2024-16718. Air Plan Partial Approval and Partial Disapproval; Wyoming; Regional Haze Plan for the Second Implementation Period

Table 1—Class I Areas in Other States That May Be Affected by Wyoming Sources

State	Class I area
Colorado	Eagles Nest Wilderness Area.
Colorado	Flat Tops Wilderness Area.
Colorado	Maroon Bells-Snowmass Wilderness Area.
Colorado	Mount Zirkel.
Colorado	Rawah Wilderness.
Colorado	Rocky Moutain National Park.
Colorado	West Elk Wilderness.
Idaho	Craters of the Moon National Monument.
Montana	Red Rocks Lakes National Wildlife Refuge.
North Dakota	Theodore Roosevelt National Park.
Nevada	Jarbidge Wilderness.
South Dakota	Badlands/Sage Creek Wilderness.
South Dakota	Wind Cave National Park.
Utah	Arches National Park.
Utah	Canyonlands National Park.
Utah	Capitol Reef National Park.

B. Calculation of Baseline, Current, and Natural Visibility Conditions; Progress to Date; and Uniform Rate of Progress for Class I Areas Within 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).

The IMPROVE monitoring network measures visibility impairment caused by air pollution at Class I areas. Wyoming's 2022 SIP submission provides visibility conditions for each IMPROVE monitor and associated Class I area in Wyoming (table 2).^[49]

Table 2—Visibility Conditions (Deciviews) for Wyoming IMPROVE Stations

Monitor ID	Class I areas	Baseline (2000-2004)	Period (2008-2012)	Current (2014-2018)	Natural (2064)	Progress since baseline (2000-2004)- (2014-2018)	Progress during last implementation period (2008-2012)- (2014-2018)	Difference between current (2014-2018) and natural (2064)
Most Impaired Days
YELL2	Yellowstone National Park, Grand Teton National Park, Teton Wilderness Area	8.3	7.5	7.5	4.0	0.8	0	3.5
NOAB1	Washakie Wilderness Area, North Absaroka Wilderness Area	8.8	7.7	7.2	4.5	1.6	0.5	2.7
BRID1	Bridger Wilderness Area, Fitzpatrick Wilderness Area	8.0	7.2	6.8	3.9	1.2	0.4	3.5
Clearest Days
YELL2	Yellowstone National Park, Grand Teton National Park, Teton Wilderness Area	2.6	1.5	1.4	0.4	1.1	0.1	1
NOAB1	Washakie Wilderness Area, North Absaroka Wilderness Area	2.0	1.4	0.7	0.6	1.3	0.7	0.1
BRID1	Bridger Wilderness Area, Fitzpatrick Wilderness Area	2.1	1.1	0.9	0.3	1.2	0.2	0.6

The State also determined the uniform rate of progress for the most impaired and clearest days for all Wyoming Class I areas.^[50] Under 40 CFR 51.308(f)(1)(vi)(B), Wyoming chose to adjust the uniform rate of progress glidepath for all the State's Class I areas to account for impacts from anthropogenic sources outside the United States and impacts from wildland prescribed fires.^[51 52] Wyoming also provided haze indices and the uniform rate of progress for IMPROVE monitors and associated Class I areas outside the State.^[53]

Based on the information provided in Chapter 6 of Wyoming's 2022 SIP submission, the EPA is proposing to approve the State's visibility condition calculations for Grand Teton National Park, Yellowstone National Park, Bridger Wilderness Area, Fitzpatrick Wilderness Area, North Absaroka Wilderness Area, Teton Wilderness Area, and Washakie Wilderness Area, as meeting the requirements of 40 CFR 51.308(f)(1) related to the calculations of baseline, current, and natural visibility conditions; progress to date; and the URP.

C. Long-Term Strategy

Each state having a Class I area within its borders or emissions that may affect visibility in any Class I area outside the state must develop a long-term strategy for making reasonable progress towards the national visibility goal for each impacted Class I area. CAA section 169A(b)(2)(B). As explained in the Background section of this document, 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 strategy, 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).

1. Summary of Wyoming's 2022 SIP Submission

Wyoming identified 23 Class I areas that must be addressed in its long-term strategy.^[54] Under 40 CFR 51.308(f)(2)(i), SIP submittals must include a description of the criteria a state used to determine which sources or groups of sources to evaluate through four-factor analysis. Wyoming used a Q/d screening approach to identify sources for four-factor analysis. The Q/d screening metric uses a source's annual emissions in tons (Q) divided by the distance in kilometers (d) between the source and the nearest Class I area, along with a reasonably selected threshold for this metric. The larger the Q/d value, the greater the source's expected effect on visibility in each associated Class I area. Wyoming opted to use the Q/d screening metric because, according to the State, it accounts for three of the largest anthropogenically-sourced pollutants (NO_X, SO₂ , and PM) that contribute to visibility impairment in Wyoming Class I areas.^[55]

Using a screening threshold of Q/d > 10 and emissions information from the 2014 National Emission Inventory (NEI), Wyoming initially identified 20 sources in the State that may be affecting visibility at Class I areas in Wyoming and surrounding states.^[56] Upon contacting the identified sources, the State received updated emissions information from 14 of the 20 sources,^[57] and the State further revised emissions values for the sources that did not provide updated emissions information to reflect the 2017 NEI.^[58] Using updated emissions information to calculate Q/d, the State screened out five sources because they fell below its Q/d threshold of 10.^[59] Three coal facilities (Antelope Mine, Black Thunder Mine, and North Antelope Rochelle Mine) were also screened out from further consideration based on the State's assessment that coarse mass PM, the primary component of emissions from those mines, has relatively little effect on visibility in Class I areas and should not be included in the mines' Q values.^[60] Ultimately, the State selected twelve sources to perform a four-factor analysis (table 3).

Table 3—Facilities Screened in Using Q/ d and Class I Area With Maximum Q/ d

Facility name	Class I area with maximum Q/d	Class I area state	Distance (km) to Class I area	Updated Q/d value (tpy/km)
				NO X + SO 2 + PM 10	NO X	SO 2	PM 10
Jim Bridger Power Plant (PacifiCorp)	Bridger Wilderness Area	WY	97.39	160	83.75	68.48	7.77
Laramie River Station Power Plant (Basin Electric)	Rawah Wilderness Area	CO	164.27	85.89	36.25	42.80	6.85
Laramie Portland Cement (Mountain Cement Company)	Rocky Mountain National Park	CO	30.54	82.23	73.16	4.19	4.87
Naughton Power Plant (PacifiCorp)	Bridger Wilderness Area	WY	141.64	78.57	39.31	28.58	10.68
Dave Johnston Power Plant (PacifiCorp)	Wind Cave National Park	SD	198.38	77.33	32.15	41.38	3.80
Green River Works (TATA Chemicals)	Bridger Wilderness Area	WY	122.11	43.81	16.08	18.52	9.22
Westvaco Facility (Genesis Alkali)	Bridger Wilderness Area	WY	122.62	38.23	17.04	11.96	9.23
Wyodak Power Plant (PacifiCorp)	Wind Cave National Park	SD	167.23	37.53	21.89	14.65	0.99
Elk Basin Gas Plant (Contango Resources, Inc.)	North Absaroka Wilderness Area	WY	52.84	27.64	16.58	10.82	0.24
Granger Soda Ash Facility (Genesis Alkali)	Bridger Wilderness Area	WY	119.74	15.49	10.94	1.62	2.93
Lost Cabin Gas Plant (Burlington Resources)	Washakie Wilderness Area	WY	132.94	13.06	0.54	12.28	0.24
Cheyenne Fertilizer (Dyno Nobel Inc.)	Rocky Mountain National Park	CO	81.73	12.33	8.57	0.01	3.76

The State then requested each of the twelve sources to submit four-factor analyses for its review and consideration.^[61] As described in this document, some sources elected not to do so, arguing that four-factor analysis should not be required for their facilities. Wyoming attached the facilities' four-factor analyses (or other submissions) as Appendices C-L to its 2022 SIP submission. Chapter 11 of the SIP submission contains Wyoming's evaluation of the four statutory factors for each source (or the reasons for not performing a four-factor analysis) and Wyoming's determinations of the source-specific emission reduction measures necessary to make reasonable progress. In sections IV.C.1.a.-l. of this document, we summarize the four-factor analyses or other facility submissions for the twelve selected sources.

a. PacifiCorp—Jim Bridger Power Plant ^[62]

PacifiCorp's Jim Bridger Power Plant is located in Sweetwater County, Wyoming. Jim Bridger is comprised of four identically sized nominal 530 megawatts (MW) tangentially coal-fired boilers that have a total net generating capacity of 2,120 MW. Emissions from Jim Bridger may affect visibility in 17 Class I areas in Colorado, Montana, Utah, and Wyoming (table 32 in section IV.C.2.a. of this document).

Neither the State nor PacifiCorp conducted a four-factor analysis for this source. Relying on the “facility analysis information” submitted by PacifiCorp (appendix C to Wyoming's 2022 SIP submission), the State concluded that Jim Bridger Units 1-4 already have effective NO_X and SO₂ emission control technologies in place (table 4).

Table 4—Installed NO _X and SO ₂ Emissions Controls at Jim Bridger Units 1-4

Unit	SO 2 controls	NO X controls
1	FGD 1	LNB 2 /SOFA.3
2	FGD	LNB/SOFA.
3	FGD	LNB/SOFA + SCR.4
4	FGD	LNB/SOFA + SCR.
1  Flue gas desulfurization (FGD).
2  Low NO X burners (LNB).
3  Separated overfire air (SOFA).
4  Selective catalytic reduction (SCR).

Additionally, the State describes a consent decree between Wyoming and PacifiCorp allowing for the short-term continued operation of Jim Bridger Units 1-2, subject to lower plant-wide month-by-month permitted emission limits and an annual emissions cap for NO_X and SO₂ , until Units 1-2 are converted to natural gas in 2024.^[63] Finally, the State notes that dry sorbent injection (DSI) was not recommended for Jim Bridger because the existing SO₂ controls are more efficient.

In its response to the State's initial request to submit a four-factor analysis,^[64] PacifiCorp asserted that Jim Bridger should be excluded from that requirement, and consequently the facility should not be analyzed or required to install any additional controls or take further actions during the regional haze second planning period. First, PacifiCorp claimed that Jim Bridger Units 1-4 already have effective NO_X and SO₂ controls in place, thereby exempting these units from further analysis. Specifically, PacifiCorp referenced: (1) FGD scrubber systems, installed on all units, as meeting the applicable alternative SO₂ emission limit of the 2012 Mercury and Air Toxics Standards (MATS); (2) LNB/SOFA NO_X emission controls installed in 2010 (Unit 1), 2006 (Unit 2), 2007 (Unit 3), and 2008 (Unit 4); and (3) SCR NO_X emission controls installed in 2015 (Unit 3) and 2016 (Unit 4). PacifiCorp also referenced plant-wide monthly-block NO_X and SO₂ emission limits, which it stated have been demonstrated to achieve greater reasonable progress and visibility improvement than could be achieved through installation of SCR at Jim Bridger Units 1 and 2 and at a substantially lower cost. PacifiCorp contended that these circumstances align with the examples provided in the EPA's 2019 Guidance, which detail scenarios ^[65] in which it may be reasonable for a state not to select a particular source for further analysis, including: (1) FGD controls that meet the applicable alternative SO₂ emission limit of the 2012 MATS rule for power plants; (2) NO_X and SO₂ controls that were installed during the first planning period and operate year-round with an effectiveness of at least 90 percent on a pollutant-specific basis ( e.g., FGD or SCR); and (3) BART-eligible units that installed and began operating controls to meet BART emission limits for the first regional haze implementation period.

Second, PacifiCorp argued that recent decision making regarding emission controls for the first implementation period and PacifiCorp's installation of post-combustion controls during that period should exempt Jim Bridger from further analysis during the second implementation period. PacifiCorp referenced the reasonable progress “reassessment” conducted under 40 CFR 51.308(d)(1) for the first implementation period, which led to Wyoming's submission of a first implementation period SIP revision containing emission limits associated with the conversion from coal-firing to natural gas-firing at Units 1-2.^[66] PacifiCorp also highlighted the 2015-2016 installation of SCR on Units 3-4 and FGD scrubbers upgraded on Units 1-4 between 2008-2011. PacifiCorp argued that these first implementation period controls eliminate the need for a four-factor analysis for the second implementation period, pointing to the EPA's statement in the 2019 Guidance that “it may be appropriate for a state to rely on a previous . . . reasonable progress analysis for the characterization of a factor, for example information developed in the first implementation period on the availability, cost, and effectiveness of controls for a particular source, if the previous analysis was sound and no significant new information is available.” ^[67]

Third, PacifiCorp asserted that Jim Bridger Units 1-2 are exempt from four-factor analysis for the second implementation period because, under the company's 2019 Integrated Resource Plan (IRP), Unit 1 was scheduled for retirement by the end of 2023 and Unit 2 was scheduled for retirement before the end of 2028.^[68] Those scheduled closures both fall within the second planning period, although PacifiCorp acknowledged it is not subject to an enforceable obligation to close any units at Jim Bridger.

Lastly, PacifiCorp stated that under the EPA's 2019 Guidance, Wyoming may consider changes in operating parameters, such as those resulting from renewable energy sources coming online, to exempt Jim Bridger Units 1-4 from four-factor analysis. PacifiCorp cited its 2019 IRP,^[69] which documents plans to make operational adjustments at Jim Bridger to accommodate renewable energy resources. PacifiCorp stated that these changes will cause future emissions at Jim Bridger to differ significantly from historical emissions.

b. PacifiCorp—Naughton Power Plant ^[70]

PacifiCorp's Naughton Power Plant is located in Lincoln County, Wyoming. Naughton is comprised of two tangentially-fired units burning pulverized coal (Units 1-2) and one natural gas-fired unit (Unit 3), which have a total net generating capacity of 700 MW. Emissions from Naughton may affect the visibility in 17 Class I areas in Colorado, Idaho, Montana, Nevada, Utah, and Wyoming (table 32).

Neither the State nor PacifiCorp conducted a four-factor analysis for Naughton. Instead, Wyoming refers to the “facility analysis information” submitted by PacifiCorp, which Wyoming included as appendix C in its 2022 SIP submission. The State references PacifiCorp's 2019 IRP, which includes the planned retirement of Units 1 and 2 by the end of 2025.^[71] Unit 3 ceased coal combustion in 2019 and converted to natural gas that same year. The State also notes that Naughton Units 1-2 already have NO_X and SO₂ emission control technologies in place (table 5).

Table 5—Installed NO _X and SO ₂ Emissions Controls at Naughton Units 1-2

Unit	SO 2 controls	NO X controls
1	FGD	LNB/SOFA.
2	FGD	LNB/SOFA.

The State further explains that although its modeling incorporated the planned retirements and associated emissions reductions at Units 1-2, the State is not crediting the planned emissions reductions until the facility submits a permit application and the State issues a permit. The State notes that DSI is not being considered for Units 1-2 because the existing scrubbers are more effective for SO₂ removal. Wyoming states that it intends to conduct additional analysis on Units 1-2 in its 2025 regional haze progress report.

With respect to Naughton Unit 3, the State asserts that the 2019 conversion to natural gas resulted in a potential reduction of 8,909.5 tons of visibility impairing pollutants. The Q/d analysis of Naughton Unit 3 is 4.1, which the State notes is below its chosen threshold of Q/d > 10 for sources warranting a four-factor analysis.

In its response to the State's initial request to submit a four-factor analysis,^[72] PacifiCorp asserted that its Naughton facility should be excluded from that requirement, and consequently should not be required to install any additional controls or take further actions during the regional haze second implementation period. PacifiCorp relied on arguments similar to those it provided for Jim Bridger, discussed in section IV.C.1.a. above.

First, PacifiCorp cited its 2019 IRP preferred portfolio, which includes the planned retirement of Naughton Units 1-2 by the end of 2025 (before the end of the regional haze second planning period in 2028). PacifiCorp acknowledged that it is under no legal obligation to close those units by that time, but detailed the plans in its 2019 IRP to initiate closure of Units 1-2, complete regulatory notices and filings, engage in employee transition and community action plans, confirm transmission system reliability, and terminate, amend, or close out existing permits, contracts, and agreements.^[73] PacifiCorp also pointed to the EPA's coal combustion residuals (CCR) disposal rule as further impacting the certainty of closure for Naughton Units 1-2 if that rule is finalized as proposed. According to PacifiCorp, the CCR rule would require it to construct new, lined CCR impoundments that PacifiCorp claimed would prove uneconomical for its customers, or otherwise cease operation and close the CCR impoundments by 2028.

Second, PacifiCorp asserted that Naughton Units 1-3 already have effective NO_X and SO₂ controls in place, thereby exempting these units from further analysis. Specifically, PacifiCorp referenced: (1) FGD scrubber systems, installed on Unit 1 in 2011 and on Unit 2 in 2012, as meeting the applicable alternative SO₂ emission limit of the 2012 MATS rule; and (2) LNB/SOFA NO_X emission controls installed on Unit 1 in 2012 and on Unit 2 in 2011. Additionally, PacifiCorp explained that Unit 3 ceased coal-fired operation in 2019 and is undergoing conversion to natural gas. These NO_X and SO₂ emission control technologies, according to PacifiCorp, align with the examples provided in the EPA's 2019 Guidance.

Third, PacifiCorp cited expected operational adjustments at Naughton to accommodate increases in renewable energy as an additional reason why a four-factor analysis is not required. PacifiCorp stated that Naughton's 2028 projected operations, or lack thereof, indicate that the plant's emissions will differ significantly from historical emissions due to PacifiCorp's changing portfolio and market opportunities to increase both energy efficiency and renewable resources.

Finally, PacifiCorp concluded that given the planned retirements of Units 1-2, Naughton would fall below Wyoming's Q/d threshold of >10 and should therefore be excluded from four-factor analysis at this time. According to PacifiCorp's calculations, Unit 3 would be the only operating unit throughout the second implementation period and has a Q/d of 4.1 for the nearest Class I area (Bridger Wilderness).

c. Basin Electric—Laramie River Station Power Plant ^[74]

Basin Electric's Laramie River Station Power Plant is located in Platte County, Wyoming and is comprised of three 614 MW (gross) subbituminous coal-fired boilers. Emissions from Laramie River Station may affect the visibility in 10 Class I areas in Colorado, South Dakota, and Wyoming (table 32).

Table 6 describes the installed NO_X, SO₂, and PM emissions controls for all three units.

Table 6—Installed NO _X , SO ₂ , and PM Emissions Controls at Laramie River Station 1-3

Unit	SO 2 controls	NO X controls	PM controls
1	Wet FGD	LNB/OFA 1 + SCR	ESPs.2
2	Wet FGD	LNB/OFA + SNCR 3	ESPs.
3	Dry FGD	LNB/OFA + SNCR	ESPs.
1  Overfire air (OFA).
2  Electrostatic precipitation (ESP).
3  Selective non-catalytic reduction (SNCR).

Relying on an analysis submitted by the facility (included as appendix D in the Wyoming 2022 SIP submission), the State conducted a four-factor analysis for NO_X and SO₂ controls, but not for PM controls. The State did not evaluate Unit 1 for further NO_X emissions controls because it is equipped with SCR, which the State asserts is the best available control technology (BACT) for NO_X . The State evaluated SCR as the technically feasible option for further NO_X emissions control on Units 2 and 3 (table 7). For further SO₂ emissions control for Units 1 and 2, the State evaluated equipment upgrades and chemical additives to the existing wet FGD controls as well as the installation of a 6th absorber vessel. For SO₂ emissions controls for Unit 3, the State evaluated converting the existing ESP to a fabric filter (FF) and replacing the existing ESP and installing a new stand-alone FF (table 8).

Table 7—Summary of Laramie River Station Units 2-3 NO _X Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
2	SCR	1,917	$45,473,000	$23,722
3	SCR	2,676	45,058,000	16,840

Table 8—Summary of Laramie River Station Units 1-3 SO ₂ Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
1	Wet FGD upgrades	235	$1,134,000	$4,824
	Wet FGD additives	494	5,018,000	10,156
	6th absorber vessel	587	7,399,000	12,611
2	Wet FGD upgrades	266	1,167,000	4,388
	Wet FGD additives	559	7,266,000	12,998
	6th absorber vessel	664	10,068,000	15,168
3	ESP to FF conversion	703	20,079,000	28,551
	ESP to FF replacement	703	25,022,000	35,580

The State estimated the time necessary to achieve compliance using SCR controls at Units 2 and 3 to be 60 months. It estimated the time necessary to achieve compliance at Units 1 and 2 using wet FGD upgrades as 11 months, wet FGD additives as 12 months, and addition of a 6th absorber vessel as 60 months. The State estimated the time necessary to achieve compliance with ESP to FF conversion to be 32 months and ESP to FF replacement to be 46 months. These timelines do not include the time associated with regulation development or SIP approval.

The State identified several energy and non-air environmental impacts associated with the installation and operation of potential controls at Laramie River Station. For SCR on Units 2 and 3, the State noted increased auxiliary power requirements and heat rate penalty, potential decrease in ammonia slip emissions, and potential increase in SO₂ emissions. For SO₂ controls on Units 1 and 2, the State observed that (1) wet FGD upgrades may result in increased limestone consumption, increased solid FGD by-product management and disposal, and increased auxiliary power requirements and heat rate penalty; (2) wet FGD additives may result in increased limestone consumption, high reagent consumption cost, increased solid FGD by-product management and disposal, and increased auxiliary power requirements and heat rate penalty; and (3) 6th absorber vessel addition may require capital intensive projects, resulting in relocation of existing dewatering equipment, increased limestone and water consumption, increased solid FGD by-product management and disposal, and increased auxiliary power requirements and heat rate penalty. Finally, as to converting the existing ESP to a FF or replacing the existing ESP with a FF, the State noted impacts from capital intensive projects, extended unit outage or unit derate, and increased auxiliary power requirements and heat rate penalty.

In its consideration of the remaining useful life of Laramie River Station Units 1-3, the State used the 20-year equipment life of the control measures.

Finally, the State highlighted that NO_X emissions are below the permitted ^[75] threshold and have been decreasing overall, particularly for Units 1 and 3. The State also noted that it did not expect permit conditions to change between 2020 and the third implementation period. Likewise, the State determined that SO₂ emissions have declined by over 780 tons/year between the three units, SO₂ emissions trends do not show an increase in emissions, and permit conditions are not anticipated to change between 2020 and the third planning period.

Ultimately, after considering the four factors, historical emissions data, and permit conditions, Wyoming determined that no additional controls are necessary on Laramie River Station Units 1-3 in the second planning period for regional haze. The State concluded that further controls will be evaluated in the third planning period.

d. PacifiCorp—Dave Johnston Power Plant ^[76]

PacifiCorp's Dave Johnston Power Plant is located in Converse County, Wyoming and is comprised of four coal-fired units using local subbituminous coal. Units 3 and 4 were both subject to BART in the first planning period. Unit 3 is a nominal 230 MW pulverized coal-fired boiler that commenced service in 1964 and has a federally enforceable commitment to shut down by December 31, 2027. Unit 4 is a nominal 361 MW pulverized coal-fired tangential boiler that commenced service in 1972 and is equipped with FGD for SO₂ control, LNB/SOFA for NO_X control, and a baghouse retrofit for PM control. Emissions from Dave Johnston may affect the visibility in 13 Class I areas in Colorado, South Dakota, and Wyoming (table 32).

Neither the State nor PacifiCorp conducted a four-factor analysis for Units 1-3. Instead, the State referenced information supplied by PacifiCorp in appendix C of Wyoming's 2022 SIP submission and in PacifiCorp's 2019 IRP. The 2019 IRP includes the planned retirement of Units 1 and 2 by the end of 2027 ^[77] and the federally enforceable retirement of Unit 3 by December 31, 2027.^[78] The State explained that its modeling incorporated the planned retirements and associated emission reductions at Units 1-3. However, until the facility submits a permit application and the State issues a permit, the State is not crediting the planned emission reductions and intends to conduct additional analysis on Units 1-3 in its 2025 regional haze progress report.

In its response to the State's initial request to submit a four-factor analysis,^[79] PacifiCorp asserted that Dave Johnston should be excluded from that requirement, and consequently should not be required to install any additional controls or take further actions during the regional haze second planning period. PacifiCorp submitted a four-factor analysis only for Unit 4.

PacifiCorp argued that several factors alleviate the need for a four-factor analysis for Dave Johnston Units 1-3. First, PacifiCorp cited its 2019 IRP preferred portfolio, which includes the planned—but not federally enforceable—retirement of Dave Johnston Units 1-2 by the end of 2027 (before the end of the regional haze second planning period in 2028).^[80] PacifiCorp also pointed to the EPA's proposed revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category as further impacting the certainty of closure for Units 1-2 if the rules are finalized as proposed. PacifiCorp contended that the rules would require generating units like Dave Johnston Units 1-2 that currently rely on the discharge of treated bottom ash transport water into a surface impoundment to close by December 31, 2028.

Second, PacifiCorp explained that Dave Johnston Unit 3 is subject to a federally enforceable requirement to shut down and is therefore not subject to four-factor analysis. As a result of its decision to pursue a shutdown compliance option provided in the EPA's 2014 FIP, PacifiCorp requested that the State revise BART permit MD-6041A to include an enforceable requirement for Unit 3 to cease operation by December 31, 2027.

Third, PacifiCorp argued that Dave Johnston Unit 3 currently has effective SO₂ and PM emissions control technology in place, which it asserted exempts this unit from further analysis. PacifiCorp referenced: (1) FGD scrubber systems, installed in 2010, as meeting the applicable alternative SO₂ emission limit of the 2012 MATS rule; and (2) a baghouse retrofit for PM emissions control installed in 2010. PacifiCorp argued that these SO₂ and PM emissions controls align with the examples provided in the EPA's 2019 Guidance.

Finally, PacifiCorp urged Wyoming to consider changes in operating parameters at Dave Johnston Units 1-3 to accommodate increased deployment of renewable energy resources in its portfolio. PacifiCorp stated that these operational adjustments will cause future emissions at Dave Johnston to decline compared to historical emissions. PacifiCorp argued that the EPA's 2019 Guidance allows for consideration of such circumstances when evaluating the need for a four-factor analysis.

Unlike Units 1-3, the State performed a four-factor analysis for Dave Johnston Unit 4 for NO_X and SO₂ controls. Table 9 describes the installed NO_X, SO₂, and PM controls at Unit 4.

Table 9—Installed NO _X , SO ₂ , and PM Emissions Controls at Dave Johnston, Unit 4

Unit	SO 2 controls	NO X controls	PM controls
4	FGD; SDA 1	LNB/OFA	FF baghouse.
1  Spray dryer absorber.

The State evaluated both SNCR and SCR as technically feasible options for NO_X control at Unit 4 (table 10). DSI was not evaluated for SO₂ control because, according to the State, scrubber upgrades are more effective than DSI for incremental pollution control; no further SO₂ analysis was conducted. No four-factor analysis for PM controls was provided.

Table 10—Summary of Dave Johnston Unit 4 NO _X Cost Analysis

Control technology	Emission rate (lb/MMBtu) 1	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
SNCR	0.12	187	$2,889,000	$15,411
SCR	0.05	1,035	11,881,000	11,480
1  Pound per one million British thermal units (lb/MMBtu).

The State estimated the time necessary to achieve compliance using either SNCR or SCR at Unit 4 to be 2028, the end of the second planning period.

The State identified the following energy and non-air environmental impacts associated with the installation and operation of SCR: increased electrical energy to operate; the storage, use, and disposal of ammonia (a hazardous substance); and a potential increase in the amount of coal the unit would be required to burn to achieve the same amount of energy production, resulting in an increase of CCR waste requiring disposal, emissions of greenhouse gases, and consumption of water and other resources. The State also identified the storage and use of urea as a non-air environmental impact associated with the installation and operation of SNCR.

The State estimated the remaining useful life of Unit 4 to be 2027 based on PacifiCorp's 2019 IRP. However, the State also noted that PacifiCorp used a depreciable life of 20 years for SNCR and 30 years for SCR to estimate costs.

Based on the four-factor analysis, the State determined that installation of SNCR or SCR at Unit 4 is not cost-effective, would require long lead times before emissions reductions are achieved, would have negative energy and non-air environmental impacts, and would make the unit less likely to operate through the end of its remaining useful life. Additional consideration of historical emissions data and permit conditions, which Wyoming expects to remain the same, led the State to ultimately determine that no additional controls are necessary for Unit 4 in the second planning period.

e. Genesis Alkali—Westvaco ^[81]

Genesis Alkali's Westvaco facility is a trona ore ^[82] mine and soda ash production plant located in Sweetwater County, Wyoming. Westvaco has two existing subbituminous coal-fired boilers, Unit NS-1A and Unit NS-1B, with each having a design heat input rate of 887 MMBtu/hr. The facility also has two mono calciners (MONO5 and NS3) and one lime kiln (SM-1) that, combined with the two boilers, have emissions of NO_X, SO₂, and PM totaling at least 100 tons/year. Emissions from Westvaco may affect the visibility in 19 Class I areas in Colorado, Idaho, Montana, Utah, and Wyoming (table 32).

Table 11 describes the installed NO_X, SO₂, and PM emissions controls at Westvaco.

Table 11—Installed NO _X , SO ₂ , and PM Emissions Controls at Westvaco

Unit	SO 2 controls	NO X controls	PM controls
NS-1A (coal-fired boiler)	Wet scrubber	LNB/OFA	ESP.
NS-1B (coal-fired boiler)	Wet scrubber	LNB/OFA	ESP.
NS3 (gas-fired calciner)		Good combustion 1	ESP.
MONO5 (gas-fired calciner)		Good combustion 1	Wet scrubber.
SM-1 (gas-fired kiln)		Good combustion 1	Wet scrubber.
1  Wyoming used the term “good combustion practices” to describe existing efforts to control NO X emissions from these units. Although not specified by the State, good combustion practices may include, but are not limited to, proper burner maintenance, proper burner alignment, proper fuel to air distribution and mixing, routine inspection, and preventive maintenance.

The State conducted a four-factor analysis for several units at Westvaco, relying on information submitted by the facility (attached as appendix E to the Wyoming 2022 SIP submission). In its evaluation of further NO_X emissions controls, the State considered SNCR and SCR for the two coal-fired boilers and LNB for the gas-fired calciners and lime kiln (table 12). Trona injection prior to ESP was evaluated for further SO₂ emissions control on the coal-fired boilers; no further SO₂ emissions controls were evaluated for the gas-fired calciners and lime kiln (table 13). For further PM emissions control, the State evaluated FF and wet ESP on the two coal-fired boilers, wet ESP on one of the calciners (NS3), and ESP and wet ESP on the other calciner (MONO5) and lime kiln (table 14).

Table 12—Summary of Westvaco NO _X Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
NS-1A (coal-fired boiler)	SNCR/SCR	397/893	$3,079,590/$5,395,079	$7,757/$6,039
NS-1B (coal-fired boiler)	SNCR/SCR	414/933	3,014,532/5,379,506	7,273/5,769
NS3 (gas-fired calciner)	LNB	36.6	530,569	14,490
MONO5 (gas-fired calciner)	LNB	28.3	395,507	14,000
SM-1 (gas-fired kiln)	LNB	44.1	323,875	7,339

Table 13—Summary of Westvaco SO ₂ Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
NS-1A (coal-fired boiler)	Trona injection prior to ESP	205.6	$2,674,635	$13,007
NS-1B (coal-fired boiler)	Trona injection prior to ESP	201.9	2,674,634	13,249

Table 14—Summary of Westvaco PM Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
NS-1A (coal-fired boiler)	Fabric filter/Wet ESP	1  242.2/242.2	$3,466,804/$3,064,278	$14,314/$12,652
NS-1B (coal-fired boiler)	Fabric filter/Wet ESP	1  33.4/33.4	3,445,297/3,026,284	103,079/90,542
NS3 (gas-fired calciner)	Wet ESP	267.2	2,196,068	8,219
MONO5 (gas-fired calciner)	ESP/Wet ESP	145/145	1,203,249/1,330,528	8,296/9,174
SM-1 (gas-fired kiln)	ESP/Wet ESP	15.7/15.7	911,823/1,114,931	58,004/70,924
1  The PM emissions reductions for NS-1A and NS-1B do not match due to a difference in the 2014 stack test data and heat input.

The State estimated the time necessary to achieve compliance using the controls it evaluated to be at least four years.

The State identified several energy and non-air environmental impacts associated with potential controls at Westvaco. For installation and operation of SNCR on the coal-fired boilers, the State noted storage of additional reagent chemicals onsite, ammonia slip, generation and disposal of wastewater, and generation of emissions due to additional fuel combustion to overcome the energy penalty associated with SNCR. For installation and operation of SCR on the coal-fired boilers, the State identified impacts related to the transport, handling, and use of aqueous ammonia, replacement and disposal of spent catalyst, and adverse air impacts due to ammonia slip; possible formation of a visible plume; oxidation of carbon monoxide to carbon dioxide; and oxidation of SO₂ to sulfur trioxide, with subsequent formation of sulfuric acid mist due to ambient or stack moisture. The State observed that running a wet ESP would require additional electricity and would lead to the generation and disposal of solid waste and wastewater, while replacement of the ESP with a FF would require additional electricity and disposal of the filter bags as waste upon replacement.

The State considered the remaining useful life of the emission units at Westvaco to be 20 years or more.

Finally, Wyoming described the Westvaco permitted NO_X, SO₂, and PM emissions limits ^[83] for the boilers, calciners, and lime kiln in addition to emissions trends for these units over five years (2016-2020). For the boilers, the figures show consistent declines in NO_X emissions (from approximately 900 tons/year to approximately 600 tons/year), SO₂ emissions (from approximately 1,300 tons/year to approximately 550 tons/year), and PM emissions (from approximately 100 tons/year to almost 0 tons/year). For the calciners, NO_X emissions remained constant (50-100 tons/year) and PM emissions slightly declined (from approximately 230 tons/year to 220 tons/year). PM emissions for the lime kiln remained consistent (approximately 20 tons/year), while NO_X emissions increased slightly (from approximately 50 tons/year to approximately 75 tons/year). The State notes that permit conditions were renewed in 2021 and it does not expect emissions at Westvaco to increase before the third planning period.

After considering the four factors, historical emissions data, and current control technologies, Wyoming determined that no additional controls are necessary at Westvaco in the second planning period for regional haze. The State concluded that further controls will be evaluated in the third planning period.

f. Mountain Cement Company—Laramie Portland Cement ^[84]

Mountain Cement Company's Laramie Portland Cement plant is located in Laramie, Wyoming and consists of one long-dry process kiln (Kiln 1) and one long-dry 2-stage preheater kiln (Kiln 2). Together, the kilns are permitted to produce 900,000 tons of cement annually, with Kilns 1 and 2 capable of producing 254,000 tons/year of clinker and 547,500 tons/year of clinker, respectively. Emissions from Laramie Portland Cement may affect the visibility in five Class I areas in Colorado (table 32).

Table 15 describes the installed NO_X, SO₂, and PM emissions controls at Laramie Portland Cement.

Table 15—Installed NO _X , SO ₂ , and PM Emissions Controls at Laramie Portland Cement

Unit	SO 2 controls	NO X controls	PM controls
Kiln 1	Inherent dry scrubbing	Good combustion practice	Baghouse.
Kiln 2	Inherent dry scrubbing	Good combustion practice/2-stage preheater	Baghouse.

Wyoming did not evaluate further SO₂ or PM emissions controls based on historical decreasing emissions trends, PM emissions limits for both kilns based on CAA maximum achievable control technology (MACT) standards, and the use of dust collectors/baghouses that constitute BACT for PM at all point sources at the facility.^[85]

Relying on an evaluation submitted by the facility (attached as appendix L to the Wyoming 2022 SIP submission), the State conducted a four-factor analysis for NO_X emissions control and evaluated SNCR as a technically feasible option (table 16).

Table 16—Summary of Laramie Portland Cement Plant Kilns 1-2 * NO _X Cost Analysis Associated With SNCR

Level of control (% emissions reductions)	Total capital investment ($)	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
10	$5,833,000	933	$17,639,442	$18,900
15		1,005.6		17,540
20		1,077.9		16,360
25		1,150.2		15,340
* Figures are for both kilns combined.

The State estimated the time necessary to achieve compliance using SNCR to be a minimum of 18 months for design, procurement, build, and installation, plus an additional 12 months for staging the installation process across both kilns.

The State identified the following energy and non-air environmental impacts associated with the installation and operation of SNCR: increased electrical energy to operate the SNCR system; possible byproducts from unreacted ammonia, including ammonium sulfate, ammonium bisulfite, and ammonium chloride; and ammonia slip, which can reduce visibility. In addition, the State noted that ammonia and salt absorption into the cement kiln dust (a byproduct) could also make the cement kiln dust unsellable, resulting in an economic penalty.

The State estimated the remaining useful life of Kilns 1 and 2 to be longer than the projected lifetime of the pollution control technology (SNCR) of 20 years, which is the capital cost recovery period of the controls.^[86]

The State noted that NO_X emissions at Kilns 1 and 2 consistently decreased between 2016 and 2020 and that permitted emissions are not expected to change. It also pointed out that Kiln 2 NO_X emissions, in particular, have consistently fallen under the allowable emission limit. Based on consideration of the four factors, historical emissions data, and current control technologies, Wyoming determined that no additional controls at Laramie Portland Cement are necessary to make reasonable progress in the regional haze second implementation period. It stated that further controls will be evaluated in the third implementation period.

g. PacifiCorp—Wyodak Power Plant ^[87]

PacifiCorp's Wyodak Power Plant (Wyodak) is located in Campbell County, Wyoming and includes one coal-fired boiler burning sub-bituminous coal, with a net generating capacity of 335 MW. Emissions from Wyodak may affect the visibility in 11 Class I areas in Colorado, North Dakota, South Dakota, and Wyoming (table 32).

Neither the State nor PacifiCorp conducted a four-factor analysis for Wyodak. In response to the State's initial request to submit a four-factor analysis,^[88] PacifiCorp explained that it was participating in ongoing confidential settlement discussions regarding the first planning period requirements for Wyodak, which it argued will influence whether and how a four-factor analysis will be completed. PacifiCorp requested that the State delay submittal of a second planning period analysis until after settlement discussions concluded. Wyoming referred to ongoing litigation as the reason not to evaluate this source and stated that a four-factor analysis will occur in a future implementation period, if needed.

h. TATA Chemicals—Green River Works ^[89]

TATA Chemicals' Green River Works facility is a trona ore mine and soda ash production plant located in Sweetwater County, Wyoming. Green River Works has two existing subbituminous coal-fired stoker boilers, C Boiler and D Boiler, with a firing rate of 534 MMBtu/hour and 880 MMBtu/hour, respectively. In addition, Green River Works has seven natural gas-fired calciners: five smaller calciners rated at 65 tons of soda ash/hour (50 MMBtu/hour) and two larger calciners, Calciner 1 and Calciner 2, rated at 145 tons of soda ash/hour (200 MMBtu/hour). Relying on information submitted by the facility (attached as appendix G to Wyoming's 2022 SIP submission), the State conducted a four-factor analysis for the two coal-fired boilers and the two large natural gas-fired calciners, as these units have annual actual emissions of visibility-impairing pollutants in excess of 100 tons/year. The State asserts that the remaining emission units at Green River Works are small and contribute a fraction of the facility's visibility-impairing emissions; no four-factor analysis was performed for those units. Emissions from Green River Works may affect the visibility in 19 Class I areas in Wyoming (table 32).

Table 17 describes the installed NO_X, SO₂, and PM emissions controls at Green River Works.

Table 17—Installed NO _X , SO ₂ , and PM Emissions Controls at Green River Works

Unit	NO X controls	SO 2 controls	PM controls
C Boiler	LNB + OFA	DSI	ESPs.
D Boiler	LNB + OFA	DSI	ESPs.
Calciner 1			ESPs.
Calciner 2			ESPs.

In its evaluation of further NO_X emissions controls, the State evaluated SNCR and SCR on the two coal-fired boilers and LNB and SCR on the two calciners (table 18). It evaluated wet and dry flue gas desulfurization (FGD) for further SO₂ emissions control on the coal-fired boilers (table 19). The State evaluated wet and dry ESP for further PM emissions control on the two calciners (table 20).

Table 18—Summary of Green River Works NO _X Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year) 1	Average cost effectiveness 1 ($/ton)
C Boiler	SNCR/SCR	98/295	$885,174/$3,701,998	$9,000/$12,547
D Boiler	SNCR/SCR	150/449	$1,195,034/$5,525,216	$7,992/$12,317
Calciner 1	LNB/SCR	48.3/56.4	$269,500/$548,100	$5,580/$9,720
Calciner 2	LNB/SCR	28.9/38.3	$269,500/$540,900	$9,310/$14,140
1  The total annual cost and average cost effectiveness figures for the C and D Boilers in Wyoming's 2022 SIP submission on page 164 conflict with the figures presented in appendix G (pages G-36 and G-57, among others). The figures from page 164 are presented in table 18.

Table 19—Summary of Green River Works SO ₂ Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
C Boiler	Dry FGD/Wet FGD	855.3/894.4	$5,407,000/$6,092,600	$6,320/$6,810
D Boiler	Dry FGD/Wet FGD	1,392.0/1,456.7	$8,889,200/$10,023,100	$6,390/$6,880

Table 20—Summary of Green River Works PM Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
Calciner 1	Wet ESP/Dry ESP	67.8/57.9	$1,202,900/$976,900	$17,700/$16,900
Calciner 2	Wet ESP/Dry ESP	69.3/67.7	$1,202,900/$976,900	$17,400/$14,400

For the two boilers, the State estimated the time necessary to achieve compliance using SCR to be 28 months and using SNCR to be 24 months. For the two calciners, the State estimated that installation of LNB or SCR would take 28 months, and installation of wet or dry ESP would take 18 months. It estimated the time needed to install wet and dry FGD on the two boilers to be 36 months. These timelines do not include time associated with regulation development or SIP approval.

The State identified several energy and non-air environmental impacts associated with the installation and operation of controls at Green River Works. For SCR or SNCR, the State noted the storage of additional reagent chemicals onsite, ammonia slip, increased electric power requirements, and formation of ammonium salt, which may result in additional fine particulate matter emissions. As to wet or dry FGD, the State identified steam output capacity penalty or reduction of more than 1%, along with a boiler efficiency impact of approximately 1.5%, combined with additional electricity and water demand and liquid and solid waste disposal requirements. In addition, the State asserted that dry FGD systems (for SO₂ control) may increase PM emissions from the boiler, while the operation of a wet FGD system, and potentially a dry FGD system, would result in visibility impacts by causing a visible plume from the stack.

In considering remaining useful life, the State explained that both the emission units and the new equipment are expected to last 20 years or more.

Finally, Wyoming provided the emission trends for the C and D Boilers over five years (2016-2020).^[90] The figures show that C Boiler NO_X emissions remained steady (at approximately 400 tons/year), while SO₂ emissions consistently declined (from approximately 1,800 tons/year to approximately 700 tons/year). For the D Boiler, NO_X emissions also remained steady (at approximately 600 tons/year), while SO₂ emissions consistently declined (from approximately 3,500 tons/year to approximately 1,000 tons/year). Wyoming stated that NO_X and SO₂ emissions from the C and D Boilers are not expected to significantly increase between 2020 and the third planning period.

Ultimately, based on its consideration of the four factors, historical emissions data, and current control technologies, Wyoming determined that no additional controls are necessary at Green River Works in the second planning period for regional haze. The State concluded that further controls will be evaluated in the third planning period.

i. Contango Resources, Inc.—Elk Basin Gas Plant ^[91]

Contango Resources, Inc.'s Elk Basin Gas Plant in Park County, Wyoming is a sour natural gas processing and liquids extraction plant designed to process 10 million standard cubic feet per day of sour gas into propane, butane, natural gas, gasoline, and elemental sulfur. The Elk Basin Gas Plant has nine natural gas-fired compressor engines and a natural gas-fired incinerator, with each having a design heat input rate of 358.5 MMBtu/hour. Emissions from the Elk Basin Gas Plant may affect the visibility in two Class I areas in Wyoming (table 32).

Relying on information submitted by the facility (attached as appendix H to the Wyoming 2022 SIP submission), the State evaluated low emission combustion (LEC) for further NO_X emissions control on the nine compressor engines (table 21). For further SO₂ emissions control on the incinerator, it evaluated one option of optimization of the existing 2-stage Claus Plant, and another option of adding a third stage to the Claus Plant and adding a tail gas treating unit (table 22). The State did not evaluate further PM emissions controls on any units.

Table 21—Summary of Elk Basin Gas Plant NO _X Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Average cost effectiveness ($/ton)
Nine (9) compressor engines (EC1-EC9)	LEC	1,793.55	$1,500-$2,200

Table 22—Summary of Elk Basin Gas Plant SO ₂ Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Average cost effectiveness ($/ton)
Incinerator (INC-1)	Optimizing 2-stage Claus Plant	50	$24,000
	Adding a 3rd stage to the Claus Plant and a tail gas treating unit	80	200,000

The State estimated the time necessary to achieve compliance using LEC NO_X emissions controls on the nine compressor engines to be three to five years after the SIP is approved. For SO₂ control on the incinerator, it estimated that optimizing the 2-stage Claus Plant would take two to five years, while adding a third stage to the Claus Plant together with adding a tail gas treating unit would take three to five years after the SIP is approved.

The State identified the following energy and non-air environmental impacts associated with the installation and operation of LEC controls on the nine compressor engines: an annual electricity cost increase of approximately $11,500 per 1,200 horsepower engine and a potential decrease in PM emissions due to more ideal combustion. Likewise, the State expected that optimizing the 2-stage Claus Plant and adding a third stage to the Claus Plant would both result in increased use of electricity due to added instrumentation. It noted that the amount of sulphur catalyst requiring landfill disposal is expected to decrease with the optimization of the existing 2-stage Claus Plant, while adding a third stage to the Claus Plant is expected to increase sulphur catalyst disposal needs.

In evaluating remaining useful life, Wyoming stated that the LEC control units are expected to last 20 to 25 years. Both control options for the tail gas incinerator are expected to last 30 years.

The State also provided the permitted SO₂ emissions limits for the incinerator ^[92] and emissions trends for both the incinerator and nine compressor engines over five years (2016-2020). The figures show that the incinerator's SO₂ emissions consistently dropped (from approximately 500 tons/year to approximately 350 tons/year) and are below the permitted limit of 3,044.1 tons/year. According to the State, the SO₂ emissions from the incinerator are expected to continue to decrease. The figures show consistent declines in NO_X emissions between 2016-2020 for all compressor engines except EC8, which showed a slight increase. Overall, Wyoming concluded that NO_X and SO₂ emissions at the Elk Basin Gas Plant have consistently declined and are not expected to change in a way that significantly increases emissions.

Ultimately, after considering the four factors, emissions trends, and permit conditions, Wyoming determined that the Elk Basin Gas Plant may warrant further analysis of emission controls. The State remarked that it would submit more detailed analyses in the regional haze progress report due January 31, 2025, to determine if any new controls are reasonable for this facility and should be scheduled for implementation.

j. Genesis Alkali—Granger Soda Ash Facility ^[93]

Genesis Alkali's Granger Soda Ash facility (Granger) is a trona ore mine and soda ash production plant located in Sweetwater County, Wyoming. Granger has two existing subbituminous coal-fired stoker boilers, Unit UIN-14 and Unit UIN-15, with each having a design heat input rate of 358.5 MMBtu/hour. The remaining emission units at Granger reported 2014 actual emissions of less than 5 tons/year each of SO₂, NO_X, and PM₁₀. Emissions from Granger may affect the visibility in two Class I areas in Wyoming (table 32).

Table 23 describes the installed NO_X, SO₂, and PM emissions controls at Granger.

Table 23—Installed NO _X , SO ₂ , and PM Emissions Controls at Granger

Unit	SO 2 controls	NO X controls	PM controls
UIN-14 (coal-fired boiler)	Wet scrubber	OFA	ESP.
UIN-15 (coal-fired boiler)	Wet scrubber	OFA	ESP.

Relying on information submitted by the facility (attached as appendix I to the Wyoming 2022 SIP submission), the State conducted a four-factor analysis for further emissions controls on the two coal-fired boilers. It evaluated SNCR and SCR for further NO_X control (table 24), trona injection prior to ESP for further SO₂ control (table 25), and wet ESP and FF for further PM control (table 26).

Table 24—Summary of Granger NO _X Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
UIN-14 (coal-fired boiler)	SNCR/SCR	271/610	$1,450,702/$3,175,904	$5,347/$5,202
UIN-15 (coal-fired boiler)	SNCR/SCR	233/524	1,422,667/3,175,825	6,111/6,063

Table 25—Summary of Granger SO ₂ Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
UIN-14 (coal-fired boiler)	Trona injection prior to ESP	104.5	$2,745,234	$26,283
UIN-15 (coal-fired boiler)	Trona injection prior to ESP	70.4	2,745,202	38,994

Table 26—Summary of Granger PM Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
UIN-14 (coal-fired boiler)	Wet ESP/FF	8.9/8.9	$1,765,111/$1,945,510	$198,774/$219,089
UIN-15 (coal-fired boiler)	Wet ESP/FF	120/120	1,732,090/1,933,758	14,434/16,115

The State estimated the time necessary to achieve compliance to be at least four years. The State also identified several energy and non-air environmental impacts associated with the installation and operation of the controls it evaluated. For SNCR, it noted the storage of additional reagent chemicals onsite, ammonia slip, generation and disposal of wastewater, and generation of further emissions due to additional fuel combustion to overcome the energy penalty associated with SNCR. As to SCR, the State identified the transport, handling, and use of aqueous ammonia; replacement and disposal of spent catalyst; and adverse air impacts due to ammonia slip, possible formation of a visible plume, oxidation of carbon monoxide to carbon dioxide, and oxidation of SO₂ to sulfur trioxide with subsequent formation of sulfuric acid mist due to ambient or stack moisture. The State remarked that additional electricity would be needed for operation of a wet ESP, which would also require generation and disposal of solid waste and wastewater. Replacement of the ESP with a FF would require additional electricity and disposal of the filter bags as waste upon replacement, while trona injection prior to electrostatic precipitation would generate solid waste and require additional electricity. For remaining useful life, the State estimated that the emission units are expected to last 20 years or more.

Finally, Wyoming noted that Granger has shut down several sources since 2014 and has made voluntary emissions reductions as part of the Granger Optimization Project. That project triggered prevention of significant deterioration (PSD) review for NO_X, SO₂, and PM₁₀ emissions and included an evaluation of the facility's emissions impacts at nearby Class I areas, which the State found to be acceptable.

The State also provided the permitted NO_X, SO₂ , and PM emission limits ^[94] and emissions trends for the boilers over five years (2016-2020). The figures show that boiler UIN-14 NO_X emissions dropped (from approximately 630 tons/year to approximately 120 tons/year), as did SO₂ emissions (from approximately 180 tons/year to approximately 20 tons/year) and PM emissions (from approximately 95 tons/year to approximately 10 tons/year). Emissions also declined for boiler UIN-15 for NO_X (from approximately 675 tons/year to approximately 150 tons/year), SO₂ (from approximately 150 tons/year to approximately 10 tons/year), and PM (from approximately 40 tons/year to approximately 10 tons/year). Wyoming concluded that NO_X, SO₂, and PM emissions at both boilers decreased or remained consistent between 2016 and 2020, remained under their permitted emission limits, and are not expected to change for the next permit renewal.

Ultimately, Wyoming determined, based on the four factors, emissions trends, and permit conditions, that no additional controls are necessary at Granger to make reasonable progress in the second planning period for regional haze. The State concluded that further controls will be evaluated in the third planning period.

k. Burlington Resources—Lost Cabin Gas Plant ^[95]

Burlington Resources' Lost Cabin Gas Plant is a natural gas sweeting plant located in Fremont County, Wyoming. The plant has two natural gas processing trains, Trains 2 and 3; each processing train consists of a solvent absorption section to separate carbon dioxide (CO₂), hydrogen sulfide (H₂ S), and carbonyl sulfide (COS) from the natural gas.^[96] Emissions from the Lost Cabin Gas Plant may affect the visibility in three Class I areas in Wyoming (table 32).

Relying on information submitted by the facility (attached as appendix J to the Wyoming 2022 SIP submission), the State evaluated wet scrubbers for SO₂ emissions control on Trains 2 and 3 (table 27).^[97] It noted that the Lost Cabin Gas Plant is currently controlling SO₂ emissions by continued emphasis on minimization of flaring events through the combination of operational controls, equipment upgrades, and facility design changes.^[98] Wyoming did not conduct a four-factor analysis for NO_X and PM emissions control measures, reasoning that NO_X and PM account for a small fraction of total emissions from the facility.^[99]

Table 27—Summary of Lost Cabin Gas Plant SO ₂ Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year) 1	Average cost effectiveness ($/ton) 2
Train 2	Wet Scrubber	174.9	$1,442,233	$7,710
Train 3	Wet Scrubber	304.2	2,438,411	7,470
1  Cost figures reflect those on page 179 and appendix J of the Wyoming 2022 SIP submission. The cost figures found in table 11-34 on page 180 of the Wyoming 2022 SIP submission ($1,348,694 for Train 2 and $2,272,044 for Train 3) conflict with these. These conflicting numbers are addressed in section IV.C.2.b.ii. of this document.
2  Cost figures reflect those on page 180 of the Wyoming 2022 SIP submission, which conflict with the cost figures found in appendix J ($8,250 for Train 2 and $8,010 for Train 3). These conflicting numbers are addressed in section IV.C.2.b.ii. of this document.

The State estimated the time necessary to achieve compliance using wet scrubbers to be 30 months, but potentially up to 42 months.

The State identified the following energy and non-air environmental impacts associated with the installation and operation of wet scrubbers on Trains 2 and 3: an energy penalty from operation of the scrubber systems; significant water usage; disposal of salt-laden spent scrubber liquor; and the possibility of highly visible secondary particulate formation.

The State estimated the remaining useful life of the wet scrubbers to be 15 years. Additionally, Wyoming noted that actual SO₂ emissions (269 tons/year from Train 2 and 338.05 tons/year from Train 3 in 2020) have consistently remained under allowable emission limits (503.7 tons/year for Train 2 and 1,366.6 tons/year for Train 3). The State also provided SO₂ emissions trends for Trains 2 and 3 over five years (2016-2020). The figures show that SO₂ emissions from Train 2 consistently increased (from approximately 125 tons/year to approximately 275 tons/year), while SO₂ emissions from Train 3 trended upward between 2016 and the end of 2018 (from approximately 280 tons/year to approximately 340 tons/year) before dropping to 0 tons/year in 2019 and 2020.^[100] The State also noted an overall reduction in actual SO₂ emissions from 2014 to 2018 of 1,553.6 tons/year (which represents total SO₂ actual emissions, including those from flaring), as well as a permitted allowable SO₂ emission reduction of 389.6 tons/year.

Wyoming concluded that installing wet scrubbers for SO₂ emissions control on Trains 2 and 3, at a cost of over $7,000/ton removed, is cost prohibitive. In addition, the State noted that it expects total SO₂ emissions to decrease year-over-year as production continues to decline at an approximate rate of 4 to 5 percent, with overall SO₂ emissions declining at 3 to 5 percent per year during normal operation.

Ultimately, Wyoming determined, after consideration of the four factors and emissions trends, not to propose any changes to current SO₂ emissions controls at the Lost Cabin Gas Plant. The State concluded that further controls will be evaluated in the third planning period.

l. Dyno Nobel Inc.—Cheyenne Fertilizer Facility ^[101]

Dyno Nobel Inc.'s Cheyenne Fertilizer Facility is a chemical manufacturing plant located in Cheyenne, Wyoming that produces ammonia, nitric acid, urea/diesel exhaust fluid, carbon dioxide, low density ammonium nitrate, and other related products. Relying on information submitted by the facility (attached as appendix K to the Wyoming 2022 SIP submission), the State conducted a four-factor analysis for several emission units: two natural gas-fired Cooper reciprocating compressor engines (ENG004 and ENG005), a natural gas-fired primary reformer (CKD001), and three cooling towers (CTW001, CTW002, CTW003). Together, these units account for 88.6% of the total NO_X, SO₂, and PM₁₀ emissions from the facility. Emissions from the Cheyenne Fertilizer Facility may affect the visibility in two Class I areas in Colorado (table 32).

Table 28 describes the installed NO_X, SO₂, and PM emissions controls at the Cheyenne Fertilizer Facility.

Table 28—Installed NO _X , SO ₂ , and PM Emissions Controls at the Cheyenne Fertilizer Facility

Unit	SO 2 controls 1	NO X controls	PM controls
ENG004 (engine)		Lean burn combustion
ENG005 (engine)		Lean burn combustion
CKD001 (reformer)		LNB
CTW001 (cooling tower)			Legacy mist eliminator.
CTW002 (cooling tower)			Mist eliminator.2
CTW003 (cooling tower)			Legacy mist eliminator.
1  All emission units are natural gas-fired.
2 Designed for 0.001% drift.

For further NO_X emissions control, the State evaluated LEC and SCR on the two engines and SCR on the reformer (table 29). The State evaluated upgraded mist eliminators for further PM emissions control on two of the cooling towers (CTW001 and CTW003) (table 30). No additional SO₂ controls were evaluated for any of the natural gas-fired units.

Table 29—Summary of the Cheyenne Fertilizer Facility NO _X Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
ENG004, ENG005 (engines)	LEC SCR	229/engine 78 1	$244,100/engine 418,700	$1,067/engine 5,354.
CKD001 (reformer)	SCR	34	716,300	21,030.
1  Emission reductions beyond LEC.

Table 30—Summary of Cheyenne Fertilizer Facility PM Cost Analysis

Unit	Control technology	Emission reduction (tons/year)	Total annual cost ($/year)	Average cost effectiveness ($/ton)
CTW001 (cooling tower)	Upgraded mist eliminators	15.5	$16,300	$1,056
CTW003 (cooling tower)	Upgraded mist eliminators	2.4	5,740	2,368

The State estimated the time necessary to achieve compliance using LEC retrofits on the engines to be one year. However, the State asserted that the retrofits need to be completed during the next scheduled turnarounds, which are four years apart for each engine and are scheduled for 2026 and 2030. The State estimated the time necessary to achieve compliance using SCR to be one to two years but noted it would require a total shutdown that could not occur until 2030 or later. The State estimated the time necessary to achieve compliance using the mist eliminator upgrades on the cooling towers to be one to five years for CTW001 and six or more years for CTW003 because the upgrades must occur during a scheduled turnaround/shutdown.

The State identified several energy and non-air environmental impacts associated with the installation and operation of potential controls. For SCR on the engines and reformer, the State noted the need to retrofit both the engines and reformer into the existing structures using extensive ductwork, which may lead to a pressure drop corresponding to a slight decrease in efficiency. Wyoming asserted this could result in greater fuel and energy consumption as well as upsets due to backpressure effects, which could lead to forced shutdowns, safety incidents/injuries, excess emissions, and wasted product. The LEC retrofit on the engines would require a modest increase to heat load, while the mist eliminator upgrades for the cooling towers were not expected to result in any significant energy and non-air quality environmental impacts. In its evaluation of remaining useful life, the State estimated 25 years for SCR and LEC and 30 years for the mist eliminator upgrades.

Wyoming also provided the Cheyenne Fertilizer Facility permitted NO_X emission limits ^[102] for the engines and reformer, in addition to NO_X emissions trends for these units over five years (2016-2020). NO_X emissions for the engines initially declined (from approximately 1,500 tons/year in 2016 to approximately 500 tons/year in 2019) before increasing in 2020 (to approximately 1,500 tons/year). According to the State, a stack test performed in April 2021 indicated that NO_X emissions from the engines were 700 tons/year, representing a decrease of over 50% in emissions from the 2016-2020 time frame.^[103] In addition, the average NO_X emission rate for both engines was 46.9 lb/hour in 2021, below their allowable emission rate of 170.61 lb/hour, which has remained the same since 2012 and the State asserts is unlikely to change when a new permit is issued. The NO_X emissions trends for the reformer over five years (2016-2020) indicate a decline from approximately 120 tons/year in 2016 to approximately 35 tons/year in 2020. In addition, the average NO_X emission rates for the reformer between 2016-2020 varied between 4-10 lb/hour, below the permitted limit of 28.2 lb/hour, which has also remained the same since 2012 and the State believes is unlikely to change when a new permit is issued. The State also provided PM emissions trends for all three cooling towers (CTW001, CTW002, and CTW003) over five years (2016-2020), which show a decline in PM emissions (from approximately 400 tons/year to approximately 25 tons/year across all three cooling towers combined).

Wyoming concluded that, given emissions trends and allowable vs. actual emission rates, there is no evidence that NO_X emissions from the engines and reformer will increase or that changes to the allowable emissions will be necessary, as NO_X emissions are expected to remain consistent or decrease between 2020 and 2028. The State also determined that the total capital investment required to install mist eliminators on CTW001 and CTW003 is not justified given what it considered to be a “minute” amount of potential PM emissions reductions.

Overall, after considering the four factors and emissions trends, Wyoming determined that no additional emission controls are necessary at the Cheyenne Fertilizer Facility to make reasonable progress in the second planning period for regional haze. At the same time, the State also concluded that this facility may warrant further analysis of emission controls to reach reasonable progress, which it stated would be detailed in the progress report due January 31, 2025.

m. Summary of Wyoming's Reasons for Concluding That No Additional Emission Reduction Measures Are Necessary To Make Reasonable Progress

After evaluating the twelve sources it had selected for consideration of additional controls, Wyoming concluded that no new controls on those sources are warranted during the regional haze second planning period.^[104] Chapter 13 of Wyoming's 2022 SIP submission summarizes the State's reasons for not requiring any additional emission reduction measures to make reasonable progress toward the national visibility goal.

First, the State explained how it considered costs of compliance. Wyoming did not rely on a cost-effectiveness threshold to determine whether additional emission reduction measures are reasonable. It asserted that the cost of additional controls could harm the State's economy and the livelihoods of Wyoming's rural communities, particularly because coal-fired units and oil and gas development tend to operate in rural areas that depend on those activities for economic support. The State remarked that any additional costs could cause economic stress to energy producers that are operating in an uncertain financial climate, potentially forcing those sources out of the market prematurely. It also pointed to potential detrimental effects on grid stability and on Wyoming and out-of-state ratepayers.

Second, Wyoming highlighted historical and anticipated reductions in emissions from first implementation period measures, increasing renewable energy generation, facility shutdowns and conversions, and measures taken in other states and nationwide. It described emission reductions at Wyoming facilities since 2014, noting that NO_X emissions declined by almost 17,400 tons, SO₂ emissions declined by approximately 18,000 tons, and PM₁₀ emissions declined by almost 850 tons. Wyoming expects further reductions to occur between 2020 and 2028, which it asserted will benefit all Class I areas. It pointed to expected facility retirements at Dave Johnston Units 1 and 2, which Wyoming stated has an enforceable consent decree requirement to cease coal operations by 2028; Dave Johnston Unit 3, which has an enforceable state and federal commitment to close by the end of 2027; and Naughton Units 1 and 2, which Wyoming stated are planned to retire by the end of 2025. Wyoming also cited future facility conversions at Jim Bridger Units 1 and 2, which have an enforceable conversion to natural gas by January 2024,^[105] and Naughton Unit 3, which converted from coal to natural gas in 2019.

Third, the State considered the level of potential visibility improvements at issue. Wyoming stated that all seven Class I areas within the State are below the adjusted URP glidepath to attain natural conditions by 2064. It noted that potential additional controls, which would reduce NO_X by 12,300 tons and SO₂ by 10,000 tons, would not impact the projected 2028 and 2064 visibility conditions in Wyoming Class I areas. According to the State, WRAP modeling indicates that potential additional controls would have “little to no influence” (less than 0.1 deciview) ^[106] on visibility improvement in Wyoming's Class I areas. Wyoming also pointed to the impact on visibility of sources beyond its control, noting that international anthropogenic sources and natural sources such as wildfires are large contributors to visibility impairment in the State's Class I areas.

The State ultimately concluded that imposing any additional costs on Wyoming sources is unwarranted during the second implementation period. Wyoming stated that it will continue to monitor Class I area visibility, regional haze, sources of emissions, and electrical and oil and gas markets, and will reevaluate its position in the next regional haze progress report due in January 2025.

2. The EPA's Evaluation

The EPA finds that Wyoming's selection of twelve sources to evaluate through four-factor analyses, as described in section IV.C.1. of this document, was reasonable. However, as detailed in sections IV.C.2.a.-d. below, we find that Wyoming's long-term strategy does not satisfy the requirements of CAA section 169A and 40 CFR 51.308(f)(2) on four separate grounds: (1) Wyoming failed to consider the required four statutory factors to analyze control measures for some selected sources to determine what is necessary to make reasonable progress, despite determining that those sources may affect visibility at certain Class I areas; (2) Wyoming did not document the technical basis of some of its decisions and made numerous calculation and other methodological errors; (3) Wyoming unreasonably rejected emission reduction measures for some sources; and (4) Wyoming's other reasons for not requiring any emission reduction measures in its long-term strategy ( e.g., its reliance on alleged economic hardships, historical and future emissions reductions, and lack of visibility improvement) are not adequately supported or lack foundation in the CAA and RHR. Therefore, we are proposing to disapprove Wyoming's long-term strategy for the second implementation period under CAA section 169A and 40 CFR 51.308(f)(2). The following sections IV.C.2.a.-d. detail these separate bases for our proposed disapproval, with a focus on specific sources, units, and pollutants for illustrative purposes.

a. Failure To Perform a Four-Factor Analysis To Analyze Control Measures for Selected Sources To Determine What Is Necessary To Make Reasonable Progress

Under CAA section 169A and 40 CFR 51.308(f)(2), a state must submit a long-term strategy to make reasonable progress for Class I areas within the state and Class I areas outside the state that may be affected by the state's emissions. CAA section 169A(g)(1) and 40 CFR 51.308(f)(2)(i) provide that in determining the emission reduction measures necessary to make reasonable progress, the state must consider the following four factors:

• Costs of compliance;
• Time necessary for compliance;
• Energy and non-air quality environmental impacts of compliance; and
• Remaining useful life of any potentially affected sources.

In its 2022 SIP submission, Wyoming determined that twelve stationary sources should be evaluated for additional controls due to their potential effect on visibility at Class I areas within the State and outside the State. For some of these sources, we acknowledge that there are several instances where the State appropriately relied on the effectiveness of existing controls or an existing federally enforceable commitment to cease operations as a reason to forgo a four-factor analysis. However, for other sources, neither the State nor the facility determined the emission reduction measures that are necessary for reasonable progress by considering the four statutory factors—nor did they provide technical documentation or other justification to support that lack of analysis—despite the State's determination that those sources may affect visibility at Class I areas. Therefore, we find that Wyoming failed to meet the requirements under CAA section 169A and 40 CFR 51.308(f)(2)(i) to consider the four statutory factors for the sources and associated units and pollutants listed in table 31 that may affect visibility at Class I areas.

Table 31—Sources, Units, and Associated Pollutants That May Affect Visibility at Class I Areas and Selected for Four-Factor Analysis Where No Four-Factor Analysis Was Performed

Source	Unit(s)	Associated pollutant(s)
Jim Bridger (PacifiCorp)	1, 2	NO X , SO 2 , PM
Jim Bridger (PacifiCorp)	3, 4	SO 2 , PM
Naughton (PacifiCorp)	1, 2	NO X , SO 2 , PM
Naughton (PacifiCorp)	3	NO X , PM
Dave Johnston (PacifiCorp)	1, 2	NO X , SO 2 , PM
Dave Johnston (PacifiCorp)	4	PM
Wyodak (PacifiCorp)	1	NO X , SO 2 , PM
Laramie River Station (Basin Electric)	1-3	PM
Laramie Portland Cement (Mountain Cement Company)	Kilns 1, 2	SO 2
Elk Basin Gas Plant (Contango Resources, Inc.)	Engines (9) and incinerator	PM
Elk Basin Gas Plant (Contango Resources, Inc.)	Engines (9)	SO 2
Elk Basin Gas Plant (Contango Resources, Inc.)	Incinerator	NO X
Lost Cabin Gas Plant	Trains 2, 3	NO X , PM

States are required to evaluate sources, or groups of sources, that may be affecting visibility at Class I areas within the state and outside the state. Although states have discretion under the RHR in identifying sources or groups of sources, the implementation plan must include a description of the criteria the state used to determine which sources or groups of sources it evaluated and how the four factors were taken into consideration in selecting the measures for inclusion in its long-term strategy.^[107] Many of the sources for which Wyoming failed to conduct a four-factor analysis are among the largest contributors to visibility impairment in Class I areas, according to the State's own Q/d analysis (table 32).

Table 32—Wyoming Sources That the State Determined May Affect Class I Areas and Respective Q/d Values for Total NO X , SO 2 , and PM 10 Emissions at Affected Class I Areas

Table 32 shows the Q/d value associated with each of the sources that Wyoming determined may affect visibility at Class I areas and that it selected for four-factor analysis. Q represents the total sum of NO_X, SO₂, and PM emissions, and d represents the distance (in kilometers) to the nearest Class I area. The larger the Q/d value, the greater the source's expected effect on visibility in each associated Class I area. The State's own analysis shows that Jim Bridger, Naughton, and Dave Johnston are expected to have the greatest effect on visibility at the seven Wyoming Class I areas, more than the other sources the State selected. Nevertheless, the State did not conduct a four-factor analysis on any of those sources, except for a single unit (Unit 4) at Dave Johnston. Further, as detailed in sections IV.C.2.a.i.-iii. below, none of the reasons the State provided justify not conducting four-factor analyses of sources it determined may affect visibility at Class I areas to determine what is necessary for reasonable progress, as required under CAA section 169A(g)(1) and 40 CFR 51.308(f)(2)(i).

i. Reliance on Existing Controls Without Adequate Technical Documentation To Avoid Four-Factor Analysis of Sources That May Affect Visibility at Class I Areas

In declining to perform a four-factor analysis for Jim Bridger Units 1-4 and Naughton Units 1-3, the State maintained that these sources have effective NO_X and SO₂ emissions control technologies in place. PacifiCorp argued in its submittal to the State (appendix C to the SIP submission) that these sources are exempt from further analysis under the EPA's 2019 Guidance because they have effective NO_X and SO₂ emissions control technologies in place. PacifiCorp and the State specifically referred to the presence of: (1) FGD scrubber systems that meet the applicable alternative SO₂ MATS emissions limit; (2) NO_X and SO₂ emissions controls installed during the first planning period and operated year-round with an effectiveness of at least 90 percent on a pollutant-specific basis ( e.g., FGD or SCR); (3) LNB/SOFA NO_X emission controls; and (4) BART-eligible units that installed and began operating controls to meet BART emission limits in the first planning period.

Without additional explanation from the State, the EPA disagrees that these sources' existing NO_X and SO₂ emissions controls exempt these sources from the requirement to consider the four statutory factors to determine whether additional controls are necessary for reasonable progress. The EPA's 2019 Guidance illustrates scenarios in which it may be reasonable for a state not to select a particular source for further analysis due to the source's existing emissions controls, including:

• For the purposes of SO₂ emissions control measures, FGD controls that meet the applicable alternative SO₂ emission limit of the 2012 MATS rule for coal-fired power plants (0.2 lb/MMBtu);
• For the purposes of SO₂ and PM emissions control measures, combustion of only pipeline natural gas;
• For the purposes of SO₂ and NO_X emissions control measures, FGD that operates year-round with an effectiveness of at least 90 percent or SCR that operates year-round with an overall effectiveness of at least 90 percent, on a pollutant-specific basis; and
• BART-eligible units that installed and began operating controls to meet BART emission limits for the first implementation period, on a pollutant-specific basis.^[108]

The premise underlying the flexibility for “effectively controlled” sources is that performing a four-factor analysis would be futile due to the unavailability of further cost-effective emission controls.^[109] Indeed, some units at Jim Bridger and Naughton may already have effective controls installed on a pollutant-specific basis ( e.g., Jim Bridger Units 3-4 with SCR for NO_X emissions control and Naughton Unit 3 with combustion of pipeline natural gas for SO₂ emissions control), and we agree that it would be reasonable not to perform four-factor analyses for those particular units on a pollutant-specific basis. However, it is not readily apparent, due to the State's failure to provide a sufficient technical demonstration, that additional emission controls for NO_X or SO₂ at Jim Bridger and Naughton would not be cost-effective or reasonable. For example, the State could have evaluated post-combustion NO_X controls ( e.g., SNCR and SCR) for Jim Bridger Units 1-2 and Naughton Units 1-3, which are currently equipped only with combustion controls. It may also be possible to achieve a lower SO₂ emissions rate at Jim Bridger Units 1-4 ^[110] and Naughton Units 1-2 by optimizing existing SO₂ emissions controls ( e.g., requiring existing scrubbers to run continuously at their maximum efficiencies), in addition to evaluating whether scrubber upgrades or tightening emission limits might be reasonable. Additionally, regardless of the State's determination that existing SO₂ emissions controls are effective, those existing controls may be necessary to make reasonable progress and therefore must be included in the SIP.^[111] Wyoming's 2022 SIP submission does not address whether any of the existing SO₂ emissions controls at Jim Bridger and Naughton are necessary to make reasonable progress, and thus whether they are a part of Wyoming's long-term strategy for the second planning period. Moreover, the State did not address PM emissions controls in any context for any of these sources. Thus, the State failed to evaluate and determine the emission reduction measures that are necessary to make reasonable progress through consideration of the four statutory factors, as required by 40 CFR 51.308(f)(2), for Jim Bridger Units 1 and 2 for NO_X, SO₂, and PM; Jim Bridger Units 3 and 4 for SO₂ and PM; Naughton Units 1 and 2 for NO_X, SO₂, and PM; and Naughton Unit 3 for NO_X and PM.

Finally, for Laramie Portland Cement, the State notes that SO₂ emissions, which are currently controlled only through the inherent dry scrubbing processes of the rotary kiln itself, are consistently less than permitted allowable emissions (table 33) and have decreased by over 100 tons/year from 2014 to 2018. Wyoming appears to consider inherent dry scrubbing as an existing effective control that justifies the lack of a four-factor analysis for SO₂ controls at this source. However, because the State provides no details about the operation or emissions performance of the inherent dry scrubbing process, we cannot determine whether it is reasonable to assume that a four-factor analysis would not identify any reasonable additional controls. The State does not address, and it is not clear based on the emissions information alone, whether further SO₂ reductions would be reasonable at Laramie Portland Cement, particularly emission limit tightening. The State is also silent as to whether the facility's existing control measures are necessary for reasonable progress and are a part of the state's long-term strategy for the second planning period.

Table 33—Laramie Portland

Cement Actual and Permitted SO₂ Limits

Unit	Permitted SO 2 emissions	Actual SO 2 emissions (2018)
	tons/year
Kiln 1	438	114.2
Kiln 2	438	13.7

ii. Reliance on Unenforceable Source Retirements To Avoid Four-Factor Analysis

Wyoming also improperly relies on unenforceable source retirements to avoid conducting a four-factor analysis for certain sources. For example, Wyoming's SIP submission refers to planned retirements at Jim Bridger Units 1-2, Naughton Units 1-2, and Dave Johnston Units 1-2, as described in PacifiCorp's 2019 IRP and in PacifiCorp's submittal to Wyoming (appendix C to the Wyoming 2022 SIP submission). However, these shutdowns are not federally enforceable. Under the CAA and the RHR, a state's long-term strategy must include the enforceable emissions limitations, compliance schedules, and other measures that are necessary to make reasonable progress.^[112] Thus, if a state is relying on source shutdowns to forgo conducting a four-factor analysis (because a shutdown is effectively the most stringent control available), the shutdown must be federally enforceable (for example, through inclusion in the SIP).^[113]

As PacifiCorp conceded in its submittal to the State, it has no legal obligation to close these units and is not committing to do so in connection with the second planning period SIP.^[114] Indeed, in the time since the State submitted its 2022 SIP submission, PacifiCorp has changed its planned retirement of Naughton Units 1-2, which is now slated for 2036 despite PacifiCorp's previous statements that the CCR rule necessitated a 2025 closure. Similarly, PacifiCorp has changed its retirement of Dave Johnston Units 1-2 ^[115] (now planned for 2028 instead of 2027) and Jim Bridger Units 1-2 (now planned for 2037 instead of 2023 and 2028, respectively).^[116] For Naughton specifically, we also disagree with the State's reliance on the planned unenforceable retirements of Units 1 and 2 to calculate a revised Q/d value using only Unit 3, and then choosing to exempt the entire source from a four-factor analysis. These shifting plans underscore the importance of shutdowns being federally enforceable to justify excluding a source from conducting a four-factor analysis given that the SIP needs to meet the requirements of the CAA.

Because Wyoming has not demonstrated that these planned retirements are federally enforceable as required under the CAA and RHR, we find that the State unreasonably failed to consider the required four statutory factors to determine the emission reduction measures necessary to make reasonable progress for sources it determined may affect visibility at Class I areas.^[117]

iii. Other Improper Rationales for Not Performing Four-Factor Analyses

The State's decision not to perform four-factor analyses for certain sources it selected is improper for several other reasons. For Jim Bridger, the State determined, without providing additional examination or explanation, that first planning period actions—specifically, the conversion to natural gas and associated NO_X and annual heat input limits ^[118] for Units 1-2 and the monthly and annual NO_X and SO₂ emissions limits for Units 1-4—demonstrate that no further analysis for the second planning period is necessary. As we previously acknowledged, states may appropriately rely in some instances on the effectiveness of existing controls (including first planning period controls) or an existing federally enforceable commitment to cease operations to forgo a four-factor analysis. However, the existence of these first planning period obligations alone (none of which are currently federally enforceable), without adequate technical documentation of their effectiveness, does not automatically eliminate the requirement for a four-factor analysis in the second planning period if emissions from the facility continue to affect visibility at Class I areas.^[119] One of the fundamental requirements of the RHR is the requirement for periodic revisions of implementation plans at prescribed intervals in order to meet the national goal of preventing and remedying visibility impairment at Class I areas.^[120] As explained in section IV.C.2.a.i. of this document, a four-factor analysis might have shown that more stringent NO_X and SO₂ controls are cost-effective and reasonable at Jim Bridger and thus necessary for reasonable progress. Ultimately, regardless of first planning period obligations and requirements, the State must continue to meet its regional haze obligations for the second planning period under the statute and the RHR.

Similarly, for Wyodak, the State's decision not to conduct a four-factor analysis due to ongoing first planning period litigation is not justified. In its submittal to the State, PacifiCorp asserted, without explanation, that first planning period settlement negotiations may impact whether and how a four-factor analysis for the second planning period would be conducted for Wyodak.^[121] Nothing in CAA section 169A or the RHR supports excluding a source from analysis based on litigation and settlement negotiations, and the State provided no explanation for its decision to do so. Conducting a second planning period four-factor analysis for a source is not contingent on completion of first planning period obligations. Just as the presence of BART controls does not exempt sources from pursuing additional emission reduction measures that are shown to be necessary, through four-factor analysis, to make reasonable progress during the second planning period,^[122] the absence of BART (or other first implementation period controls) does not exempt sources from conducting a four-factor analysis to determine what emission reduction measures are necessary to make reasonable progress for subsequent planning periods. While the anticipated approach may have been for states to submit second planning period SIP revisions that take into account finalized first planning period measures, the obligation to submit a second planning period SIP revision was not suspended for states with outstanding first planning period obligations. As required, Wyoming submitted its second planning period SIP submission, which must include a long-term strategy for making reasonable progress, pursuant to the second planning period deadline. Consequently, the EPA has a statutory obligation to review and act on a SIP submission within one year after it has been deemed complete.^[123]

For the Lost Cabin Gas Plant, Wyoming did not conduct a four-factor analysis evaluating NO_X or PM emission reduction measures. As justification, the State explains that permitted NO_X and PM emissions account for only a “small fraction” of the total emissions from the facility.^[124] However, the State did not show that these NO_X and PM emissions do not affect visibility in Class I areas. Nor did it supply information that NO_X or PM emissions are effectively controlled or point to applicable regulations that may subject the facility to control measures that would limit future emissions increases. Given the lack of information regarding existing NO_X and PM controls or applicable regulations limiting these emissions, we cannot conclude that Wyoming's decision not to conduct a four-factor analysis was reasonable or justified.

Finally, the State failed to conduct a four-factor analysis evaluating PM emission reduction measures for several sources, including Laramie River Station, Dave Johnston Unit 4, and the Elk Basin Gas Plant, despite doing so for NO_X and/or SO₂ control measures. For the Elk Basin Gas Plant, the State did not perform a four-factor analysis for NO_X control measures for the incinerator and SO₂ control measures for the nine compressor engines. It is unclear whether these omissions are intentional ( e.g., based on effectively controlled emissions or some other justification) or an oversight, as Wyoming did not address the absence of these four-factor analyses in its SIP submission.

In summary, we propose to disapprove Wyoming's long-term strategy under CAA section 169A and 40 CFR 51.308(f)(2) because the State failed to consider the required four statutory factors to determine the measures necessary to make reasonable progress for certain sources it determined may affect visibility at Class I areas.

b. Failure To Document the Technical Basis of the State's Determination of the Emission Reduction Measures Necessary To Make Reasonable Progress

In formulating their long-term strategies, states must comply with the requirements under CAA section 110(a), CAA section 169A, and 40 CFR 51.308(f)(2)(iii) to document the technical basis, including modeling, monitoring, cost, engineering, and emissions information, on which they are relying to determine the emission reduction measures necessary to make reasonable progress. The EPA must exercise its independent technical judgment in evaluating the adequacy of the State's long-term strategy, including the sufficiency of the underlying methodology and documentation; we may not approve a SIP that is based on unreasoned analysis or that lacks foundation in the CAA's requirements.^[125]

As detailed in this section IV.C.2.b., we are proposing to disapprove Wyoming's long-term strategy due to the State's reliance on unsupported technical rationales and its failure to adequately document the technical basis on which it is relying to determine the emission reduction measures necessary to make reasonable progress (table 34).

Table 34—Sources, Units, and Associated Pollutants Where the State Failed To Document the Technical Basis of Its Determination of Emission Reduction Measures Necessary To Make Reasonable Progress

Source	Unit(s)	Associated pollutant(s)
Dave Johnston (PacifiCorp)	4	SO 2.
Laramie Portland Cement (Mountain Cement Company)	Kilns 1, 2	NO X.
Green River Works (TATA Chemicals)	Calciner 1, Calciner 2	NO X , PM.
Elk Basin Gas Plant (Contango Resources, Inc.)	Engines (9)	NO X.
Elk Basin Gas Plant (Contango Resources, Inc.)	Incinerator	SO 2.
Lost Cabin Gas Plant	Trains 2, 3	SO 2.

i. Laramie Portland Cement

We identified several consequential errors and unsupported technical rationales in the State's evaluation of NO_X emission reduction measures for Laramie Portland Cement, where NO_X is currently controlled using good combustion practices (Kilns 1 and 2) and a 2-stage preheater (Kiln 2). Considered in the aggregate, the problems detailed in this section IV.C.2.b.i. prevent us from concluding that the State's determination of the emission reduction measures for Laramie Portland Cement that are necessary to make reasonable progress is based on sound and adequately documented technical grounds.

First, there are consequential errors with the State's calculation of the level of NO_X emissions reductions achievable through installing SNCR on Kiln 2. The State calculated the combined NO_X emissions reductions that could be achieved on both Kiln 1 and Kiln 2 considering 10%, 15%, 20%, and 25% SNCR control efficiencies.^[126] In addition, the State (through information submitted by the facility in appendix L) provided baseline and controlled emissions rates, including NO_X emissions reductions estimates at 10% and 25% control efficiency, for Kiln 1 and Kiln 2 separately (table 35).^[127]

Table 35—Wyoming's Analysis of Laramie Portland Cement Baseline and Estimated NO _X Emission Reductions for Kiln 1 and Kiln 2 Associated With SNCR NO _X Controls at 10% and 25% Control Efficiency

Kiln	Baseline NO X emissions	NO X emissions reduction (control efficiency)
	tons/year
Kiln 1	722.8	72.3 (10%) 181 (25%)
Kiln 2	1,511.6	861 (10%) 970 (25%)

Using the baseline NO_X emission rate provided, we performed an accuracy check on the calculations of the NO_X emission reductions for Kiln 2 ^[128] associated with 10% and 25% control efficiency. We multiplied the baseline NO_X emissions (tons/year) with each control efficiency (%) to achieve the NO_X emissions reduction (tons/year) associated with each control efficiency (table 36).^[129]

Table 36—The EPA's Analysis of Laramie Portland Cement Estimated NO _X Emission Reductions for Kiln 2 Associated With SNCR NO _X Controls at 10% and 25% Control Efficiency

Kiln	Baseline NO X emissions	NO X emissions reduction (level of control)
	tons/year
Kiln 2	1,511.6	151 (10%) 378 (25%)

We find that Wyoming overestimated the amount of NO_X emissions reductions by 710 tons/year at 10% control efficiency and 592 tons/year at 25% control efficiency. This overestimation appears to be the result of a math error. Because the State's calculated NO_X emissions reductions associated with SNCR for Kiln 2 are incorrect, the emissions reductions for Kilns 1 and 2 combined, as well as the associated average cost effectiveness ($/ton) shown in table 16 for all levels of control efficiencies, are also incorrect. Given that the error impacts the control efficiencies of various control technologies, the calculated emissions reductions and cost effectiveness values cannot be relied upon to determine what NO_X emissions control measures for Laramie Portland Cement are necessary to make reasonable progress.

Second, the State did not document the technical basis of the SNCR control efficiencies that were used to calculate costs of compliance for the four-factor analysis. The State evaluated the cost effectiveness of SNCR NO_X emission controls on Kiln 1 and Kiln 2 using control efficiencies ranging from a minimum of 10% to a maximum of 25% without any supporting documentation.^[130] The EPA recognizes that it is challenging to predict the control efficiency of SNCR for long cement kilns.^[131] We agree that absent the use of post-installation control demonstrations to set NO_X emission limits, it is appropriate to include a range of control efficiencies in the four-factor analysis. However, Wyoming did not justify its use of SNCR control efficiencies as low as 10-25% for Kiln 1 and Kiln 2. In 2017, we revised the Montana regional haze FIP NO_X emission limit on a long kiln in Montana. As part of that action, we assessed information on SNCR control efficiencies that had been demonstrated on long kilns since our promulgation of the original FIP and SNCR-based NO_X emission limit in 2012.^[132 133] We found that the control efficiency of SNCR installed on kilns as a result of consent decrees ^[134] is highly variable and ranges from 29% to 47%, with a mean of 40%.^[135] Wyoming did not consider this or any other data showing higher SNCR efficiencies in the four-factor analysis for Laramie Portland Cement. While the facility asserted generally that other cement kilns “have challenges” and “are battling issues” with SNCR, it provided no documentation of the control efficiencies those other cement kilns have achieved.^[136] Therefore, we find that Wyoming did not adequately document the technical basis of the control efficiencies it relied on, and, as a result, likely underestimated the cost effectiveness of SNCR.

Third, the State included the potential loss of cement kiln dust sales in its cost analysis without providing technical documentation to substantiate the expected loss. The State projected a loss of over $13,000,000 in kiln dust sales across all control efficiencies due to purported contamination associated with the operation of SNCR.^[137] This figure represents a very significant portion—over 76%—of the total annualized costs associated with SNCR on Kilns 1 and 2. However, Wyoming did not submit any documentation on the likelihood of contamination or the specific amount of projected lost sales, which greatly influenced the cost-effectiveness of controls. Given the lack of justification and supporting evidence, incorporating potential lost cement kiln dust sales into the cost analysis was unreasonable.

Fourth, the State did not provide technical documentation to support its reliance on a 10-year amortization period and 10% interest rate in its cost analysis for SNCR on Kilns 1 and 2. The amortization period (also termed the remaining useful life) and interest rate are used to calculate annualized capital costs. Annualized capital costs ultimately determine, along with the tons of emissions reduced and additional annualized costs, the cost per ton of emissions reduced of the evaluated control technology. Wyoming used a 10-year equipment life for SNCR ^[138] —half the 20-year amortization period specified in EPA's Control Cost Manual ^[139] —without providing documentation justifying that deviation or otherwise explaining why a 10-year equipment life is reasonable. And while the Control Cost Manual recommends using a firm-specific nominal interest rate if one is available,^[140] the State provided no documentation to support its use of a 10% interest rate, which was more than double the bank prime rate as of January 2020 ^[141] (when the analysis was conducted) and well outside the range of similar firms' interest rates.^[142]

EPA's Control Cost Manual provides detailed technical guidance on the estimation of capital and annual costs for air pollution control devices for stationary sources. The Control Cost Manual is commonly used by the EPA, State and local officials, and industry parties that must comply with EPA regulations or EPA permits. EPA has been updating the Control Cost Manual under the authority of the Consolidated Appropriations Act of 2014.^[143] Chapter revisions undergo public notice and comment.^[144] In the EPA's 2019 Guidance, we noted that if a state deviates from the principles and factors recommended in the Control Cost Manual, it should explain and document how its alternative approach is appropriate.^[145] Because Wyoming provided no justification or documentation to support the unusually short amortization period and atypically high firm-specific interest rate it used to evaluate SNCR for Laramie Portland Cement, as required by 40 CFR 51.308(f)(2)(iii), we find that the State's cost analysis methodology lacks adequate technical support.

In summary, the multitude of methodological errors and unsupported technical bases, considered collectively, makes it impossible for us to determine the adequacy of the State's determination of the emission reduction measures for Laramie Portland Cement that are necessary to make reasonable progress.

ii. Lost Cabin Gas Plant

We identified several defects in the State's cost analysis for SO₂ controls at the Lost Cabin Gas Plant, including conflicting cost figures and SO₂ emissions data, use of an unsubstantiated amortization period and firm-specific interest rate, and an unjustifiably low estimate of wet scrubber control efficiency. Considered in the aggregate, the problems detailed in this section IV.C.2.b.ii. prevent us from concluding that the State's determination of the emission reduction measures for Lost Cabin Gas Plant that are necessary to make reasonable progress is based on sound and adequately documented technical grounds.

First, we find numerous discrepancies between the cost figures, specifically `Total Annual Cost ($/year)' and `Cost per Ton of SO₂ Removed ($/ton)' on pages 179 and 180 and appendix J of the Wyoming 2022 SIP submission.^[146] Ultimately, these discrepancies lead to the inaccurate calculation of cost/ton of SO₂ emissions removed ($/ton) in table 11-34 for both Trains 2 and 3.

Second, other aspects of Wyoming's cost analysis lack adequate documentation. The State provides no support for its reliance on a 15-year amortization period (remaining useful life) in its evaluation of wet scrubbers for SO₂ control,^[147] which is half the useful life for wet scrubbers (30 years) recommended in the EPA's Control Cost Manual.^[148] The State also relied on a 10% firm-specific interest rate—more than double the bank prime rate at the time of analysis—without offering any rationale or supporting documentation.^[149] These factors are important inputs in the calculation of control technology cost effectiveness, and Wyoming's failure to substantiate them undermines its cost analysis.

Third, the State's use of a 90% control efficiency for wet scrubber SO₂ emissions control is not adequately supported. As documented in the Control Cost Manual, wet scrubbers typically achieve removal efficiencies of between 95% and 99% for most industrial applications, with many vendors publishing SO₂ removal efficiencies of over 99% for new wet FGD systems.^[150 151] We acknowledge the State's concern regarding the necessary water requirements to supply a 95% efficiency or greater wet scrubber system, which it cited as justification for using a 90% efficiency. However, the State makes no attempt to quantify or otherwise detail the incremental water requirements necessary to achieve a 95% or greater control efficiency to support its rejection of control efficiencies above 90% for a wet scrubber system. Without any supporting demonstration of the impact of those water requirements on the cost analysis, beyond a bare assertion that supplying additional water would not be economical, we find the State's assumption of 90% wet scrubber control efficiency to be unfounded. Relatedly, despite its concern regarding the necessary water requirements for the operation of wet scrubbers, the State did not demonstrate why less water-intensive SO₂ emissions control options ( i.e., dry scrubbing) are not feasible. Indeed, dry scrubbing was identified in public comments as a potential control option.^[152] The State provided no explanation for its failure to evaluate whether dry scrubbing is an emission reduction measure that is necessary to make reasonable progress toward the national visibility goal.

Collectively, these factors—conflicting cost figures, an unsubstantiated amortization period and firm-specific interest rate, and an unjustifiably low estimate of wet scrubber control efficiency—undercut the technical support for Wyoming's cost analysis and its resulting conclusion that additional SO₂ controls are not cost-effective at the Lost Cabin Gas Plant.

iii. Elk Basin Gas Plant, Dave Johnston Unit 4, and Green River Works

Finally, some of the State's four-factor analyses are critically incomplete because there are gaps in technical analysis with no documentation or justification to support that lack of analysis. For example, the State provided no data or cost figures to support its decision not to evaluate additional SO₂ emissions control measures for Dave Johnston Unit 4, including possible upgrades to the existing spray dryer absorber, other than stating that scrubber upgrades are more effective than DSI for incremental pollution control removal.^[153] In its evaluation of NO_X controls for Elk Basin Gas Plant's nine compressor engines and SO₂ controls for the plant's incinerator, the State omitted key elements necessary to determine cost-effectiveness: figures related to direct, indirect, and total costs; information necessary ( i.e., interest rate, amortization period) to determine the capital recovery factor and associated total annual costs and annualized capital costs; the assumed control efficiency of LEC NO_X emissions controls on the compressor engines; and the SO₂ emissions baseline for the incinerator.^[154] And in its evaluation of NO_X and PM emissions controls for Calciner 1 and Calciner 2 at Green River Works, the State failed to provide a demonstration with supporting documentation that existing measures are likely not necessary to make reasonable progress, despite having made that showing for the C Boiler and D Boiler.^[155]

In summary, for the reasons explained in this section IV.C.2.b., we propose to disapprove Wyoming's long-term strategy under CAA section 169A and 40 CFR 51.308(f)(2) because the State relied on unsupported technical rationales and failed to adequately document the technical basis on which it relied to determine the emission reduction measures necessary to make reasonable progress.

c. Sources Where the State Unreasonably Rejected Potential Emission Reduction Measures

We also propose to disapprove Wyoming's long-term strategy due to the State's unreasonable rejection of emission reduction measures at the Elk Basin Gas Plant and the Cheyenne Fertilizer Facility (table 37).

Table 37—Sources, Units, and Associated Pollutants and Emission Control Technology Where the State Unreasonably Rejected Emission Reduction Measures

Source	Unit(s)	Associated pollutant(s)	Emission control technology
Elk Basin Gas Plant (Contango Resources, Inc.)	Engines (9)	NO X	LEC.
Cheyenne Fertilizer Facility (Dyno Nobel, Inc.)	ENG004, ENG005 (engines)	NO X	LEC.
Cheyenne Fertilizer Facility (Dyno Nobel, Inc.)	CTW001, CTW003 (cooling towers)	PM	Upgraded Mist Eliminators.

In its evaluation of NO_X emissions controls for Elk Basin Gas Plant's nine engines, the State determined the cost/ton of LEC to be between $1,500-$2,200 per ton of NO_X emissions reduced, with a total expected reduction of 1,793.5 tons of NO_X per year.^[156] Similarly, the State determined the cost/ton of an LEC retrofit at Cheyenne Fertilizer Facility for engines ENG004 and ENG005 to be $1,067 per ton of NO_X emissions reduced, with a total expected reduction of 229 tons of NO_X per year for each engine.^[157] The State then rejected LEC control technology for both facilities despite concluding, after consideration of the four statutory factors as well as emission trends and permit conditions, that these facilities may warrant further analysis of emission controls to reach reasonable progress. Notably, Wyoming did not determine these cost/ton values for LEC to be unreasonable. Indeed, cost-effectiveness values of $1,067-$2,200 are in line with what the EPA and states found reasonable for regional haze control measures in the first planning period, even without adjusting for inflation.^[158] While Wyoming stated it would further analyze these facilities in its next regional haze progress report, nothing in the CAA or RHR allows states to defer controls that are shown, through four-factor analysis, to be necessary to make reasonable progress. States may not avoid their second planning period obligations by delaying decision making to a future date.^[159]

For its evaluation of PM emissions controls at the Cheyenne Fertilizer Facility on cooling towers CTW001 and CTW003, the State found the cost/ton for upgraded mist eliminators to be $1,056 for CTW001 and $2,368 for CTW003 per ton of PM emissions reduced, for total expected reductions of 15.5 tons (CTW001) and 2.4 tons (CTW003) of PM per year.^[160] Here again, Wyoming did not determine these cost/ton values to be unreasonable. However, the State concluded that the total capital investment for upgraded mist eliminators of $153,600 (for CTW001) and $53,990 (for CTW003) was not justified given what it considered to be the “minute” amount of emissions reductions that could be achieved; the State also cited declining PM emissions trends. At the same time, Wyoming concluded that the Cheyenne Fertilizer Facility may warrant further analysis of emission controls in the next regional haze progress report. We find that the State did not adequately justify its rejection of upgraded mist eliminators. Wyoming inappropriately relied on declining emissions trends—which is not one of the four statutory factors—to summarily reject controls shown to be cost-effective and otherwise reasonable through four-factor analysis.

In summary, we propose to disapprove Wyoming's long-term strategy under 40 CFR 51.308(f)(2) because the State unreasonably rejected potential controls for certain sources and thus did not reasonably determine the emission reduction measures necessary to make reasonable progress.

d. Other Unjustified Reasons for Rejecting All Additional Emission Reduction Measures

After evaluating potential emission reduction measures at the source-specific level, Wyoming explained its overall reasoning for not requiring any additional measures in its long-term strategy to make reasonable progress for the second planning period for affected Class I areas.^[161] Whether individually or in combination, Wyoming's reasons are not supported by the CAA and the RHR and provide another basis for our proposed disapproval of Wyoming's long-term strategy.

First, Wyoming unreasonably relied on generalized and unsubstantiated assertions that any emission reduction measures would impose economic hardships on sources and negatively affect rural communities. Wyoming provided no analyses, data, or other evidence to support its assertions that the cost of additional controls could force energy producers out of the market, harm ratepayers, impose economic stress on rural communities, or cause grid instability. In CAA section 169A, Congress established the national goal of preventing any future and remedying any existing impairment of visibility in Class I areas; it then directed states to develop SIPs containing long-term strategies comprised of emission limits, schedules of compliance, and other measures necessary to make reasonable progress toward that national goal through consideration of the four statutory factors.^[162] Wyoming cannot overcome Congress's express mandate by relying on an unsupported policy position that any additional control costs will cause unwarranted economic harm.

Second, past and projected emissions reductions do not support Wyoming's rejection of all additional control measures for the second planning period. To support its determination that no further emissions reductions are warranted, Wyoming pointed to first implementation period measures, increasing renewable energy generation, facility shutdowns and conversions, and measures taken in other states and nationwide. The RHR, however, sets out an iterative planning process by which states have a continuing obligation to determine the emission reduction measures necessary to make reasonable progress in each implementation period. As we recognized in the 2017 RHR Revisions, while first implementation period measures resulted in significant reductions in emissions nationwide, continued progress is still necessary and is required by statute.^[163] The fact that some emissions reductions have already been achieved and are expected to occur in the future, whatever the source of those reductions, does not exempt states from determining the measures necessary to make reasonable progress based on consideration of the four statutory factors in each planning period. Furthermore, as detailed in section IV.C.2.a.ii. of this document, the facility shutdowns cited by the State (with the exception of Dave Johnston Unit 3) are not federally enforceable or have otherwise not been validated. Nor did Wyoming quantify or substantiate the changes in emissions that it believes will occur due to increased renewable energy generation.^[164]

Third, Wyoming unreasonably pointed to other sources' contribution to visibility impairment in the State's Class I areas as a reason not to require its own emission reduction measures. But nothing in the CAA or RHR authorizes the rejection of control measures that are shown to be appropriate through four-factor analysis on the basis that some portion of visibility-impairing pollutants affecting Class I areas originates from international anthropogenic sources or natural sources such as wildfires. The four statutory factors do not include a state's relative level of contribution of visibility-impairing pollutants. Indeed, Congress's national goal is “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,” including visibility impairment caused by sources within the states.^[165]

Fourth, Wyoming improperly relied on the fact that its seven Class I areas are currently below the adjusted URP and are projected to remain so in 2028. As the EPA has consistently explained, states may not use the URP as a “safe harbor” to conclude that additional emission reduction measures are not necessary for reasonable progress. The 2017 RHR explains that the CAA requires that each SIP revision contain long-term strategies for making reasonable progress, and that in determining reasonable progress states must consider the four statutory factors. Treating the URP as a safe harbor would be inconsistent with the statutory requirement that states assess the potential to make further reasonable progress towards natural visibility goal in every implementation period. Even if a state is currently on or below the URP, there may be sources contributing to visibility impairment for which it would be reasonable to apply additional control measures in light of the four factors. Although it may conversely be the case that no such sources or control measures exist in a particular state with respect to a particular Class I area and implementation period, this should be determined based on a four-factor analysis for a reasonable set of in-state sources that are contributing the most to the visibility impairment that is still occurring at the Class I area. It would bypass the four statutory factors and undermine the fundamental structure and purpose of the reasonable progress analysis to treat the URP as a safe harbor, or as a rigid requirement.^[166] The EPA reiterated this concept in the 2019 Guidance ^[167] and in the 2021 Clarifications Memo.^[168] The CAA and RHR do not include the URP among the four factors states must consider in developing their long-term strategies. Treating the URP as a safe harbor, as Wyoming has done, is inconsistent with statutory requirements and undermines the core structure of an appropriate regional haze analysis.

Finally, Wyoming claims that WRAP modeling indicates that “potential additional controls will have little to no influence (< 0.1 dv)” on visibility conditions at Wyoming Class I areas.^[169] There is no basis for Wyoming's assertion. First, the State does not explain what “potential additional controls” on Wyoming sources were modeled; our review of the WRAP modeling information shows that none were. To support its claim, Wyoming pointed to the figures in Chapter 15 of its SIP submission, which show visibility modeling results for various emission scenarios: the WRAP modeling scenario “2028OTBa2” (“On the Books Inventory”) reflects emissions levels associated with implementation by 2028 of all applicable “on the books” federal and state requirements; ^[170] the WRAP modeling scenario “PAC2” (“Potential Additional Controls”) reflects emissions levels associated with implementation of potential additional controls beyond those included in the 2028OTBa2/“On the Books Inventory” scenario.^[171] No potential additional control measures beyond the “on the books inventory” were modeled for Wyoming, as indicated in tables 9-1 through 9-4 of Wyoming's 2022 SIP submission,^[172] WRAP spreadsheets for the modeling scenarios,^[173] and other WRAP modeling documentation.^[174] Instead, the < 0.1 deciview modeled visibility improvement that Wyoming referenced is attributable to potential emission reductions in other states.^[175] Simply put, Wyoming did not model visibility improvements associated with the emission reduction measures it considered, and rejected, through four-factor analysis. The State therefore had no basis to conclude that potential additional controls would have little to no influence on visibility conditions at its Class I areas.^[176]

In conclusion, Wyoming's unsubstantiated reasons for not requiring any additional emission reduction measures as part of its long-term strategy to make reasonable progress lack foundation in the CAA and RHR. Therefore, we propose to disapprove Wyoming's long-term strategy under CAA section 169A and 40 CFR 51.308(f)(2).

e. Other Long-Term Strategy Requirements (40 CFR 51.308(f)(2)(ii)-(iv))

States must meet the additional requirements specified in 40 CFR 51.308(f)(2)(ii)-(iv) when developing their long-term strategies. 40 CFR 51.308(f)(2)(ii) requires states to consult with other states that have emissions that are reasonably anticipated to contribute to visibility impairment in Class I areas to develop coordinated emission management strategies. Chapters 14.7.2 through 14.7.5 of Wyoming's 2022 SIP submission describe the State's consultation with other states throughout the development of its regional haze plan.

40 CFR 51.308(f)(2)(iii) requires states to document the technical basis, including modeling, monitoring, costs, 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 area it impacts. The State relied on WRAP technical information, modeling, and analysis to support development of its long-term strategy.^[177]

40 CFR 51.308(f)(2)(iv) specifies five additional factors states must consider in developing their long-term strategies. The five additional factors are: emission reductions due to ongoing air pollution control programs, including measures to address reasonably attributable visibility impairment; measures to mitigate the impacts of construction activities; source retirement and replacement schedules; basic smoke management practices for prescribed fire used for agricultural and wildland vegetation management purposes and smoke management programs; and 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. Chapter 14.5 of Wyoming's 2022 SIP submission describes each of the five additional factors.

Regardless, as explained in the preceding sections, due to flaws and omissions in its four-factor analyses and the resulting control determinations, we find that Wyoming failed to reasonably “evaluate and determine the emission reduction measures that are necessary to make reasonable progress” by considering the four statutory factors as required by CAA section 169A(b)(2)(A), CAA section 169A(g)(1), and 40 CFR 51.308(f)(2)(i). We also find that Wyoming failed to adequately document the technical basis that it relied upon to determine these emissions reduction measures, as required by 40 CFR 51.308(f)(2)(iii). In so doing, Wyoming failed to submit to the EPA a long-term strategy that includes “the enforceable emissions limitations, compliance schedules, and other measures that are necessary to make reasonable progress” ^[178] Consequently, the EPA finds that the Wyoming's 2022 SIP submission does not satisfy the long-term strategy requirements of 40 CFR 51.308(f)(2). Therefore, we are proposing to disapprove these corresponding portions of Wyoming's 2022 SIP submission.

D. Reasonable Progress Goals

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) in states' long-term strategies, as well as implementation of other CAA requirements.

After establishing its long-term strategy, Wyoming developed reasonable progress goals for each Class I area for the 20% most impaired days and 20% clearest days based on the results of 2028 WRAP modeling (table 38).^[179]

Table 38—Reasonable Progress Goals for the 20% Most Impaired Days and 20% Clearest Days for Wyoming Class I Areas

Class I Area	20% Most impaired days			20% Clearest days
	Average baseline conditions (2000-2004)	2028 Uniform progress goal 1	2028 Reasonable progress goal 2	Average baseline conditions (2000-2004)	2028 Reasonable progress goal
	Deciviews
Grand Teton National Park	8.3	7.2	7	2.6	2.3
Teton Wilderness Area
Yellowstone National Park
North Absaroka Wilderness Area	8.8	8.1	6.9	2.0	1.7
Washakie Wilderness Area
Bridger Wilderness Area	8	7.1	6.3	2.1	1.8
Fitzpatrick Wilderness Area
1  Based on the adjusted glidepath.
2  Based on WRAP 2028OTBa2.