 51.308(f)(6), the RHR also contains a requirement at 40 CFR 51.308(f)(4) related to any additional monitoring that may be needed to address visibility impairment in Class I Areas from a single source or a small group of sources. This is called “reasonably attributable visibility impairment.”  29 Under this provision, if EPA or the FLM of an affected Class I Area has advised a State that additional monitoring is needed to assess reasonably attributable visibility impairment, the State must include in its SIP revision for the second implementation period an appropriate strategy for evaluating such impairment.

Section 51.308(f)(5) requires a State's regional haze SIP revision to address the requirements of paragraphs 40 CFR 51.308(g)(1) through (5) so that the plan revision due in 2021 will serve also as a progress report addressing the period since submission of the progress report for the first implementation period. The regional haze progress report requirement is designed to inform the public and EPA about a State's implementation of its existing long-term strategy and whether such implementation is in fact resulting in the expected visibility improvement. See 81 FR 26942, 26950 (May 4, 2016), (82 FR 3078 at 3119, January 10, 2017). To this end, every State's SIP revision for the second implementation period is required to describe the status of implementation of all measures included in the State's long-term strategy, including BART and reasonable progress emission reduction measures from the first implementation period, and the resulting emissions reductions. 40 CFR 51.308(g)(1) and (2).

A core component of the progress report requirements is an assessment of changes in visibility conditions on the clearest and most impaired days. For second implementation period progress reports, 40 CFR 51.308(g)(3) requires States with Class I Areas within their borders to first determine current visibility conditions for each area on the most impaired and clearest days, 40 CFR 51.308(g)(3)(i), and then to calculate the difference between those current conditions and baseline (2000-2004) visibility conditions in order to assess progress made to date. See 40 CFR 51.308(g)(3)(ii). States must also assess the changes in visibility impairment for the most impaired and clearest days since they submitted their first implementation period progress reports. See 40 CFR 51.308(g)(3)(iii), (f)(5). Since different States submitted their first implementation period progress reports at different times, the starting point for this assessment will vary State by State.

Similarly, States must provide analyses tracking the change in emissions of pollutants contributing to visibility impairment from all sources and activities within the State over the period since they submitted their first implementation period progress reports. See 40 CFR 51.308(g)(4), (f)(5). Changes in emissions should be identified by the type of source or activity. Section 51.308(g)(5) also addresses changes in emissions since the period addressed by the previous progress report and requires States' SIP revisions to include an assessment of any significant changes in anthropogenic emissions within or outside the State. This assessment must include an explanation of whether these changes in emissions were anticipated and whether they have limited or impeded progress in reducing emissions and improving visibility relative to what the State projected based on its long-term strategy for the first implementation period.

Clean Air Act section 169A(d) requires that before a State holds a public hearing on a proposed regional haze SIP revision, it must consult with the appropriate FLM or FLMs; pursuant to that consultation, the State must include a summary of the FLMs' conclusions and recommendations in the notice to the public. Consistent with this statutory requirement, the RHR also requires that States “provide the [FLM] with an opportunity for consultation, in person and at a point early enough in the State's policy analyses of its long-term strategy emission reduction obligation so that information and recommendations provided by the [FLM] can meaningfully inform the State's decisions on the long-term strategy.” 40 CFR 51.308(i)(2). Consultation that occurs 120 days prior to any public hearing or public comment opportunity will be deemed “early enough,” but the RHR provides that in any event the opportunity for consultation must be provided at least 60 days before a public hearing or comment opportunity. This consultation must include the opportunity for the FLMs to discuss their assessment of visibility impairment in any Class I Area and their recommendations on the development and implementation of strategies to address such impairment. 40 CFR 51.308(i)(2). In order for EPA to evaluate whether FLM consultation meeting the requirements of the RHR has occurred, the SIP submission should include documentation of the timing and content of such consultation. The SIP revision submitted to EPA must also describe how the State addressed any comments provided by the FLMs. 40 CFR 51.308(i)(3). Finally, a SIP revision must provide procedures for continuing consultation between the State and FLMs regarding the State's visibility protection program, including development and review of SIP revisions, five-year progress reports, and the implementation of other programs having the potential to contribute to impairment of visibility in Class I Areas. 40 CFR 51.308(i)(4).

DNREC submitted its regional haze SIP for the first implementation period to EPA on September 25, 2008. EPA approved Delaware's first implementation period regional haze SIP submission on July 19, 2011 (76 FR 42557). Delaware has no Class I Areas within its borders but was identified as influencing the visibility impairment of the Brigantine National Wildlife Refuge Class I Area (“Brigantine” or “Brigantine Wilderness Class I Area”), located in the State of New Jersey. EPA's approval included the portions of the plan that addressed the reasonable progress requirements and Delaware's implementation of Best Available Retrofit Technologies (BART) on eligible sources. The requirements for regional haze SIPs for the first implementation period are contained in 40 CFR 51.308(d) and (e). 40 CFR 51.308(b). Pursuant to 40 CFR 51.308(g), Delaware was also responsible for submitting a five-year progress report as a SIP revision for the first implementation period, which it did on September 24, 2013. EPA approved the progress report into the Delaware SIP on May 5, 2014. See 79 FR 25506.

In accordance with CAA sections 169A and the RHR at 40 CFR 51.308(f), on August 8, 2022, DNREC submitted a revision to the Delaware SIP, titled “Delaware's Visibility SIP Revision Final August 2022” to address its regional haze obligations for the second implementation period, which runs through 2028. DNREC subsequently submitted a supplemental SIP submittal to EPA on March 7, 2024, referred to as “Supplemental Submission for Delaware's Second Regional Haze SIP”, which included title V permit provisions for three facilities owned by Calpine Mid-Atlantic Generation, LLC to be incorporated into the Delaware SIP. These permits and their associated public notice and transmittal letters are included in the rulemaking docket for this action. 30

The following sections describe Delaware's SIP submission, including analyses conducted by MANE-VU and Delaware's determinations based on those analyses, Delaware's assessment of progress made since the first implementation period in reducing emissions of visibility impairing pollutants, and the visibility improvement progress at the nearby Class I Area. This rulemaking also contains EPA's evaluation of Delaware's submission against the requirements of the CAA and RHR for the second implementation period of the regional haze program.

Section 169A(b)(2) of the CAA requires each State in which any Class I Area is located or “the emissions from which may reasonably be anticipated to cause or contribute to any impairment of visibility” in a Class I Area to have a plan for making reasonable progress toward the national visibility goal. The RHR implements this statutory requirement at 40 CFR 51.308(f), which provides that each State's plan “must address regional haze in each mandatory Class I Area located within the State and in each mandatory Class I Area located outside the State that may be affected by emissions from within the State,” and (f)(2), which requires each State's plan to include a long-term strategy that addresses regional haze in such Class I Areas.

Delaware does not have a Class I Area located within its borders, but has been identified as influencing the visibility impairment of the Brigantine Wilderness Class I Area, located in the State of New Jersey. For the second implementation period, MANE-VU performed technical analyses  31 to help assess source and State-level contributions to visibility impairment and the need for interstate consultation. MANE-VU used the results of these analyses to determine which States' emissions “have a high likelihood of affecting visibility in MANE-VU's Class I Areas.”  32 Similar to metrics used in the first implementation period, 33 MANE-VU used a greater than 2 percent of sulfate plus nitrate emissions contribution criteria to determine whether emissions from individual jurisdictions within the region affected visibility in any Class I Areas. The MANE-VU analyses for the second implementation period used a combination of data analysis techniques, including emissions data, distance from Class I Areas, wind trajectories, and California Puff Model (CALPUFF) dispersion modeling. Although many of the analyses focused only on SO 2 emissions and resultant particulate sulfate contributions to visibility impairment, some also incorporated NO X emissions to estimate particulate nitrate contributions.

One MANE-VU analysis used for contribution assessment was CALPUFF air dispersion modeling. The CALPUFF model was used to estimate sulfate and nitrate formation and transport in MANE-VU and nearby regions originating from large electric generating unit (EGU) point sources and other large industrial and institutional sources in the eastern and central United States. Information from an initial round of CALPUFF modeling was collated for the 444 EGUs that were determined to warrant further scrutiny based on their emissions of SO 2 and NO X . The list of EGUs was based on an enhanced “Q/d” analysis  34 that considered recent SO 2 emissions in the eastern United States and an analysis that adjusted previous 2002 MANE-VU CALPUFF modeling by applying a ratio of 2011 to 2002 SO 2 emissions. This list of sources was then enhanced by including the top five SO 2 and NO X emission sources for 2011 for each State included in the modeling domain. A total of 311 EGU stacks (as opposed to individual units) were included in the CALPUFF modeling analysis. Initial information was also collected on the 50 industrial and institutional sources that, according to 2011 Q/d analysis, contributed the most to visibility impact in each Class I Area. The ultimate CALPUFF modeling run included a total of 311 EGU stacks and 82 industrial facilities. The summary report for the CALPUFF modeling included the top 10 most impacting EGUs and the top five most impacting industrial/institutional sources for each Class I Area and compiled those results into a ranked list of the most impacting EGUs and industrial sources at MANE-VU Class I Areas. 35

The second MANE-VU contribution analysis used a meteorologically weighted Q/d calculation to assess States' contributions to visibility impairment at MANE-VU Class I Areas. 36 This analysis focused predominantly on SO 2 emissions and used cumulative SO 2 emissions from a source and a State for the variable “Q,” and the distance of the source or State to the IMPROVE monitor receptor at a Class I Area as “d.” The result is then multiplied by a constant (C i ), which is determined based on the prevailing wind patterns. MANE-VU selected a meteorologically weighted Q/d analysis as an inexpensive initial screening tool that could easily be repeated to determine which States, sectors, or sources have a larger relative impact and warrant further analysis. MANE-VU's analysis estimated SO 2 emission contribution from Delaware sources of less than 2% of visibility impairment for all seven MANE-VU Class I Areas. Although MANE-VU did not originally estimate nitrate impacts, the MANE-VU Q/d analysis was subsequently extended to account for nitrate contributions from NO X emissions and to approximate the nitrate impacts from area and mobile sources. MANE-VU therefore developed a ratio of nitrate to sulfate impacts based on the previously described CALPUFF modeling and applied those to the sulfate Q/d results in order to derive nitrate contribution estimates. Several States did not have CALPUFF nitrate to sulfate ratio results, however, because there were no point sources modeled with CALPUFF.

To develop a final set of contribution estimates, MANE-VU weighted the results from both the Q/d and CALPUFF analyses. The MANE-VU mass-weighted sulfate and nitrate contribution results were reported for the MANE-VU Class I Areas (the Q/d summary report included results for several non-MANE-VU areas as well). If a State's contribution to sulfate and nitrate concentrations at a particular Class I Area was 2 percent or greater, MANE-VU regarded that State as contributing to visibility impairment in that area. Delaware's highest mass-weighted sulfate and nitrate contribution to any Class I Area was 0.6% to the Brigantine Wilderness Class I Area. Even with a contribution level below 2 percent threshold, Delaware agreed to participate in the consultation process, as part of the MANE-VU RPO.

As explained above, the EPA concluded in the 1999 RHR that “all [s]tates contain sources whose emissions are reasonably anticipated to contribute to regional haze in a Class I Area,” 64 FR 35714 at 35721 (July 1, 1999), and this determination was not changed in the 2017 RHR. Critically, the statute and regulation both require that the cause-or-contribute assessment consider all emissions of visibility-impairing pollutants from a State, as opposed to emissions of a particular pollutant or emissions from a certain set of sources. Consistent with these requirements, the 2019 Guidance makes it clear that “all types of anthropogenic sources are to be included in the determination” of whether a State's emissions are reasonably anticipated to result in any visibility impairment. 2019 Guidance at 8.

First, as an aside, the screening analyses on which MANE-VU relied are useful for certain purposes. MANE-VU used information from its technical analysis to rank the largest contributing States to sulfate and nitrate impairment in five Class I Areas within MANE-VU States and three additional, nearby Class I Areas. 37 The rankings were used to determine upwind States that were deemed important to include in state-to-state consultation (based on an identified impact screening threshold). Additionally, large individual source impacts were used to target MANE-VU control analysis “Asks”  38 of States and sources both within and upwind of MANE-VU. 39 EPA finds the nature of the analyses generally appropriate to support decisions on States with which to consult. However, we have cautioned that source selection methodologies that target the largest regional contributors to visibility impairment across multiple States may not be reasonable for a particular State if it results in few or no sources being selected for subsequent analysis. 2021 Clarifications Memo at 3. Delaware has participated in the MANE-VU visibility analysis and has provided information in its SIP submission on the magnitude of visibility impacts from certain Delaware emission sources, specifically the Indian River Generating Station and the Edge Moor Energy Center (EMEC), on nearby Class I Areas.

With regard to the analysis and determinations regarding Delaware's contribution to visibility impairment at out-of-state Class I Areas, the MANE-VU technical work focuses on the magnitude of visibility impacts from certain Delaware emissions on its Class I Area and other nearby Class I Areas. However, the analyses did not account for all emissions and all components of visibility impairment ( e.g., primary PM emissions, and impairment from fine PM, elemental carbon, and organic carbon). In addition, Q/d analyses with a relatively simplistic accounting for wind trajectories and CALPUFF applied to a very limited set of EGUs, and major industrial sources of SO 2 and NO X are not scientifically rigorous tools capable of evaluating contribution to visibility impairment from all emissions in a State. We again clarify that each State is obligated under the CAA and RHR to address regional haze visibility impairment resulting from emissions from within the State, irrespective of whether another State's contribution is greater. See 2021 Clarifications Memo at 3. Additionally, we note that the 2 percent or greater sulfate-plus-nitrate threshold used to determine whether Delaware's emissions contribute to visibility impairment at a particular Class I Area may be higher than what EPA believes is an “extremely low triggering threshold” intended by the statute and regulations. In sum, based on the information provided, it is clear that emissions from Delaware contribute to visibility impairment at out-of-state Class I Areas. However, due to the low triggering threshold implied by the Rule and the lack of rigorous modeling analyses, we do not necessarily agree with the level of the State's 2% contribution threshold.

Delaware determined that sources and emissions within the State contribute to visibility impairment at three out-of-state Class I Areas. 40 Furthermore, the State took part in the emission control strategy consultation process as a member of MANE-VU pursuant to the regulatory requirements. As part of that process, MANE-VU developed a set of emissions reduction measures identified as being necessary to make reasonable progress in the five MANE-VU Class I Areas. This strategy consists of six “Asks” for States within MANE-VU and five “Asks” for States outside the region that were found to impact visibility at Class I Areas within MANE-VU. 41 Delaware's submission discusses each of the “Asks” and explains why or why not each is applicable and how it has complied with the relevant components of the emissions control strategy MANE-VU has laid out for its States. Delaware worked with MANE-VU to determine potential reasonable measures that could be implemented by 2028, considering the cost of compliance, the time necessary for compliance, the energy and non-air quality environmental impacts, and the remaining useful life of any potentially affected sources. As discussed in further detail below, the EPA is proposing to find that Delaware has submitted a regional haze plan that meets the requirements of 40 CFR 51.308(f)(2) related to the development of a long-term strategy. Although we have concerns regarding some aspects of MANE-VU's technical analyses supporting States' contribution determinations, we propose to find that Delaware has nevertheless satisfied the applicable regulatory requirements for making reasonable progress towards natural visibility conditions in Class I Areas that may be affected by emissions from the State.

Section 51.308(f)(1) requires States to determine the following for “each mandatory Class I Federal area located within the State”: baseline visibility conditions for the most impaired and clearest days, natural visibility conditions for the most impaired and clearest days, progress to date for the most impaired and clearest days, the differences between current visibility conditions and natural visibility conditions, and the URP. This section also provides the option for States to propose adjustments to the URP line for a Class I Area to account for visibility impacts from anthropogenic sources outside the United States and/or the impacts from wildland prescribed fires that were conducted for certain, specified objectives. 40 CFR 51.308(f)(1)(vi)(B).

Delaware does not have any Class I Area within its borders therefore, § 51.308(f)(1) and its requirements do not apply. 42

Each State having a Class I Area within its borders or emissions that may affect visibility in a Class I Area must develop a long-term strategy for making reasonable progress towards the national visibility goal. CAA 169A(b)(2)(B). As explained in the Background section of this rulemaking, reasonable progress is achieved when all States contributing to visibility impairment in a Class I Area are implementing the measures determined—through application of the four statutory factors to sources of visibility impairing pollutants—to be necessary to make reasonable progress. 40 CFR 51.308(f)(2)(i). Each State's long-term strategy must include the enforceable emission limitations, compliance schedules, and other measures that are necessary to make reasonable progress. 40 CFR 51.308(f)(2). All new ( i.e., additional) measures that are the outcome of four-factor analyses are necessary to make reasonable progress and must be in the long-term strategy. If the outcome of a four-factor analysis and other measures necessary to make reasonable progress is that no new measures are reasonable for a source, that source's existing measures are necessary to make reasonable progress, unless the State can demonstrate that the source will continue to implement those measures and will not increase its emission rate. Existing measures that are necessary to make reasonable progress must also be in the long-term strategy. In developing its long-term strategies, a State must also consider the five additional factors in 40 CFR 51.308(f)(2)(iv). As part of its reasonable progress determinations, the State must describe the criteria used to determine which sources or group of sources were evaluated ( i.e., subjected to four-factor analysis) for the second implementation period and how the four factors were taken into consideration in selecting the emission reduction measures for inclusion in the long-term strategy. 40 CFR 51.308(f)(2)(iii).

The following section summarizes how Delaware's SIP submission addressed the requirements of 40 CFR 51.308(f)(2)(i). Specifically, it describes MANE-VU's development of the six Asks and how Delaware addressed each one.

States may rely on technical information developed by the RPOs of which they are members to select sources for four-factor analysis and to conduct that analysis, as well as to satisfy the documentation requirements under 40 CFR 51.308(f). Where an RPO has performed source selection and/or four-factor analyses (or considered the five additional factors in 40 CFR 51.308(f)(2)(iv)) for its member States, those States may rely on the RPO's analyses for the purpose of satisfying the requirements of 40 CFR 51.308(f)(2)(i) so long as the States have a reasonable basis to do so and all State participants in the RPO process have approved the technical analyses. 40 CFR 51.308(f)(3)(iii). States may also satisfy the requirement of 40 CFR 51.308(f)(2)(ii) to engage in interstate consultation with other States that have emissions that are reasonably anticipated to contribute to visibility impairment in a given Class I Area under the auspices of intra- and inter-RPO engagement.

Delaware is a member of the MANE-VU RPO and participated in the RPO's regional approach to developing a strategy for making reasonable progress towards the national visibility goal in the MANE-VU Class I Areas. MANE-VU's strategy includes a combination of: (1) measures for certain source sectors and groups of sectors that the RPO determined were reasonable for States to pursue, and (2) a request for member States to conduct four-factor analyses for individual sources that it identified as contributing to visibility impairment. MANE-VU refers to each of the components of its overall strategy as an Ask of its member States. On August 25, 2017, the Executive Director of MANE-VU, on behalf of the MANE-VU States and Tribal nations, signed a statement that identifies six emission reduction measures that comprise the “Asks” for the second implementation period. 43 The “Asks” were “designed to identify reasonable emission reduction strategies that must be addressed by the states and tribal nations of MANE-VU through their regional haze SIP updates.”  44 The statement explains that “[i]f any State cannot agree with or complete a Class I State's Asks, the State must describe the actions taken to resolve the disagreement in the Regional Haze SIP.”  45

MANE-VU's recommendations as to the appropriate control measures were based on technical analyses documented in the RPO's reports and included as appendices to or referenced in Delaware's regional haze SIP submission. One of the initial steps of MANE-VU's technical analysis was to determine which visibility-impairing pollutants should be the focus of its efforts for the second implementation period. In the first implementation period, MANE-VU determined that sulfates were the most significant visibility impairing pollutant at the region's Class I Areas. To determine the impact of certain pollutants on visibility at Class I Areas for the purpose of second implementation period planning, MANE-VU conducted an analysis comparing the pollutant contribution on the clearest and most impaired days in the baseline period (2000-2004) to the most recent period (2012-2016)  46 at MANE-VU and nearby Class I Areas. MANE-VU found that while SO 2 emissions were decreasing and visibility was improving, sulfates still made up the most significant contribution to visibility impairment at MANE-VU and nearby Class I Areas. According to the analysis, NO X emissions have begun to play a more significant role in visibility impacts in recent years, especially at the Brigantine Wilderness Class I Area. The technical analyses used by Delaware are included in their submission and are as follows:

To support development of the “Asks,” MANE-VU gathered information on each of the four statutory factors for six source sectors it determined, based on an examination of annual emission inventories, “had emissions that were reasonabl[y] anticipated to contribute to visibility degradation in MANE-VU:” electric generating units (EGUs), industrial/commercial/institutional boilers (ICI boilers), cement kilns, heating oil, residential wood combustion, and outdoor wood combustion. 47 MANE-VU also collected data on individual sources within the EGU, ICI boiler, and cement kiln sectors. 48 Information for the six sectors included explanations of technically feasible control options for SO 2 or NO X, illustrative cost-effectiveness estimates for a range of model units and control options, sector-wide cost considerations, potential time frames for compliance with control options, potential energy and non-air-quality environmental impacts of certain control options, and how the remaining useful lives of sources might be considered in a control analysis. 49 Source-specific data included SO 2 emissions  50 and existing controls  51 for certain existing EGUs, ICI boilers, and cement kilns. MANE-VU considered this information on the four factors as well as the analyses developed by the RPO's Technical Support Committee when it determined specific emission reduction measures that were found to be reasonable for certain sources within two of the sectors it had examined—EGUs and ICI boilers. The “Asks” were based on this analysis and looked to either optimize the use of existing controls, have States conduct further analysis on EGU or ICI boilers with considerable visibility impacts, implement low sulfur fuel standards, or lock-in lower emission rates.

MANE-VU Ask 1 is “ensure the most effective use of control technologies on a year-round basis to consistently minimize emissions of haze precursors or obtain equivalent alternative emission reductions” at EGUs with a nameplate capacity larger than or equal to 25 megawatts (MW) with already installed NO X and/or SO 2 controls. 52

To address Ask 1, first, Delaware indicated that all the units that burn fuel oil are covered year-round by a Delaware low sulfur fuel regulation at Title 7 Delaware Administrative Code (7 DE Admin Code) 1108, 53 that was approved into the SIP on July 11, 2022 (87 FR 41074). Delaware's SIP-approved low sulfur fuel regulation reduces the SIP-approved maximum allowable sulfur content limit for distillate fuels from 3,000 ppm to 15 ppm, for residual fuel from 1% to 0.5% by weight, and for any other fuel, the sulfur content would remain at 1.0% by weight. Based on that, the State asserted that it met the request to ensure SO 2 controls year-round under Ask 1.

Delaware then focused its efforts on the control of NO X emissions and identified 10 EGUs with nameplate capacity larger than or equal to 25 MW, of which four had permits that did not require the use of NO X controls year-round on some of their units. The four sources are Christiana Energy Center (ChEC), Edge Moor Energy Center (EMEC), Garrison Energy Center (GEC), and Hay Road Energy Center (HREC), which are all owned by Calpine Mid-Atlantic Generation, LLC (Calpine). To meet the Ask, Delaware requested the EGUs to perform four-factor analyses on the pertinent units to determine if year-round NO X controls are feasible. Details of the EGUs' four-factor analyses with regard to Ask 1 can be found in a technical support document (TSD) of this proposed rulemaking action; specifically, it describes how Delaware addressed each Ask.

Based on the four-factor analyses performed by the sources to evaluate adding or expanding NO X controls year-round, only one of the sources, ChEC, concluded that it was feasible to operate the existing controls for an additional period throughout the year. Based upon that conclusion and in order to meet the Ask, Delaware updated applicable permits in May 2021 to reflect the new measures, and submitted the redacted permits for incorporation into the SIP. Additional details can be found in the TSD (section III-a.-1. at 8). Delaware therefore concluded that it met Ask 1.

MANE-VU Ask 2 requests that States “perform a four-factor analysis for reasonable installation or upgrade to emissions controls” for specified sources. MANE-VU developed its Ask 2 list of sources for analysis by performing modeling and identifying facilities with the potential for 3.0 inverse megameters (Mm −1 ) or greater impacts on visibility at any Class I Area in the MANE-VU region. 54 Delaware explained that it has no facilities that were modeled by MANE-VU to impact visibility at any Class I Area by 3.0 Mm −1 or more and concluded that it is currently meeting Ask 2. While Delaware did not select sources that fell under MANE-VU's 3.0 Mm −1 threshold for four-factor analysis, it did provide supplemental information about a large source that was identified by commenters and explanation supporting its decision not to request the facility to evaluate measures for reasonable progress because the facility is effectively controlled.

Specifically, commenters asserted that Delaware should have selected the Delaware City Refinery Company, LLC (DCRC) for a four-factor analysis of possible controls. In its SIP submission, Delaware explained the reasons it did not conduct a four-factor analysis for DCRC. First, based on MANE-VU's modeling results, DCRC showed that its impact on visibility impairment was low;  55 second, Delaware relied on the threshold that was agreed to by all MANE-VU States, including those that have Class I Areas within their boundaries; and third, the source is well controlled for SO 2 and NO X through existing State regulations and several consent decrees. Section 8.13.2 of the SIP submission contains a detailed description of controls required for SO 2 and NO X emissions, pursuant to two Federal consent decrees, an agreement governing the acquisition and operation of the facility, and State and Federal regulations that DCRC is subject to. 56 More details about Delaware's response to Ask 2 can be found in the TSD of this proposed rulemaking action.

MANE-VU Ask 3 requests that “each MANE-VU State that has not yet fully adopted an ultra-low fuel oil standard as requested by MANE-VU in 2007”, to “pursue this standard as expeditiously as possible and before 2028, depending on supply availability.” The Ask includes percent by weight standards for #2 distillate oil (0.0015% sulfur by weight or 15 parts per million (ppm)), #4 residual oil (0.25-0.5% sulfur by weight), and #6 residual oil (0.3-0.5% sulfur by weight). Delaware explained that, in 2013, it adopted the 7 DE Admin Code 1108 low-sulfur fuel regulation  57 which went into effect on July 1, 2016. Delaware therefore concluded that it is meeting Ask 3. Additional details about Delaware's response to Ask 3 can be found in the TSD of this proposed rulemaking action at 24.

MANE-VU Ask 4 requests States to “pursue updating permits, enforceable agreements, and/or rules to “lock in” lower emissions rates for SO 2 , NO X and PM” at emission sources larger than 250 million British Thermal Units (MMBtu) per hour heat input that have switched to lower emitting fuels. 58 Based on Delaware's SIP submission, two EGUs fell under Ask 4. The first source is Calpine's EMEC, which had switched operations to lower emitting fuels and had its permits updated to lock in lower emission rates for SO 2 , NO X and PM. A second source, City of Dover McKee Run Generating Station, had its permits cancelled in November 2021. 59 Based on these updates, Delaware concluded it is meeting Ask 4. More details about Delaware's response to Ask 4 are included in the TSD of this proposed rulemaking action.

MANE-VU Ask 5 requests that MANE-VU States “where emission rules have not been adopted, control NO X emissions for peaking combustion turbines that have the potential to operate on high electric demand days (HEDD)” by either: (a) striving to meet NO X emissions standards specified in the Ask for turbines that run on natural gas and fuel oil, (b) performing a four-factor analysis for reasonable installation of or upgrade to emission controls, or (c) obtaining equivalent alternative emission reductions on HEDD. 60 The Ask requests States to strive for NO X emission standards of no greater than 25 ppm for natural gas and 42 ppm for fuel oil, or at a minimum, NO X emissions standards of no greater than 42 ppm for natural gas and 96 ppm for fuel oil.

For Ask 5, Delaware identified seven sources with units affected by HEDD, 61 and two of the seven sources met the emission limits provided in option (a). Delaware requested that each of the remaining five sources perform four-factor analyses as stated in option (b) of the Ask because their current Title V permits do not meet the NO X standards from option (a). 62 Based on the four-factor analyses conducted by the five sources to evaluate potential control options for HEDD units, three of them found it economically feasible to operate existing controls during two additional months adjacent to the ozone season, for which Delaware updated their Title V permits accordingly and submitted the permits for incorporation into the SIP. For the remaining two sources, Delaware reviewed the facilities' estimates of compliance costs  63 of $192,000/ton of NO X removed for one and $334,897/ton of NO X removed for the other to upgrade their respective units, 64 and Delaware concluded that it was not an economically feasible option for these sources to upgrade their existing control given the limited operational time and low level of reported annual NO X emissions within the State as shown on table 10-5 of the SIP submittal. In addition, Delaware evaluated various potential new control options for the five sources but found that these were neither economically nor technically feasible. Because Delaware conducted four-factor analyses on the selected sources, Delaware concluded it has satisfied Ask 5 through option (b). More details about Delaware's EGUs four-factor analyses with regards to Ask 5 can be found in the TSD of this proposed rulemaking action.

MANE-VU Ask 6, requests that “each State should consider and report in their SIP measures or programs to: (a) decrease energy demand through the use of energy efficiency and (b) increase the use within their State of Combined Heat and Power (CHP) and other clean Distributed Generation technologies including fuel cells, wind and solar.”  65 Delaware stated that it implemented a number of measures with regard to this Ask. Some of these include the Energy Task Force Executive Order signed on April 26, 2002, the Delaware Energy Efficiency Advisory Council (EEAC), the 2005 Renewable Energy Portfolio Standards Act which is the basis for Delaware's renewable energy portfolio standards (RPS), and the Regional Greenhouse Gas Initiative (RGGI), to name a few. Based on these measures, Delaware concluded it is meeting Ask 6. Additional details about Delaware's response to Ask 6 can be found in the TSD of this proposed rulemaking action.

EPA is proposing to find that Delaware has satisfied the requirements of 40 CFR 51.308(f)(2)(i) related to evaluating sources and determining the emission reduction measures that are necessary to make reasonable progress by considering the four statutory factors.

Through Ask 1, MANE-VU instructed States to “ensure the most effective use of control technologies on a year-round basis to consistently minimize emissions of haze precursors or obtain equivalent alternative emission reductions” at EGUs with a nameplate capacity larger than or equal to 25 megawatts (MW) with already installed NO X and/or SO 2 controls. 66

EPA reviewed and evaluated Delaware's response to the four-factor analyses on the four sources with permits that did not require NO X controls year-round on some of their units and found that the State agreed with Calpine's conclusions for each of the sources. For ChEC and EMEC, Delaware agreed that it is not economically feasible to operate their NO X existing controls year-round because the units' operation and, hence, NO X emissions are both limited. On the other hand, for GEC and HREC, Delaware agreed that it is not technically feasible to retrofit the sources' NO X existing controls to operate year-round due to the same conclusion that operation and NO X emissions are limited. To support their conclusion, on table 10-2 of the SIP submittal, Delaware included the annual average operating hours and NO X emissions of the sources for a five-year period, which demonstrate the generally limited operation and the significantly low NO X emissions in recent years ( i.e., the tons of NO X emitted per unit per year ranging from less than two to less than 150).

EPA agrees with Delaware that it is not reasonable to upgrade any of the sources' NO X existing controls due to the extremely low emission reductions that would have been achieved, and that the costs of compliance, as demonstrated through the four-factor analyses, are not justified by the low amount of NO X emission reductions that the sources would achieve if these were reconfigured. More information on the amount of NO X emitted from these units can be found in the TSD at 32-33.

EPA also reviewed and evaluated the State's selection and modification of the applicable EGUs' title V permits to incorporate the regional haze requirements of the second planning period. To meet Ask 1, DNREC updated ChEC, EMEC, and HREC's title V permits after conducting four-factor analyses. For ChEC, DNREC added the 88 ppm NO X emission limit during April and October. For EMEC and HREC, DNREC added language requiring the facilities to operate and maintain their existing NO X control systems in accordance with Calpine's maintenance protocol. Based on the above, EPA thus agrees with Delaware's conclusions and proposes to find that Delaware reasonably satisfied Ask 1.

For Ask 2, MANE-VU requested that States “perform a four-factor analysis for reasonable installation or upgrade to emissions controls” for specified sources. MANE-VU developed its Ask 2 list of sources for analysis by performing modeling and identifying facilities with the potential for 3.0 inverse megameters (Mm −1 ) or greater impacts on visibility at any Class I Area in the MANE-VU region. 67

As an initial matter, EPA does not necessarily agree that MANE-VU 3.0 Mm −1 visibility impact is a reasonable threshold for source selection. The RHR recognizes that, due to the nature of regional haze visibility impairment, numerous and sometimes relatively small sources may need to be selected and evaluated for control measures in order to make reasonable progress. See 2021 Clarifications Memo at 4. As explained in the 2021 Clarifications Memo, while states have discretion to choose any source selection threshold that is reasonable, “[a] state that relies on a visibility (or proxy for visibility impact) threshold to select sources for four-factor analysis should set the threshold at a level that captures a meaningful portion of the State's total contribution to visibility impairment to Class I Areas.” 2021 Memo at 3. In this case, the 3.0 Mm −1 threshold did not identify sources in Delaware (only 22 across the entire MANE-VU region), indicating that it may be unreasonably high. 68

However, EPA proposes to find that Delaware reasonably determined that it has satisfied Ask 2. As explained above, we do not necessarily agree that a 3.0 Mm −1 threshold for selecting sources for four-factor analysis results in a set of sources the evaluation of which has the potential to meaningfully reduce the State's contribution to visibility impairment. MANE-VU's Ask 2 did not identify any source in Delaware for a four-factor analysis; however, as part of EPA's evaluation, we note that other MANE-VU Asks identified multiple sources and sectors for four-factor analyses in Delaware, and Delaware did evaluate additional control measures and conducted four-factor analyses through other Asks to meet the regional haze requirements for the second planning period. Ask 2 is not the only source selection process for this State, and thus EPA is basing this proposed finding on the State's consideration of the four factors and units and sectors analyzed in Asks 1, 3, and 5.

Ask 3 requests that, for “each MANE-VU State that has not yet fully adopted an ultra-low fuel oil standard as requested by MANE-VU in 2007”, to “pursue this standard as expeditiously as possible and before 2028, depending on supply availability.” EPA proposes to find that Delaware reasonably relied on MANE-VU's four-factor analysis for a low-sulfur fuel oil regulation, which engaged with each of the statutory factors and explained how the information supported a conclusion that a 15 ppm-sulfur fuel oil standard for fuel oils is reasonable. Delaware's ultra-low sulfur fuel oil regulations, 69 which, as previously stated, were approved into Delaware's SIP on July 11, 2022 (87 FR 41074), are consistent with Ask 3. EPA therefore proposes to find that Delaware reasonably determined that it has satisfied Ask 3.

MANE-VU Ask 4 requests that States “pursue updating permits, enforceable agreements, and/or rules to lock-in lower emission rates for SO 2 , NO X , and PM” at “EGUs and other large point emission sources larger than 250 MMBTU per hour heat input that have switched to lower emitting fuels.” Ask 4 also states that “the permit, enforceable agreement, and/or rule can allow for suspension of the lower emission rate during natural gas curtailment.” Delaware concluded that no additional updates were needed to meet Ask 4 because the EGU that fell under this Ask, Calpine EMEC, switched operations to lower emitting fuels and has already locked into the lower emission rates for NO X , SO 2 , and PM by permits. In addition, the McKee Run Generating Station, that fell under this Ask, had its permits cancelled on November 12, 2021. Finally, modified units in Delaware are required to amend their permits through the New Source Review (NSR) process if they plan to switch back to coal or a fuel that will increase emissions. A change in fuel, unless already allowed in the permit, would generally be a modification, 70 and Delaware's operating permits regulations require that an application to modify the permit be submitted prior to the change in fuel. 71

EPA proposes to find that Delaware reasonably determined it has satisfied Ask 4. This is because the permitting and regulatory requirements outlined above, including the fact that sources that have switched fuel are generally required to revise their permits to reflect the change, and because the State rules make any proposed reversion difficult by requiring permitting and other control analyses, including NSR.

Ask 5 requested that “where emission rules have not been adopted,” MANE-VU States “control NO X emissions for peaking combustion turbines that have the potential to operate on HEDD” by meeting at least one of three options: (a) striving to meet NO X emissions standards specified in the Ask for turbines that run on natural gas and fuel oil, (b) performing a four-factor analysis for reasonable installation of or upgrade to emission controls, or (c) obtaining equivalent alternative emission reductions on HEDD. 72

For Ask 5, EPA reviewed and evaluated Delaware's response to the four-factor analyses on the five sources and found that the State agreed with Calpine's conclusions for each of the sources. Delaware agreed that it is economically and technically infeasible to retrofit the sources' existing NO X controls or to add new NO X controls to further reduce NO X emissions during HEDD, because the units' operation and, hence, NO X emissions are both limited. To support their conclusion, on table 10-5 of the SIP submittal, Delaware included the annual average operating hours and NO X emissions of the sources for a five-year period, which demonstrate the limited operation and the significantly low NO X emissions in recent years ( i.e., less than 4.5 tons of NO X emitted per unit per year). EPA agrees with Delaware that it is not reasonable to upgrade any of the sources' NO X existing controls or to install new controls due to the extremely low emission reductions that would have been achieved, and that the costs of compliance, as demonstrated through the four-factor analyses, are not justified by the low amount of NO X emission reductions that the sources would achieve if these were reconfigured. More information on the extremely low amount of NO X emitted from these units with can be found in the TSD at 32-33.

EPA also reviewed and evaluated the State's selection and modification of the applicable EGUs' title V permits to incorporate the regional haze requirements of the second planning period. To meet Ask 5, DNREC updated ChEC, DEC, and WEC's Title V permits after conducting four-factor analyses and added the 88 ppm NO X emission limit during April and October. Delaware issued the new permits on May 19, 2021 and included them in appendix 10-2 of its SIP submittal; redacted copies of these permits were subsequently resubmitted to EPA with an effective date of December 19, 2023 so that the portions relevant to compliance with the regional haze requirements of the second planning period could be incorporated into the Delaware SIP. 73 Based on the above-mentioned facts, EPA thus agrees with Delaware's conclusions and proposes to find that Delaware reasonably determined it has satisfied Ask 5.

Through Ask 6, MANE-VU requests that “each State should consider and report in their SIP measures or programs to: (a) decrease energy demand through the use of energy efficiency, and (b) increase the use within their State of Combined Heat and Power (CHP) and other clean Distributed Generation technologies including fuel cells, wind, and solar.”  74 The fact that Delaware has listed its various greenhouse gas initiatives and clean energy requirements within the State including Executive Order 31—Energy Task Force, energy efficiency initiatives such as the EEAC, grants programs, Delaware Energy Code Coalition, and CHP Grant Pathway Program, RPS, RGGI, Delaware's Climate Change Impact Assessment and a Climate Action Plan, suggests that Delaware has in fact reasonably satisfied the Ask. EPA is therefore proposing to find that Delaware has reasonably determined it has met Ask 6's request to consider and report in its SIP measures or programs related to energy efficiency, cogeneration, and other clean distributed generation technologies.

Based on all of the above, EPA is proposing to find that—based on Delaware's participation in the MANE-VU planning process, how it has addressed each of the Asks, its supplemental information and explanation regarding NO X sources and emissions, and EPA's additional assessment of Delaware's emissions and point sources—Delaware has complied with the requirements of 40 CFR 51.308(f)(2). 75

As explained above, Delaware relied on MANE-VU's technical analyses and framework ( i.e., the Asks) to select sources and form the basis of its long-term strategy. MANE-VU conducted an inventory analysis to identify the source sectors that produced the greatest amount of SO 2 and NO X emissions in 2011; inventory data were also projected to 2018. Based on this analysis, MANE-VU identified the top-emitting sectors for each of the two pollutants, which for SO 2 include coal-fired EGUs, industrial boilers, oil-fired EGUs, and oil-fired area sources including residential, commercial, and industrial sources. Major-emitting sources of NO X include on-road vehicles, non-road vehicles, and EGUs. The RPO's documentation explains that “[EGUs] emitting SO 2 and NO X and industrial point sources emitting SO 2 were found to be sectors with high emissions that warranted further scrutiny. Mobile sources were not considered in this analysis because any ask concerning mobile sources would be made to EPA and not during the intra-RPO and inter-RPO consultation process among the states and tribes.” EPA proposes to find that Delaware reasonably evaluated the two pollutants—SO 2 and NO X —that currently drive visibility impairment within the MANE-VU region and that it adequately explained and supported its decision to focus on these two pollutants through its reliance on the MANE-VU technical analyses cited in its submission.

Section 51.308(f)(2)(i) requires States to evaluate and determine the emission reduction measures that are necessary to make reasonable progress by applying the four statutory factors to sources in a control analysis. As explained previously, the MANE-VU Asks are a mix of measures for sectors and groups of sources identified as reasonable for States to address in their regional haze plans. While MANE-VU formulated the Asks to be “reasonable emission reduction strategies” to control emissions of visibility impairing pollutants, EPA believes that Delaware's responses to four of the Asks, in particular, engage with the requirement that States determine the emission reduction measures that are necessary to make reasonable progress through consideration of the four factors. Specifically, MANE-VU Asks 1, 2, 3 and 5 engage with the requirement that States evaluate and determine the emission reduction measures that are necessary to make reasonable progress by considering the four statutory factors. EPA is proposing to find that Delaware's approach to Asks 1, 2, 3 and 5 is reasonable because it demonstrated that the sources and source sectors with impacts on visibility either: (1) have reduced their emissions so significantly that it is clear a four-factor analysis would not yield further reasonable emission reductions, (2) completed four-factor analyses and adopted economically feasible controls, or (3) are subject to stringent emission control measures. Delaware's SIP-approved control measures, emissions inventory  76 and information provided in response to comments  77 demonstrate that the sources of SO 2 and NO X within the State that would be expected to contribute to visibility impairment have low emissions of NO X and SO 2 , are well controlled, or both. Therefore, it is reasonable to assume that selecting additional sources for four-factor analysis would not have resulted in additional emission reduction measures being determined to be necessary to make reasonable progress for the second implementation period. EPA is proposing to incorporate the redacted permits submitted on March 7, 2024 into the SIP.

The consultation requirements of 40 CFR 51.308(f)(2)(ii) provide that States must consult with other States that are reasonably anticipated to contribute to visibility impairment in a Class I Area to develop coordinated emission management strategies containing the emission reductions measures that are necessary to make reasonable progress. Section 51.308(f)(2)(ii)(A) and (B) require States to consider the emission reduction measures identified by other States as necessary for reasonable progress and to include agreed upon measures in their SIPs, respectively. Section 51.308(f)(2)(ii)(C) speaks to what happens if States cannot agree on what measures are necessary to make reasonable progress.

Delaware participated in and provided documentation of the MANE-VU intra- and inter-RPO consultation processes and addressed the MANE-VU Asks by providing information on the measures it has in place that satisfy each Ask. 78 79 MANE-VU also documented disagreements that occurred during consultation. MANE-VU noted in their Consultation Report that upwind States expressed concern regarding the analyses the RPO utilized for the selection of States for the consultation. MANE-VU agreed that these tools, as all models, have their limitations, but nonetheless deemed them appropriate. Additionally, there were several comments regarding the choice of the 2011 modeling base year. MANE-VU agreed that the choice of base year is critical to the outcome of the study. MANE-VU acknowledged that there were newer versions of the emission inventories and the need to use the best available inventory for each analysis. However, MANE-VU disagreed that the choice of these inventories was not appropriate for the analysis. Upwind States also suggested that MANE-VU States adopt the 2021 timeline for regional haze SIP submissions for the second planning period. MANE-VU agreed with the reasons the comments provided, such as collaboration with data and planning efforts. However, MANE-VU disagreed that the 2018 timeline would prohibit collaboration. Additionally, upwind States noted that they would not be able to address the MANE-VU Asks until they finalize their SIPs. MANE-VU believed the assumption of the implementation of the Asks from upwind States in its 2028 control case modeling was reasonable.

In sum, Delaware participated in the MANE-VU intra- and inter-RPO consultation and satisfied the MANE-VU Asks, satisfying 40 CFR 51.308(f)(2)(ii)(A) and (B). Delaware satisfied 40 CFR 51.308(f)(2)(ii)(C) by participating in MANE-VU's consultation process, which documented the disagreements between the upwind States and MANE-VU and explained MANE-VU's reasoning on each of the disputed issues. Based on the entirety of MANE-VU's intra- and inter-RPO consultation and both MANE-VU's and Delaware's responses to States' comments on the SIP submission and various technical analyses therein, we propose to determine that Delaware has satisfied the consultation requirements of 40 CFR 51.308(f)(2)(ii).

The documentation requirement of 40 CFR 51.308(f)(2)(iii) provides that States may meet their obligations to document the technical bases on which they are relying to determine the emission reductions measures that are necessary to make reasonable progress through an RPO, as long as the process has been “approved by all State participants.” As explained above, Delaware chose to rely on MANE-VU's technical information, modeling, and analysis to support development of its long-term strategy. The MANE-VU technical analyses on which Delaware relied are listed in the State's SIP submission and include source contribution assessments, information on each of the four factors and visibility modeling information for certain EGUs, and evaluations of emission reduction strategies for specific source categories. Delaware also provided supplemental information to further demonstrate the technical bases and emission information on which it relied on to determine the emission reductions measures that are necessary to make reasonable progress. Based on the documentation provided by the State, we propose to find Delaware satisfies the requirements of 40 CFR 51.308(f)(2)(iii).

Section 51.308(f)(2)(iii) also requires that the emissions information considered to determine the measures that are necessary to make reasonable progress include information on emissions for the most recent year for which the State has submitted triennial emissions data to EPA (or a more recent year), with a 12-month exemption period for newly submitted data. Delaware's SIP submission included 2017 NEI emission data for NO X , SO 2 , PM, VOCs and NH 3 , and 2017 Air Markets Program Data (AMPD) emissions for NO X and SO 2 . Delaware's SIP submission also included 2019 AMPD for NO X and SO 2 . 80 Based on Delaware's consideration and analysis of the 2017 and 2019 emission data in their SIP submittal and supplemental documentation, EPA proposes to find that Delaware has satisfied the emissions information requirement in 40 CFR 51.308(f)(2)(iii).

We also propose to find that Delaware reasonably considered the five additional factors in 40 CFR 51.308(f)(2)(iv) in developing its long-term strategy. Pursuant to 40 CFR 51.308(f)(2)(iv)(A), Delaware noted that existing and ongoing State and Federal emission control programs that contribute to emission reductions through 2028 would impact emissions of visibility impairing pollutants from point and nonpoint sources in the second implementation period. Delaware included in its SIP comprehensive lists of control measures with their effective dates, pollutants addressed, and corresponding Delaware Administrative Code provisions. 81

Delaware's consideration of measures to mitigate the impacts of construction activities as required by 40 CFR 51.308(f)(2)(iv)(B) began during the Regional Haze first implementation period. Delaware indicated that it has regulations that mitigate potential impacts of construction on visibility such as the 7 DE Admin Code 1106, which regulates particulate emissions from construction and materials handling in the State. In addition, Delaware stated that based on the 2017 NEI, commercial construction emissions of PM 2.5 were 135 tons, which makes up only 3% of the PM 2.5 emissions inventory within the State. Delaware concluded that “ Because the contribution from construction dust is small, Delaware is determining that no changes in its regulatory program for construction dust is necessary to make reasonable progress. ”  82

Pursuant to 40 CFR 51.308(f)(2)(iv)(C), source retirements and replacement schedules are addressed in section 8.8 of Delaware's submission. Source retirements and replacements were considered in developing the 2028 emission projections, with on the books/on the way retirements and replacements included in the 2028 projections, with on the books/on the way retirements and replacements included in the 2028 projections. The EGU point sources included in the inventories used in the MANE-VU contribution assessment and that were subsequently retired are identified in Delaware's SIP submittal as McKee Run and Indian River Generating Stations. No non-EGU point source retirements in Delaware were considered when developing the 2028 emissions projections.

In considering smoke management as required in 40 CFR 51.308(f)(2)(iv)(D), Delaware explained, in section 8.9 of its submission, that emission contribution from prescribed agricultural and forest burning within the State are low; PM 2.5 statewide emissions from prescribed fires were 36 tons and emissions from agricultural burning were 60 tons (2% of Delaware's overall PM 2.5 emissions inventory). Delaware therefore concludes that it is unlikely that fires in Delaware for agricultural or forestry management cause impacts on visibility in the MANE-VU and nearby Class I Areas, including the Brigantine Wilderness Class I Area. Delaware states that Smoke Management Plans (SMPs) is a required element of a SIP only if it is required to make reasonable progress, and that Delaware does not need an official SMP since both a speciation trends analysis report  83 and Delaware's 2014 emissions inventory data show that agricultural and forestry management woodsmoke emissions are low. However, Delaware notes that under 7 DE Admin 1113 for Open Burning, during the months of May to September, both prescribed and agricultural burning are prohibited, and even though DNREC does not consider open burning regulation an SMP, the regulation does benefit Class I Areas to some degree.

Delaware considered the anticipated net effect of projected changes in emissions as required by 51.308(f)(2)(iv)(E) by discussing, in section 8.10 of its submission, the photochemical modeling for the 2018-2028 period it conducted in collaboration with MANE-VU. The two modeling cases run were a 2028 base case, which considered only on-the-books controls, and a 2028 control case that considered implementation of the MANE-VU Ask. Delaware presented the differences between the base and control cases on the 20% most impaired and 20% clearest days for each MANE-VU Class I Area. 84

Because Delaware has reasonably considered each of the five additional factors, EPA proposes to find that Delaware has satisfied the requirements of 40 CFR 51.308(f)(2)(iv).

Section 51.308(f)(3) contains the requirements pertaining to RPGs for each Class I Area. Section 51.308(f)(3)(i) requires a State in which a Class I Area is located to establish RPGs—one each for the most impaired and clearest days—reflecting the visibility conditions that will be achieved at the end of the implementation period as a result of the emission limitations, compliance schedules and other measures required under paragraph (f)(2) to be in States' long-term strategies, as well as implementation of other CAA requirements. The long-term strategies as reflected by the RPGs must provide for an improvement in visibility on the most impaired days relative to the baseline period and ensure no degradation on the clearest days relative to the baseline period. Section 51.308(f)(3)(ii) applies in circumstances in which a Class I Area's RPG for the most impaired days represents a slower rate of visibility improvement than the uniform rate of progress calculated under 40 CFR 51.308(f)(1)(vi). Under 40 CFR 51.308(f)(3)(ii)(A), if the State in which a mandatory Class I Area is located establishes an RPG for the most impaired days that provides for a slower rate of visibility improvement than the URP, the State must demonstrate that there are no additional emission reduction measures for anthropogenic sources or groups of sources in the State that would be reasonable to include in its long-term strategy. Section 51.308(f)(3)(ii)(B) requires that if a State contains sources that are reasonably anticipated to contribute to visibility impairment in a Class I Area in another State, and the RPG for the most impaired days in that Class I Area is above the URP, the upwind State must provide the same demonstration. Because Delaware has no Class I Areas within its borders, it is subject only to 40 CFR 51.308(f)(3)(ii)(B).

Under 40 CFR 51.308(f)(3)(ii)(B), a State that contains sources that are reasonably anticipated to contribute to visibility impairment in a Class I Area in another State for which a demonstration by the other State is required under 40 CFR 51.308(f)(3)(ii)(B) must demonstrate that there are no additional emission reduction measures that would be reasonable to include in its long-term strategy. Delaware's SIP submittal included MANE-VU's glidepath checks for nearby downwind Class I Areas, 85 such as the Brigantine Wilderness Class I Area, 86 which show that the RPG for the 20 percent most anthropogenically impaired days for the affected downwind Class I Areas (Acadia, Moosehorn, Great Gulf, Lye Brook, Brigantine, Shenandoah, Dolly Sods and James River Face) are not above the URP glidepath, and that the RPG for the 20 percent clearest days shows no degradation. In addition, the modeled MANE-VU 2028 visibility projections at nearby Class I Areas show that the base case 2028 projections for the most impaired days at these areas are below the respective 2028 points on the URPs. Therefore, we propose it is reasonable to assume that the demonstration requirement under 40 CFR 51.308(f)(3)(ii)(B) as it pertains to these areas will not be triggered.

EPA proposes to determine that Delaware has satisfied the applicable requirements of 40 CFR 51.308(f)(3) relating to RPGs.

Section 51.308(f)(6) specifies that each comprehensive revision of a State's regional haze SIP must contain or provide for certain elements, including monitoring strategies, emissions inventories, and any reporting, recordkeeping and other measures needed to assess and report on visibility. A main requirement of this section is for States with Class I Areas to submit monitoring strategies for measuring, characterizing, and reporting on visibility impairment. Compliance with this requirement may be met through participation in the IMPROVE network.

Section 51.308(f)(6)(i) requires SIPs to provide for the establishment of any additional monitoring sites or equipment needed to assess whether reasonable progress goals to address regional haze for all mandatory Class I Areas within the State are being achieved. Section 51.308(f)(6)(ii) requires SIPs to provide for procedures by which monitoring data and other information are used in determining the contribution of emissions from within the State to regional haze visibility impairment at mandatory Class I Areas both within and outside the State. Because Delaware does not have any Class I Areas located within its borders, § 51.308(f)(6)(i) and (ii) do not apply.

Section 51.308(f)(6)(iii) requires States with no Class I Areas to include procedures by which monitoring data and other information are used in determining the contribution of emissions from within the State to regional haze visibility impairment at Class I Areas in other States. States with Class I Areas must establish a monitoring program and report data to EPA that is representative of visibility at the Class I Areas. The IMPROVE network meets this requirement. Delaware stated that, it has conducted receptor modeling and emissions inventory analysis to determine source contributions from within the State, and the proportional impacts of those sources to areas outside the State. Even though, Delaware does not have IMPROVE monitors, Delaware agrees that NESCAUM is providing quality technical information by using the IMPROVE program data and the Visibility Information Exchange Web System (VIEWS) site for the regional haze purposes.

Section 51.308(f)(6)(iv) requires the SIP to provide for the reporting of all visibility monitoring data to the Administrator at least annually for each Class I Area in the State. As noted above, Delaware does not have any Class I Areas located within its borders, therefore this requirement does not apply.

Section 51.308(f)(6)(v) requires SIPs to provide for a statewide inventory of emissions of pollutants that are reasonably anticipated to cause or contribute to visibility impairment, including emissions for the most recent year for which data are available and estimates of future projected emissions. It also requires a commitment to update the inventory periodically. Delaware provides for emissions inventories and estimates for future projected emissions by participating in the MANE-VU RPO and complying with EPA's Air Emissions Reporting Rule (AERR). In 40 CFR part 51, subpart A, the AERR requires States to submit updated emissions inventories for criteria pollutants to EPA's Emissions Inventory System (EIS) every three years. The emission inventory data is used to develop the NEI, which provides for, among other things, a triennial state-wide inventory of pollutants that are reasonably anticipated to cause or contribute to visibility impairment.

Section 7 of Delaware's submission includes tables of NEI data. The source categories of the emissions inventories included are: (1) point sources, (2) nonpoint sources, (3) non-road mobile sources, and (4) on-road mobile sources. The point source category is further divided into AMPD point sources and non-AMPD point sources. 87 Delaware included NEI emissions inventories for the following years: 2002 (one of the regional haze program baseline years), 2008, 2011, 2014, and 2017;  88 and for the following pollutants: NO X , PM 10 , PM 2.5 , SO 2 , VOCs, and NH 3 . Delaware also provided a summary of SO 2 and NO X emissions for AMPD sources for the years of 2016, 2017, 2018, and 2019. 89

Section 51.308(f)(6)(v) also requires States to include estimates of future projected emissions and include a commitment to update the inventory periodically. Delaware relied on the MANE-VU 2028 emissions projections for MANE-VU States. MANE-VU completed two 2028 projected emissions modeling cases—a 2028 base case that considers only on-the-books controls and a 2028 control case that considers implementation of the MANE-VU Asks. 90

EPA proposes to find that Delaware has met the requirements of 40 CFR 51.308(f)(6) as described above, including through its continued participation in the IMPROVE network and the MANE-VU RPO and its ongoing compliance with the AERR, and that no further elements are necessary at this time for Delaware to assess and report on visibility pursuant to 40 CFR 51.308(f)(6)(vi).

Section 51.308(f)(5) requires that periodic comprehensive revisions of States' regional haze plans also address the progress report requirements of 40 CFR 51.308(g)(1) through (5). The purpose of these requirements is to evaluate progress towards the applicable RPGs for each Class I Area within the State and each Class I Area outside the State that may be affected by emissions from within that State. Section 51.308(g)(1) and (2) apply to all States and require a description of the status of implementation of all measures included in a State's first implementation period regional haze plan and a summary of the emission reductions achieved through implementation of those measures. Section 51.308(g)(3) applies only to States with Class I Areas within their borders and requires such States to assess current visibility conditions, changes in visibility relative to baseline (2000-2004) visibility conditions, and changes in visibility conditions relative to the period addressed in the first implementation period progress report. Section 51.308(g)(4) applies to all States and requires an analysis tracking changes in emissions of pollutants contributing to visibility impairment from all sources and sectors since the period addressed by the first implementation period progress report. This provision further specifies the year or years through which the analysis must extend depending on the type of source and the platform through which its emission information is reported. Finally, 40 CFR 51.308(g)(5), which also applies to all States, requires an assessment of any significant changes in anthropogenic emissions within or outside the State that have occurred since the period addressed by the first implementation period progress report, including whether such changes were anticipated and whether they have limited or impeded expected progress towards reducing emissions and improving visibility.

Delaware's submission describes the status of measures of the long-term strategy from the first implementation period. As a member of MANE-VU, Delaware considered the MANE-VU Asks and adopted corresponding measures into its long-term strategy for the first implementation period. The MANE-VU Asks were: (1) timely implementation of BART requirements; (2) EGU controls including Controls at 167 Key Sources that most affect MANE-VU Class I Areas; (3) low sulfur fuel oil strategy; and (4) continued evaluation of other control measures. Delaware met all the identified reasonable measures requested during the first implementation period. During the first planning period for regional haze, programs that were put in place focused on reducing SO 2 emissions. The reductions achieved led to vast improvements in visibility at the MANE-VU Class I Areas due to reduced sulfates formed from SO 2 emissions. Delaware describes in section 11 of its submittal control measures put in place during the first implementation period to help reduce the emissions of visibility impairing pollutants, including NO X and SO 2 . This includes a non-trading emissions control regulation  91 for EGUs to aid in the attainment of ozone and PM ambient air quality standards and reduce emissions of neurotoxin mercury. Delaware Stated that the regulation “ provides for stringent control of EGU NO X and SO 2 emissions by implementation of unit-specific annual NO X and SO 2 mass emissions caps and short term (rolling 24-hour) NO X and SO 2 emission rate limits (lb/MMBTU) .” Delaware added that implementation of the 7 DE Admin Code 1146, among other measures, like related consent decrees and permit conditions, have served to significantly reduce Delaware's NO X and SO 2 emissions from the EGUs that were subject to it and demonstrated it in table 10-8 and Figure 10-1 of the DE Regional Haze SIP submittal. The first step change reduction of NO X and SO 2 emissions happened in 2009, corresponding to the promulgation of 7 DE Admin Code 1146. Based on the data, by 2019, the EGUs that were subject to this State regulation had reduced their SO 2 and NO X mass emissions by 30,197 tpy and 8,005 tpy, which is approximately 99% and 98% emissions reductions, respectively.

Delaware also described the status of the implementation of primary particulate matter BART for the respective eligible EGUs, how they were able to meet the 90% or greater SO 2 reduction emissions at 167 stacks inside and outside of MANE-VU, their low sulfur fuel oil standards  92 for the State, and the status of other control methods  93 established during and after the first implementation period.

EPA proposes to find that Delaware has met the requirements of 40 CFR 51.308(g)(1) and (2) because its SIP submission describes the measures included in the long-term strategy from the first implementation period, as well as the status of their implementation and the emission reductions achieved through such implementation.

Section 51.308(g)(3) requires States to assess Reasonable Progress Goals, including current visibility conditions and changes, for any Class I Areas within the State. As described above, Delaware does not have any Class I Areas within its borders, therefore § 51.308(g)(3) does not apply.

Pursuant to 40 CFR 51.308(g)(4), in section 7 of their submittal, Delaware provided a summary of emissions of NO X , PM 10 , PM 2.5 , SO 2 , VOCs, and NH 3 from all sources and activities, including from point, nonpoint, non-road mobile, and on-road mobile sources, for the time period from 2002 to 2017. Delaware also included AMPD data for SO 2 and NO X emissions for 2016, 2017, 2018 and 2019 in their submission.

The reductions achieved by Delaware emission control measures are seen in the emissions inventory. Based on Delaware's SIP submission, NO X emissions have continuously declined in Delaware from 2002 through 2017, especially in the point, nonroad and onroad mobile sectors. During that period, onroad sources contributed almost half of the emissions at 41%, followed by area sources at 21%. Nonroad sources contributed 15% and point sources contributed the least at 14%. Table 7-2 of Delaware's SIP submittal also shows additional NO X emissions data from 2016 to 2019 for Delaware's point sources that report to EPA's AMPD. 94 NO X emissions are expected to continue to decrease as fleet turnover occurs and the older more polluting vehicles and equipment are replaced by newer, cleaner ones. 95

Emissions of PM 10 have generally remained relatively stable and in a downward trend in Delaware from 2002 to 2017, particularly in the point, nonroad and onroad sectors, see section 7.1.2 and table 7-7 of Delaware's SIP submittal. The variations in the onroad are due to changes in emission inventory calculation methodologies, which resulted in higher particulate matter estimates in the other years than in 2002. The large variation in emissions in the nonpoint category is due to changes in calculation methodologies for residential wood burning and fugitive dust categories, which have varied significantly. Similar trends are observed for emissions of PM 2.5 in Delaware from 2002 to 2017, see section 7.1.3 and table 7-10 of Delaware's SIP submittal. As with PM 10 , some of the variations could be due to changes in estimation methodologies for categories such as yard waste burning, paved and unpaved road dust and residential wood combustion.

Emissions of SO 2 have shown a steady significant decline in Delaware over the period 2002 to 2017, across all multiple sectors. 96 Delaware stated that these reductions are primarily due to promulgation of 7 DE Admin Code 1146 and 1108. 97 Additionally, some of these decreases are attributable to the MANE-VU low sulfur fuel strategy and the 90% or greater reduction in SO 2 emissions at 167 EGU stacks, both inside and outside of MANE-VU, requested in the “Non-MANE-VU Ask” for States within MANE-VU for the first regional haze planning period. 98

Table 7-21 of Delaware's SIP submittal shows VOC emissions from all NEI data categories for the period 2002 to 2017 in Delaware, which have shown a steady decline. VOC decreases were achieved in all sectors due to Federal and State rules for evaporative sources of VOC emissions such as portable fuel containers; architectural, industrial, and maintenance coatings (AIM); adhesives and sealants, consumer products; and solvent degreasing. 99 The State added that other decreases are due to States' VOC RACT rules and due to State motor vehicle Inspection & Maintenance (I&M) programs and the permeation of more on-board refueling vapor recovery (ORVR) equipped vehicles into the fleet.

Emissions of NH 3 have shown declines in Delaware from 2002 to 2017; see section 7.1.6 and table 7-24 of Delaware's SIP submittal. Ammonia decreases were achieved in the onroad sector due to Federal new engine standards for vehicles and equipment. Nonpoint increases and decreases from 2002 to 2014 are due to reporting, grouping and methodology changes. While ammonia emissions were stable between 2014 and 2017 inventories, there was a slight increase in ammonia emissions from 2011 and 2014. The increase is due to methodology changes and the addition of NH 3 emissions from domestic and wild animals in 2014.

EPA is proposing to find that Delaware has satisfied the requirements of 40 CFR 51.308(g)(4) by providing emissions information for NO X , PM 10 , PM 2.5 , SO 2, VOCs, and NH 3 broken down by type of source.

Delaware uses the emissions trend data in the SIP submission  100 and supporting MANE-VU information  101 provided to support the assessment that anthropogenic haze-causing pollutant emissions in Delaware have decreased during the reporting period and that changes in emissions have not limited or impeded progress in reducing pollutant emissions and improving visibility. Delaware's 2017 emission inventories for NO X , PM 10 , PM 2.5 , SO 2 , VOCs, and NH 3 were lower than their 2014 emission inventories for those same pollutants emissions. 102 EPA is proposing to find that Delaware has met the requirements of 40 CFR 51.308(g)(5).

Section 169A(d) of the Clean Air Act requires States to consult with FLMs before holding the public hearing on a proposed regional haze SIP, and to include a summary of the FLMs' conclusions and recommendations in the notice to the public. In addition, 40 CFR 51.308(i)(2)'s FLM consultation provision requires a State to provide FLMs with an opportunity for consultation that is early enough in the State's policy analyses of its emission reduction obligation so that information and recommendations provided by the FLMs can meaningfully inform the State's decisions on its long-term strategy. If the consultation has taken place at least 120 days before a public hearing or public comment period, the opportunity for consultation will be deemed early enough. Regardless, the opportunity for consultation must be provided at least sixty days before a public hearing or public comment period at the State level. Section 51.308(i)(2) also provides two substantive topics on which FLMs must be provided an opportunity to discuss with States: assessment of visibility impairment in any Class I Area and recommendations on the development and implementation of strategies to address visibility impairment. Section 51.308(i)(3) requires States, in developing their implementation plans, to include a description of how they addressed FLMs' comments.

The States in the MANE-VU RPO conducted FLM consultation early in the planning process concurrent with the state-to-state consultation that formed the basis of the RPO's decision making process. As part of the consultation, the FLMs were given the opportunity to review and comment on the technical documents developed by MANE-VU. The FLMs were invited to attend the intra- and inter-RPO consultations calls among States and at least one FLM representative was documented to have attended seven intra-RPO meetings and all inter-RPO meetings. Delaware participated in these consultation meetings and calls. 103

As part of this early engagement with the FLMs, on April 12, 2018, the NPS sent letters to the MANE-VU States requesting that they consider specific individual sources in their long-term strategies. 104 NPS used an analysis of emissions divided by distance (Q/d) to estimate the impact of MANE-VU facilities. To select the facilities, NPS first summed 2014 NEI NO X , PM 10 , SO 2 , and SO 4 emissions and divided by the distance to a specified NPS mandatory Class I Federal area. NPS summed the Q/d values across all MANE-VU States relative to Acadia, Mammoth Cave and Shenandoah National Parks, ranked the Q/d values relative to each Class I Area, created a running total, and identified those facilities contributing to 80% of the total impact at each NPS Class I Area. NPS applied a similar process to facilities in Maine relative to Acadia National Park. NPS merged the resulting lists of facilities and sorted them by their States. NPS suggested that a State consider those facilities comprising 80% of the Q/d total, not to exceed the 25 top ranked facilities. The NPS identified two facilities in Delaware in this letter. 105 Delaware included the NPS initial letter in their proposed SIP. In a subsequent letter dated October 22, 2018, NPS identified two facilities for which more control information was desired. Delaware detailed the emission controls and updates to the two facilities to address the NPS's request for more information. 106

On February 11, 2021, Delaware submitted a draft Regional Haze SIP to the U.S. Forest Service, the U.S. Fish and Wildlife Service, and the National Park Service for a 60-day review and comment period pursuant to 40 CFR 51.308(i)(2). 107 Delaware received comments from the Forest Service on March 31, 2021, and from the National Park Service on April 9, 2021. Delaware responded to the FLM comments and included the responses in appendix 4-1 of their submission to EPA, in accordance with 40 CFR 51.308(i)(3). Notices of the proposed SIP, availability and the public hearing were published on DNREC's website and in the Delaware Register, and interested parties were emailed the notice, along with air quality contacts from other States, air quality regional organizations and the EPA. A public hearing on the proposed SIP revision was held on December 29, 2021. Written comments relevant to the proposal were accepted until the close of business January 13, 2022.

For the reasons stated above, EPA proposes to find that Delaware has satisfied the requirements under 40 CFR 51.308(i) to consult with the FLMs on its regional haze SIP for the second implementation period.

Delaware's August 2022 SIP submission includes a commitment to revise and submit a regional haze SIP by July 31, 2028, and every ten years thereafter. The State's commitment includes submitting periodic progress reports in accordance with 40 CFR 51.308(f) and a commitment to evaluate progress towards the reasonable progress goal for each mandatory Class I Area located within the State and in each mandatory Class I Area located outside the State that may be affected by emissions from within the State in accordance with 40 CFR 51.308(g). 108

EPA is proposing to approve Delaware's August 8, 2022, SIP submission, and supplemental SIP submission dated March 7, 2024, as satisfying the regional haze requirements for the second implementation period contained in 40 CFR 51.308(f).

In accordance with requirements of 1 CFR 51.5, EPA is proposing to incorporate by reference specific provisions of the revised title V permits for Calpine Christiana Energy Center, Calpine Delaware City Energy Center, and Calpine West Energy Center, dated and effective December 19, 2023, between DNREC and Calpine Mid-Atlantic Generation, LLC, which includes emission limits and associated permit conditions for these facilities to comply with Regional Haze requirements for the 2nd Planning Period, as discussed in section IV of this preamble. These permit revisions are contained in DNREC's supplemental SIP submittal dated March 7, 2024, submitted on behalf of the State of Delaware; the portions of these permit revisions that will be incorporated by reference into the SIP are clarified by the DNREC Air Quality Division Director via a letter dated May 28, 2024. EPA has made, and will continue to make, these materials generally available through www.regulations.gov and at the EPA Region 3 Office (please contact the person identified in the FOR FURTHER INFORMATION CONTACT section of this preamble for more information). Therefore, these materials have been proposed for approval by EPA for inclusion in the SIP, will be incorporated by reference by EPA into that plan, will be fully federally enforceable under sections 110 and 113 of the CAA as of the effective date of the final rule of EPA's approval, and will be incorporated by reference in the next update to the SIP compilation.

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

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

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

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

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

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

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

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

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

Executive Order 12898 (Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations, 59 FR 7629, February 16, 1994) directs Federal agencies to identify and address “disproportionately high and adverse human health or environmental effects” of their actions on minority populations and low-income populations to the greatest extent practicable and permitted by law. EPA defines environmental justice (EJ) as “the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies.” EPA further defines the term fair treatment to mean that “no group of people should bear a disproportionate burden of environmental harms and risks, including those resulting from the negative environmental consequences of industrial, governmental, and commercial operations or programs and policies.” The Delaware Department of Natural Resources and Environmental Control did not evaluate environmental justice considerations as part of its SIP submittal; the CAA and applicable implementing regulations neither prohibit nor require such an evaluation. EPA did not perform an EJ analysis and did not consider EJ in this action. Due to the nature of the action being taken here, this action is expected to have a neutral to positive impact on the air quality of the affected area. Consideration of EJ is not required as part of this action, and there is no information in the record inconsistent with the stated goal of E.O. 12898 of achieving environmental justice for people of color, low-income populations, and Indigenous peoples.

In addition, this proposed rulemaking action, pertaining to Delaware's regional haze SIP submission for the second planning period, is not approved to apply on any Indian reservation land or in any other area where the EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have Tribal implications and will not impose substantial direct costs on Tribal governments or preempt Tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).

First, PHMSA proposes to redesignate the current prefatory text governing fees for cost recovery in connection with facility design safety reviews as a new paragraph (a); existing paragraphs (a)-(d) will then be redesignated as paragraphs (1)-(4) within the new paragraph (a).

Second, PHMSA proposes introduction of a new paragraph (b) establishing the procedural mechanism for billing and payment of fees for estimated costs for each LNG facility siting review before PHMSA initiates each review, as well as subsequent adjustment of those fees based on PHMSA's actual costs in performing each review. PHMSA proposes those up-front fees for its estimated costs will be derived from the personnel costs associated with historical work efforts by PHMSA personnel involved in performing siting reviews for LNG facility project applications with design and construction costs of $2.5 billion or more, and will automatically change in future calendar years to reflect changes in the salaries of pertinent employees memorialized on OPM's website. PHMSA also proposes that, before issuance of a finding of compliance with its part 193, subpart B, requirements, it will bill the project applicant for any difference in the actual costs incurred by PHMSA and the up-front fee for its estimated costs; issuance of PHMSA's compliance determination will be contingent on an applicant's payment of any outstanding fees as a result of that adjustment process.

Third, and lastly, PHMSA proposes redesignating and clarifying the disclaimer at existing paragraph (e) regarding PHMSA's discretion to exercise its authorities under law to protect public safety and the environment as a new paragraph (c).

This proposed rule is published under the authority of the Secretary of Transportation (Secretary) delegated to the PHMSA Administrator pursuant to 49 CFR 1.97. Among the statutory authorities delegated to PHMSA are those set forth in the federal pipeline safety statutes (49 U.S.C. 60101 et seq. ). Section 60102 authorizes the Secretary to issue regulations governing the design, installation, inspection, emergency plans and procedures, testing, construction, extension, operation, replacement, and maintenance of pipeline facilities. Section 60117(o) directs the Secretary to prescribe procedures for fees recovering PHMSA's costs in performing design safety reviews for jurisdictional pipeline facilities. Lastly, section 103 of the PIPES Act of 2020 (codified at 49 U.S.C. 60303) requires the Secretary to establish procedures for recovering PHMSA's costs in performing LNG facility siting reviews pursuant to 49 CFR part 193, subpart B.

Executive Order 12866 (“Regulatory Planning and Review”), as amended by Executive Order 14094 (“Modernizing Regulatory Review”), requires that agencies “assess all costs and benefits of available regulatory alternatives, including the alternative of not regulating.”  14 Agencies should consider quantifiable measures and qualitative measures of costs and benefits that are difficult to quantify. Further, Executive Order 12866 requires that agencies select those regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity), unless a statute requires another regulatory approach. Similarly, DOT Order 2100.6A (“Rulemaking and Guidance Procedures”) requires that regulations issued by PHMSA and other DOT Operating Administrations consider an assessment of the potential benefits, costs, and other important impacts of the proposed action, and should quantify (to the extent practicable) the benefits, costs, and any significant distributional impacts, including any environmental impacts.

Executive Order 12866 (as amended by Executive Order 14094) and DOT Order 2100.6A require that PHMSA submit “significant regulatory actions” to the Office of Management and Budget (OMB) for review. NPRM is not a significant regulatory action under section 3(f) of Executive Order 12866 (“Regulatory Planning and Review”) and, therefore, was not reviewed by OMB; nor is this NPRM considered a significant rulemaking under DOT Order 2100.6A.

Executive Order 12866 (as amended) and DOT Order 2100.6A also require PHMSA to provide a meaningful opportunity for public participation, which reinforces requirements for notice and comment in the Administrative Procedure Act (APA, 5 U.S.C. 551 et seq. ). In accord with the requirement, PHMSA seeks public comment on the proposals in the NPRM (including preliminary cost and cost savings analyses pertaining to those proposals, as well as discussions of the public safety, environmental, and equity benefits), as well as any information that could assist in evaluating the benefits and costs of PHMSA's NPRM.

Consistent with Executive Order 12866 (as amended by Executive Order 14094) and DOT Order 2100.6A, PHMSA has assessed the benefits and costs of the proposed rule as well as reasonable alternatives. As discussed in section II above, this rulemaking implements a mandate by Congress in section 103 of the PIPES Act of 2020 for the establishment of procedures for recovery of PHMSA's costs in performing part 193, subpart B, design reviews of large ($2.5 billion or more design and construction costs) LNG facility project applications to FERC. PHMSA expects the proposed rule could result in unquantified public safety and environmental benefits by preventing the potential diversion of PHMSA's limited resources from the Agency's other pipeline safety regulatory oversight responsibilities to cover costs associated with PHMSA's LNG facility siting reviews for those projects. However, because it is not clear which activities would go unfunded due to the costs of conducting LNG facility siting reviews, PHMSA is unable to quantify those benefits with a meaningful degree of certainty.

PHMSA acknowledges that its proposed new fees providing cost recovery for its part 193, subpart B, LNG facility siting reviews will impose a new line item cost on affected applicants seeking FERC authorization to construct and operate certain LNG facilities. Pursuant to an August 2018 Memorandum of Understanding (MOU) between FERC and PHMSA, FERC agreed to reimburse PHMSA for direct costs that PHMSA incurred performing LNG facility siting reviews that are considered in FERC's authorization certificate application process. FERC and PHMSA subsequently entered into an interagency agreement whereby FERC reimbursed PHMSA for time spent by PHMSA staff to complete siting reviews for LNG facilities. The funds FERC used for those reimbursements were not passed along as a cost to applicants. The fees proposed herein will, therefore, be a new cost for affected applicants.

Since the August 2018 FERC/PHMSA MOU, PHMSA has on average completed seven siting reviews for LNG facility applications of any size per year, with a typical breakdown of labor required from PHMSA employees for large facilities (design and construction costs of $2.5 billion or more) as laid out in the table below. 15

PHMSA calculates the cost of an average siting review to include approximately $41,000 in wages, and an additional $14,000 in non-wage benefits, for an average per siting review cost of $65,000. 17 PHMSA projects that, notwithstanding continued demand for LNG worldwide, the volume of its review of applications for new, large LNG facility projects of the sort that would be subject to the fees proposed herein will decrease going forward, given reduced interest in building new LNG facilities due to large-scale LNG export terminals that have already been built or authorized, and a wave of recently announced LNG export projects in other exporting countries. 18 PHMSA has therefore conservatively estimated that (1) the current average of seven reviews for facilities of any size per year would reduce to six over the next three years, then to five, and finally four per year over the remaining years within a 10-year forecast period; and (2) those reviews would be for large ($2.5 billion or more design and construction costs) projects that would be subject to the cost recovery requirements proposed herein. Similarly, PHMSA expects that its own personnel costs in conducting part 193, subpart B, siting reviews for those facilities will be at or near its historical estimated average of $65,000 per review throughout the analysis period as that value accounts for a range of LNG facility projects—some well in excess of, and some closer to, the $2.5 billion monetary threshold PHMSA proposes in this NPRM. 19

Given the reduced frequency of the required siting reviews and assuming the current average cost to remain static over the 10-year forecast period, the rule would result in an additional burden of approximately $3.71 million over 10 years, as described in Table 3.

This is discounted to $3.43 million using a two percent rate, and the annualized cost is $381,899. Although these costs associated with directly itemized and billed LNG facility siting reviews are not substantial relative to the total project costs ($2.5 billion or greater), these costs in this proposed rulemaking will create a new cost for affected applicants.

As a sensitivity analysis, alternative costs assuming a constant demand for siting reviews per year are presented below in Table 4, as opposed to the moderately decreased demand presented in Table 3 above.

Under this scenario, the nominal cost over 10 years increases from $3.71 million to $4.55 million—discounted to $4.17 million at two percent—from the original $3.43 million. The annualized cost estimate increases from $381,899 to $464,100 under this alternative scenario.

In both of these scenarios, the total cost to industry over the next 10 years would be less than $5 million. For comparison, PHMSA takes the value of a statistical life to be $12.5 million, 20 meaning that prevention of even one fatality by avoiding diversion of limited PHMSA personnel resources from other regulatory oversight responsibilities over the next 10 years would cause the benefits of this rule to exceed the costs twice over. Similarly, when ranking injuries on the 6-Point Maximum Abbreviated Injury Scale (MAIS), a MAIS 5 “critical” injury is valued at approximately $7.4 million, 21 so preventing even one “critical” injury over the next 10 years would cause the benefits of this rule to exceed the costs. While PHMSA is not able to estimate the benefits of this rule due to uncertainty about which projects would go unfunded in its absence, it believes the benefits of the rule would exceed the costs.

With respect to the anticipated benefits of the rulemaking, as discussed in section II above, PHMSA (absent a statutory change to increase the funds appropriated to the Liquefied Natural Gas Siting Account) would not be able to spend any collected fees for LNG facility siting reviews in excess of $400,000 appropriated by Congress in the 2023 Act. However, PHMSA has been mandated to recover costs associated with LNG facility siting reviews, even if it does not yet have approval to spend the collected funds in excess of the $400,000 appropriated by the 2023 Act. Thus, the potential safety benefits of this rule may not be fully realized until PHMSA is authorized by Congress to spend the fees it collects as they are received, or unless in future legislation Congress appropriates funds commensurate with fees collected pursuant to this rulemaking.

Lastly, PHMSA has considered and rejected alternatives to the fee recovery procedures proposed in this NPRM. PHMSA notes that it lacks discretion to avoid establishing fees for cost recovery as proposed herein given that this rulemaking responds to a congressional mandate in section 103 of the PIPES Act of 2020 to establish such procedures. PHMSA also submits that other, alternative approaches for calculating and assessing such fees ( e.g., employing the negotiated Master Agreement approach used for pipeline facility design review cost recovery; assessing actual costs on completion of its LNG facility siting review; etc.) could involve considerable delay before PHMSA receives fees, thereby increasing the risk that PHMSA's limited resources would be diverted from other critical regulatory oversight functions. In contrast, PHMSA expects its approach proposed in this NPRM appropriately balances its and projects applicants' interests. An applicant's payment of fees at initiation of each part 193, subpart B, LNG facility siting review will ensure the Agency has timely access to funds needed to perform that review without diversion of PHMSA's limited resources from other regulatory oversight activities. Moreover, PHMSA's proposed “true-up” mechanism at the conclusion of that review ensures it will be made whole by each applicant for any actual costs incurred conducting a siting review for that applicant's LNG facility project. Lastly, the flat, up-front estimated fee PHMSA proposes to use for its estimated costs in performing each LNG facility siting review provides certainty for applicants in projecting costs associated with their FERC applications.

The Regulatory Flexibility Act, as amended by the Small Business Regulatory Flexibility Fairness Act of 1996 (5 U.S.C. 601 et seq. ), generally requires federal agencies to prepare an initial regulatory flexibility analysis (IRFA) for a proposed rule subject to notice-and-comment rulemaking under the Administrative Procedures Act (5 U.S.C. 604(a)). 22 Executive Order 13272 (“Proper Consideration of Small Entities in Agency Rulemaking”)  23 obliges agencies to establish procedures promoting compliance with the Regulatory Flexibility Act; DOT's implementing guidance is available on its website. 24

This NPRM was developed in accordance with Executive Order 13272 and DOT guidance to ensure compliance with the Regulatory Flexibility Act and provide appropriate consideration of the potential impacts of the rulemaking on small entities. The proposed fee structure and assessment methodology will be assessed only on large-scale new applications for LNG facility construction or expansion projects with design and construction costs totaling or exceeding $2.5 billion. Since the fee structure will be assessed only on large-scale new projects, PHMSA does not expect small entities to be capable of investing in projects of this size, and thus does not expect the rule will have a significant economic impact on a substantial number of small entities.

PHMSA analyzed this proposed rule in accordance with the principles and criteria contained in Executive Order 13175 (“Consultation and Coordination with Indian Tribal Governments”)  25 and DOT Order 5301.1A (“Department of Transportation Tribal Consultation Policy and Procedures”). Executive Order 13175 requires agencies to ensure meaningful and timely input from tribal government representatives in developing rules that significantly or uniquely affect tribal communities by imposing “substantial direct compliance costs” or “substantial direct effects” on such communities, or the relationship and distribution of power between the Federal Government and tribes.

PHMSA assessed the impact of the proposed rule and does not expect it will significantly or uniquely affect tribal communities or Native American tribal governments. The proposed rule's regulatory amendments are facially neutral and will have broad, national scope. PHMSA, therefore, does not expect this rule to significantly or uniquely affect tribal communities, much less impose substantial compliance costs on Native American tribal governments or mandate tribal action. Therefore, PHMSA concludes that the funding and consultation requirements of Executive Order 13175 and DOT Order 5301.1A do not apply.

Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide interested members of the public and affected agencies an opportunity to comment on information collection and recordkeeping requests.

PHMSA proposes requiring LNG facility operators submitting applications for large ($2.5 billion or more) new or expansion projects at their facilities to notify PHMSA officials of those applications; thereafter, affected entities would need to pay PHMSA fees for PHMSA's costs in performing siting reviews pursuant to part 193, subpart B. PHMSA also proposes clarifying revisions to longstanding procedures at part 190, subpart E, for operator notification and assessment of fees for recovery of its costs in performing design safety reviews of jurisdictional pipeline facilities. PHMSA plans to create a new information collection process to cover these notification requirements for affected facility operators. PHMSA will request a new Control Number from OMB for this information collection. PHMSA will submit these information collection requests to OMB for approval based on the proposed requirements in this rule. The information collection is contained in the pipeline safety regulations, 49 CFR parts 190-199. The following information is provided for each information collection: (1) title of the information collection; (2) OMB control number; (3) current expiration date; (4) type of request; (5) abstract of the information collection activity; (6) description of affected public; (7) estimate of total annual reporting and recordkeeping burden; and (8) frequency of collection. The information collection burden is estimated as follows:

1. Title: Notifications for Siting and Design Reviews.

OMB Control Number: Will request from OMB.

Current Expiration Date: TBD.

Abstract: This mandatory information collection covers the burden for pipeline facility owners and/or operators to notify PHMSA, according to 49 CFR 190.405, and provide design specifications, construction plans and procedures, project schedule, and related materials of their prospective project. Pipeline facility owners and operators must also notify PHMSA when costs associated with the design and construction of new facilities for which PHMSA conducts siting reviews exceed $2.5 billion.

Affected Public: Jurisdictional pipeline facility operators applying for authorization to construct and operate new or expanded facilities for which PHMSA conducts facility design safety reviews; pipeline facility owners and operators with new facilities with design and construction costs exceeding $2.5 billion for which PHMSA conducts siting reviews.

Annual Reporting Burden:

Total Annual Responses: 14.

Total Annual Burden Hours: 14 hours.

Frequency of Collection: On occasion.

Requests for a copy of this information collection should be directed to Angela Hill, Office of Pipeline Safety (PHP-30), Pipeline Hazardous Materials Safety Administration (PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-0001, 202-366-4595.

Comments are invited on:

(a) The need for the proposed collection of information for the proper performance of the functions of the agency, including whether the information will have practical utility;

(b) The accuracy of the agency's estimate of the burden of the revised collection of information, including the validity of the methodology and assumptions used;

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

(d) Ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques; and

(e) Ways the collection of this information is beneficial or not beneficial to public safety.

Send comments directly to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attn: Desk Officer for the Department of Transportation, 725 17th Street NW, Washington, DC 20503. Comments should be submitted on or prior to October 18, 2024.

The Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq. ) requires agencies to assess the effects of federal regulatory actions on state, local, and tribal governments, and the private sector. For any NPRM or final rule that includes a federal mandate that may result in the expenditure by state, local, and tribal governments, in the aggregate of $100 million or more (in 1996 dollars) in any given year, the agency must prepare, amongst other things, a written statement that qualitatively and quantitatively assesses the costs and benefits of the federal mandate. The proposed rule pertains to operators reimbursing PHMSA for the cost of conducting siting reviews of LNG facility project applications where the design and construction costs total $2.5 billion or more. It only involves such applicants and PHMSA, and does not involve or pertain to state, local, and tribal governments. Further, as discussed in section V.B above, PHMSA does not anticipate the proposed rule will impose enforceable duties on state, local, and tribal governments or on the private sector of $100 million or more (adjusted annually for inflation) in any one year. Therefore, the requirement to prepare a statement pursuant to UMRA does not apply.

The National Environmental Policy Act of 1969 (NEPA), as amended (42 U.S.C. 4321 et seq. ), 26 requires federal agencies to consider the environmental impacts of their actions in the decision-making process. NEPA requires federal agencies to assess the environmental effects of proposed federal actions prior to making decisions and involve the public in the decision-making process. Agencies must prepare an environmental assessment (EA) for a proposed action for which a categorical exclusion is not applicable, and is either unlikely to have significant effects or when significance of the action is unknown. In accordance with these requirements, an EA must briefly discuss the need for the action; the alternatives considered; the environmental impacts of the proposed action and alternatives; and a listing of the agencies and persons consulted (40 CFR 1508.9(b)). If, after reviewing public comments in response to the draft EA (DEA), an agency determines that a proposed rule will not have a significant impact on the human or natural environment, it can conclude the NEPA analysis with a finding of no significant impact (FONSI).

The purpose of the proposed rule is to amend existing cost recovery regulations at part 190, subpart E, to establish procedures for assessment and recovery of its necessary expenses in performing 49 CFR part 193, subpart B, siting reviews of applications for new or expanded liquefied natural gas (LNG) facilities with project design and constructions costs totaling at least $2.5 billion, as mandated by the PIPES Act of 2020 (Pub. L. 116-260). The codification of these procedures within regulations is a prerequisite for PHMSA accessing funds appropriated by Congress for such reviews in the 2023 Act and any future appropriations legislation. The proposed rule is needed as PHMSA's access to funds recovering the costs of its part 193, subpart B, siting reviews is critically important given the increasing strain placed on its limited resources by such reviews. Many of the same PHMSA personnel performing part 193, subpart B, siting reviews are also responsible for other regulatory oversight activities ( e.g., design safety reviews, inspections, enforcement, guidance and regulation development, etc.) related to LNG facilities and other jurisdictional pipeline facilities. This need has become increasingly pressing in recent years, as PHMSA has had to perform a large number of part 193, subpart B, siting reviews.

No Action Alternative:

The no action alternative would be to not make any changes to the current regulatory requirements. Existing regulations in 49 CFR part 190, subpart E, prescribe a fee structure and assessment methodology for recovering costs from design safety reviews of applications to FERC for new or expanded gas, LNG, hazardous liquid, and carbon dioxide pipeline facility projects consisting of new or expanded LNG facilities with project design and construction costs totaling at least $2.5 billion. In this case, PHMSA would not collect fees directly from operators of LNG facilities to recover the necessary expenses incurred during part 193, subpart B, reviews. Additionally, the statutory mandate that Congress added in section 103 of the PIPES Act of 2020 would not be fulfilled.

Proposed Action Alternative (Proposed Rule):

This alternative implements the mandate in the PIPES Act of 2020 to amend the pipeline safety regulations (49 CFR parts 190-199) to prescribe a fee assessment methodology for PHMSA to recover its costs in performing 49 CFR 193, subpart B, siting reviews of applications for new or expanded LNG facilities with project design and constructions costs totaling at least $2.5 billion. PHMSA is proposing an up-front fee for estimated costs, derived from the personnel costs associated with historical work effort by PHMSA personnel involved in performing siting reviews for LNG facility project applications with design and construction costs of $2.5 billion or more, coupled with “true-up” payments to PHMSA at conclusion of that review should PHMSA's costs exceed the fee paid up-front based on PHMSA's estimated costs. The proposed amendments are summarized below.

Because the proposed rule only describes modifications to the cost recovery process, there would be no effect on environmental resources. Therefore, the affected environment does not include any environmental resources and only includes the existing regulatory framework related to cost recovery regulations at part 190, subpart E.

Existing regulations in 49 CFR part 190, subpart E, prescribe a fee structure and assessment methodology for recovering costs from design safety reviews of applications to FERC for new or expanded gas, LNG, hazardous liquid, and carbon dioxide pipeline facility projects consisting of new or expanded LNG facilities with project design and construction costs totaling at least $2.5 billion.

PHMSA is also currently responsible for the review of LNG facility siting; that review is an input to FERC's evaluation of applications for authorization to construct and operate a new LNG facility (or an expansion of an existing LNG facility). During the LNG facility siting review, PHMSA assesses the siting packages prepared by the applicants for new or expanded LNG facility projects for compliance with siting regulations at part 193, subpart B.

No Action Alternative:

The No Action Alternative would have no new impact on the natural or human environment as the status quo would remain in place. PHMSA would continue to recover costs from design safety reviews of applications for new or expanded gas, LNG, hazardous liquid, and carbon dioxide pipeline facility projects consisting of new or expanded LNG facilities with project design and construction costs totaling at least $2.5 billion. PHMSA would not collect fees directly from operators of LNG facilities to recover the necessary expenses incurred during part 193, subpart B, reviews, and the current and ever-increasing strain placed on PHMSA's limited resources by such reviews would not be alleviated.

The No Action Alternative does not include any activities, such as ground disturbing activities, building or landscape alterations, construction or installation of any new aboveground components, or the introduction of visual, auditory, or atmospheric elements. Therefore, the proposed rule would not adversely affect, either temporarily or permanently, historic resources and/or cultural resources, ecological resources, wetlands and waterways, or farmland.

Proposed Action Alternative (Proposed Rule):

PHMSA recognizes the difficulty in quantifying any environmental impact of prescribing a fee assessment methodology for PHMSA to recover its costs in performing 49 CFR 193, subpart B, siting reviews of applications for new or expanded LNG facilities with project design and constructions costs totaling at least $2.5 billion. The Proposed Action Alternative would have no adverse impact on the natural or human environment because the changes proposed would not adversely impact the process of the part 193, subpart B, reviews, nor would it affect the siting, construction, operations, or other management practices of LNG facilities. The proposed rule would only affect the cost recovery process itself.

That said, PHMSA notes that its access to funds recovering the costs of its part 193, subpart B, siting reviews is critically important given the increasing strain placed on its limited resources by such reviews. Part 193, subpart B, covers siting requirements of LNG facilities—including thermal radiation protection, flammable vapor-gas dispersion protection, and wind forces—to ensure LNG facilities operate at approved national safety standards. By directly recovering costs, PHMSA could relieve some of the strain on its limited personnel resources, allowing for not only more efficient and high-quality reviews, but also ensuring resources would not be diverted from other critical regulatory oversight functions that advance the safety of gas, hazardous liquid, LNG, and carbon dioxide pipeline facilities. However, because it is not clear which activities would go unfunded due to the costs of conducting LNG facility siting reviews, PHMSA is unable to quantify those benefits with a meaningful degree of certainty.

The Proposed Action Alternative (proposed rule) would not include any activities such as ground disturbing activities; building or landscape alterations; construction or installation of any new aboveground or belowground components; or the introduction of visual, auditory, or atmospheric elements. Therefore, the proposed rule would not adversely affect, either temporarily or permanently historic resources and/or cultural resources, ecological resources, wetlands and waterways, or farmland. Further, because this alternative only includes procedures related to cost recovery, this alternative would have no direct or indirect effect on greenhouse gas emissions.

PHMSA's proposed fees for LNG facility part 193, subpart B, siting reviews would be a new line-item cost for certain applicants. Given the reduced frequency of the required siting reviews and assuming the work effort remains static over the 10-year forecast period, the rule would result in an additional burden of approximately $3.48 million over 10 years, as described in Section V.B. of this NPRM. This is discounted to $3.22 million using a two percent rate, and the annualized cost is $358,589. However, PHMSA's projections for the fees paid by applicants for each LNG facility siting review would be trivial (ca. 0.0024 percent) compared to the minimum design and construction costs for pertinent projects. Further, PHMSA has designed its proposed approach to imposing fees in a way that maximizes regulatory certainty for affected entities. PHMSA's timely access to adequate financial resources to perform part 193, subpart B, siting reviews as those reviews initiate also benefits project applicants by facilitating timely completion of such reviews. PHMSA expects these new costs would only be shouldered by a small number of entities. Consistent with the threshold identified in 49 U.S.C. 60303, the NPRM proposes fees for cost recovery for only very large LNG facility new construction or expansion projects—specifically, fees would only be assessed for LNG facility siting reviews for project applications with design and construction costs totaling or exceeding $2.5 billion. And PHMSA expects continued, although decreased, demand for such reviews during the analysis period.

Executive Order 12898 (“Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations”  27 ), directs federal agencies to take appropriate and necessary steps to identify and address disproportionately high and adverse effects of federal actions on the health or environment of minority and low-income populations to the greatest extent practicable and permitted by law. DOT Order 5610.2C (“U.S. Department of Transportation Actions to Address Environmental Justice in Minority Populations and Low-Income Populations”) establishes departmental procedures for effectuating Executive Order 12898 promoting the principles of environmental justice through full consideration of environmental justice principles throughout planning and decision-making processes in the development of programs, policies, and activities—including PHMSA rulemaking.

Executive Order 14096 (“Revitalizing Our Nation's Commitment to Environmental Justice for All”  28 ) was issued on April 21, 2023. Executive Order 14096 on environmental justice does not rescind Executive Order 12898, which has been in effect since February 11, 1994, and is currently implemented through DOT Order 5610.2C. This implementation will continue until further guidance is provided regarding the implementation of the new Executive Order 14096 on environmental justice.

Through the NEPA process, PHMSA has evaluated this NPRM under DOT Order 5610.2C and Executive Order 12898, and has preliminarily determined it would not cause disproportionately high and adverse human health and environmental effects on minority and low-income populations. The proposed rule would not result in any adverse environmental or health impact on minority populations and low-income populations. As explained in this DEA above, the proposed action would not impact the technical requirements associated with the siting requirements described at part 193, subpart B. The Proposed Action Alternative only affects the cost recovery process, which would result in no ground disturbance, building or landscape alterations, or construction activities of any kind. Therefore, no impacts to environmental justice populations would occur. This preliminary finding is consistent with Executive Order 14096 by achieving several goals, including continuing to deepen the Biden-Harris Administration's whole of government approach to environmental justice and to better protect overburdened communities from pollution and environmental harms.

Public involvement is a key component of the NEPA process. This DEA and the proposed rule will be released for public review and comment in docket PHMSA-2022-0118. To access the docket, which contains background documents and any comments that PHMSA has received, go to https://www.regulations.gov. Follow the online instructions for accessing the docket. Alternatively, you may review the documents in person at DOT's Docket Management Office at the address listed below.

E-Gov Web: http://www.regulations.gov. This site allows the public to enter comments on any Federal Register notice issued by any agency. Follow the online instructions for submitting comments.

Mail: Docket Management System: U.S. Department of Transportation, 1200 New Jersey Avenue SE, West Building Ground Floor, Room W12-140, Washington, DC 20590-0001.

Hand Delivery: DOT Docket Management System: West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, between 9:00 a.m. and 5:00 p.m. EST, Monday-Friday, except federal holidays.

No other agencies or persons were consulted during development of this Draft Environmental Assessment.

PHMSA is soliciting comments on the environmental and safety impacts of the proposed rule and on this DEA. PHMSA will respond to the comments received during the comment period and will address comments in the final environmental assessment (FEA). If a determination of no significant impact is made, PHMSA will prepare a FONSI, which would be attached to the FEA and would conclude the NEPA process for this rulemaking.

PHMSA has analyzed this NPRM in accordance with the principles and criteria contained in Executive Order 13132 (“Federalism”)  29 and the Presidential Memorandum  30 titled “Preemption.” Executive Order 13132 requires agencies to ensure meaningful and timely input by state and local officials in the development of regulatory policies that may 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.”

States are generally prohibited by 49 U.S.C. 60104(c) from regulating the safety of interstate pipelines. States that have submitted a current certification under 49 U.S.C. 60105(a) and that adopt the minimum federal pipeline safety requirements may regulate intrastate pipelines within the state. Those states may also adopt additional or more stringent safety standards for intrastate pipelines if those standards are compatible with the federal requirements. A state may also regulate an intrastate pipeline facility that PHMSA does not regulate.

In this instance, the proposed rule would not impose any regulation that has substantial direct effects 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. Therefore, PHMSA has determined that the consultation and funding requirements of Executive Order 13132 do not apply.

Executive Order 13211 (“Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use”)  31 requires federal agencies to prepare a Statement of Energy Effects for any “significant energy action.” Executive Order 13211 defines a “significant energy action” as any action by an agency (normally published in the Federal Register ) that promulgates or is expected to lead to the promulgation of a final rule or regulation that (1)(i) is a significant regulatory action under Executive Order 12866 or any successor order;, and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) is designated by the Administrator of the Office of Information and Regulatory Affairs (OIRA) as a significant energy action.

This proposed rule is not anticipated to be a “significant energy action” under Executive Order 13211. It is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, OIRA has not designated this proposed rule as a significant energy action.

In accordance with 5 U.S.C. 553(c), DOT solicits comments from the public to better inform its rulemaking process. DOT posts these comments without edit, including any personal information the commenter provides, to https://www.regulations.gov, as described in the system of records notice (DOT/ALL-14 Federal Docket Management System), which can be reviewed at https://www.dot.gov/privacy.

A regulation identifier number (RIN) is assigned to each regulatory action listed in the Unified Agenda of Federal Regulatory and Deregulatory Actions (Unified Agenda). The Regulatory Information Service Center publishes the Unified Agenda in April and October of each year. The RIN contained in the heading of this document can be used to cross-reference this action with the Unified Agenda.

Executive Order 13609 (“Promoting International Regulatory Cooperation”)  32 requires agencies to consider whether the impacts associated with significant variations between domestic and international regulatory approaches are unnecessary or may impair the ability of American business to export and compete internationally. In meeting shared challenges involving health, safety, labor, security, environmental, and other issues, international regulatory cooperation can identify approaches that are at least as protective as those that are or would be adopted in the absence of such cooperation. International regulatory cooperation can also reduce, eliminate, or prevent unnecessary differences in regulatory requirements.

Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as amended by the Uruguay Round Agreements Act (Pub. L. 103-465), prohibits federal agencies from establishing any standards or engaging in related activities that create unnecessary obstacles to the foreign commerce of the United States. For purposes of these requirements, federal agencies may participate in the establishment of international standards so long as the standards have a legitimate domestic objective, such as providing for safety, and do not operate to exclude imports that meet this objective. The statute also requires consideration of international standards and, where appropriate, that they serve as the basis for U.S. standards.

PHMSA participates in the establishment of international standards to protect the safety of the American public. PHMSA assessed the effects of the proposed rule and determined that it will not cause unnecessary obstacles to foreign trade.

Executive Order 14028 (“Improving the Nation's Cybersecurity”)  33 directed the Federal Government to improve its efforts to identify, deter, and respond to “persistent and increasingly sophisticated malicious cyber campaigns.” In keeping with these policies and directives, PHMSA has assessed the effects of this NPRM to determine what impact the proposed regulatory amendments may have on cybersecurity risks for LNG facilities, and has preliminarily determined that this NPRM will not materially affect the cybersecurity risk profile for those facilities.

This proposed rule will establish fee structures and assessment methodology for recovering costs associated with siting reviews of certain new LNG facility project applications. Those reviews occur in the status quo; this rulemaking merely formalizes notification practices and establishes procedures for calculation and forwarding of (estimated and actual) fees to recover PHMSA's costs in performing those reviews. PHMSA envisions that entities paying the fees proposed herein will have the option of doing so by either check or the Federal Government's centralized fee payment website ( https://pay.gov ). PHMSA does not expect, therefore, that the NPRM's proposed regulatory amendments will entail the electronic transfer of sensitive or confidential business information of the sort that could materially affect applicants' cybersecurity risk profiles.

The purpose of this proposed rule is to operate holistically and, in concert with existing part 190, subpart E, requirements, provide for cost recovery of part 193, subpart B, siting reviews for certain LNG facility project applications. However, PHMSA recognizes that certain provisions focus on unique topics. Therefore, PHMSA preliminarily finds that the various provisions of this proposed rule are severable and able to operate functionally if severed from each other. In the event a court were to invalidate one or more of the unique provisions of any final rule issued in this proceeding, the remaining provisions should stand, thus allowing their continued effect. PHMSA seeks comment on which portions of this rule should or should not be severable.

For the reasons provided in the preamble, PHMSA proposes to amend 49 CFR part 190 as follows: