SUPPLEMENTARY INFORMATION:

Throughout this document, the use of “we,” “us,” or “our” is intended to refer to the EPA. We use multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here:

BART Best Available Retrofit Technology

CAA Clean Air Act

CAMPD Clean Air Markets Program Data

CBI Confidential Business Information

CFR Code of Federal Regulations

EGU Electric Generating Unit

EPA U.S. Environmental Protection Agency

FGD Flue Gas Desulfurization

FIP Federal Implementation Plan

FLM Federal Land Manager

FR Federal Register

IRP Integrated Resource Plan

LB Pound

LNB/OFA Low-NO_X Burners With Overfire Air

MMBtu Million British Thermal Units

MW Megawatt

NAAQS National Ambient Air Quality Standards

NERC North American Electric Reliability Corporation

NO_X  Nitrogen Oxides

OMB Office of Management and Budget

PM Particulate Matter

PRA Paperwork Reduction Act

RFA Regulatory Flexibility Act

RHR Regional Haze Rule

RTC Response to Comments

SCR Selective Catalytic Reduction

SIP State Implementation Plan

SNCR Selective Non-Catalytic Reduction

SO₂  Sulfur Dioxide

TPY Tons Per Year ( printed page 34590)

UMRA Unfunded Mandates Reform Act

USFS United States Forest Service

Table of Contents

I. What action is the EPA proposing?

II. Background

A. Dave Johnston Power Plant

B. Legal Authority and Requirements

C. Regulatory History

III. NO_X BART Determination for Dave Johnston Unit 3

A. Costs of Compliance

B. Energy and Non-Air Quality Environmental Impacts of Compliance

C. Pollution Control Equipment in Use at the Source

D. Remaining Useful Life of the Source

E. Degree of Improvement in Visibility

F. Conclusion

IV. Coordination With FLMs

V. Clean Air Act Section 110(l)

VI. Statutory and Executive Order Reviews

I. What action is the EPA proposing?

The EPA is proposing to revise the Wyoming regional haze FIP to amend the NO_X BART determination for Dave Johnston Unit 3. Specifically, the EPA is proposing to: (1) remove the NO_X BART requirement of 0.28 pounds per million British thermal units (lb/MMBtu) (30-day rolling average) interim emission limit and permanent cessation of operations at Dave Johnston Unit 3 on or before December 31, 2027; and (2) revise the other NO_X BART requirement of 0.07 lb/MMBtu (30-day rolling average).^[1] Specifically, the EPA is proposing to revise the NO_X BART determination and establish a new NO_X BART requirement of 0.23 lb/MMBtu (30-day rolling average) and associated compliance date for Dave Johnston Unit 3. Although the EPA is proposing to revise the Wyoming regional haze FIP NO_X BART determination for Dave Johnston Unit 3, the Agency invites Wyoming to submit a new regional haze State Implementation Plan (SIP) NO_X BART determination in the future for Dave Johnston Unit 3 to the Agency in an effort to replace this FIP with a SIP.

II. Background

A. Dave Johnston Power Plant

The Dave Johnston power plant is located in Converse County, Wyoming and is comprised of four coal-fired units, but only Units 3 and 4 are subject to BART requirements.^[2]

Dave Johnston Unit 3 is a 230 megawatt (MW) coal-fired boiler that commenced service in 1964. The coal is currently sourced from the Dry Fork Mine, Caballo Mine, and Coal Creek Mine in the Powder River Basin in Wyoming.^[3] In June 2008, Wyoming issued a construction permit approving PacifiCorp's construction permit application request to install new emission controls at Dave Johnston Units 3 and 4.^[4] In December 2009, Wyoming issued a BART permit with emission limits to meet BART requirements for Dave Johnston Unit 3.^[5] In 2010, PacifiCorp completed emissions controls upgrades on Unit 3, including installation of Flue Gas Desulfurization (FGD) sulfur dioxide (SO₂) emission controls, upgrades to the existing electrostatic precipitator to a baghouse for particulate matter (PM) emission controls, and installation of low-NO_X burners with overfire air (LNB/OFA) for NO_X emission controls. Additionally, Dave Johnston Unit 3 was originally equipped with burners in a cell configuration until the 2010 upgrades when it was converted to a dry bottom wall-fired boiler to enable the installation of the LNB/OFA combustion controls.

B. Legal Authority and Requirements

Clean Air Act (CAA) section 169A sets forth the regional haze program for protecting visibility in certain national parks and wilderness areas, establishing “as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I Federal areas which impairment results from manmade air pollution.” ^[6] The EPA promulgated the Regional Haze Rule (RHR) to address regional haze on July 1, 1999,^[7] and published a revision to the RHR on January 10, 2017.^[8]

The CAA requires each State to develop a SIP to meet various air quality requirements, including protection of visibility.^[9] Regional haze SIPs must ensure reasonable progress toward the national goal of achieving natural visibility conditions in Class I areas. A State must submit its SIP and SIP revisions to the EPA for approval.^[10] If a State elects not to make a required SIP submittal, fails to make a required SIP submittal, or if the EPA finds that a State's required submittal is incomplete or not approvable, then CAA section 110(c)(1) requires the EPA to promulgate a FIP.^[11]

Under the CAA, even if the EPA establishes a FIP, a State may submit a SIP that, if approved by the Agency, would replace the FIP.

1. Best Available Retrofit Technology (BART)

CAA section 169A directs States, or the EPA if developing a FIP, to evaluate the use of retrofit controls at certain larger stationary sources built between 1962 and 1977 to address visibility impacts from these sources.^[12] Specifically, CAA section 169A(b)(2) requires SIPs to contain such measures as may be necessary to make reasonable progress toward the natural visibility goal.^[13] This includes a requirement that existing major stationary sources built between 1962 and 1977 that emit air pollutants which may reasonably be anticipated to cause or contribute to any impairment in a Class I area shall procure, install, and operate, as expeditiously as practicable, BART for controlling emissions from such sources for the purpose of eliminating or reducing any such impairment. BART is determined by the States through their SIPs, or by the EPA in a FIP.^[14] For fossil fuel-fired generating powerplants having a total generating capacity in excess of 750 megawatts, the emission limitations required shall be determined pursuant to guidelines promulgated by the Administrator.^[15]

CAA section 169A(g)(2) requires that States, or the EPA if developing a FIP, must consider the following five factors in making BART determinations: (1) the costs of compliance; (2) the energy and non-air quality environmental impacts of compliance; (3) any existing pollution control technology in use at the source; (4) the remaining useful life of the source; and (5) the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. Under the RHR, States (or the EPA) are directed to conduct BART determinations for such “BART-eligible” sources that may reasonably be anticipated to cause or contribute to any visibility impairment in a Class I area.^[16]

On July 6, 2005, the EPA published the Guidelines for BART Determinations under the RHR at appendix Y to 40 ( printed page 34591) Code of Federal Regulations (CFR) part 51 (the “BART Guidelines”) to assist States and the Agency in determining which sources should be subject to the BART requirements and the appropriate emission limits for each applicable source.^[17 18] Under the BART Guidelines promulgated per CAA 169A(b)(2), “States must follow the guidelines in making BART determinations on a source-by-source basis for 750 megawatt power plants but are not required to use the process under the guidelines when making BART determinations for other type of sources.” In addition to what is required by the RHR, general SIP requirements mandate that the SIP or FIP include all regulatory requirements related to monitoring, recordkeeping, and reporting for the BART emission limitations.^[19]

2. Consultation With Federal Land Managers

The RHR requires that a State, or the EPA if promulgating a FIP, consult with the Federal land managers (FLMs) before adopting and submitting a required SIP or SIP revision, or a required FIP or FIP revision.^[20] Further, a State, or the EPA if considering a FIP revision, must include in its notice to the public a summary of the conclusions and recommendations of the FLMs.^[21]

3. BART Guidelines Definition of Baseline Emissions

On January 30, 2014, the EPA partially approved and partially disapproved a regional haze SIP revision submitted by the State of Wyoming on January 12, 2011 (the “2014 Final Rule”).^[22] In the 2014 Final Rule, the EPA limited the adjustment of baseline emissions for recently installed controls and stated that the baseline should only be adjusted in cases in which controls were installed to meet other CAA requirements. However, the BART Guidelines gives discretion to States and the EPA in setting baseline emissions and defines baseline emissions as a “realistic depiction of anticipated emissions.” ^[23 24] Additionally, the third BART statutory factor requires consideration of “existing pollution control technology in use at the source.” ^[25] Therefore, given the language in both the statute and the BART Guidelines, the EPA is proposing to determine that inclusion of existing controls in the baseline emissions, regardless of purpose, is both permissible and reasonable.

According to the BART Guidelines, for purposes of calculating the costs of compliance, “the baseline emissions rate should represent a realistic depiction of anticipated annual emissions for the source.” ^[26] The BART Guidelines allow States and the EPA to adjust baseline emissions to take into account projections of “future operating parameters” by making such assumptions into enforceable limits.^[27] In previous regional haze first planning period actions, the EPA confirmed that neither the RHR nor the BART Guidelines require a particular timeframe be used as the baseline for BART determinations at individual sources.^[28] Consequently, States and the EPA have considerable discretion in how they consider existing controls in use at a source, so long as that consideration is explained and reasonable.

In the 2014 Final Rule, the EPA did not update the baseline NO_X emissions to account for the newly installed LNB/OFA combustion controls. In the EPA's responses to comments, the Agency explained that it would have been inappropriate for the Agency to take LNB/OFA into consideration, because it appeared the controls on certain sources in Wyoming had been installed early to avoid a more stringent BART determination as opposed to comply with other CAA requirements.^[29] Allowing for inclusion of existing controls in the baseline emissions, regardless of purpose, more closely aligns with the “consideration of any existing pollution control technology” CAA requirement and the BART Guidelines requirement that the baseline emissions rate should represent a “realistic depiction of annual emissions” and “in general, for the existing source subject to BART, you will estimate the anticipated annual emissions based upon actual emissions from a baseline period.” ^[30] Therefore, given the language in both the statute and the BART Guidelines, the EPA believes it is permissible and appropriate to adjust the baseline emissions rate to reflect existing controls at the source, regardless of purpose, despite the EPA declining to do so in the 2014 Final Rule.

In the 2014 Final Rule, the EPA also stated that the Agency's action would not be inconsistent with the Eighth Circuit's decision in North Dakota.^[31 32] In the EPA's responses to comments, the Agency stated that the Eighth Circuit rejected the Agency's position to not consider the Dry Fining^[TM] control technology in use at Coal Creek Station in the BART evaluation (either in the cost of control options or adjustment to the baseline), holding that the “EPA's refusal to consider Dry Fining^[TM] as an existing pollution control technology in use at the Coal Creek Station because it had been voluntarily installed was arbitrary and capricious.” ^[33] The Eighth Circuit explained that “any existing pollution control technology” also included voluntarily installed controls.^[34] The Eighth Circuit did not opine as to how “existing” must be considered and, thus, North Dakota did not specifically require the EPA to “take into consideration” the existing controls by adjusting the baseline emissions.^[35] However, the Eighth Circuit recognized that the relevance of the plain language requirement of the CAA to “take into consideration” existing pollution control technology in use at the source can include adjusting the baseline emissions to reflect existing controls.^[36]

Subsequent to the EPA's 2014 NO_X BART determination for Dave Johnston Unit 3, the Ninth Circuit upheld the Agency's selection of a 2008-2010 baseline period representing the 2009 installation of combustion controls for a source subject-to-BART in the Agency's 2012 FIP for Montana.^[37] Conservation organizations argued that the EPA should have chosen earlier periods between 2000-2004 because the source was not required to maintain the rate of emissions achieved between 2008-2010, describing the changes at the source as “unenforceable.” The Ninth Circuit found that the EPA offered a reasoned response to the comment. Specifically, ( printed page 34592) the Ninth Circuit agreed with the EPA on the following: (1) the Agency's decision to adjust the baseline to include recently installed controls to meet CAA Acid Rain Program emission limits; (2) that the source had achieved reduced emissions using technology it has no plans to deactivate; and (3) that conservation organizations suggested no reason to believe that the source would change course and remove the additional combustion controls it had already installed.^[38] While the EPA updated the baseline in the 2012 FIP for Montana to reflect currently installed controls for Colstrip due to CAA acid rain requirements, as described above, the CAA and the BART Guidelines allow for adjustment of baseline to account for installed controls, regardless of purpose.

In summary, the EPA considered the following when determining the baseline emissions rate for Dave Johnston Unit 3: (1) BART requires the consideration of any pollution control equipment in use at the source; ^[39] (2) the BART Guidelines provide that, for purposes of calculating the costs of compliance, the baseline emissions rate should represent a realistic depiction of the anticipated annual emissions for the source; ^[40] (3) neither the RHR nor the BART Guidelines require a particular timeframe be used as the baseline for BART determinations at individual sources; and (4) updating the baseline to reflect installation of additional combustion controls is consistent with case law. Thus, it is reasonable to interpret the BART Guidelines to allow for NO_X emission controls that are currently in place at Dave Johnston Unit 3 to represent the baseline emissions rate when calculating the costs of compliance, particularly given the fact that Dave Johnston Unit 3 has maintained that rate for 15 years and the emissions represent a realistic depiction of anticipated annual emissions.^[41]

C. Regulatory History

In the 2014 Final Rule, the EPA partially disapproved the Wyoming regional haze SIP, including the NO_X BART emission limit of 0.28 lb/MMBtu (30-day rolling average) reflecting LNB/OFA at Dave Johnston Unit 3, among other actions. Within the same action, the EPA promulgated a FIP that required a NO_X BART emission limit of 0.07 lb/MMBtu (30-day rolling average) to be implemented by March 4, 2019 (five years from the effective date of the FIP). At PacifiCorp's request, the EPA also included an alternative NO_X BART requirement of 0.28 lb/MMBtu (30-day rolling average) interim emission limit and permanent cessation of operations at Dave Johnston Unit 3 by December 31, 2027. PacifiCorp is currently operating within the NO_X BART requirement of 0.28 lb/MMBtu interim emission limit and permanent cessation of operations at Dave Johnston Unit 3 on or before December 31, 2027.^[42 43]

On March 4, 2026, PacifiCorp informed the EPA that it withdrew its consent to the closure of Dave Johnston Unit 3 by December 31, 2027.^[44] In its letter, PacifiCorp explained that due to projected “[d]ramatic increases in electricity demand” associated with the “resurgence of domestic manufacturing and the construction of artificial intelligence data processing centers,” PacifiCorp's 2025 Integrated Resource Plan (IRP) projects a need for an additional 1,000 MW more generating capacity in the next eight years than had been projected in the 2019 IRP for the same time period. Accordingly, PacifiCorp states that it “no longer consents to closure of [Dave Johnston Unit 3] and has retracted its prior request to the EPA to include the retirement option in the FIP.” ^[45]

III. NO X BART Determination for Dave Johnston Unit 3

A. Costs of Compliance

In the 2014 Final Rule, the EPA relied on a number of emissions and control cost assumptions for Dave Johnston Unit 3. To provide cost information that is consistent with the original FIP, the EPA generally relied on the same control costs assumptions used in the 2014 Final Rule to re-analyze the prior control scenarios at Dave Johnston Unit 3. This allows for a direct comparison between the current cost assumptions and other BART analyses from that same time period.

In the 2014 Final Rule, the EPA relied on baseline pre-combustion control NO_X emissions of 4,913 tons per year (tpy), based on the actual annual average of NO_X emissions for the years 2001-2003, as the baseline emissions.^[46] However, for this current analysis, and as previously described, the EPA is reconsidering the baseline emissions assumptions. As noted earlier, in 2010, PacifiCorp installed LNB/OFA combustion controls on Dave Johnston Unit 3, and those controls are permanent and have now been operating for over 15 years. Therefore, based on the third BART statutory factor, “pollution equipment in use at the source,” ^[47] the EPA is adjusting the baseline to reflect the pollution equipment installed at Dave Johnston Unit 3. Additionally, in selecting a baseline emissions period, the BART Guidelines state that the baseline should “represent(s) a realistic depiction of anticipated emissions for the source.” ^[48] Therefore, in selecting baseline emissions for this revised BART analysis, a baseline that includes operation of LNB/OFA combustion controls represents both “pollution equipment in use at the source” and “represent(s) a realistic depiction of anticipated emissions for the source.” ^[49]

Since LNB/OFA was installed in 2010, the EPA is using the period of operation immediately following the LNB/OFA installation as the updated baseline period for the revised BART analysis. Dave Johnston Unit 3 achieved an actual NO_X emission rate of 0.22 lb/MMBtu (annual average) for the years 2011, 2012, and the first two quarters of 2013,^[50] which reduced NO_X emissions by 2,837 tpy and resulted in post-combustion control baseline NO_X emissions of 2,076 tpy.^[51] Based on the current boiler configuration, PacifiCorp provided information that LNB/OFA has consistently achieved an emission limit of 0.23 lb/MMBtu (30-day rolling average) since installation in 2010.^[52] Therefore, for purposes of calculating the costs of compliance, the EPA's revised NO_X BART determination for Dave Johnston Unit 3 uses the post-combustion control baseline of 2,076 tpy. As explained above, this baseline is ( printed page 34593) consistent with the demonstrated actual NO_X emissions from the installation of LNB/OFA in 2010 continuing through present day (over a 15-year period) and is consistent with both the CAA statutory factor(s) and the BART Guidelines.

The next step in determining BART is to identify all available retrofit control technologies and eliminate technically infeasible options. As determined in the 2014 Final Rule, selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR) are the primary available post-combustion retrofit technologies for the Dave Johnston Unit 3 boiler, and both technologies were determined to be feasible, which are not being challenged currently. The next step is to evaluate the control effectiveness of the feasible control technologies. To calculate the potential NO_X emissions reductions for the SNCR and SCR scenarios, the EPA used a NO_X emission rate assumption of 0.16 lb/MMBtu (annual average) for SNCR and 0.05 lb/MMBtu (annual average) for SCR.^[53] The emission reductions associated with the installation of SNCR reflect a control efficiency of 25 percent and would potentially reduce NO_X emissions by only 519 tpy compared to the post-combustion control baseline NO_X emissions of 2,076 tpy. The emission reductions associated with the installation of SCR reflect a control efficiency of 77 percent and would potentially reduce NO_X emissions by 1,597 tpy compared to the post-control baseline NO_X emissions of 2,076 tpy. Based on these assumptions, the annualized costs to install SNCR and SCR using a 20-year equipment life were found to be $1,810,782 per year and $9,980,337 per year, respectively, as compared to the pre-combustion control annualized costs of $3,510,589 per year and $11,680,144 per year to install LNB/OFA + SNCR and LNB/OFA + SCR, respectively.^[54] The current version of the EPA's Control Cost Manual (revised in 2014) includes a 30-year equipment life for SCR.^[55] Therefore, the EPA also calculated the annualized costs to install SCR using a 30-year equipment life to be $8,862,953 per year. Thus, the average cost-effectiveness for SNCR, SCR (20-year life), and SCR (30-year life) are $3,488 per ton, $6,251 per ton, and $5,551 per ton, respectively. The incremental cost-effectiveness ^[56] of installing SCR compared to an SNCR is $7,583 per ton for SCR (20-year life) and $6,602 per ton for SCR (30-year life). Costs of compliance for Dave Johnston Unit 3 NO_X BART are summarized in table 1.^[57]

Notably, the EPA's NO_X BART determination relies on the baseline NO_X rate of 0.22 lb/MMBtu (annual average) contained in the 2014 Final Rule as opposed to the proposed 0.23 lb/MMBtu (30-day rolling average) NO_X emission limit. Generally, the NO_X annual average emission rate is based on the expected annual emission performance under a 30-day rolling average emission rate. The latter value will be higher than the former because of the shorter averaging period and a margin for compliance. For example, Dave Johnston Unit 3 is generally able to achieve a 30-day rolling average NO_X emission rate of 0.23 lb/MMBtu and an annual average emission rate of between 0.20 to 0.21 lb/MMBtu.^[58] Thus, the proposed 0.23 lb/MMBtu (30-day rolling average) reflects a more conservative annual NO_X emission rate than the 0.22 lb/MMBtu (annual average) that was used in the 2014 Final Rule and in this proposed revision for purposes of calculating the costs of compliance contained in table 1.

As described in section III.E of this preamble and consistent with other BART actions, the EPA proposes to find that neither SNCR nor SCR are cost effective when compared to the associated visibility improvement.

B. Energy and Non-Air Quality Environmental Impacts of Compliance

In its March 2026 letter to the EPA withdrawing its consent to the closure of Dave Johnston Unit 3, PacifiCorp noted the recent increase in energy demand. Specifically, PacifiCorp noted that the North American Electric Reliability Corporation's (NERC) 2024 Long-Term Reliability Assessment, which includes Wyoming and other western States, describes the need for replacement of five gigawatts of baseload resource retirements, anticipated between 2024 and 2028 in the region.^[59]

PacifiCorp's 2025 IRP projects increasing system-wide retail sales with a compounded annual growth rate of 2.17 percent between 2024 and 2033 and a compounded annual growth rate of 1.35 percent between 2024 and 2042, which reflects a noticeable increase in forecasted growth from previous forecasts.^[60 61] According to PacifiCorp's 2025 IRP, growth is driven, in part, by “significant new data center loads ( printed page 34594) coming online in the 2027-2033 timeframe.” ^[62]

PacifiCorp states that Dave Johnston Unit 3 is “uniquely poised to respond to these growing demand needs” because, in part, it has an operating range of 90-220 MW of dispatchable generation that allows Unit 3 to generate more or less power to respond to changes in energy demand, including accommodating intermittent wind generation.^[63] Additionally, Dave Johnston Unit 3 also provides frequency response—an automatic, rapid adjustment of power output to stabilize grid frequency—making it “uniquely capable of offsetting unanticipated reductions in wind generation,” according to PacifiCorp.^[64]

The EPA recognizes that any source that previously decided to close could determine in the future that closure is no longer appropriate. As PacifiCorp notes in its March 2026 letter to the EPA, the demand for electricity is rising. Executive Order 14261, Reinvigorating America's Beautiful Clean Coal Industry and Amending Executive Order 14241, states that “[o]ur Nations' beautiful clean coal resources will be critical to meeting the rise in electricity demand due to the resurgence of domestic manufacturing and the construction of artificial intelligence data processing centers” and power generated from coal resources is critical to addressing this surging demand and a matter of national interest, national security, and energy policy.^[65]

The EPA does not encourage electric generating facilities to close in the face of this energy demand. Moreover, the EPA does not expect an electrical generating facility to close in order to comply with the CAA's regional haze requirements. Voluntary source retirement and replacement is much different from enforceable, unconsented closures, which neither the RHR nor the CAA's regional haze provisions reference or contemplate in any manner. Furthermore, the EPA is unaware of any instance where the Agency has approved a SIP revision containing a forced, unconsented closure. Finally, although there are identified energy impacts from potential emission controls ( e.g., parasitic energy requirements to operate SCR), the EPA did not identify any “energy and non-air quality environmental impacts of compliance” that would preclude the selection of any of the emission controls evaluated.

C. Pollution Control Equipment in Use at the Source

Dave Johnston Unit 3 currently employs LNB/OFA for control of NO_X emissions, which was installed in 2010. As part of the installation of LNB/OFA, PacifiCorp converted the boiler configuration from a cell boiler to a dry-bottom wall-fired configuration.^[66] Based on the current boiler configuration, PacifiCorp provided information from the EPA's Clean Air Markets Program Data (CAMPD) that LNB/OFA has consistently achieved an emission limit of 0.23 lb/MMBtu (30-day rolling average) since installation in 2010.^[67]

As previously stated, the EPA accounted for the “pollution equipment in use at the source” in the Agency's adjustment of the baseline to reflect the pollution equipment currently installed. In doing so, the EPA finds that the Agency's proposed BART determination for Dave Johnston Unit 3, as described in section III of this preamble, is consistent with the Ninth Circuit's decision. Dave Johnston Unit 3 has achieved NO_X emission reductions using technology (LNB/OFA) that it has no plans to deactivate. Additionally, there is no reason to believe that PacifiCorp would remove the combustion controls it has already installed, given that PacifiCorp received a Wyoming 2008 construction permit to construct those control technologies.^[68] This is further demonstrated by Dave Johnston Unit 3 maintaining its existing NO_X emissions close to 0.23 lb/MMBtu (30-day rolling average) for the last 15 years since its installation of LNB/OFA.^[69] If this proposed rule is finalized as proposed, Dave Johnston Unit 3 would be required to continue to meet a 0.23 lb/MMBtu (30-day rolling average) NO_X emission limit by the compliance date.

D. Remaining Useful Life of the Source

With this proposed action, the EPA is proposing to withdraw the requirement to permanently close Dave Johnston Unit 3 by December 31, 2027, because the source no longer consents to closure.^[70] As previously stated in section III.B of this preamble, the EPA does not expect an electrical generating facility to close in order to comply with the CAA's regional haze requirements. Thus, because the proposal removes the enforceable closure for Dave Johnston Unit 3, the remaining useful life is based on the useful life of the control equipment.^[71] Therefore, for the remaining useful life for evaluation of controls consistent with the Control Cost Manual, the BART Guidelines, and the 2014 Final Rule, the EPA evaluated both 20-years (for SNCR and SCR) and 30-years (for SCR).^[72] Those 20-year and/or 30-year lifetime of the emission controls assumptions are accounted for in the cost calculations for both SNCR and SCR controls.

E. Degree of Improvement in Visibility

The EPA relied on CALPUFF ^[73] used in the 2014 Final Rule ^[74] and adjusted the baseline to reflect the inclusion of the pollution control equipment in use at the source (LNB/OFA) when determining visibility improvement. The 2014 model included visibility impacts from Dave Johnston Unit 3 to Badlands National Park, Wind Cave National Park, Mount Zirkel Wilderness Area, Rawah Wilderness Area, and Rocky Mountain National Park. The modeling indicated that visibility impact was greatest at Wind Cave National Park. The visibility improvement (delta deciviews) for Dave Johnston Unit 3 with LNB/OFA as baseline controls is summarized in table 2.^[75]

( printed page 34595)

While all five BART statutory factors must be considered when determining BART, the average cost-effectiveness value is weighed against the expected visibility improvement from the controls to determine if the potential control is overall “cost-effective.” Additionally, to promote consistency, the facts of each BART decision can be compared to previous BART decisions by both States and the EPA. As shown in table 1, the EPA evaluated NO_X emission controls, SNCR and SCR, from the baseline reflecting the currently installed LNB/OFA emission controls.

First, the EPA evaluated SNCR as a potential BART control. For Dave Johnston Unit 3, the average cost-effectiveness associated with the installation of SNCR is $3,488 per ton with an associated visibility improvement of only 0.06 deciviews. This is similar to the installation of SNCR on Colorado's Comanche Unit 1 for which the average cost-effectiveness was $3,644 per ton with an associated visibility improvement of 0.11 deciviews. In 2012, the EPA agreed with Colorado that based on its consideration of the five factors, the NO_X BART emission limit for Comanche Unit 1, a tangentially fired boiler,^[76] is 0.20 lb/MMBtu (30-day rolling average)—and not SNCR—which can be achieved through the operation of existing LNBs.^[77] Although other alternatives, including SNCR, achieve more emission reductions, Colorado determined, and the EPA agreed, that the added expense of achieving lower limits through different controls was not reasonable based on the “high cost effectiveness coupled with the low-visibility (under 0.20 deciview) afforded.” ^[78] Here, the average cost-effectiveness value is similar, but the visibility benefit from the addition of SNCR is half as much, at only 0.06 deciviews. Similarly, in the 2014 Final Rule, the EPA found it unreasonable to require SNCR on Naughton Units 1 and 2 due to the “very low” incremental visibility improvement of 0.10 deciviews across both units (0.04 deciviews for Unit 1; 0.06 deciviews for Unit 2).^[79] Therefore, this proposed action is consistent with historical BART decisions on sources for which controls were found not to be BART due to the very small visibility benefits of installing controls.

Next, the EPA evaluated SCR as a potential control. For Dave Johnston Unit 3, the installation of SCR would result in a modest increase in visibility improvement of 0.12 deciviews compared to SNCR and 0.18 deciviews compared to the LNB/OFA baseline with an average cost-effectiveness of $6,251 per ton (20-year life) and $5,551 per ton (30-year life). In this case, the cost-effectiveness of SCR is similar to the installation of SCR on Colorado's Martin Drake Units 5, 6, and 7 of $7,314 per ton, $5,395 per ton, and $4,981 per ton, respectively. In 2012, the EPA agreed with Colorado that SCR was not cost effective on Martin Drake Units 5, 6, and 7 when compared with the associated visibility improvement of 0.12 deciviews, 0.27 deciviews, and 0.37 deciviews, respectively.^[80] Similarly, the EPA also determined that Colorado reasonably considered the five BART statutory factors when Colorado determined SCR was not reasonable at Craig Units 1 and 2 due to the “high cost-effectiveness value[s]” of $6,432 per ton and $6,299 per ton, respectively, despite an associated visibility improvement of 1.01 deciviews for each unit.^[81] The cost-effectiveness values at Craig Units 1 and 2 are almost identical to the cost-effectiveness of the installation of SCR at Dave Johnston Unit 3 at $6,251 per ton (using the same 20-year amortization period as Colorado), while the associated visibility improvement is significantly less at Dave Johnston Unit 3 at only 0.18 deciviews. Again, the average cost-effectiveness of SCR for Dave Johnston Unit 3 is similar to the average cost-effectiveness at other BART sources for which the EPA determined SCR was not cost effective, and the potential visibility benefit from SCR at Dave Johnston Unit 3 is considerably smaller than at these same BART sources. In conclusion, based on considering the average cost-effectiveness and expected visibility improvement, the EPA finds that neither SNCR nor SCR are reasonable.

F. Conclusion

Based on the EPA's consideration of the CAA and BART Guidelines and evaluation of the five BART factors (cost of controls, predicted visibility improvement, energy and non-air quality environmental impacts of compliance, pollution control currently in use, and remaining useful life), the Agency proposes to find that a NO_X emission limit of 0.23 lb/MMBtu (30-day rolling average), consistent with the continued operation of LNB/OFA combustion controls, is NO_X BART for Dave Johnston Unit 3. The proposed emission limit is consistent with a rate that Dave Johnston Unit 3 has consistently achieved since installation of the LNB/OFA and is equal to the presumptive NO_X BART limit for a dry-bottom, wall-fired boiler burning sub-bituminous coal in the BART Guidelines.^[82] Additionally, PacifiCorp recently submitted a permit application to Wyoming requesting a revised NO_X emission limit for Dave Johnston Unit 3 of 0.23 lb/MMBtu based on a 30-day rolling average.^[83] To ensure uninterrupted implementation of NO_X BART at Dave Johnston Unit 3, and because Unit 3 can already meet the proposed limit without any upgrades or changes in operation, the EPA proposes to require compliance upon the effective date of the final rule.^[84]

IV. Coordination With FLMs

There are seven Class I areas in the State of Wyoming. The U.S. Forest Service (USFS) manages the Bridger Wilderness, Fitzpatrick Wilderness, North Absaroka Wilderness, Teton Wilderness, and the Washakie Wilderness. The U.S. National Park ( printed page 34596) Service manages the Grand Teton National Park and Yellowstone National Park.

There are obligations to consult on the plan revisions under CAA section 169A(d) and associated regulations found at 40 CFR 51.308(i). Thus, the EPA consulted with the USFS, the U.S. Fish and Wildlife Service, and the U.S. National Park Service on the proposed FIP revision. The EPA described the proposed revisions with the USFS, the Fish and Wildlife Service, and the National Park Service on April 13, 2026, and provided a summary of the conclusions and recommendations of the FLMs along with a description of how the Agency addressed the comments in the docket for this action.^[85] Therefore, the EPA met the obligations under 40 CFR 51.308(i)(2) and (3) and CAA 169A(d).

V. Clean Air Act Section 110(l)

Under CAA section 110(l), the EPA cannot approve a plan revision “if the revision would interfere with any applicable requirement concerning attainment and reasonable further progress (as defined in section 7501 of this title), or any other appliable requirement of this chapter.” ^[86] The EPA proposes to find that these revisions satisfy section 110(l). The previous section of this preamble explains how the proposed FIP revision will comply with applicable regional haze requirements and general implementation plan requirements such as enforceability. With respect to requirements concerning attainment and reasonable further progress, the FIP, as revised by this action, will not result in an increase in emissions compared to historical levels. In addition, the area where the Dave Johnston power plant is located is in attainment for all National Ambient Air Quality Standards (NAAQS). Thus, the revision will ensure no increases in NO_X emissions compared to historical levels in an area that has not been designated nonattainment for any NAAQS.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

This action is not a significant regulatory action and was therefore not submitted to the Office of Management and Budget (OMB) for review.

B. Executive Order 14192: Unleashing Prosperity Through Deregulation

This action is expected to be an Executive Order 14192 deregulatory action. This proposed rule is expected to provide burden reduction by revising the NO_X BART determination for, and not requiring the contested closure of, Dave Johnston Unit 3.

C. Paperwork Reduction Act (PRA)

This proposed rule does not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.).

D. Regulatory Flexibility Act (RFA)

I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA (5 U.S.C. 601 et seq.). This action will not impose any requirements on small entities. This action will establish an emission limit for one electric generating unit. This unit is not owned by a small entity, and therefore, there are no impacts on small entities.

E. Unfunded Mandates Reform Act (UMRA)

This action does not contain any unfunded mandate as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. The action imposes no enforceable duty on any State, local, or Tribal governments or the private sector.

F. Executive Order 13132: Federalism

This action does not have federalism implications as it revises an already existing FIP. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.

G. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments

This proposed rule does not have Tribal implications, as specified in Executive Order 13175. It will not have substantial direct effects on Tribal governments. Thus, Executive Order 13175 does not apply to this proposed rule.

H. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks

This action is not subject to Executive Order 13045 because it is not 3(f)(1) significant as defined in Executive Order 12866, and because the EPA does not believe the environmental health or safety risks addressed by this action present a disproportionate risk to children.

I. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use

This action is not subject to Executive Order 13211 because it is not a significant regulatory action under Executive Order 12866. This action will not have a significant adverse effect on the supply, distribution, or use of energy as, if finalized, it would result in additional electricity generation remaining on the grid.

J. National Technology Transfer Advancement Act

This rulemaking does not involve technical standards.

Authority: 42 U.S.C. 7401 et seq.

For the reasons stated in the preamble, the Environmental Protection Agency is proposing to amend 40 CFR part 52 as follows:

1. The authority citation for part 52 continues to read as follows:

Authority: 42 U.S.C. 7401 et seq.

2. In § 52.2636:

a. Table 2 in paragraph (c)(1) is amended by:

i. Revising the entry “PacifiCorp Dave Johnston Unit 3”;

ii. Adding footnote “5” in numerical order; and ( printed page 34597)

iii. Removing footnote “*”; and

b. Removing paragraph (d)(4).

The revisions and additions read as follows:

91 FR 34589