Powder River Basin Resource Council 

Wyoming Chapter of Sierra Club 

Wyoming Wilderness Association 

Wyoming Outdoor Council 

Biodiversity Conservation Alliance 

Western Resource Advocates 

Natural Resources Defense Council 

 March 27, 2007 

David A. Finley, Administrator 

Division of Air Quality 

Department of Environmental Quality 

122 W. 25th Street 

Cheyenne, WY 82002 

RE: Comments on Wyoming’s Proposal to Approve Construction of a CoalFired Power Plant (“Dry Fork Station”) by Basin Electric Power 

Cooperative 

Dear Mr. Finley, 

The Wyoming Chapter of the Sierra Club, Wyoming Outdoor Council, Wyoming Wilderness 

Association, Powder River Basin Resource Council, Western Resource Advocates and the 

Natural Resources Defense Council respectfully submit the following comments on the 

Wyoming Department of Environmental Quality’s (WYDEQ’s) proposal to approve construction 

of a 422 megawatt (gross) coal-fired power plant to be known as the “Dry Fork Station” by 

Basin Electric Power Cooperative. WYDEQ’s proposed approval to construct would be issued 

under Chapter 6 of the Wyoming Air Quality Standards and Regulations (WAQSR) including 

the prevention of significant deterioration (PSD) requirements of Chapter 6, Section 4 of the 

WAQSR because this power plant would be a “major emitting facility.” 

In June 2004, Wyoming joined other Western states in launching the Western Governors’ 

Association’s Clean and Diversified Energy Initiative. The initiative’s goal is to develop 30,000 

megawatts of additional clean energy in the West by 2015 and increase efficiency of energy use 

by 20 percent by 2020. In addition, Wyoming has committed to bringing in new “clean coal” 

technologies such as Integrated Gasification Combined Cycle (IGCC) power plants to help curb 

emissions of carbon dioxide to the atmosphere. Yet, the proposed Dry Fork coal fired power 

project does nothing to fulfill either of these objectives for Wyoming or the West. The Dry Fork 

coal project proposes utilizing hundred-year-old, pulverized coal (PC) technology that is obsolete 

even before the plant is built, when Westerners are calling for renewable energy and energy 

efficiency-and at the very least clean coal technologies-to meet our goals. How will Wyoming 
2

meet these goals and encourage new and innovative power production when we continue to 

permit out-dated technology? 

1. WYDEQ FAILED TO MEET PUBLIC NOTICE REQUIREMENTS

Section 165(a)(2) of the Clean Air Act requires that, in order for a PSD permit to be issued, “the 

proposed permit has been subject to a review in accordance with [section 165 of the Clean Air 

Act]. . .and a public hearing has been held with opportunity for interested 

persons. . .including representatives of the Administrator to appear and submit written or oral 

presentations on the air quality impact of such source, alternatives thereto, control technology 

requirements, and other appropriate considerations.” In EPA’s implementing regulations for 

PSD SIPs, it is stated that the public notice for a proposed permit must provide “the degree of 

increment consumption that is expected from the source.” 40 C.F.R. §51.166(q)(2)(iii). 

Wyoming has a similar provision in Section 2(m) of Chapter 6 of the WAQSR. The EPA’s 

Environmental Appeals Board (EAB) has interpreted these provisions as meaning that the public 

notice for a PSD permit must include the degree of increment consumption that is expected in all 

of the locations impacted by the proposed source. IN THE MATTER OF HADSON POWER 

14- BUENA VISTA, PSD Appeal Nos. 92-3, 92-4, 92-5, 4 E.A.D. 258, 272-3 (EAB 1992). In 

particular the EAB noted “We do not believe that the phrase ‘degree of increment consumption’ 

can be read as allowing for providing data at only one location, albeit the one with the greatest 

projected consumption. Different potential commentors may have an interest in different areas to 

be impacted and would want, and would reasonably be entitled to, available data on increment 

consumption at the area of their particular concern. Otherwise their ability to comment on the air 

quality impact and proposed alternatives would be severely limited ” Id. at 272. 

WYDEQ’s public notice for the Dry Fork facility only identified the degree of sulfur dioxide 

(SO2) increment consumption “near the plant site.” WYDEQ did not identify the degree of 

increment consumption for NO2 or PM10. Further, WYDEQ did not identify the degree of 

increment consumption expected in any Class I areas. This omission seems particularly 

egregious for the Northern Cheyenne Indian Reservation Class I area, especially considering that 

Basin Electric’s cumulative SO2 increment analysis shows that there would be SO2 increment 

violations in that area and that Dry Fork would contribute to SO2 increment concentrations in 

that area. Therefore, WYDEQ failed to meet public notice requirements for the Dry Fork 

proposed permit. 

The imperative to provide public notice of increment consumption at specific Class I areas flows 

directly from the core statutory purposes of the PSD program. Section 160(2) of the Clean Air 

Act plainly provides that a central statutory purpose of the PSD program is “to preserve, protect, 

and enhance the air quality in national parks, national wilderness areas, national monuments, 

national seashores, and other areas of special national, scenic, or historic value.” Congress also 

instructed that the PSD program is intended “to assure that any decision to permit increased air 

pollution in any area to which this section applies is made only after careful evaluation of all the 

consequences of such a decision and after adequate procedural opportunities for informed public 

participation in the decisionmaking process.” CAA Sec. 160(5). Adequate notice is a 

necessary predicate to informed public participation in the PSD permit process. 
3

Thus, WYDEQ failed to adequately inform the public of the degree of increment consumption 

expected by Dry Fork in all areas to be impacted by the proposed facility and, accordingly, 

WYDEQ must re-issue its public notice to comply with public participation requirements.

2. THE PROPOSED DRY FORK PERMIT AND BASIN ELECTRIC’S PERMIT 

APPLICATION FAIL TO ADDRESS CARBON DIOXIDE AND OTHER 

GREENHOUSE GAS EMISSIONS

Basin Electric’s permit application for Dry Fork did not address carbon dioxide (CO2) or other 

greenhouse gases to be emitted from plant. WYDEQ’s proposed permit also did not address 

greenhouse gas emissions. However, such emissions can be very significant from coal-fired 

boilers. Based on information in the permit application and AP-42 emission factors, Dry Fork 

has a potential to emit 4.857 million tons of carbon dioxide each year.1

 

We believe that the EPA, and the State of Wyoming have a legal obligation to regulate CO2 and 

other greenhouse gases as pollutants under the Clean Air Act. Twelve states, 14 environmental 

groups and two cities have filed suit against EPA, asserting that EPA has ample authority under 

the Clean Air Act to regulate air pollutants associated with climate change and that EPA must 

adhere to the enumerated statutory factors in determining whether global warming pollution is 

reasonably anticipated to endanger public health and welfare. This issue is now before the U.S. 

Supreme Court.2

 In addition, legislation to address global warming and CO2 emission is being 

considered by Congress, and many states (including California) are increasingly attempting to 

regulate CO2 emissions. 

At the minimum, WYDEQ should have required consideration of emissions of CO2 in the Dry 

Fork best available control technology (BACT) analysis. However, neither Basin Electric or 

WYDEQ considered CO2 or other greenhouse gases in the BACT analysis and thus the proposed 

Dry Fork permit is seriously deficient in this regard. 

The EPA has long recognized the obligation for a permitting authority to meaningfully consider 

collateral environmental impacts, even if such impacts are due to unregulated pollutants. See In 

re North County, 2 E.A.D. 229, 230 (Adm’r 1986). The Administrator stated in that case: 

Region IX’s [asserts] that EPA lacks the authority to “consider” pollutants not regulated 

by the [CAA] when making a PSD determination. This assertion is correct only if it is 

read narrowly to mean EPA lacks the authority to impose limitations or other restrictions 

directly on the emission of unregulated pollutants. EPA clearly has no such authority over 

emissions of unregulated pollutants. Region IX’s assertion is overly broad, however, if it 

is meant as a limitation on EPA’s authority to evaluate, for example, the environmental 

impact of unregulated pollutants in the course of making a BACT determination for the 

regulated pollutants. EPA’s authority in that respect is clear. . . . Hence, if application of a 

 

1

 Emissions of CO2 were calculated based on AP-42 emission factors for subbituminous coal combustion in Table 

1.1-20 of Chapter 1 of AP-42 and from the expected annual tonnage of coal to be utilized at Dry Fork provided in 

Appendix B of the November 10, 2005 Dry Fork permit application). 

2

 Commonwealth of Massachusetts, et al. v. EPA, U.S. Supreme Court Docket No. 05-1120 (cert. granted June 26, 

2006). See Brief for the Petitioners, filed Aug. 31, 2006. 
4

control system results directly in the release (or removal) of pollutants that are not 

currently regulated under the Act, the net environmental impact of such emissions is 

eligible for consideration in making the BACT determination. The analysis may take the 

form of comparing the incremental environmental impact of alternative emission control 

systems with the control system proposed as BACT; however, as in any BACT 

determination, the exact form of the analysis and the level of detail required will depend 

upon the facts of the individual case. Depending upon what weight is assigned to the 

environmental impact of a particular control system, the control system proposed as 

BACT may have to be modified or be rejected in favor of another system. In other words, 

EPA may ultimately choose more stringent emission limitations for a regulated pollutant 

than it would otherwise have chosen if setting such limitations would have the incidental 

benefit of restricting a hazardous but, as yet, unregulated pollutant.

3

Thus, even if WYDEQ were to conclude (erroneously in our view) that CO2 should not be a 

regulated “pollutant” under the federal CAA or state clean air laws, it still must assess any 

differences in the potential global warming impacts of competing BACT technologies as part of 

the mandatory collateral impacts analysis. By its very nature the collateral impacts analysis is 

intended to target pollutants that are otherwise unregulated under the PSD provisions – and the 

statute is clear on its face that this inquiry is not limited exclusively to “pollutants” that the CAA 

otherwise regulates, but encompasses environmental impacts more broadly. See CAA § 169(3). 

The scientific consensus around global warming, and the significance of anthropogenic sources, 

has reached a point of unanimity; that is to say, global warming is real, and people are 

contributing to this phenomenon in a significant way.4

 Moreover, the likely impacts of global 

warming are profound. As a result, the sense of urgency related to addressing global warming – 

by reducing greenhouse gas emissions – has increased dramatically.5 The reports prepared by 

the Intergovernmental Panel on Climate Change (IPCC) provide scientific support for these 

concerns stated in the strongest possible terms.6

EPA itself recognizes that global warming is likely to have numerous and particularly severe 

adverse public health and environmental consequences, including direct heat-related effects, 

extreme weather events, climate-sensitive disease impacts, air quality effects, agricultural effects 

(and related impacts on nutrition), wildlife and habitat impacts, biodiversity impacts, impacts on 

marine life, economic effects, and social disruption (such as population displacement).7

 Indeed, 

 

3

 The EAB has consistently upheld his proposition. See, e.g., In re Genesee Power Station, 4 E.A.D. 832 (EAB 

1993); In re Steel Dynamics, 9 E.A.D. 165 (EAB 2000). 4

 The International Panel on Climate Change (IPCC) recently issued its Fourth Assessment on Global Warming, 

essentially eliminating any doubt about the existence of global warming and the contribution of human activities. 

See Fossil Fuels are to Blame, World Scientists Conclude, USA Today, Jan. 31, 2007; 

http://www.ipcc.ch/SPM2feb07.pdf. 5

 Global emissions of carbon amount to more than seven billion tons each year, and in order to address the 

impending effects of serious climate destabilization we must take action now to reduce these emissions. The more 

carbon we add to the atmosphere, the more dramatic the rise in temperature will be, and the more severe the climaterelated environmental impacts, social costs, human health effects, and impacts on habitat, species, ecosystems, and 

biodiversity. See SCIENTIFIC AMERICAN, What To Do About Coal (Sept. 2006) available at: 

http://www.sciam.com/article.cfm?chanID=sa006&articleID=0003F275-08F2-14E6-BFF883414B7F0000. 6

 IPCC reports are available at http://www.ipcc.ch/. 7 See http://www.epa.gov/climatechange/effects/health.html. 
5

numerous studies directly link global warming with increases in a variety of serious 

environmental, health, economic, and ecological impacts.8

In the BACT context, there is also no reason to dismiss important considerations of CO2

emissions simply because numerous sources collectively contribute to global warming. Indeed, 

many of the foundational regulatory provisions of the CAA, such as the National Ambient Air 

Quality Standard (NAAQS), are predicated on the principle of reducing relatively small 

quantities of emissions from large numbers of sources in order to reduce harmful levels of 

pollutants in the ambient air.9 The potential health, environmental, energy, and welfare 

consequences of global warming are profound. Reducing CO2 emissions, especially those 

associated with coal-fired power plants, is the single most important strategy to fight these 

effects.10 Because coal-fired power plants are the single largest source of CO2 emissions, they 

are a critical part of any efforts to address the effects of global warming. 

In short, the consideration of the consequence of CO2 emissions as a collateral environmental 

impact in the BACT analysis is completely independent of CO2’s status as a pollutant under the 

Clean Air Act or Wyoming law, and considering CO2 emissions when a new coal plant is 

 

8

 The Los Angeles Times recently reported on a new study that shows that global warming is likely to cause extreme 

events that will damage ecosystems, harm public health, and disrupt society well before the end of the century. See

http://www.latimes.com/news/nationworld/nation/la-na-climate20oct20,0,4849957.story?coll=la-home-nation. See, 

also links to the following studies at http://www.pewclimate.org/global-warming-indepth/environmental_impacts/reports/ : Observed Impacts of Climate Change in the U.S., Coping With Global 

Climate Change: The Role of Adaptation in the United States, A Synthesis of Potential Climate Change Impacts on 

the United States, Coral Reefs & Global Climate Change: Potential Contributions of Climate Change to Stresses on 

Coral Reef Ecosystems, Forests & Global Climate Change: Potential Impacts on U.S. Forest Resources, Coastal and 

Marine Ecosystems and Global Climate Change: Potential Effects on U.S. Resources, Aquatic Ecosystems and 

Global Climate Change: Potential Impacts on Inland Freshwater and Coastal Wetland Ecosystems in the United 

States, Human Health & Global Climate Change: A Review of Potential Impacts in the United States, Ecosystems & 

Global Climate Change: A Review of Potential Impacts on U.S. Terrestrial Ecosystems and Biodiversity, Sea-Level 

Rise & Global Climate Change: A Review of Impacts to U.S. Coasts, Water and Global Climate Change: Potential 

Impacts on U.S. Water Resources, The Science of Climate Change: Global and U.S. Perspectives, Agriculture & 

Global Climate Change: A Review of Impacts to U.S. Agricultural Resources. STERN REVIEW ON THE ECONOMICS 

OF CLIMATE CHANGE, available at: http://www.hmtreasury.gov.uk/Independent_Reviews/stern_review_economics_climate_change/sternreview_index.cfm. These studies are incorporated 

here by reference. 

9

 CAA § 112 similarly seeks to bring levels of hazardous air pollutants down to safe levels by regulating multiple 

source and multiple source categories of certain pollutants. There are other examples as well (e.g., SO2 reductions 

under the acid rain program, and the regulations of emission from mobile sources). As a former EPA Assistant 

General Counsel puts it, ignoring CO2 in the collateral impacts analysis because of the collective contribution of 

numerous sources would be: 

a recipe for total inaction that has been rejected in considering other air pollution problems and should be 

as to CO2 as well. Rather, sizable sources such as coal-fired power plants must be viewed in terms of their 

contribution to the cumulative problem of climate change and the need—at least in the absence of a 

comprehensive regulatory program of CO2 control—to mitigate that contribution. 

Foote, 34 ELR at 10665. See also Foote, 34 ELR 10663-665 (discussing among other things why consideration of 

CO2 in this context would not have unintended negative environmental effects). (This paper is included as 

Attachment 2 to this letter). 

10 See, e.g., SCIENTIFIC AMERICAN, What To Do About Coal (Sept. 2006), available at: 

http://www.sciam.com/article.cfm?chanID=sa006&articleID=0003F275-08F2-14E6-BFF883414B7F0000. 
6

proposed (i.e. as a part of the process of pre-construction review), is by far the most costeffective stage to evaluate the possibility of achieving reductions.11

Given the potential for extremely severe environmental and public health related impacts from 

global warming; given that the phenomenon of global warming is undeniably connected to 

anthropogenic releases of CO2; given that electric power production is the single most significant 

source of CO2 emissions in the U.S. and the world; and given that coal fired power plants (such 

as the one proposed by Basin Electric) contribute the vast majority of energy-sector CO2

emissions; it is simply untenable that the effects of global warming would be inherently outside 

the scope of the “collateral impacts” that permit applicants and permitting authorities must 

consider in connection with the issuance of PSD permits. Thus, any assertion that CO2

emissions (and global warming) are somehow beyond the broad mandate to consider 

“environmental impacts” under the PSD program must be rejected. 

At a minimum, therefore, WYDEQ must consider emissions of CO2 in its BACT analysis for the 

Dry Fork facility. In fact, the EPA's October 1990 New Source Review (NSR) Workshop 

Manual specifically states that "[s]ignificant differences in noise levels, radiant heat, or 

dissipated static electrical energy, or greenhouse gas emissions may be considered" in assessing 

environmental impacts from a proposed coal plant. See, EPA NSR Workshop Manual, p. b.49. 

(Attachment 1). Further, a recently issued paper entitled Considering Alternatives: The Case 

for Limiting CO2 Emissions from New Power Plants through New Source Review by Gregory B. 

Foote (Attachment 2) discusses the regulatory background to support consideration of CO2

impacts when permitting a new source and, in particular, a new coal-fired power plant. This 

paper indicates that it is entirely appropriate to consider CO2 emissions when evaluating 

environmental impacts under the new source review permit program, and the paper also 

suggested approaches for evaluating technologies in terms of CO2 emissions. 

As discussed further below, there are technologies available that produce electricity from coal 

more efficiently (burning less coal and thus emitting less CO2 to produce the same amount of 

electricity) as well as technologies that more readily accommodate carbon sequestration. The 

Dry Fork permit must not be issued by WYDEQ without such thorough and unbiased evaluation 

of these other technologies. 

Permitting authorities’ obligation to consider collateral environmental impacts extends not only 

to emission of CO2, but also to other potential environmental impacts, such as the consequences 

of water use, impacts from the generation of hazardous wastes, and impacts on species and 

habitat. These obligations grow directly from the definition of BACT at CAA § 169(3). 

The permitting authority, here WYDEQ, must consider the full range of potential collateral 

environmental impacts. This includes consideration of impacts related to water use and 

generation and disposal of solid waste products. One of the benefits of IGCC compared with 

antiquated conventional coal technology is dramatically lower water requirements – which may 

have a variety of environmental benefits (related to both water intake requirements and 

wastewater discharges). Additionally, IGCC generates considerable less solid waste than 

 

11 For example, industry would consider it cost prohibitive to consider retrofits for a pulverized coal plant in order to 

seriously address CO2 emissions (by installing CO2 capture and control equipment for example). 
7

conventional PC plants, and that waste is in a form that is much more stable and less likely to 

leach into the environment.12 The applicant (and the permitting authority) must consider these 

factors, as well as the benefits discussed above regarding CO2 benefits, in the context of an 

evaluation of collateral environmental impacts. These impacts are important to protecting public 

health, protecting water resources, and protecting the natural environment. 

With respect to endangered species, the EAB explained in In re Indeck-Elwood: 

[W]e find [that the] CAA provides that, in establishing BACT limits, the permit issuer is 

to “tak[e] into account energy, environmental, and economic impacts and other costs.” 

CAA § 169(3), 42 U.S.C. § 7479(3) (emphasis added). We think “environmental 

impacts” is most naturally read to include ESA-identified impacts to endangered or 

threatened species. . . . We therefore conclude that the CAA’s PSD requirements and the 

ESA requirements are appropriately viewed as complementary in nature, such that 

impacts on ESA-identified threatened and/or endangered species can be taken into 

account when considering a PSD permit application and establishing a permit’s terms and 

conditions.13 

Whether or not a permitting authority is subject to the Endangered Species Act for a particular 

project, impacts on species and habitat are, undeniably, “environmental impacts” – and therefore 

must be considered in connection with an applicant’s collateral impacts analysis. Moreover, this 

obligation exists above and beyond a permitting authority’s affirmative obligation to assess 

impacts on soils and vegetation. 

The U.S. Fish and Wildlife Service lists 56 threatened or endangered plant and animal species in 

the mountain prairie region (including Wyoming), and another 11 candidates for listing. See

http://mountain-prairie.fws.gov/wy.html. Clearly, therefore, an analysis of potential impacts on 

species and habitat is an important part of the information to which the public is entitled during 

the public comment period (especially where there are competing technologies – as discussed 

herein – that may have significantly different environmental impacts). 

Indeed, where competing BACT technologies would have significantly different collateral 

environmental impacts – that would have distinct affects on soils, vegetation, and/or threatened 

or endangered species – the EAB has made clear that this analysis is especially important to the 

appropriate implementation of the Clean Air Act and the meaningful participation of the public 

in the PSD permitting process.14 Moreover, the permitting authority is obligated (based on the 

definition of BACT in section 169) to specifically evaluate the differences in collateral 

 

12 See U.S. EPA, Environmental Footprints and Costs of Coal-Based Integrated Gasification Combined Cycle and 

Pulverized Coal Technologies, at p. 3-34, available at: http://www.epa.gov/air/caaac/coaltech/2007_01_epaigcc.pdf. 13 In re Indeck-Elwood, PSD Appeal 03-04, at 108-109, 13 E.A.D. __ (Sept. 27, 2006). 14 The collateral impacts analysis for soils and vegetation is important for each facet of the Dry Fork Station permit, 

including ambient air quality assessment; technology assessments and selection (for both primary and secondary 

emission units); and other collateral environmental effects (such as water, solid waste, and non-PSD air pollutants) – 

especially when the relative benefits of other technologies (like IGCC) are considered. 
8

environmental impacts between competing technologies.15 Because WYDEQ did not 

meaningfully evaluate IGCC, it has failed to meet it statutory obligation, and the public has been 

denied its right to comment on a vital component of the statutory decision-making process.

3. WYDEQ/BASIN ELECTRIC MUST CONSIDER THE COLLATERAL COSTS OF 

FUTURE CO2 REGULATION IN THE BACT ANALYSIS 

BACT also requires consideration of costs that are relevant to the selections of one BACT option 

over another. In this context, costs associated with the future regulation of carbon dioxide 

emissions from power plants should be considered in deciding between BACT options for the 

Dry Fork facility, and BACT options that are less intense emitters of CO2 should be given 

preference. 

The regulation of CO2 emissions in the U.S. in the very near future is virtually certain. The 

international community has already begun to take action to curb such emissions – 190 countries 

have joined the United Nation’s Framework Convention on Climate Change, and most have 

ratified the Kyoto Protocol (the U.S. and Australia alone among the industrialized countries have 

not). More recently, certain States have also taken concrete steps to reduce their carbon 

footprint; for example, several northeast states have formed the Region Greenhouse Gas 

Initiative (RGGI) to reduce carbon emission in that part of the country.16 The state of California 

also has passed legislation to limit the state’s greenhouse gas emissions, and to require that new 

long-term investments in baseload generation meet a minimum standard for greenhouse gas 

emissions. Also, several western and midwest states are now contemplating action to limit 

greenhouse gases. Moreover, members of Congress have introduced numerous bills, 

amendments, and resolutions specifically addressing global warming in 2005, and the Senate 

passed a resolution calling for a “comprehensive and effective national program of mandatory, 

market-based limits and incentives on emissions of greenhouse gases that slow, stop, and reverse 

the growth of such emissions.” 17,18 Studies continue to show that such regulation is the only 

responsible and economically sensible course of action; for example, the Stern Report19

concluded that while the cost of inaction could range from 5 percent to 20 percent of global 

GDP, the cost of stabilizing ambient concentrations at 450 to 550 ppm CO2-equivalent can be 

accomplished for about 1 percent of GDP. According to the report, the key policies required to 

meet this goal are the implementation of carbon emission regulations (such as cap and trade 

measures), the deployment of low-carbon-technologies and further low-carbon innovation, and 

the removal of barriers to energy efficiency. 

 

15 In this context, relevant difference may include difference in the quantity or nature of air emissions, such as NOx, 

SO2, CO, PM, and mercury, as well as impacts related to other factors such as water usage, solid waste handling and 

disposal, waste water or process water discharges, etc. 

16 See www.rggi.org. 17 Senate Amendment 866 a Sense of the Senate climate change resolution proposed by Senators Bingaman, 

Specter, Domenici, Alexander, Cantwell, Lieberman, Lautenberg, McCain, Jeffords, Kerry, Snowe, Collins and 

Boxer adopted by a vote of 53 to 44 on June 22, 2005. Congressional Record, Vol. 151, June 22 2005, S7033 – 

S7037, S7089. 

18 See www.aip.org/fyi/2005/114.html. In May of this year the House Appropriations Committee approved similar 

language. See www.pewclimate.org/what_s_being_done/in_the_congress/index.cfm for more information on 

Congressional action on global warming. 

19 STERN REVIEW ON THE ECONOMICS OF CLIMATE CHANGE, available at: http://www.hmtreasury.gov.uk/Independent_Reviews/stern_review_economics_climate_change/sternreview_index.cfm.. 
9

The general consensus in the U.S. is that federal CO2 emission controls are inevitable. Notably, 

the utility industry as well has begun to recognize that national carbon emission limits are both 

necessary and desirable; for example, executives from Duke Energy and NRG have recently 

made statements strongly supporting the idea of national carbon limits, and emphasizing the 

responsibility of the electric power sector to take action to address global warming.20 Tellingly, 

a diverse group of entities (including utilities, environmental groups, petroleum and chemical 

companies and others – including BP, Duke Energy, DuPont, and the Natural Resources Defense 

Council) recently formed the U.S. Climate Action Partnership (“USCAP”), calling for “the 

prompt enactment of national legislation in the United States to slow, stop and reverse the 

growth of greenhouse gas (GHG) emissions over the shortest period of time reasonably 

achievable.” Because power generation is the single most significant source of CO2 in the 

United States (accounting for nearly 40 percent of U.S. emission), this industry – and coal-fired 

power generation in particular – is certain to be among the first industry sectors affected by 

carbon-related regulation. 

As the momentum to regulate greenhouse gas emissions continues to grow around the country 

and internationally, businesses are increasingly recognizing the monetary risk associated with 

impending carbon emissions controls. For example: 

• PacifiCorp and Idaho Power Company have explicitly addressed the financial risk 

associated with carbon emissions in their recent IRPs. Idaho Power’s draft IRP, 

for example, explains that the utility analyzed the financial risk of carbon 

emissions because “it is likely that carbon dioxide emissions will be regulated 

within the thirty year timeframe addressed in the 2004 IRP.”21

• PG&E’s long-term plan recognizes the risk of increasing costs for carbon 

emissions. 

• Last year, the Coalition for Environmentally Responsible Economies (CERES) 

convened a Dialogue among experts from the power sector, environmental 

groups, and the investment community focusing on climate change. The Dialogue 

participants found that greenhouse gas emissions will be regulated in the U.S., 

and that the “issue is not whether the U.S. government will regulate these 

emissions, but when and how.”22

• Utility shareholders are recognizing that the likelihood of regulation of carbon 

emissions represents a real financial risk, and are asking utilities to disclose those 

risks. Thirteen major public pension funds, which manage $800 billion in assets, 

recently asked the Securities and Exchange Commission to require companies to 

disclose the financial risks they face from climate change.23 Meanwhile, in 2004 

alone institutional shareholder groups filed 29 proposals asking individual 

companies to outline their response to global warming. 

 

20 See, e.g., http://www.cleartheair.org/proactive/newsroom/release.vtml?id=25835. 21 See PacifiCorp, “2003 Integrated Resource Plan,” www.pacificorp.com. Idaho Power Company, “Draft 2004 

Integrated Resource Plan,” www.idahopower.com/energycenter/2004irpdraft.htm. 22 Coalition for Environmentally Responsible Economies, “Electric Power, Investors, and Climate Change,” June 

2003, p. 4 (www.ceres.org/reports/main.htm). 

23 Margaret Kriz, “Measuring The Climate For Change,” Congress Daily, April 22 2004. 
10

There is overwhelming evidence that carbon emissions will be regulated in the very near future, 

and accordingly, businesses in the U.S. are taking this financial risk quite seriously.24 

In short, the costs associated with the imminent regulation of CO2 (certainly within the lifetime 

of the proposed Dry Fork facility) should be expressly considered in connection with the 

selection of BACT. Because Basin Electric proposes to use a carbon-intensive PC technology, 

and because other BACT options have significantly better CO2 emissions performance (in 

particular IGCC, as discussed below – especially when used in conjunction with carbon capture 

and disposal),25 the cost of future CO2 regulation is directly relevant to the BACT analysis in this 

case. Thus, WYDEQ must require this cost to be considered in the BACT analysis for the Dry 

Fork facility.26

4. FEDERAL AND STATE CLEAN AIR LAWS REQUIRE BASIN ELECTRIC TO 

CONSIDER THE APPLICATION OF PRODUCTION PROCESSES AND AVAILABLE 

METHODS, SYSTEMS AND TECHNIQUES TO LOWER AIRBORNE 

CONTAMINANTS

 

24 Moreover, emission allowances that effectively “grandfather” the CO2 emissions of existing power plants 

(particularly those plants being permitted now – when the writing is already on the wall) is highly unlikely and 

would be entirely inappropriate. Rather, it is probable that the Congress will adopt legislation in the near term that 

is consistent with the 2005 U.S. Senate resolution calling for a “comprehensive and effective national program of 

mandatory, market-based limits and incentives on emissions of greenhouse gases that slow, stop, and reverse the 

growth of such emissions.” Given the number of plants being proposed and the fact that the Senate is on record 

calling for a program to reduce emissions, the law is likely to limit emission allowances to coal plants that were fully 

permitted or actually in operation prior to the Senate resolution (at the latest). 

25 IGCC inherently emits less CO2 than pulverized coal technologies because of its greater efficiency, but it also 

provides the ability to capture and dispose of CO2 in order to reduce CO2 emission by perhaps 80-90 percent. 26 There are various cost estimates related to future carbon dioxide emissions control that span a range from about $8 

per ton to more than $40 per ton. For example, there is currently a carbon dioxide trading program in Europe that 

serves as one component of European efforts to address global warming. In that trading program, carbon dioxide 

emissions have reached a high of about $42 per ton. See http://pubs.acs.org/subscribe/journals/esthagw/2006/jul/business/mb_carbonprices.html. Several states in the U.S. have specifically required consideration of 

future carbon costs as a part of their energy planning processes. In particular, the California Public Utilities 

Commission requires that the utilities use a “greenhouse gas adder” of $8 per ton CO2, beginning in 2004 and 

escalated at 5 percent per year, in long-term planning and procurement for purposes of evaluating new long-term 

resource investments. See California Public Utilities Commission, Decision No. 04-12-048, and Decision 05-04-

024. The Montana Public Service Commission has a similar requirement. See Montana Public Service 

Commission, “Written Comments Identifying Concerns Regarding Northwestern Energy’s Compliance with A.R.M. 

38.5.8201-8229,” Docket No. N2004.1.15, In the Matter of the Submission of Northwestern Energy’s Default 

Electricity Supply Resource Procurement Plan (August 17, 2004). Idaho Power is using a carbon cost of $14/ton 

starting in 2012. See http://www.idahopower.com/energycenter/irp/2006/2006IRPFinal.htm. In a recent filing 

before the Florida Public Services Commission, Florida Power and Light estimated CO2 emission costs ranging up 

to more than $100 per ton during the life of their proposed coal plant. See .

http://www.psc.state.fl.us/library/filings/07/01093-07/01093-07.pdf. As a result, reasonable estimates for the 

average annual cost of CO2 under expected U.S. regulations range from about $8 to well above $40 per ton. This 

range of costs is supported by a recent study by Synapse Energy Economics, Inc. available at: http://www.synapseenergy.com/Downloads/SynapsePaper.2006-06.Climate-Change-and-Power.pdf.Even assuming a relatively low 

carbon cost, of say $12 per ton, it is clear that emission from a facility like Dry Fork could create a significant 

financial burden. 
11

Section 165(a)(4) of the Clean Air Act (CAA) provides that “no major emitting facility on which 

construction is commenced after August 7, 1977, may be constructed in any area to which this 

part applies unless...the facility is subject to the best available control technology for each 

pollutant subject to regulation under this chapter emitted from, or which results from, such 

facility.”27 The requirement for conducting a BACT analysis and setting an emission limit 

reflective of BACT is codified in Chapter 6, Section 4 (b)(ii) of the Wyoming Air Quality 

Standards and Regulations. 

BACT requires a comprehensive analysis of all potentially available emission control measures, 

expressly including input changes (such as use of clean fuels), process and operational changes, 

and the use of add-on control technology. Additionally, it requires that a new source comply 

with emission limits that correspond to the most effective control measures available, unless the 

source can affirmatively demonstrate that use of the most effective control measures would be 

technologically or economically infeasible. 

BACT is specifically defined under Wyoming law as follows: 

an emission limitation (including a visible emission standard) based on the 

maximum degree of reduction of each pollutant subject to regulation under these 

Standards and Regulations or regulation under the Federal Clean Air Act, which 

would be emitted from or which results for any proposed major stationary source 

or major modification which the Administrator, on a case-by-case basis, taking 

into account energy, environmental, and economic impacts and other costs, 

determines is achievable for such source or modification through application or 

production processes and available methods, systems, and techniques, including 

fuel cleaning or treatment or innovative fuel combustion techniques for control of 

such pollutant.

Chapter 6, Section 4(i) of the WAQSR. [Emphasis added.] 

Wyoming’s definition essentially mirrors the federal definition of BACT in 40 C.F.R. 

§52.21(b)(12). 

EPA has repeatedly acknowledged that the PSD program is technology forcing and intended to 

become more stringent over time as control technologies improve and new cleaner processes are 

introduced. For example, the EAB has explained that: 

A major goal of the CAA was to create a program that was technology 

forcing. . . . “The Clean Air Amendments were enacted to ‘speed up, 

expand, and intensify the war against air pollution in the United States 

with a view to assuring that the air we breathe throughout the Nation is 

wholesome once again.’” . . . . 

In keeping with this objective, the program Congress established was 

particularly aggressive in its pursuit of state-of-the-art technology at newly 

constructed sources. At these sources, pollution control methods could be 

 

27 42 U.S.C. §7475(a)(4). 
12

efficiently and cost-effectively engineered into plants at the time of 

construction.28

Similarly, the EPA Administrator has explained that the BACT provisions of the PSD program 

are principally technology-forcing and are intended to foster “rapid adoption” of improvements 

in emissions control technology.29 

The definition of BACT includes coal gasification. The legislative history of the amendment 

adding the term “innovative fuel combustion techniques” to the Clean Air Act’s definition of 

“BACT” is clear. Coal gasification must be considered. The relevant passage of the debate is 

excerpted below: 

Mr. HUDDLESTON. Mr. President, the proposed provisions for application of 

best available control technology to all new major emission sources, although 

having the admirable intent of achieving consistently clean air through the 

required use of best controls, if not properly interpreted may deter the use of some 

of the most effective pollution controls. The definition in the committee bill of 

best available control technology indicates a consideration for various control 

strategies by including the phrase “through application of production processes 

and available methods systems, and techniques, including fuel cleaning or 

treatment.” And I believe it is likely that the concept of BACT is intended to 

include such technologies as low Btu gasification and fluidized bed combustion. 

But, this intention is not explicitly spelled out, and I am concerned that without 

clarification, the possibility of misinterpretation would remain. It is the purpose 

of this amendment to leave no doubt that in determining best available control 

technology, all actions taken by the fuel user are to be taken into account--be they 

the purchasing or production of fuels which may have been cleaned or up-graded 

through chemical treatment, gasification, or liquefaction; use of combustion 

systems such as fluidized bed combustion which specifically reduce emissions 

and/or the post-combustion treatment of emissions with cleanup equipment like 

stack scrubbers. The purpose, as I say, is just to be more explicit, to make sure 

there is no chance of misinterpretation. Mr. President, I believe again that this 

amendment has been checked by the managers of the bill and that they are 

inclined to support it. 

Mr. MUSKIE. Mr. President, I have also discussed this amendment with the 

distinguished Senator from Kentucky. I think it has been worked out in a form I 

can accept. I am happy to do so. I am willing to yield back the remainder of my 

time.30

 

28 In Re Tenn. Valley Authority, 9 E.A.D. 357, 391 (EAB 2000) (citing WEPCO, 893 F.2d at 909 and H.R. Rep. No. 

95-294, at 185, reprinted in 1977 U.S.C.C.A.N. at 1264). 

29 In re Columbia Gulf Transmission Co., 2 E.A.D. 824, 828-29 (Adm’r 1989). See also In re Kawaihae 

Cogeneration Project, 7 E.A.D. 107, 127 n.26 (EAB 1997); In re Metcalf Energy Center, PSD Appeal 01-7, 01-8, at 

15 (Aug. 10, 2001). 

30 95th Congress, 1st Session (Part 1 of 2) June 10, 1977 Clean Air Act Amendments of 1977 A&P 123 Cong. 

Record S9421. 
13

Clearly, both the language of the Act itself and the unequivocal expressions of Congressional 

intent in the legislative history indicate, that in order to fully comply with the Act, the emission 

limits identified as BACT must incorporate consideration of more than just add-on emission 

control technology – they must also reflect appropriate considerations of fuel quality (such as 

low sulfur coal) and process changes (including specifically innovative combustion techniques 

such as coal gasification). Indeed, this requirement is not only consistent with, but necessary to 

the very core objective of PSD permitting – to bring about the rapid adoption of cleaner 

technologies that provide for a greater reduction in regulated emissions.31 In “notably capacious 

terms,” Alaska v. EPA, 540 U.S. 461 (2004), the statute provides that BACT includes 

“application of production processes and available methods, systems, and techniques, including 

fuel cleaning, clean fuels, or treatment or innovative fuel combustion techniques.” CAA Sec. 

169(3). 

EPA and federal courts have consistently interpreted the BACT provisions found in the Clean 

Air Act and the EPA’s regulations as embodying certain core criteria that require the permit 

applicant either to implement the most effective available means for minimizing air pollution or 

justify its selection of less effective means on grounds consistent with the purposes of the Clean 

Air Act. Indeed, the discretion of the permitting agency in determining BACT is deliberately 

confined by the statute’s use of the “strong, normative terms ‘maximum’ and ‘achievable.’” 

Alaska v. EPA, 540 U.S. 461 (2004). 

In Citizens for Clean Air v. EPA,

32 the Ninth Circuit held that “initially the burden rests with the 

PSD applicant to identify the best available control.” As stated in long-standing EPA guidance, 

“[r]egardless of the specific methodology used for determining BACT, be it ‘top-down,’ 

‘bottom-up,’ or otherwise, the same core criteria apply to any BACT analysis: the applicant must 

consider all available alternatives, and [either select the most stringent of them or] demonstrate 

why the most stringent should not be adopted.”33 Accordingly, the PSD permit applicant not 

only must identify all available technologies, including the most stringent, but it must also 

provide adequate justification for dismissing any available technologies. 

Consistent with these core criteria, the EPA’s NSR Workshop Manual establishes that, as the 

first step in the “top-down” BACT analysis, the applicant must consider all “available” control 

options: 

The first step in a "top-down" analysis is to identify, for the emissions unit in 

question (the term "emissions unit" should be read to mean emissions unit, 

 

31 Emission controls under the Clean Air Act are universally recognized as including process changes (including 

inherently cleaner processes) as well as add-on control technology. The PSD provisions expressly recognize this in 

the definition of BACT included in section 169 of the Act. Other sections of the Act reinforce the fact that Congress 

generally understood and accepted that emission control is often most effectively achieved through process changes. 

See CAA § 112(d)(2) (identifying mechanisms for reducing emission of hazardous air pollutants as including, in 

addition to add-on controls, “process changes, substitutions of materials or other modifications,” as well as “design, 

equipment, work practice, or operational standards”). 

32 959 F.2d 839, 845 (9th Cir. 1992) 33 Memorandum from John Calcagni, Director of EPA Air Quality Management Division, to EPA Regional Air 

Directors (June 13, 1989), at 4 (emphasis added). 
14

process or activity), all "available" control options. Available control options are 

those air pollution control technologies or techniques with a practical potential for 

application to the emissions unit and the regulated pollutant under evaluation. Air 

pollution control technologies and techniques include the application of 

production process or available methods, systems, and techniques, including fuel 

cleaning or treatment or innovative fuel combustion techniques for control of the 

affected pollutant. This includes technologies employed outside of the United 

States. As discussed later, in some circumstances inherently lower-polluting 

processes are appropriate for consideration as available control alternatives.34

EPA further explains that potential control options can be categorized in three ways: 

• Inherently lower emitting processes/techniques 

• Add-on controls 

• Combinations of inherently lower emitting processes/techniques and add-on 

controls.35

With respect to inherently lower emitting processes, EPA explains that “[l]ower-polluting 

processes should be considered based on demonstrations made on the basis of 

manufacturing identical or similar products from identical or similar raw materials or 

fuels.”36

“The term ‘available’ is used...to refer to whether the technology ‘can be obtained by the 

applicant through commercial channels or is otherwise available within the common sense 

meaning of the term.’”37 In keeping with the stringent nature of the BACT requirement, EPA 

has repeatedly emphasized that “available” 

is used in the broadest sense under the first step and refers to control 

options with a “practical potential for application to the emissions unit” 

under evaluation. . . . The goal of this step is to develop a comprehensive 

list of control options.38

EPA adjudicatory decisions also examine the core requirements for the BACT determination 

process. “Under the top-down methodology, applicants must apply the best available control 

technology unless they can demonstrate that the technology is technically or economically 

infeasible. The top-down approach places the burden of proof on the applicant to justify why the 

proposed source is unable to apply the best technology available.”39 That is, a BACT review 

 

34NSR Manual, at p. B.5 (emphasis added). 35 Id. at B.10. 36 Id. 37 In re: Maui Electric Company, PSD Appeal No. 98-2 (EAB September 10, 1998), at 29-30 (quoting NSR Manual 

at B.17). 

38 In re: Knauf Fiber Glass, PSD Appeal Nos. 98-3 – 98-20 (EAB February 4, 1999), at 12-13 (quoting NSR Manual 

at B.5) (emphasis added by EAB); see also In re: Steel Dynamics, Inc., PSD Appeal Nos. 99-4 and 99-5 (EAB June 

22, 2000), at 29 n.24 (citing Knauf with approval); NSR Manual at B.10 (“The objective in step 1 is to identify all 

control options with potential application to the source and pollutant under evaluation.”); id. at B.6 (emphasizing 

that a proper Step 1 list is “comprehensive”). 

39 In re: Spokane Regional Waste-to-Energy Applicant, PSD Appeal No. 88-12 (EPA June 9, 1989), at 9) (internal 

quotation marks omitted) (emphasis in original); see also In re: Inter-Power of New York, Inc. PSD Appeal Nos. 92-

8 and 92-9 (EAB March 16, 1994) (“Under the ‘top-down’ approach, permit applicants must apply the most 
15

must facilitate adopting the best available technology, not be used as a basis for rejecting

applicable technology. 

Whatever analytical process is utilized for determining BACT, these core criteria – the 

requirement to consider all available technologies, including the most stringent, and to provide 

adequate justification in the administrative record for dismissing any of the technologies based 

on relevant statutory factors – must be satisfied.40 

Thus, to conduct a BACT analysis for the Dry Fork facility, WYDEQ must thoroughly evaluate 

all available control measures. IGCC is commercially available today and it reflects an 

inherently lower emitting process for producing electricity from coal. Therefore, this technology 

should have been thoroughly evaluated as part of the Dry Fork BACT analysis. 

Any Arguments that IGCC Does Not Need to Be Considered Because It Would Be “Redefining 

the Source” are Flawed and Must Fail

In its air quality construction permit application, Basin Electric stated “EPA has not considered 

the BACT requirement as a means to redefine the source. . .[t]herefore, this the BACT analysis 

does not evaluate different combustion designs such as circulating fluidized bed or integrated 

gasification combined cycle since these combustion processes are fundamentally different from 

the chosen PC boiler design.” November 10, 2005 Basin Electric Permit Application at 5-1. 

Basin Electric and WYDEQ have utterly ignored, in the context of evaluation of BACT for Dry 

Fork, process options for generating electricity from coal that could significantly reduce 

emissions from the facility.41 This decision on the part of WYDEQ flies in the face of the plain 

language of the Clean Air Act, the clear expressions of Congressional intent, and the rulings of 

the EAB. 

EPA has argued in other contexts that the concept of “redefining the source” may relieve it of 

certain obligations under the PSD program.42 In particular, in the Prairie State case before the 

EAB, EPA argued as a matter of statutory interpretation that the Clean Air Act did not 

contemplate that permitting authorities would require a permit applicant to consider building a 

source other than the one it had proposed. In that case, the issue involved whether a proposed 

Illinois coal-fired power plant, that was being planned in conjunction with a new coal mine, 

needed to consider (as an element of its BACT analysis) using coal that was lower in sulfur than 

the coal that the co-located mine would produce. EPA argued (as did Illinois EPA) that 

 stringent control alternative, unless the applicant can demonstrate that the alternative is not technically or 

economically achievable.”); In the Matter of Pennsauken County, New Jersey Resource Recovery Facility, PSD 

Appeal No. 88-8 (EAB November 10, 1988) (“Thus, the ‘top-down’ approach shifts the burden of proof to the 

applicant to justify why the proposed source is unable to apply the best technology available.”) 

40 The EAB has made clear that, regardless of the analytic process, if a control option is left out of the analysis because it 

is erroneously identified as not potentially available, the permit will be sent back on appeal. See In re Three Mountain 

Power, 10 E.A.D. 39, 50 (EAB 2001) (explaining that “proper BACT analysis requires consideration of all potentially 

‘available’ control technologies”). 41 In particular, the use of IGCC would allow the facility to produce electricity from coal with dramatically lower 

emission of NOx, SOx, CO, VOC, and PM. See, e.g., Permit Application for Nueces IGCC Plant (submitted to 

Texas Commission on Environmental Quality September 2006). 

42 See In re Prairie State Generating Co., PSD Appeal 05-05, 13 E.A.D. __ (Sept. 24, 2006). 
16

requiring the source to use coal other than that from the co-located mine would constitute an 

impermissible redefinition of the source. 

Ultimately, in a very narrow ruling, the Board in the Prairie State case held that the use of coal 

from the co-located mine was so integral to the very purpose and intent of the project that 

requiring the permit applicant to consider using some other source of coal instead would defeat 

the purpose of the original permit application. Accordingly, the Board ruled that the Illinois 

EPA did not “clearly err when it determined that consideration of low-sulfur coal, because it 

necessarily involves a fuel source other than the co-located mine, would require Prairie State to 

redefine the fundamental purpose or basic design of its proposed Facility, and that, therefore, 

low-sulfur coal could appropriately be rejected from further BACT analysis at step 1 of the topdown review method.” Prairie State at 36-37. 

Even assuming that the Board’s decision in Prairie State was consistent with the Clean Air Act, 

that decision clearly demonstrates that WYDEQ’s failure to require consideration of innovative 

combustion technologies as process options for controlling emission from the Dry Fork plant is 

fundamentally flawed. First, the EAB’s ruling recognized that the default assumption under the 

Clean Air Act’s PSD provisions is that the use of potentially cleaner fuels (such as low-sulfur 

coal) will normally be a required part of the BACT analysis.43 Only where some unique element 

of the facility’s basic purpose made the particular BACT-related consideration fundamentally 

incompatible with the permit application, did the EAB recognize that further analysis of that 

BACT-related consideration might be unnecessary.44 

In the end, even the Board’s decision in Prairie State reflects an understanding that the concept 

of redefining the source must be subordinate to the primary objectives of the BACT analysis. 

That is, the specific requirements inherent in the definition of BACT will define the obligations 

of permit applicants and permitting authorities, unless some specific fundamental conflict exists. 

Moreover, while the Board concluded that the permit issuer should look “in the first instance” at 

“how the permit applicant, in proposing the facility, defines the goals, objectives, purposes, or 

basic design for the proposed facility,” the permit applicant cannot manipulate the definition of 

the facility as a mechanism to avoid appropriate BACT analysis. Prairie State at 29-30. In 

evaluating the permit, the permit issuer must “discern which design elements are inherent to [the] 

purpose [of the facility], articulated for reasons independent of air quality permitting, and which 

design elements may be changed to achieve pollutant emissions reductions without disrupting the 

applicant’s basic business purpose for the proposed facility.” Id. at 30. 

 

43 Prairie State at 22 (“Petitioners correctly observe that . . . consideration of ‘clean fuels’ must be a part of the 

BACT analysis. Specifically, . . . the Agency must consider both the cleanliness of the fuel and the use of add-on 

pollution control devices.”). Indeed, numerous other PSD permits have identified the use of clean fuel (including 

low sulfur coal) as BACT for new major sources. See, e.g. In re AES Puerto Rico 8 E.A.D. 324 (EAB 1999); In re 

Encogen Cogeneration, 8 E.A.D. 244 (EAB 1999); In re Hawaiian Commercial & Sugar Co.y, PSD Appeal No. 92-

1 at 5, n.7 (EAB, July 20, 1992). 

44 In Prairie State the Board concluded that the mine and the coal-fired power plant were proposed together as a 

single source under the PSD provisions, and the mine was intended to supply the entirety of the power plant’s fuel 

throughout the plant’s entire operating life. Therefore, the EAB concluded, the plant and the mine were integral 

parts of a single proposal and the use of coal from another source would undermine the purpose of that proposal. If 

the mine were capable of supplying less than the full fuel needs of the power plant over its entire life cycle, for 

example, the Board’s analysis would likely have been different; the Board’s decision suggests that in such a case the 

consideration of low-sulfur supplemental fuel would have been required. 
17

Significantly, the Board specifically recognized that cost savings are not a valid purpose for a 

particular facility design; similarly, “the business objective of avoiding risk associated with new, 

innovative or transferable control technologies is not treated as a basic design element.” Prairie 

State at 30 n.23. Rather, cost and risk considerations are appropriately addressed during the later 

steps of the top-down BACT analysis. 

Basin Electric’s and WYDEQ’s positions on this issue are out of sync with both the Clean Air 

Act itself and with the EAB’s treatment of the concept of “redefining the source,” as well as 

Wyoming law. First, as discussed above, the Clean Air Act and Wyoming’s PSD regulations 

specifically calls for consideration of “the application of production processes and available 

methods, systems, and techniques, including fuel cleaning, clean fuels, or treatment or innovative 

fuel combustion techniques for control of each pollutant.” CAA § 169(3); Chapter 6, Section 4(i) 

of the WAQSR. This language, on its face, requires as a part of the BACT analysis the 

consideration of innovative technologies like IGCC that make the generation power from coal 

significantly cleaner.45 

Further, the two early decisions by the EPA Administrator that introduce the “redefining the 

source” policy, identify a policy that is much more limited than that put forth by Basin Electric. 

In In re Pennsauken County, New Jersey, Resource Recovery Facility the petitioner asked the 

EPA Administrator to deny a PSD permit to a municipal waste combustor and, instead, require 

the county to dispose of its waste by co-firing it with coal in existing power plants. See PSD 

Appeal No. 88-8 at 10 (Adm’r, Nov. 10, 1988). In effect, the petitioner wanted the EPA to order 

the applicant to engage in a different type of activity: electricity generation, rather than waste 

disposal. The Administrator rejected this option because the petitioner’s argument was based on 

his objection to a waste combustor generally, not to the conditions in the permit. Thus, the 

Administrator held, the petitioner was asking EPA to “redefine the source” from a waste 

combustor to a power plant.46 The Administrator subsequently reaffirmed the Pennsauken 

County decision and explained that “source,” within the newly created “redefining the source” 

policy, refers to a source category.

47

 

45 As discussed above, the legislative history of the Clean Air Act is equally as clear that the definition of BACT 

contemplates consideration of technologies like IGCC. 46 “Petitioner Filipczak’s fundamental objections to the Pennsauken permit are not with the control technology, but 

rather, with the municipal waste combustor itself. He urges rejection of the combustor in favor of co-firing a 

mixture of 20 percent refuse derived fuel and 80 percent coal at existing power plants. These objections are beyond 

the scope of this proceeding and therefore are not reviewable under 40 C.F.R. 124.19, which restricts review to 

“conditions” in the permit. Permit conditions are imposed for the purpose of ensuring that the proposed source of 

pollutant emissions-- here, a municipal waste combustor-- uses emission control systems that represent BACT, 

thereby reducing the emissions to the maximum degree possible. These control systems, as stated in the definition 

of BACT, may require application of “production processes and available methods, systems, and techniques, 

including fuel cleaning as treatment or innovative fuel combustion techniques” to control the emissions. The permit 

conditions that define these systems are imposed on the source as the applicant has defined it... [T]he source itself is 

not a condition of the permit.” Pennsauken County at 10-11 (emphasis added). 47 “In Pennsauken, the petitioner was urging EPA to reject the proposed source (a municipal waste combustor) in 

favor of using existing power plants to co-fire a mixture of 20 percent refuse derived fuel and 80 percent coal. In 

other words, the petitioner was seeking to substitute power plants (having as a fundamental purpose the generation 

of electricity) for a municipal waste combustor (having as a fundamental purpose the disposal of municipal waste).”

In re Hibbing Taconite Company, 2 E.A.D. 838, 843 at n. 12 (Adm’r 1989) (parentheticals original, emphasis 

added). 
18

After clarifying the “redefining the source” policy as only preventing a change in the 

“fundamental purpose,” i.e., the source category, the Administrator further explained that the 

“redefining the source” policy did not allow the permitting agency to blindly accept the source 

design proposed by the applicant. Hibbing, 2 EAD at 842-843. In Hibbing, the permit applicant 

wanted to burn petroleum coke at its taconite plant, but EPA required the applicant to consider 

burning natural gas – a lower polluting process and cleaner fuel – as part of a BACT 

determination. Id. The Administrator specifically rejected the idea that requiring consideration 

of cleaner fuel constitutes “redefining the source” because the fundamental purpose, or source 

category, remains the same.48

In other words, from its inception, prior to the 1990 Manual, the “redefining the source” policy 

has merely stood for the concept that EPA will not require an applicant to abandon its intended 

purpose for some other industrial venture. To the extent EPA’s subsequently-issued draft NSR 

Workshop Manual is inconsistent with prior Administrator interpretations in Pennsauken and 

Hibbing, which constitute the agency’s official position, the draft Manual is not entitled to any 

deference.49 

Because the Clean Air Act specifically calls for consideration of production processes and 

innovative fuel combustion techniques as means for reducing emissions from industrial sources 

regulated under the PSD program, even the Board’s analysis in Prairie State would require 

evaluation of IGCC as part of the BACT analysis, unless there were a specific, objectively 

discernable reason why doing so would be fundamentally at odds with the primary objective of 

the project, based on appropriate considerations not related to cost or the avoidance of risk.

50 

 

48 [O]ne argument that could be made is that the Region, by requiring the burning of natural gas to be an alternative 

to be considered in the BACT analysis [for a petroleum coke-fired plant], is seeking to "redefine the source." 

Traditionally, EPA has not required a PSD applicant to redefine the fundamental scope of its project... [The 

redefining the source] argument has no merit in this case. 

EPA regulations define major stationary sources by their product or purpose (e.g., "steel mill," "municipal 

incinerator," "taconite ore processing plant," etc.), not by fuel choice. Here, Hibbing will continue to manufacture 

the same product (i.e., taconite pellets) regardless of whether it burns natural gas or petroleum coke... The record 

here indicates that there are other taconite plants that burn natural gas, or a combination of natural gas and other 

fuels. Thus, it is reasonable for Hibbing to consider natural gas as an alternative in its BACT analysis. Id.

(parentheticals original, emphasis added).

49 In addition to simply being wrong, the NSR Manual’s application of the “redefining the source” policy is due no 

deference because it conflicts with the agency’s prior interpretations. See Pauley v. Beth-Energy Mines, 501 U.S. 

680, 698 (1991) (no deference to agency interpretations that are inconsistent with previously held view); see also 

Malcomb v. Island Creek Coal Co., 15 F.3d 364, 369 (4th Cir. 1994) (deference is not due to an agency interpretation 

of its own rules that is inconsistent); Brotherhood of Locomotive Engineers v. Atchison, Topeka Santa Fe R.R. Co., 

116 S.Ct. 595, 133 L.Ed.2d 535 (1996). Other Supreme Court precedent confirms that “Chevron deference” is not 

due to an agency’s interpreations of the statutes that it operates under when such interpretations are the product of 

informal processes such as adoption of manual provisions rather than formal processes such as notice and comment 

rulemaking. See United States v. Mead Corp., 120 S.Ct. 2164 (2001), Skidmore v. Swift & Co., 323 U.S. 134 1944). 

50 “The assertion, and finding, that the design is for reasons independent of air quality permitting must be reasonable 

and supported by the record.” Prairie State at 34 n.29. For Dry Fork, however, WYDEQ has failed to even make 

an evidence-based finding that IGCC is incompatible with the purpose of the project. This is both substantively 

inadequate and inadequate as a matter of public notice —it is arbitrary and capricious. 
19

For Dry Fork, WYDEQ has articulated no such rationale.51 As discussed above, this position is 

simply untenable as a matter of statutory interpretation. Moreover, it also runs counter to the 

EAB’s favorable consideration of Illinois EPA’s requirement for permit applicants to consider 

IGCC. 

In Prairie State, the Petitioners argued that the scope of EPA’s “redefining the source” policy 

lacked any “principled standards,” and would therefore allow permit applicants to define-away 

basic elements of the BACT analysis. See Prairie State at 33. The EAB rejected this argument, 

but in doing so relied specifically on Illinois EPA’s policy of requiring consideration of IGCC to 

demonstrate why the policy was not fatally overbroad.52 Id. 33-37. The Board noted that Illinois 

EPA “required Prairie State to submit a detailed analysis of [IGCC] as a method for controlling 

emissions from the proposed Facility.” Prairie State at 35.53 The Board explained, “IGCC is not 

simply an add-on emission control technology, but instead would have required a completely 

redesigned ‘power block.’ . . . [Illinois EPA’s] demand that Prairie State provide a detailed 

analysis of IGCC, which [Illinois EPA] noted has the promise to achieve greater [emissions] 

reductions, demonstrates that [Illinois EPA’s] application of the policy against redefining the 

design of the source through application of BACT did not treat “very few” design changes as 

consistent with the proposed Facility’s basic design. . . . To the contrary, [Illinois EPA’s] 

consideration of IGCC demonstrates that [it] gave due regard to Prairie State’s objective in 

submitting a permit application for the proposed Facility, namely development of an electric 

power generating plant that would be co-located and co-permitted with a 30-year supply of fuel, 

and then explored every potential add-on technology and potentially lower-emitting production 

processes or methods consistent with that basic design to determine the maximum emissions 

reductions achievable for the Facility.” Id at 35-36.54 

 

51 In addition to rendering this part of the BACT analysis inadequate, WYDEQ’s failure to specifically identify why 

IGCC was not evaluated in the BACT analysis has deprived commentors of WYDEQ’s essential rationale for a 

major part of its decision. Accordingly, WYDEQ must describe the basis for its determination and provide the 

public with an opportunity to comment on its rationale. 

52 If the EAB affirmed Illinois EPA’s authority to require consideration of IGCC, such consideration must be within 

the permitting authority’s discretion under the statutory definition of BACT, and therefore cannot be a fundamental 

“redefinition” of the source that is impermissible under the Clean Air Act. 53 The Board references a letter from Donald Sutton, Illinois EPA to Diana Tickner, Prairie State (March 29, 2003), 

that letter is incorporated by reference here. 

54 In its analysis, the Board specifically recognized that EPA guidance requires consideration of process-related 

technology advances like IGCC. Prairie State at 33 (“The NSR Manual also states with respect to production 

processes, that where ‘a given production process or emission unit can be made to be inherently less polluting’ ‘the 

ability of design considerations to make the process inherently less polluting must be considered as a control 

alternative for the source.’”). The Board went on to explain that “viewing the proposed facility’s basic design as 

something that generally should not be redefined through BACT review does not prevent the permit issuer from 

taking a ‘hard look’ at whether the proposed facility may be improved to reduce its pollutant emissions.” Id at 33-

34. By “hard look” it is clear that the Board means a real, substantive BACT examination that explains in detail the 

technological, engineering, process, and/or design factors that make a particular emission control option 

incompatible with the projects objectives. See Prairies State at 34 (citing Knauf, 8 E.A.D. 121, 127 (EAB 1999)). 

The Board explained that a permit issuer’s failure to take a sufficiently hard look at the design issues has “the 

potential to circumvent the purpose of BACT, which is to promote use of the best control technologies as widely as 

possible.” Prairie State at 34 (quoting Knauf, 8 E.A.D. at 140). Significantly, the EAB gave short shrift to EPA’s 

essentially meaningless “alternatives analysis” which would have relegated consideration of any process, technique 

or alternative approach to pollution control to an analysis separate and apart from the BACT determination. 

WYDEQ’s treatment of IGCC in the Dry Fork case is a perfect illustration of the danger that the EAB identified as 

inherent in the concept of a “redefining the source” exemption – WYDEQ has not taken a “hard look” at whether 
20

In contrast, for the Dry Fork facility, WYDEQ has completely abrogated its BACT-related 

responsibilities when it comes to identifying “every potential add-on technology and potentially 

lower-emitting production processes or methods consistent with that basic design to determine 

the maximum emissions reductions achievable.” 

While the Board ultimately concluded in Prairie State that IGCC was not required at the facility, 

that determination resulted from the Board’s conclusion that IGCC was essentially equivalent to 

the proposed boiler technology in terms of its potential emission control effectiveness. See 

Prairie State at 47. That conclusion was the unfortunate result of a poor record. As discussed at 

length below, it is very clear that IGCC is capable of achieving a level of emissions performance 

for virtually every regulated PSD pollutant that is significantly better than the performance of a 

PC boiler.55 Moreover, as discussed already, IGCC plants have a multitude of collateral 

environmental benefits: they provide opportunity for higher reductions in hazardous air 

pollutants like mercury, they produce less solid waste, they use less water, and they both emit 

less CO2 and provide the ability to capture CO2 emissions for permanent storage to help address 

global warming. Accordingly, the Board’s justification for rejecting IGCC in Prairie State was 

based on solely on the facts of that case, which as will be shown below are simply inapplicable 

to the Dry Fork plant.56

Indeed, EPA itself has publicly recognized IGCC as an “inherently low-polluting 

process/practice,”57 and has reaffirmed its view that IGCC is an available method for cleaning 

and treating coal to remove air pollutants prior to combustion: 

One approach to controlling SO2 emissions from steam generating units is 

to limit the maximum sulfur content in the fuel. This can be accomplished 

by burning... a fuel that has been pre-treated to remove sulfur from the 

fuel... There are two ways to pre-treat coal before combustion to lower 

 IGCC might be an appropriate consideration under the BACT analysis here, and WYDEQ’s decision in this regard 

threaten to “circumvent the purpose of BACT.” 

55 The PSD permit application for Nueces Syngas, LLC for example, includes emission limits for the IGCC turbines 

(in lb/MMBTU) of 0.018 for NOx, 0.017 for SO2, 0.037 for CO, 0.003 for VOC, 0.006 for PM and PM10, and 0.001 

for H2SO4. There are other recent permit applications in the record that also demonstrate the tremendous 

opportunities for emission reductions with IGCC. Moreover, this technology is now a viable and ready option for 

electric power production, as evidenced by among other things the 25 or so proposed IGCC plants around the 

country. See the Department of Energy’s document: Tracking New Coal-Fired Power Plants, available at: 

http://www.netl.doe.gov/coal/refshelf/ncp.pdf. 56 Moreover, to the extent that Basin Electric or WYDEQ is concerned about cost implications of IGCC, the 

technological availability or reliability of the technology, or other technological or economic considerations, the 

appropriate mechanism to address those concerns is the BACT top-down analysis – not through up-front exclusion 

of the technology from consideration. 

57 See, e.g., Robert J. Wayland, U.S. EPA Office of Air and Radiation, OAQPS, “U.S. EPA’s Clean Air 

Gasification Activities”, Presentation to the Gasification Technologies Council Winter Meeting, January 26, 2006, 

slide 4; and “U.S. EPA’s Clean Air Gasification Initiative”, Presentation at the Platts IGCC Symposium, June 2, 

2005, slide 11 (citing the “inherently lower emissions of nitrogen oxides, sulfur dioxides, and mercury,” as among 

the “fundamental advantages” of IGCC). Mr. Wayland also correctly notes that IGCC units use less water, and 

produce fewer global warming pollutants than conventional pulverized coal units, another point relevant to the 

statutory directive to “take into account environmental . . . impacts” in determining BACT limits. Wayland January 

26, 2005 Presentation, Slide 4; 42 U.S.C. § 7479(3). 
21

sulfur emissions: Physical coal cleaning and gasification... Coal 

gasification breaks coal apart into its chemical constituents (typically a 

mixture of carbon monoxide, hydrogen, and other gaseous compounds) 

prior to combustion. The product gas is then cleaned of contaminants 

prior to combustion. Gasification reduces SO2 emissions by over 99 

percent.58

As a result of fuel cleaning, IGCC units “will inherently have only trace SO2 emissions because 

over 99 percent of the sulfur associated with the coal is removed by the coal gasification 

process.” 70 Fed. Reg. at 9715. 59

Because the Clean Air Act and implementing regulations clearly require evaluation of 

technologies like IGCC which can achieve the statutory intent of reducing emissions through 

process changes, available methods and systems and techniques, innovative combustion 

techniques, and fuel cleaning, and because WYDEQ failed entirely to conduct an analysis of 

IGCC as a possible control option, the proposed Dry Fork permit is unlawful and the public has 

unlawfully been deprived of the opportunity to meaningfully engage with the agency on this 

issue. Therefore, the draft permit must be withdrawn, and WYDEQ must evaluate in detail the 

potential for applying IGCC and make its determination and its justification available for public 

comment. 

Recent State Actions Requiring Consideration of Cleaner Coal Technology Establish Irrefutable 

Precedence for the Consideration of IGCC.

In recent PSD permitting actions implementing the Federal PSD permitting program (either 

through a direct delegation from EPA or via approval of equivalent state rules in a state 

implementation plan (SIP)), several states have required consideration of IGCC in the BACT 

review process for new coal-fired power plants. These state decisions implementing the federal 

PSD program validate the plain language of the definition of BACT described above. 

Specifically, in March 2003, the State of Illinois required the applicant for a proposed circulating 

fluidized bed (CFB) coal-fired electric generation facility to conduct a robust analysis of IGCC 

as a core element of its BACT analysis: 

Additional material must be provided in the BACT demonstration to address Integrated 

Gasification Coal Combustion (IGCC) as it is a `production process’ that can be used to 

produce electricity from coal. In this regard, the Illinois EPA has determined that IGCC 

qualifies as an alternative emission control technique that must be addressed in the BACT 

demonstration for the proposed plant. In addition, based on the various demonstration 

 

58 U.S. EPA, Standards of Performance for Electric Utility Steam Generating Units for Which Construction is 

Commenced After September 18, 1978, 70 Fed. Reg. 9706, 9710-11 (February 28, 2005). 

59 Indeed, IGCC is a prime example of “fuel cleaning” (which also is a required BACT consideration under the Act) 

– involving the pre-combustion transformation of otherwise dirty coal into a fuel (syngas) that can be more cleanly 

burned in a combined-cycle power block. 
22

projects that have been completed for IGCC, the Illinois EPA believes that IGCC 

constitutes a technically feasible production process. 

Accordingly, Indeck must provide detailed information addressing the emission 

performance levels of IGCC, in terms of expected emissions rates and possible emission 

reductions, and the economic, environmental and/or energy impacts that would 

accompany application of IGCC to the proposed plant. This information must be 

accompanied by copies of relevant documents that are the basis of or otherwise 

substantiate the facts, statements and representations about IGCC provided by Indeck. In 

this regard, Indeck as the permit applicant is generally under an obligation to undertake a 

significant effort to provide data and analysis in its application to support the 

determination of BACT for the proposed plant.60 

In an ensuing letter, the State of Illinois then formally informed EPA that Illinois has “concluded 

that it is appropriate for applicants for [proposed coal-fired power plants] to consider IGCC as 

part of their BACT demonstrations.”61

Similarly, the Georgia Department of Natural Resources, in a March 2002 letter regarding the 

permit application of Longleaf Energy Station, also relied, in part, on the failure of the permit 

applicant to consider cleaner coal combustion technology in finding the application deficient. In 

making its determination of deficiency, Georgia stated that the applicant did not “discuss any 

other methods from generating electricity from the combustion of coal, such as pressurized 

fluidized bed combustion or integrated gasification combined cycle.” 62 Georgia further stated 

that the applicant “should discuss these technologies and explain why you elected to propose a 

pulverized coal-fired steam electric power plant instead.”63 

Reflecting the viability of IGCC, even at high altitudes, the State of New Mexico issued a letter 

on December 23, 2002 requiring the permit applicant for a new coal-fired power plant to conduct 

a site-specific analysis of IGCC as well as CFB as part of the BACT analysis for the proposed 

facility: “The Department requires a site-specific analysis of IGCC and CFB in order to make a 

determination regarding BACT for the proposed facility.” The New Mexico determination goes 

on to provide: “The analysis must include a discussion of the technical feasibility and availability 

of IGCC and CFB for the proposed site in McKinley County, including a discussion of existing 

IGCC and CFB systems.”64 

On August 29, 2003, New Mexico issued its evaluation of the applicant’s response. New 

Mexico found that the applicant’s BACT analysis had in fact indicated that IGCC is 

commercially available but that the applicant had improperly relied on cost to find that the 

technology was infeasible: 

 

60 Letter from Illinois Division of Air Pollution Control to Jim Schneider, Indeck-Elwood, LLC (March 8, 2003), 

Attachment 3 . 

61 Letter from Illinois EPA Director to EPA Regional Administrator, Region V (March 19, 2003), Attachment 4. 

62 Letter from James A. Capp, Manager, Stationary Source Permitting Program, Georgia DNR, to D. Blake 

Wheatley, Assistant Vice President, Longleaf Energy Associates, LLC (March 6, 2002). Attachment 5. 63 Id.

64 Letter from New Mexico Environment Department to Larry Messinger, Mustang Energy Corporation (Dec. 23, 

2002). Attachment 6. 
23

Mustang concludes that neither IGCC nor CFB are technically feasible control options 

for the Mustang site. After careful review of the revised BACT analysis, as well as 

information gathered from independent sources, the Department determines that 

Mustang’s conclusion is not supported by the evidence. Accordingly, the Department 

finds that Mustang has not demonstrated the technical infeasibility of IGCC and CFB. 

Moreover, applying the criteria in the NSR Manual, the Department determines that 

IGCC and CFB are technically feasible at the Mustang site, and must be evaluated in the 

remaining steps of the top down BACT methodology. 

(a) IGCC and CFB are technically feasible at the Mustang site. A technology is 

considered to be technically feasible if it is commercially available and 

applicable to the source under consideration. See NSR Manual at B.17-18. 

A technology is commercially available if it has reached a licensing and 

commercial sales stage of development. Id. A technology is applicable if it 

has been specified in a permit for the same or a similar source type. Id. 

Mustang’s revised BACT analysis indicates that IGCC is commercially 

available, and IGCC has been specified in air quality permits for coal-fired 

power plants. See, e.g., Lima Energy Facility, 580 megawatt coal-fired power 

plant. Similarly, CFB is commercially available and has been specified in air 

quality permits for coal-fired power plants. See, e.g., AES Puerto Rico 454 

megawatt coal-fired power plant; Reliant Energy Seward 584 megawatt coalfired power plant. 

(b) For both IGCC and CFB, Mustang improperly relies on cost to determine 

technical infeasibility. A technology is technically feasible when the 

resolution of technical difficulties is a matter of cost. See NSR Manual at 

B.19-20. Mustang’s revised BACT analysis indicates that the resolution of 

technical difficulties for both IGCC and CFB are a matter of cost. These costs 

do not support a finding of technical infeasibility, but may be considered 

during Step 4 of the top down BACT methodology. See NSR Manual at 

B.26.65

In addition, the Montana Board of Environmental Review found that the Montana Department of 

Environmental Quality must consider IGCC as an available technology in the BACT review for a 

coal-fired power plant. Specifically, the Board of Environmental Review stated “. . .the 

Department should require applicants to consider innovative fuel combustion techniques in their 

BACT analysis and the Department should evaluate such techniques in its BACT determination 

in accordance with the top-down five-step method.”66 Again, much of Montana is at relatively 

high elevations. 

 

65 Letter from New Mexico Environment Department to Larry Messinger, Mustang Energy Company (Aug. 29, 

2003), at p. 3, Attachment 7. 

66 Montana Board of Environmental Review, Findings of Fact, Conclusions of Law, and Order In the Matter of the 

Air Quality Permit for the Roundup Power Project (Permit No, 3182-00), Case No. 2003-04 AQ (June 23, 2003) at 

18-19. See Attachment 8 for a copy of this finding. 
24

It is important to note that, while some of these states were operating under SIP-approved PSD 

programs, the definition of BACT that applied in all cases is virtually identical to the federal 

definition of BACT (as is Wyoming’s) with respect to consideration of inherently lower emitting 

processes. It is noteworthy that these states determined it was entirely appropriate, indeed 

necessary, to require consideration of IGCC in the BACT review for a coal-fired power plant. 

The aforementioned state determinations are attached hereto. 
25

EPA Region 8 Has Also Determined It Was Appropriate to Evaluate IGCC in the BACT 

Analysis for a Coal-Fired Power Plant

Further, EPA Region 8 submitted comments to the Utah Division of Air Quality in an April 6, 

2004 letter on Utah’s proposed permit for NEVCO Energy’s Sevier Power Company Project in 

which EPA requested that further documentation on costs be provided to support Utah’s claim 

that IGCC was too costly.67 EPA did not indicate that IGCC didn’t need to be considered as an 

alternative for the proposed Sevier CFB boiler. Instead, EPA stated “It is our understanding that 

IGCC is a potentially lower polluting process than Circulating Fluidized Bed combustion.” 

EPA’s comments requesting more documentation of the costs of IGCC provide strong indication 

that EPA found it appropriate to consider IGCC in the BACT analysis. 

Thus, for all of the reasons described above, WYDEQ erred in failing to fully evaluate IGCC for 

Dry Fork in a top-down BACT review. Below we have provided an analysis of IGCC in a topdown BACT review and the results indicated that IGCC is the top technology. 

5. IGCC IS AN AVAILABLE CLEAN COAL COMBUSTION TECHNOLOGY THAT 

MUST BE EVALUATED AS PART OF THE BACT ANALYSIS FOR DRY FORK 

IGCC is an available, demonstrated clean coal combustion technology with significant emission 

reduction benefits. There are numerous benefits to IGCC, including fewer emissions of criteria 

and hazardous air pollutants, the opportunity for capturing greenhouse gases, such as CO2, that 

cause global warming, and a general increase in efficiency over other coal burning technologies. 

However, the permit application for Dry Fork does not evaluate coal technology and instead 

focused solely on the construction of PC coal combustion. Because Basin Electric did not fully 

consider IGCC in its BACT analysis, WYDEQ must direct the applicant to thoroughly evaluate 

these advanced combustion options as part of the BACT analysis for Dry Fork for all of the 

reasons discussed above. The definitions of BACT under Wyoming and federal law, and the 

core requirements of the BACT analysis under federal case law, EPA adjudicatory decisions, and 

the NSR Workshop Manual, demonstrate that an available technique such as IGCC must be 

identified and evaluated as a control option in the first step of the BACT analysis. These are 

minimum core requirements of a state-administered PSD program. 

Electricity generation from coal using IGCC technology is a commercially available and proven 

process. IGCC units generate electricity by integrating a coal gasifier with combined cycle 

(combustion turbine and steam turbine) electricity generation equipment (see figure below). 

 

67 April 6, 2004 letter from Richard R. Long, EPA, to Rick Sprott, Utah Division of Air Quality, at 1 (Attachment 

9). 
26

Information about IGCC is Readily Available and WYDEQ is Obligated to Meaningfully 

Examine Such Information for Dry Fork’s Permit

Gasification is not a new technology, but rather one that has been around for at least a hundred 

years. Detailed information about the gasification process and IGCC is readily available to the 

utility industry and regulatory decision-makers, including EPA and WYDEQ. For example, the 

Gasification Technologies Council (GTC) (which “was created in 1995 to promote a better 

understanding of the role Gasification can play in providing the power, chemical and refining 

industries with economically competitive technology options to produce electricity, fuels and 

chemicals in an environmentally superior manner”) maintains a website with copious 

information about gasification, IGCC, specific IGCC technologies, vendor products, and existing 

IGCC projects. See http://www.gasification.org/.

68 

Among other things, the GTC accurately explains that “Gasification offers the cleanest, most 

efficient method available to produce synthesis gas from low or negative-value carbon-based 

feedstocks such as coal, petroleum coke, high sulfur fuel oil or materials that would otherwise be 

disposed as waste. The gas can be used in place of natural gas to generate electricity, or as a 

basic raw material to produce chemicals and liquid fuels.” A prime source of information is 

available on the GTC website including papers and presentations compiled into an on-line library 

 

68 The Department of Energy also has a website dedicated to gasification: 

http://www.netl.doe.gov/technologies/coalpower/gasification/database/database.html. 
27

that can function as an important resource for both utilities and regulators. See

http://www.gasification.org/library.htm. Among the important resources on this website is 

information about gasification generally, IGCC, and use of IGCC with low-rank coals;69

information about the readiness of IGCC technology and the appropriateness of requiring 

examination of IGCC as a part of the BACT analysis;70 information about polygeneration and 

capture of global warming gases from gasification plants;71 and information about IGCC projects 

currently in the works.72 Indeed, the GTC’s 2006 annual conference last summer generated 

literally dozens of papers and presentations about gasification and IGCC technology.73

In the face of the remarkable wealth of available information, WYDEQ has made the clearly 

arbitrary decision to ignore IGCC entirely as a possible option for the proposed Dry Fork facility. 

Even a cursory examination would demonstrate that IGCC is a technology that has arrived and 

that is available now as an option for utilities planning new coal-based power plant projects,74

and that information regarding the technology is readily available to appropriately inform the 

top-down BACT decisionmaking process.75 Moreover, it is clear that EPA is aware that IGCC is 

a technology that is rapidly becoming a market force in the utility industry – for example, in July 

2006 EPA issued a report entitled Environmental Footprints and Costs of Coal-Based Integrated 

Gasification Combined Cycle and Pulverized Coal Technologies,76 which examined various 

aspects of IGCC.77 Given the wealth of available information, the fact that WYDEQ has failed 

utterly to examine the possibility of employing IGCC as a technology option for the proposed 

Dry Fork plant is demonstrably at odds with its statutory responsibilities.78 

 

69 http://www.gasification.org/Docs/Bismarck%2006/02Amick.pdf; 

http://www.gasification.org/Docs/Bismarck%2006/01Phillips.pdf. 70 http://www.gasification.org/Docs/Tampa%2006/Ely.pdf. 71 http://www.gasification.org/Docs/Bismarck%2006/03RJones.pdf; 

http://www.gasification.org/Docs/Bismarck%2006/05pan.pdf. 72 http://www.gasification.org/Docs/Bismarck%2006/07Smet.pdf; 73 http://www.gasification.org/Presentations/2006.htm. Additional technical information about IGCC and carbon 

capture and storage is available from U.S government websites, environmental organizations, and organizations like 

the World Energy Council (see http://www.worldenergy.org/wec-geis/focus/ccs/; 

http://www.fe.doe.gov/sequestration/index.html; http://www.pewclimate.org/). The fifth annual conference on 

carbon capture and sequestration was held this past May just outside Washington, D.C. (see 

http://www.carbonsq.com/). 74 Even the utility industry is beginning to acknowledge the all-too-obvious fact that the time for IGCC has come 

and that the nation must begin to seriously address its carbon future. See: 

http://www.cleanenergypartnership.org/news/article_detail.cfm?id=231. Sadly, when it come to carbon emissions, 

global warming, and advance coal technologies, even the utility industry, it appears, is out in front of EPA. 75 In addition to the tremendous amount of activity directed at refining the technology, making it cheaper, more 

reliable, and more commercially attractive, the fact that there are now more than 25 proposals for IGCC plants 

nationwide make it clear that it is an option that is technologically available. See 

http://www.netl.doe.gov/coal/refshelf/ncp.pdf. 76 See http://www.gasification.org/Docs/News/2006/EPA%20-%20IGCC%20cf%20PC.pdf. 77 This report however, by its own terms, was a snapshot in time of the state of IGCC, based on 2004 information – 

information that is now badly out of date (especially given the rapid advances being made in this dynamic field). 

Even from a PSD perspective, a two-year-old analysis is inadequate (PSD permits expire after eighteen months 

precisely because the information upon which they are predicated is expected to become stale as processes and 

control technologies become more effective at reducing pollutant emissions). 78 Other information that WYDEQ should consider in its examination of IGCC for Dry Fork includes among other 

things: 
28

Producing Electricity with an IGCC Facility with Add-On Pollution Controls is Inherently Less 

Polluting than Producing Electricity with a Pulverized Coal Facility

The coal gasification fuel-processing step in IGCC power plants results in superior 

environmental performance and lower emissions compared to the PC technology that is proposed 

for the Dry Fork power plant. Gasifying coal at high pressure prior to combustion facilitates 

removal of pollutants that would otherwise be released into the air. According to James 

Childress, “...criteria pollutant emissions for a coal-based IGCC plant are well below those of 

even the most modern pulverized coal plants with post combustion cleanup.”79 Mercury removal 

rates of greater than 94 percent can also be achieved using currently available control 

technologies with IGCC.80 DOE states that “an IGCC power plant has the potential of achieving 

very high mercury removal performance with established technology” and mercury removal in 

an IGCC power plant can be expected to be very high in removal effectiveness, low in cost, and 

reliable in design.”81 

Table 1 summarizes the Dry Fork proposed permit emission rates with permit emission rates for 

an IGCC plant using the design fuel for Dry Fork. For each of the important pollutants in the 

BACT analysis, IGCC is the top ranked technology or is equivalent to the proposed Dry Fork 

emission limits. 

 http://www.ciel.org/Publications/CO2_Foote_11May04.pdf (article by Greg Foote, former EPA Assistant General 

Council); http://www.synapse-energy.com/Downloads/SynapsePaper.2006-06.Climate-Change-and-Power.pdf

(report by Synapse Energy Economics); http://www.grida.no/climate/ipcc_tar/wg2/index.htm (Climate Change 2001 

Report); http://www.synapse-energy.com/Downloads/SynapseReport.2006-02.SCE.Mohave-AlternativeGeneration-Resources.05-020.pdf (Synapse Mojave Report); http://www.epa.gov/climatechange/ (information 

available on EPA’s own climate web site); http://www.publicaffairs.noaa.gov/pdf/economic-statistics-may2006.pdf

(NOAA economic statistics); http://www.wvecouncil.org/issues/gambling_with_coal.pdf (Union of Concerned 

Scientists Report); STERN REVIEW ON THE ECONOMICS OF CLIMATE CHANGE, available at: http://www.hmtreasury.gov.uk/Independent_Reviews/stern_review_economics_climate_change/sternreview_index.cfm. 79 Childress, James M. Statement Submitted for the Record, Senate Environment and Public Works Subcommittee 

on Clean Air, Wetlands and Climate Change, January 29, 2002. 

80 See, e.g., http://seca.doe.gov/technologies/coalpower/gasification/pubs/pdf/Coal%20Gasification%20Report%20-

%20Chapters.pdf; http://dha.state.wi.us/home/Decisions/DNR/2005/ih0403.pdf; and 

http://www.netl.doe.gov/technologies/coalpower/gasification/pubs/pdf/MercuryRemoval%20Final.pdf. 81 “The Cost of Mercury Removal in an IGCC Plant,” US DOE, NETL, September 2002 at 1-2, Attachment 10. 
29

Table 1: Comparison of Emission Rates for Dry Fork to a Recently Proposed Permit for an

IGCC Plant

 

Dry Fork Station PC Proposed 

Emission Rates 

Christian County Generation IGCC 

Emission Rates* 

 (lb/MMBtu) (lb/MMBtu) 

NOx 0.05 (12 month rolling) 0.0246 (24-hour average)

VOC 

0.0037 (limit not in draft 

permit82) 0.006

PM10 0.012 (filterable) 0.0063

CO 0.15 0.036

Sulfuric Acid Mist SO2 limit is surrogate for BACT 0.0026

SO2 0.08 (12 month rolling) 0.0117 (3-hour average) 

Hg 0.000010283 0.000001984

* All IGCC emission rates for the BACT analysis are based on the November 26, 2007 proposed 

permit to Christian County Generation for an IGCC facility to be located in Taylorville, Illinois 

with the exception of the mercury emission rate. As discussed in footnote 84, the mercury 

emission rate is from the Christian County Generation permit application for the Taylorville 

IGCC facility. A copy of the proposed permit is included as Attachment 11 to this letter. The 

limits in the proposed permit are in terms of heat input of the syngas. We converted those limits 

to be in terms of heat input to the coal for a direct comparison to the proposed Dry Fork emission 

limits in this table. 

For the limits found in Table 1 under baseload conditions, IGCC would yield significantly lower 

amounts of NOx, SO2, PM10, CO, and mercury, as well as significantly lower amounts of the 

climate changing emissions of CO2. As previously stated, IGCC facilities are typically more 

efficient than pulverized coal-fired boilers, thus producing less CO2 compared to a PC boiler 

producing the same amount of electricity.85 Furthermore, IGCC allows for an option to make 

even deeper cuts in carbon dioxide that conventional coal plants cannot do. The CO2 in the 

syngas can be captured and sequestered at a fraction of the cost of post-combustion carbon 

capture and sequestration at other coal plants. 

 

82 The WYDEQ Permit Application Analysis provides this limit as reflecting BACT, but the proposed permit does 

not include any limit for VOCs. See WYDEQ Permit Application Analysis at 14, 47. 

83 This mercury emission rate was calculated from the proposed mercury emission limit of 97 x 10-6 lb/MWh, 

assuming an efficiency of the plant of 36 percent which is the efficiency assumed by EPA in its 2005 updates to the 

New Source Performance Standards for electric utility steam generating units (70 Fed.Reg. 9714 (2/28/05)). It must 

be noted that the proposed permit also includes a mercury reduction optimization study with a target mercury 

emission rate of 20 x 10-6 lb/MWh, which is equivalent to 0.0000021 lb/MMBtu (assuming 36 percent efficiency). 84 This is the mercury emission rate provided in the Christian County Generation permit application for the 

Taylorville IGCC facility. The facility will be equipped with a mercury removal system (see page 4 of the proposed 

permit (Attachment 11 to this letter). The Illinois EPA has only included the mercury limit of the New Source 

Performance Standards in the proposed permit, i.e., 20 x 10-6 lb/MWh. 85 EPA’s Final Report entitled “Environmental Footprints and Costs of Coal-Based Integrated Gasification 

Combined Cycle and Pulverized Coal Technologies,” at ES-7. Attachment 13. 
30

The waste leaving an IGCC plant is vitrified, thereby potentially reducing some of the solid 

waste disposal issues associated with coal combustion. Indeed, IGCC plants produce 30 to 50 

percent less solid waste than PC plants.86 As discussed in great detail above, WYDEQ has a 

duty under federal and state law to consider the environmental impacts of the solid waste 

associated with different technology options. 

IGCC is clearly an available method, system and technique for producing electricity from coal 

and thus must be fully and fairly evaluated in the Dry Fork BACT analysis. Basin Electric and/or 

WYDEQ must develop average and incremental costs for each pollutant removed and compare 

these costs to the proposed configuration of the Dry Fork facility. 

6. WYDEQ AND BASIN ELECTRIC FAILED TO EVALUATE A SUPERCRITICAL 

BOILER IN THE DRY FORK BACT ANALYSIS 

WYDEQ and Basin Electric should have also considered the construction of a supercritical or 

ultra supercritical PC boiler in the BACT analysis for Dry Fork.87 Supercritical boilers are more 

efficient than subcritical boilers, burning 7 percent to 17 percent less coal to produce the same 

amount of electricity88. Thus, supercritical boilers emit less carbon dioxide emissions than 

conventional subcritical PC boilers to produce the same amount of electricity. Further, such 

supercritical boilers achieve up to 17 percent lower emission rates of carbon monoxide (CO), 

nitrogen oxides (NOx) and sulfur oxides (SOx), as well as up to 15 percent lower PM emission 

rates per unit of electricity produced.89 This means lower overall hourly and annual rates of 

emissions of NOx, SO2 and other pollutants to the air. Such boilers also use less water and 

produce less waste than subcritical boilers.90 Many recently proposed or permitted power plants 

will be using more efficient supercritical boilers, including the proposed Desert Rock power 

plant to be located in New Mexico, the proposed Unit 3 at the Intermountain Power Plant to be 

located in Utah (whose owners recently decided to switch from an originally planned subcritical 

boiler to a supercritical boiler), the White Pine and Nevada Power power plants both to be 

located in Nevada, the Toquop power plant to be located on the Toquop Indian Reservation, Unit 

4 of the Council Bluffs Energy Center in Iowa, and Unit 3 of the Comanche power plant in 

Colorado. Many of these facilities will be utilizing Powder River Basin subbituminous coal. As 

stated by the owners of the proposed Unit 3 of the Intermountain Power Plant, supercritical 

boilers are “more efficient and better for the environment [and] reflects the latest engineering and 

market developments for [pulverized coal] facilities. . . .”91

 

86 Major Environmental Aspects of Gasification-Based Power Generation Technologies, US DOE, December 2002, 

Table 1-7, Page 1-28, Attachment 12. 

87 The permit application for Dry Fork appears to be silent on whether the facility is planned to have a subcritical or 

supercritical boiler, but a review of the unit net heat rate provided in Appendix B of the Dry Fork permit application 

(10,077 Btu/ne kWh at 100 percent load) indicates that the boiler would be a subcritical boiler. 88 Calculated from fuel requirement data provided in Table ES-1 of EPA’s Final Report entitled “Environmental 

Footprints and Costs of Coal-Based Integrated Gasification Combined Cycle and Pulverized Coal Technologies,” at 

ES-7. Attachment 13. 

89 See attached presentation by Tom Bartolomei, ALSTOM, Sliding Pressure Supercritical Boilers: Flexible and 

Efficient Technology for New Coal-Fired Generation, presented at COAL-GEN, August 1, 2002. Attachment 14. . 

90 EPA’s Final Report entitled “Environmental Footprints and Costs of Coal-Based Integrated Gasification 

Combined Cycle and Pulverized Coal Technologies,” at ES-8. Attachment 13. 

91 August 4, 2006 letter from Utah Associated Municipal Power Systems to Utah Division of Air Quality at 1. 
31

Thus, the Dry Fork BACT analysis is significantly flawed without evaluating supercritical boiler 

technology for the Dry Fork power plant. WYDEQ and Basin Electric must evaluate the 

installation of both a supercritical and an ultra supercritical boiler at Dry Fork as inherently 

lower emitting processes and a more environmentally beneficial technologies, with lower hourly 

and annual emissions of all pollutants including CO2 for the same amount of electricity 

produced. 

7. WYDEQ’S PROPOSED BACT LIMITS FOR THE PROPOSED PULVERIZED COAL 

BOILER AT THE DRY FORK FACILITY ARE FLAWED. 

WYDEQ’s proposed BACT limits for the proposed PC boiler at the Dry Fork facility are flawed 

for numerous reasons, including that the averaging times of the proposed limits aren’t consistent 

with the averaging times of the NAAQS and other PSD standards, WYDEQ has not proposed 

BACT limits on all regulated pollutants, and that the proposed limits fail to reflect the maximum 

degree of emission reduction that is achievable as required by the definition of BACT in the 

WAQSR (Chapter 6, Section 4(i)). Our detailed comments are as follows: 

a. The Proposed BACT Emission Limits for Dry Fork Must Have Averaging Times 

Consistent with the NAAQS and Other PSD Standards 

WYDEQ has proposed the following emission limits as reflective of BACT for the proposed PC 

boiler at the Dry Fork facility: 

Pollutant WYDEQ’s Proposed BACT Limit 

NOx 0.05 lb/MMBtu (annual average) 

190.1 lb/hr (30 day average) 

SO2 0.08 lb/MMBtu (annual average) 

304.1 lb/hr (30 day average) 

PM/PM10

(filterable) 

0.012 lb/MMBtu (no averaging time indicated) 

CO 0.15 lb/MMBtu (no averaging time indicated) 

EPA’s NSR Workshop Manual and other policy clearly state that the BACT emission limits must 

demonstrate compliance with the NAAQS and other PSD standards and, as such, must 

appropriate averaging times consistent with those standards. See EPA’s NSR Workshop 

Manual, October 1990 Draft, at B.56. See also November 24, 1986 EPA memo with subject 

“Need for Short-term Best Available Control Technology (BACT) Analysis for the Proposed 

William A. Zimmer Power Plant,” Attachment 15. 

Further, emission limits reflective of BACT are to be met on a continuous basis. Specifically, 

Section 302(k) of the Clean Air Act expressly defines the term “emission limitation” as a 

limitation on emissions of air pollutants “on a continuous basis.” Section 169(3) of the Clean 

Air Act, in turn, defines BACT as an “emission limitation.” Accordingly, the Clean Air Act 

mandates that BACT continuously limit emissions of air pollutants. BACT emission limits over 

annual averaging times or over 30 day averaging times do not effectively ensure that the control 

technology will be used to limit emissions of air pollutants to the maximum extent achievable on 
32

a continuous basis. Such long averaging times will allow Basin Electric to operate the Dry Fork 

facility at uncontrolled emission rates for some periods and still comply with the proposed 

annual average or 30 day average emission limits. 

Accordingly, WYDEQ must impose BACT limits with averaging times equal to or shorter than 

the most stringent averaging time of the NAAQS or PSD standards for each pollutant. Thus, this 

means the SO2 BACT limit must be based on a 3-hour averaging time, the PM10 limit must be 

based on a 24-hour averaging time, and the CO limit must be based on an 8-hour averaging time. 

Further, in assessing compliance with visibility protection requirements in Class I areas, 

visibility impacts are assessed over a 24-hour averaging period. Accordingly, the BACT 

emission limits for all pollutants modeled in the Class I area visibility modeling assessment must 

reflect a 24-hour averaging period or less. This would pertain to the BACT limits for NOx, SO2, 

and PM10. 

As demonstrated below in our specific comments on WYDEQ’s proposed BACT limit for each 

pollutant, there are numerous examples of BACT limits for recently issued or proposed coalfired power plant permits that are consistent with the policy described above. WYDEQ has no 

legal justification for setting BACT limits with annual or 30-day averaging times. Thus, 

WYDEQ must set BACT limits for Dry Fork with averaging times consistent with the shortest 

averaging period of the NAAQS and PSD standards applicable to each pollutant that is subject to 

BACT. 

b. The Proposed NOx BACT Limit Does Not Reflect the Maximum Degree of Reduction 

that Can Be Achieved at a Pulverized Coal-Fired Boiler 

As previously cited, the WAQSR define “BACT” as follows: 

an emission limitation (including a visible emission standard) based on the 

maximum degree of reduction of each pollutant subject to regulation under these 

Standards and Regulations or regulation under the Federal Clean Air Act, which 

would be emitted from or which results for any proposed major stationary source 

or major modification which the Administrator, on a case-by-case basis, taking 

into account energy, environmental, and economic impacts and other costs, 

determines is achievable for such source or modification through application or 

production processes and available methods, systems, and techniques, including 

fuel cleaning or treatment or innovative fuel combustion techniques for control of 

such pollutant. 

Chapter 6, Section 4(i) of WAQSR [emphasis added]. 

The WYDEQ’s proposed NOx BACT limits do not reflect the maximum degree of 

reduction in NOx emissions achievable at the proposed PC boiler at the Dry Fork facility. 

WYDEQ stated that Basin Electric has proposed the top control technologies of low NOx

burners with overfire air and selective catalytic reduction (SCR) to control NOx. 
33

WYDEQ Permit Application Analysis, NSR –AP-3546, February 5, 2007, at 5. Then 

WYDEQ apparently evaluated entries in the EPA’s RACT/BACT/LAER Clearinghouse 

and evaluated actual emissions data from several Texas coal-fired electrical generating 

units to determine emission rates reflective of NOx BACT for Dry Fork. Consideration 

of this type of data is extremely important in a BACT determination, but WYDEQ should 

have also gathered and considered other available data on pollution reduction capabilities 

from control technology vendors, consultants, and technical journals and reports. See 

NSR Workshop Manual, October 1990 Draft, at B.11. 

First, Basin Electric indicated that the outlet NOx emission rate expected from the Dry 

Fork boiler would be 0.20 to 0.25 lb/MMBtu. November 10, 2005 Application for Permit 

to Construct Dry Fork Station Project at 2-8. However, technical papers and vendor 

information indicate that much lower NOx emission rates can be achieved with current 

state-of-the-art low NOx burners and overfire air. For example, available vendor 

information for ultra low NOx burners with overfire air indicates that boiler outlet NOx

emission rates of 0.17 lb/MMBtu or lower can be met at boilers burning subbituminous 

coal from the Powder River Basin.92 Another study conducted by Babcock & Wilcox at 

tangentially-fired units burning subbituminous Powder River Basin coal showed NOx

emission rates with ultra low NOx burners and overfire air that were generally less than 

0.13 lb/MMBtu.93 Basin Electric has indicated that the planned PC boiler at Dry Fork 

will be either tangentially-fired or wall-fired. See November 10, 2005 Application for 

Permit to Construct Dry Fork Station Project at 2-5. Even with a wall-fired boiler 

burning subbituminous coal, similar low NOx emission rates have been met with current 

state-of-the-art low NOx burners and overfire air. For example, a study conducted at a 

600 MW wall-fired subbituminous coal burning boiler found that NOx emission rates of 

0.15 lb/MMBtu or lower (as low as 0.138 lb/MMBtu) were achieved with Low NOx Dual 

Air Zone CCV® Burners and overfire air.94 

Further, neither Basin Electric nor WYDEQ evaluated the maximum degree of NOx reduction 

that can be achieved with SCR at Dry Fork. Assuming Basin Electric’s claim of NOx emission 

rates exiting the boiler of 0.20-0.25 lb/MMBtu (which we think is too high, as discussed above), 

the NOx BACT emission limit proposed by Basin Electric of 0.07 lb/MMBtu only reflects a 65 

percent to 72 percent reduction in NOx emissions from the SCR. WYDEQ requested that an 

emission limit of 0.05 lb/MMBtu be evaluated (WYDEQ Permit Application Analysis, NSR –

AP-3546, February 5, 2007, at 5), but this only reflects 80 percent control from the SCR. If the 

NOx emission rates exiting the boiler are 0.15 lb/MMBtu or lower, which is most likely if current 

state-of-the-art low NOx burners are used, then a NOx BACT limit of 0.05 lb/MMBtu only 

reflects a 67 percent NOx reduction from the SCR. Yet, SCR systems can reduce NOx emissions 

by 90 percent or more. According to Babcock & Wilcox, commercial SCR installations have 

 

92 See Bryk, S.A. et al., First Commercial Application of DRB-4ZTM Ultra-Low NOx Coal-Fired Burner, presented 

to POWER-GEN International 2000, November 14-16, 2000, Orlando, FL. Attachment 16. 

93 See Whitfield, T. et al., Comparison of NOx Emission Reductions with PRB and Bituminous Coals in 900 MW 

Tangentially-Fired Boilers, presented to EPRI-DOE-EPA-AWMA Combined Power Plant Air Pollutant Control 

Mega Symposium, May 19-22, 2003, Washington, D.C. at 8. Attachment 17. 

94 See Penterson, Craig A., Reducing NOx Emissions to Below 0.15 lb/106

 Btu on a 600 MW Utility Boiler with 

Combustion Control Only, presented to EPRI-DOE-EPA-AWMA Combined Power Plant Air Pollutant Control 

Mega Symposium, May 19-22, 2003, Washington, D.C. Attachment 18. 
34

shown that 90 percent NOx reductions can be achieved with low ammonia slip.95 Indeed, 

Babcock & Wilcox states that up to 95 percent NOx control can be achieved with SCR. 

Using Basin Electric’s projections of NOx emissions exiting the boiler of 0.20 to 0.25 lb/MMBtu, 

90 percent control with the SCR system would equate to a NOx emission rate of 0.020 to 0.025 

lb/MMBtu. However, as shown above and in the attached documents, a NOx rate exiting of the 

boiler of 0.15 lb/MMBtu (or lower) can be achieved with state-of-the-art ultra low NOx burners 

and overfire air at a subbituminous coal-fired PC boiler. Thus, with 90 percent control with 

SCR, a NOx emission rate of 0.015 lb/MMBtu could be met. WYDEQ failed to require Basin 

Electric to evaluate either of these NOx emission rates, and thus WYDEQ failed to require Basin 

Electric to evaluate the maximum degree of NOx emission reduction that can be achieved, as 

required by the WAQSR BACT rules. 

Further, the lb/MMBtu NOx BACT limit for Dry Fork must apply on a shorter averaging time 

than the proposed 12-month rolling average limit. Not only is it important for the averaging time 

of the BACT limit to be equal to or shorter than the most stringent averaging time of the NAAQS 

or PSD standards (which in the case of NOx means at least a 24-hour averaging time to be 

consistent with the Class I area visibility modeling), but the averaging time of the BACT limit 

must be consistent with the BACT requirement that the limit be based on the maximum degree of 

reduction that can be achieved. A long averaging period such as the WYDEQ’s proposed 

12-month rolling average does not require that Basin Electric operate its NOx pollution control 

equipment in a manner consistent with achieving the maximum reduction in emissions on a 

continuous basis. Further, a rolling 12 month average NOx BACT limit simply does not provide 

much compliance incentive when, at most, Basin Electric could be liable for only 12 violations 

of the limit per year. A rolling 30-day average limit provides much more compliance incentive 

with up to 365 violations per year. A 24-hour average limit provides a similar level of 

compliance incentive and more definitely ensure that the pollution control equipment will be 

operated to provide the maximum emission reduction achievable on a continuous basis. 

While WYDEQ has also proposed a 30-day rolling average BACT limit of 190.1 lb/hr, this limit 

only ensures that an emission level of 0.05 lb/MMBtu will be met when the unit is operating at 

maximum heat input capacity. When the unit is operating at less than maximum heat input 

capacity, the proposed 30-day average lb/hr limit will allow emission levels higher than 0.05 

lb/MMBtu. Thus, to more effectively ensure that the maximum degree of reduction in emissions 

will be met on a continuous basis, the lb/MMBtu BACT limit should apply on a shorter 

averaging time than the proposed 12-month rolling average. 

It is for these reasons that annual average or even 12-month rolling average NOx BACT limits 

are virtually unheard of in any recent PSD permitting actions for new coal-fired power plants. 

At most, NOx BACT limits have been imposed with rolling 30-day averaging times, and more 

commonly, NOx BACT limits have been imposed over a 24-hour averaging time to be consistent 

with the visibility modeling as required by EPA’s NSR Workshop Manual, and the underlying 

protections applicable to Class I areas. 

 

95 See Bielawski, G.T., J.B. Rogan, and D.K. McDonald, How Low Can We Go? Controlling Emissions in New 

Coal-Fired Power Plants, Presented to the U.S. EPA/DOE/EPRI Combined Power Plant Air Pollutant Control 

Symposium: “The Mega Symposium,” August 2001. Attachment 19. 
35

. 

While WYDEQ has proposed a lower NOx BACT limit than has typically been required in recent 

PSD permitting actions for new coal-fired power plants, that does not justify a longer averaging 

time. Indeed, WYDEQ’s own research found that such a limit was being met on a shorter 

averaging time. WYDEQ Permit Application Analysis at 5. As we have shown above, even 

lower emission limits could be met with ultra low NOx burners, overfire air, and an SCR system 

operated to achieve the maximum degree of reduction in NOx emissions that is achievable. 

Thus, for all of the above reasons, WYDEQ must revise the proposed NOx BACT limit for Dry 

Fork to be reflective of the maximum degree of NOx reduction that can be achieved. Further, the 

revised NOx BACT limit must be based on an averaging time that requires the NOx control 

equipment to be operated to achieve the maximum amount of continuous reduction in NOx

emissions that is achievable. 

c. The Proposed SO2 BACT Limit Does Not Reflect the Maximum Degree of Reduction 

that Can Be Achieved at a Pulverized Coal-Fired Boiler 

WYDEQ has proposed a SO2 BACT limit for Dry Fork of 0.08 lb/MMBtu, 12-month rolling 

average, and 304.1 lb/hr (which is equivalent to the 0.08 lb/MMBtu emission limit when the 

facility is operating at maximum heat input capacity), 30-day average. Neither WYDEQ nor 

Basin Electric has sufficiently demonstrated that these emission limits reflect the maximum 

degree of SO2 emission reduction that is achievable at the proposed Dry Fork facility. 

First, WYDEQ notes that the Newmont Nevada TS power plant has a lower SO2 BACT emission 

limit. Specifically, the Newmont PSD permit has an SO2 limit of 0.065 lb/MMBtu that applies 

on a 24-hour averaging time, along with a SO2 removal efficiency requirement of 91 percent, 

when combusting coal with less than 0.45 percent sulfur. The Newmont facility will be burning 

subbituminous coal from the Powder River Basin. Basin Electric’s statements that it could not 

obtain a vendor guarantee for an SO2 emission rate of less than 0.08 lb/MMBtu when another 

similar plant burning similar coal and using similar pollution control equipment apparently could 

obtain a vendor guarantee for a lower emission limit (or, at the least, Newmont Nevada has not 

appealed its PSD permit that requires the power plant to meet these lower SO2 emission limits) 

provides ample reason why it is not appropriate to only rely on vendor guarantees obtained by a 

permit applicant in determining BACT emission limits for a facility. As EPA states in the NSR 

Workshop Manual, “. . .lack of a vendor guarantee by itself does not provide sufficient 

information that a control option or an emissions limit is technically infeasible.” EPA’s October 

1990 Draft NSR Workshop Manual at B.20. 

The Newmont Nevada BACT requirements should not only set precedent for Dry Fork in terms 

of the emission limits but also in terms of averaging time and the SO2 removal efficiency 

required. The Newmont Nevada TS Power facility SO2 BACT emission limits are 0.065 

lb/MMBtu, 24-hour average, and a minimum of 91 percent control, 30 day average, when 

burning coal with sulfur content less than 0.45 percent. When burning coal with sulfur content 

equal to or greater than 0.45 percent, the SO2 BACT emission requirements are 0.09 lb/MMBtu, 

24-hour average basis, and a minimum of 95 percent control, 30 day average basis. See 
36

Attachment 20 with May 5, 2005 Newmont Nevada Energy Investment Class I Air Quality 

Operating Permit to Construct. WYDEQ’s proposed SO2 BACT limit of 0.08 lb/MMBtu that 

would apply on a 12-month rolling average is nowhere near as stringent as the Newmont limits. 

Even when coal with 0.45 percent sulfur content or greater is burned, the proposed Dry Fork 

limit of 0.08 lb/MMBtu with its long 12-month averaging time is not as stringent as the 24-hour 

average limit of 0.09 lb/MMBtu that applies to the Newmont Nevada TS Power Plant. Further, 

the WYDEQ’s proposed limit only reflects 93.3 percent removal from the worst case 

uncontrolled emission rate expected at Dry Fork96, as compared to the minimum 95 percent SO2

removal requirement that applies when Newmont Nevada TS Power is burning coal with more 

than 0.45 percent sulfur content. The proposed 0.08 lb/MMBtu limit at Dry Fork only reflects 90 

percent control from the average uncontrolled SO2 emission rate expected at Dry Fork.97 Worse 

yet, the proposed Dry Fork SO2 BACT limit only reflects 86.7 percent control from the lowest 

uncontrolled SO2 emission rate expected at Dry Fork, as compared to the minimum 91 percent 

removal efficiency that is required at the Newmont Nevada TS Power plant in addition to the 

Newmont facility being required to comply with a 24-hour average limit of 0.065 lb/MMBtu.98, 

99 

The cost analysis provided by WYDEQ in its Permit Application Analysis is of little importance 

given that much more stringent SO2 requirements have been required as BACT at the Newmont 

Nevada TS power plant - a facility that will be equipped with similar SO2 control technology 

and will be burning similar coal to Dry Fork. As EPA states in its NSR Workshop Manual, “In 

the absence of unusual circumstance, the presumption is that sources within the same category 

are similar in nature, and that cost and other impacts that have been borne by one source of a 

given source category may be borne by another source of the same source category.”100 Neither 

WYDEQ or Basin Electric have provided any indication of unusual circumstances at Dry Fork 

that would make this facility unable to meet the same emission limits as those at the Newmont 

Nevada TS power plant, with possibly the lone exception being that Basin Electric’s statements 

that they can’t obtain vendor guarantees for emission rates less than 0.08 lb/MMBtu which, as 

discussed above, is unpersuasive. 

In addition to the proposed Dry Fork SO2 limits being less stringent than the Newmont Nevada 

TS power plant limits, the WYDEQ’s proposed SO2 BACT emission limit for Dry Fork also fails 

to reflect the degree of SO2 reduction that can be achieved across a spray dryer/absorber. Using 

AP-42 emission factors to estimate the uncontrolled SO2 emissions exiting the proposed Dry 

Fork boiler101, the worst case uncontrolled emission rate would be 1.05 lb/MMBtu, the average 

 

96 Uncontrolled SO2 emission rate from Basin Electric’s permit application for Dry Fork at 2-6 (Table 2-1). 97 Id. 

98 Id. 99 The lowest uncontrolled SO2 emission rate expected at Dry Fork was calculated approximately 0.60 lb/MMBtu 

based on Basin Electric’s lowest projection of sulfur content of the fuel (0.25 percent) and the highest heating value 

provided (8,300 Btu/lb). It must be noted that uncontrolled emission rates of this level or even lower are commonly 

found in Powder River Basin coal, as is shown in the attached 2000 Directory of Power Plants Burning Wyoming 

Coal which was obtained from the Wyoming Geological Survey. (Attachment 21). 

100 See EPA’s New Source Review Workshop Manual, October 1990 Draft, at B.29. 101 The uncontrolled SO2 emission rates provided in Basin Electric’s permit application for Dry Fork at 2-6 (Table 2-

1) are based on the sulfur content of the coal and do not reflect the fact that some of the sulfur will be removed as 

bottom ash via combustion of the coal in the boiler. 
37

would be 0.72 lb/MMBtu, and the lowest uncontrolled emission rate would be 0.53 

lb/MMBtu.102 Thus, the WYDEQ’s proposed 0.08 lb/MMBtu emission limit would only reflect a 

92.4 percent SO2 removal efficiency across the spray dryer/absorber at best, an 88.9 percent SO2

removal efficiency on average, and an 84.8 percent removal efficiency when lowest sulfur, 

highest heating value coal is burned. As indicated in WYDEQ’s Permit Application Analysis, 

Basin Electric has indicated that the “lowest emission guarantee available for SDA [spray 

dryer/absorber] is 94 percent.” (WYDEQ Permit Application Analysis at 11 (emphasis added). 

There is ample indication in PSD permit applications that spray dry absorbers can achieve at 

least 90 percent SO2 removal even with low sulfur coals.103 Indeed, as found by EPA in its 

review of the New Source Performance Standards for coal-fired electric utility boilers, a spray 

dryer/absorber can generally achieve greater than 90 percent SO2 removal. See 70 Fed.Reg. 

9711 (February 28, 2005). 

WYDEQ must also take into account other impacts in setting BACT including environmental 

impacts. In the case of Dry Fork, this facility will contribute to SO2 increment violations at the 

Northern Cheyenne Indian Reservation Class I area. Although WYDEQ claims the facility’s 

impacts will be less than the proposed “Class I significant impact levels,” that is irrelevant for 

two reasons: First, the Class I significant impacts levels are not authorized in any state PSD 

regulation. Second, even if use of such significant impact levels were authorized under state law, 

EPA Region VIII has previously indicated that any impact in an area with existing increment 

violations must be considered significant.104 WYDEQ has known about these predicted SO2

increment violations at Northern Cheyenne Indian Reservation at least since the permitting of 

Wygen 3. In addition, Basin Electric’s modeling also showed that total sulfur deposition linked 

to the Dry Fork Station would exceed the Federal Land Managers’ (FLM) deposition analysis 

thresholds (DATs) at Wind Cave National Park and at the Northern Cheyenne Indian 

Reservation. Further, Basin Electric’s modeling that followed FLM modeling procedures also 

indicated that Dry Fork could cause noticeable changes in visibility (i.e., a greater than 5 percent 

change) at Wind Cave National Park and at the Northern Cheyenne Indian Reservation. Thus, 

WYDEQ must take all of these significant environmental impacts into account in setting SO2

BACT limits for Dry Fork. 

For all of the above reasons, SO2 BACT for Dry Fork must be at least as stringent as the SO2

BACT emission limits required at the similarly configured proposed Newmont Nevada TS power 

plant, including in terms of averaging time of the BACT limits. Further, given the wide range of 

sulfur content of the coal, it is imperative that WYDEQ impose a SO2 removal efficiency 

 

102 These emission rates were calculated using AP-42 SO2 emission factors for dry bottom tangentially-fired or wallfired subbmituminous coal-fired NSPS boilers (Table 1.1-3 of Chapter 1.1 of AP-42) and the worst case, best case, 

and average coal characteristic data provided in Basin Electric’s permit application for Dry Fork (at 2-6 (Table 2-

1)). 

103 For example, two recently permitted circulating fluidized bed boilers – Gascoyne (to be located in North Dakota) 

and Sevier (to be located in Utah) will have add-on spray dryers that reduce SO2 by approximately 90 percent from 

the gas stream exiting the circulating fluidized bed boiler, and the gas stream exiting the boiler will already reflect 

90 percent SO2 removal. For Gascoyne, the inlet to the scrubber is expected to be 0.348 lb/MMBtu and the required 

outlet emission limit is 0.038 lb/MMBtu. See Attachment 22 with Appendix C of the Gascoyne Permit Application 

at page C-29. 

104 See April 12, 2002 letter from EPA, Region VIII to the North Dakota Department of Health, Attachment 23.
38

requirement in addition to an SO2 emission limit to ensure that the control equipment will be 

operated to achieve the maximum degree of emission reduction over all of the varying levels of 

uncontrolled SO2 emissions expected at the Dry Fork facility. It is also important to note that 

there are no exemptions from the SO2 BACT limits in the Newmont Nevada TS power plant 

permit. Thus, there is also absolutely no justification for adding a safety margin to the limits 

that have been imposed at the similarly configured Newmont Nevada TS power plant. WYDEQ 

must revise its proposed BACT emission limit for Dry Fork and impose emission limitations and 

requirements that ensure the maximum degree of reduction in SO2 emissions that can be 

achieved with the spray dry/absorber will actually be achieved at Dry Fork. 

c. The Proposed Mercury BACT Limit Does Not Reflect the Maximum Degree of 

Reduction that Can Be Achieved at a Pulverized Coal-Fired Boiler 

WYDEQ has proposed a mercury BACT limit for Dry Fork of 97 x 10-6 lb/MWh on a 12-month 

rolling average, which is equivalent to the limit that applies under the New Source Performance 

Standards. WYDEQ’s proposed permit also requires Basin Electric to undertake a mercury 

reduction optimization study with a target emission rate of 20 x 10-6 lb/MWh, and to install “a 

mercury control system.” Based on the optimization study, the mercury limit would be revised. 

WYDEQ provided no justification for this approach to setting mercury BACT in its permit 

application analysis. Instead, WYDEQ should have followed a top-down approach and set a 

mercury BACT emission limit that reflects the maximum degree of mercury reduction that is 

achievable considering energy, economics and environmental issues. 

Sorbent injection is an available mercury control technology that could be utilized at the Dry 

Fork facility, and yet WYDEQ did not require full evaluation of sorbent injection in the BACT 

analysis. Basin Electric mentioned installation of a sorbent injection system and even stated it 

would leave space available for installation of such a system. Dry Fork Permit Application at 5-

21. Basin Electric made no claims that the technology was not available in its permit 

application. Indeed, there is a wealth of information indicating that sorbent injection is an 

available and effective control measure for reducing mercury emissions. 

For example, the owners of two new coal-fired power plants in Montana have agreed to use 

activated carbon injection for mercury control (i.e., the Hardin and Roundup power plants105). 

Both of these facilities will burn subbituminous coal similar to Dry Fork. Activated carbon 

injection has also been required by the state of Iowa at the coal-fired Unit 4 at the Council Bluffs 

Energy Center which will burn subbituminous coal from the Powder River Basin.106 Also, the 

Newmont Nevada’s TS power plant will be equipped with a sorbent injection system.107 The 

proposed White Pines power plant in Nevada, which will primarily burn Powder River Basin 

subbituminous coal, is planned to be equipped with a halogenated activated carbon injection 

 

105 See December 8, 2005 Air Quality Permit for the Roundup Power Project (Attachment 24). See May 16, 2005 

Air Quality Permit for the Hardin Generation Project (Attachment 25). 106 The June 17, 2003 MACT permit and associated Technical Support Document for MidAmerican Energies’ Unit 

4 at the Council Bluffs Energy Center included as Attachment 26. 107 See Newmont Nevada TS power plant permit included as Attachment 20 to this letter. 
39

system for mercury control in addition to its planned criteria pollutant control technologies.108 

Not only will all of these facilities be burning subbituminous coal, but they will also be equipped 

with SCRs, spray dryer/absorbers and baghouses, similar to the proposed Dry Fork facility. 

Clearly, sorbent injection is an available technology for subbituminous coal-fired power plants, 

and WYDEQ should have evaluated this technology as part of the mercury BACT process. 

Because the costs of sorbent injection were considered reasonable for mercury control at these 

subbituminous coal-fired power plants, WYDEQ must also consider the costs of sorbent 

injection to be reasonable at Dry Fork. Use of such a mercury-specific control technology in 

conjunction with other criteria pollutant control technologies will undoubtedly reduce mercury to 

the maximum degree that can be achieved with the combustion of subbituminous coal that is 

planned to be used at Dry Fork. 

Halogenated sorbents have been shown to be effective at removing mercury at subbituminous 

power plants, especially those equipped with spray dryer absorbers (SDA). The SDA may 

remove halogens in the flue gas that are needed for the adsorption of elementary mercury with 

untreated activated carbon. With a halogenated carbon injection system used for mercury control 

at the proposed Dry Fork facility, Basin Electric should be able to achieve 90 percent control or 

better with Powder River Basin subbituminous coal. Indeed, testing at the Holcomb Station Unit 

1 in Garden City, Kansas, which burns Powder River Basin coal and is equipped with an SDA 

and a fabric filter, showed an average mercury removal efficiency of 93 percent with a low 

halogenated carbon injection rate of 1.2 pounds per million actual cubic feet (lb/MMacf).109 

Brominated powdered activated carbon (B-PAC) is a halogenated sorbent that has also shown 

high levels of mercury control across a range of coals. For example, full-scale tests of B-PAC at 

the St. Clair power plant in Detroit, Michigan, which burns at least 85 percent subbituminous 

coal blended with bituminous coal and is equipped with an electrostatic precipitator, showed that 

greater than 90 percent mercury removal could be routinely achieved.110 

Basin Electric provided average coal mercury contents of 0.05 to 0.08 μg/g. Dry Fork Permit 

Application at 5-21. Assuming a unit net heat rate of 10,077 Btu/net kWh (which reflects 100 

percent load as provided in the Dry Fork permit application in Appendix B under “Criteria 

Pollutant Potential to Emit”), these values equate to uncontrolled mercury emission rates of 

62.2 to 100.2 x 10-6 lb/net MWh. Thus, WYDEQ’s proposed mercury BACT limit of 97 x 10-6

lb/MW does not reflect any reduction in mercury emissions at Dry Fork. And, WYDEQ’s 

proposed “target” mercury emission rate of 20 10-6 lb/MW (and there is no guarantee that 

WYDEQ will mandate this target limit in a revised permit pursuant to the mercury reduction 

optimization study currently proposed for Dry Fork) only reflects 68 percent to 80 percent 

mercury reductions. As discussed above and as has been shown by a wealth of other available 

information, at least 90 percent control of mercury should be achievable with a sorbent injection 

system for control of mercury. This level of control from the projected level of uncontrolled 

 

108 See the Nevada Department of Environmental Protection’s proposed permit to be issued to White Pine Energy 

Associates, LLC, included as Attachment 27 to this letter. 

109 Bustard, Jean et al., Full-Scale Evaluation of Mercury Control Technologies with PRB Coals, presented at 

ICAC’s Clean Air Technologies & Strategies Conference & Workshop, Baltimore, MD, March 7-10, 2005, at 3. 

Attachment 28 to this letter. Also available at www.adaes.com under publications. 110 McCoy, Melanie et al., “Full-Scale Mercury Sorbent Injection Testing at DTE Energy’s St. Clair Station,” 

presented at the Combined Power Plant Air Pollutant Control Mega Symposium, Washington, D.C., August 30 – 

September 2, 2004, at 8. Attachment 29 to this letter. 
40

mercury emission rates equates to corresponding emission limits ranging from 6.26 to 10.02 x10-

6

 lb/net MW (based on Basin Electric’s range of mercury content of the coal to be utilized at Dry 

Fork). Thus, mercury emission limits in the range of 6.26 to 10.02 x10-6 lb/net MW are the 

maximum mercury emission limits that WYDEQ should have evaluated as reflecting BACT for 

Dry Fork. WYDEQ should also require evaluation of emission limits that reflect even greater 

than 90 percent mercury control. 

Thus, WYDEQ must revise its BACT analysis for mercury emissions at Dry Fork to fully 

evaluate sorbent injection systems, in addition to the planned criteria pollutant control 

equipment, and to impose emission limits reflective of the maximum degree of mercury 

reduction that can be achieved with these control systems at Dry Fork. Given the projected 

uncertainty in uncontrolled mercury emission rates, WYDEQ must also impose a percent 

reduction requirement reflective of BACT for mercury to ensure that the maximum degree of 

reduction of mercury achievable is continually achieved at Dry Fork. There is no adequate 

justification for deferring this decision on a mercury BACT emission limitation and requirement 

prior to any mercury control optimization studies conducted by Basin Electric. There is more 

than sufficient information available now for WYDEQ to impose a mercury BACT emission 

limit and other requirements reflective of at least 90 percent mercury reduction at Dry Fork, 

especially if WYDEQ imposes this mercury reduction requirement over a long averaging time as 

has been typical in recent PSD permits. 

d. WYDEQ Must Impose BACT Limits for Volatile Organic Compounds, Sulfuric Acid 

Mist, and Ammonia 

Although WYDEQ determined emission limits as reflective of BACT for volatile organic 

compounds (VOCs), sulfuric acid mist (H2SO4) and ammonia, the proposed permit conditions 

fail to set emission limits for these pollutants. WYDEQ must impose permit limits reflective of 

BACT for these pollutants in the final permit for Dry Fork, consistent with the state’s BACT 

determination provided in its Permit Application Analysis. (See pp. 14-16 and 47 of the Dry 

Fork Permit Application Analysis). 

e. WYDEQ Failed to Propose a Visible Emission Limit Reflective of BACT at the Dry 

Fork Facility 

The Wyoming definition of BACT explicitly states that BACT includes a “visible emission 

standard.” Chapter 6, Section 4(i) of the WAQSR. Yet, WYDEQ has not evaluated or proposed 

a visible emission standard reflective of BACT for the Dry Fork facility. While WYDEQ has 

included the applicable opacity requirements of the New Source Performance Standards as a 

proposed condition of the Dry Fork permit (see Permit Application Analysis at 48, proposed 

Condition 11.A), this limit does not reflect BACT for a coal-fired power plant. 

With a fabric filter baghouse for PM10 control, an opacity BACT limit should be at least 10 

percent. Indeed, the recently permitted Intermountain Power Plant Unit 3 in Utah is subject to a 

10 percent visible emissions limit.111 Similarly, the Gascoyne CFB facility will also be subject 

 

111 See October 15, 2004 Approval Order for Unit 3 at Intermountain Power Generating Station, Condition 12, at 9 

(Attachment 30). 
41

to a 10 percent opacity BACT limit.112 Also noteworthy is the permit for the Longview power 

plant in West Virginia, which will utilize a PC boiler. This permit requires both a PM 

continuous emission monitoring system (CEMS) to ensure compliance with its PM BACT limit 

and imposes a 10 percent opacity BACT limit.113 Thus, WYDEQ must evaluate BACT for 

opacity and impose a visible emission standard on the Dry Fork facility that reflects the 

maximum degree of reduction achievable. Further, to ensure compliance on a continuous basis, 

a continuous opacity monitoring system (COMS) must be required. 

8. WYDEQ MUST IMPOSE A LIMIT ON TOTAL PM10 CONSISTENT WITH PM10

AND VISIBILITY MODELING CONDUCTED FOR DRY FORK 

While WYDEQ proposed a BACT emission limit for filterable PM10 emissions at Dry Fork, 

WYDEQ has failed to propose any limit on total PM10 emissions, i.e., filterable plus condensable 

emissions. Yet, condensable PM10 emissions affect PM10 concentrations as well as visibility.114 

Indeed, WYDEQ required consideration of condensable PM10 emissions in the modeling 

analyses conducted for Dry Fork. See WYDEQ Permit Application Analysis at 22. 

Accordingly, WYDEQ must impose an emission limit on total PM10 emissions reflective of the 

level of PM10 emissions modeled for Dry Fork in its near field and far field analyses. Without 

such a limit on total PM10, Basin Electric must be required to model condensable PM10 emissions 

at the allowable emission rates – i.e., uncontrolled emissions of these pollutants. 

9. WYDEQ MUST ADDRESS PM2.5 IN THE DRY FORK PERMIT

WYDEQ has not addressed the PM2.5 emissions to be emitted by the Dry Fork facility in its 

proposed PSD permit or permit application analysis. Yet, PM2.5 is subject to PSD permitting 

requirements as a regulated pollutant. Specifically, Wyoming regulations defined “regulated 

NSR pollutant” to mean, among other things, “[a]ny pollutant for which a national ambient air 

quality standard has been promulgated and any constituents or precursors for such pollutants 

identified by the EPA Administrator (e.g., volatile organic compounds are precursors for 

ozone).” WAQSR Chapter 6, Section 4(a). EPA has promulgated a NAAQS for PM2.5. 62 Fed. 

Reg. 38,652 (July 18, 1997); revised at 71 Fed.Reg. 61144-61233 (October 17, 2006). 

Wyoming’s PSD regulations list significance levels for a number of “regulated NSR pollutants,” 

but not PM2.5. See definition of “significant” in WAQSR Chapter 6, Section 4(a). When a 

significance level has not been identified for a regulated NSR pollutant, the significance level is 

any emission rate over zero. See WAQSR Chapter 6, Section 4(a), subsection (ii) of the 

definition of “significant.” Although there is no analysis in the Dry Fork permit application, the 

proposed permit conditions, or the permit analysis regarding PM2.5, a facility of this size will 

undoubtedly be emitting PM2.5 in substantial amounts. Consequently, Basin Electric is required 

to comply with all PSD requirements, including monitoring, modeling, and BACT regarding 

PM2.5. WYDEQ cannot issue a PSD permit for this facility unless this criteria pollutant is 

properly addressed. 

 

112 See Air Pollution Control Permit to Construct for Gascoyne, Condition II.A. 3), at 8 (Attachment 31). 113 See March 2, 2004 Permit to Construct for Longview Power, Conditions A.8. and A.18., at 4, 9. (Attachment 32). 114 See, e.g., EPA’s March 31, 1994 letter to the Iowa Department of Natural Resources, Attachment 33. 
42

We are aware that EPA issued guidance providing that sources would be allowed to use 

implementation of a PM10 program as a surrogate for meeting PM2.5 NSR requirements. John 

Seitz, “Interim Implementation for the New Source Review Requirements for PM[2.5],” (October 

23, 1997). The purpose of that guidance was to provide time for the development of necessary 

tools to calculate the emissions of PM2.5 and related precursors, adequate modeling techniques to 

project ambient impacts, and PM2.5 monitoring sites. 70 Fed. Reg. 65984, 66043 (Nov. 1, 2005). 

EPA has resolved most of these issues. Id. More importantly, the guidance clearly contravenes 

the regulations. 

Thus, WYDEQ must require the Dry Fork facility to be subject to all PSD permitting 

requirements for PM2.5 emissions, including monitoring, modeling and BACT. 

10. THE PROPOSED PERMIT FOR DRY FORK FAILS TO INCLUDE ANY 

CONDITIONS REGARDING THE DESIGN OF THE SOURCE

The proposed permit conditions provided at the end of WYDEQ’s Permit Application Analysis 

for Dry Fork do not include any description of the Dry Fork facility or any description of how it 

will be designed. WYDEQ must issue a permit that is specific to the Dry Fork facility as 

proposed in Basin Electric’s November 10, 2005 permit application. Further, the permit must 

specify the control equipment and emission limit that reflects BACT. Thus, the proposed permit 

must contain, among other things, terms identifying the type of boiler, the maximum heat input 

capacity of the boiler, the generating capacity of the unit, the control equipment that WYDEQ 

based its BACT emission limitations on, and the emission limitations that reflect BACT. 

Without such conditions in the permit, Basin Electric could potentially be allowed to build a very 

different source than what WYDEQ reviewed under its permitting regulations. 

11. WYDEQ CANNOT ISSUE A PERMIT TO DRY FORK BECAUSE IT WOULD 

CONTRIBUTE TO VIOLATIONS OF THE SO2 PSD INCREMENTS AT THE 

NORTHERN CHEYENNE INDIAN RESERVATION CLASS I AREA. 

Basin Electric’s modeling indicated that there are existing violations of the 24-hour average SO2

PSD increments occurring at the Northern Cheyenne Indian Reservation Class I area (NCIR) (as 

discussed in WYDEQ’s Permit Application Analysis at 40), and the Dry Fork facility will 

contribute to the increment violations. Consequently, Wyoming’s PSD regulations provide that 

the permit for Dry Fork must be denied. 

Although WYDEQ provided analyses to determine whether the Dry Fork facility’s impact on the 

predicted increment violations would be “significant,” such an approach to discounting the 

impacts of the Dry Fork facility are not grounded in state or federal law. Specifically, WYDEQ 

evaluated Dry Fork’s contribution to the predicted exceedances of the SO2 PSD increment 

concentrations at the NCIR Class I area, and then determined that the Dry Fork facility’s impacts 

would not be “significant” at those receptors and time periods during which increment violations 

were shown to occur in the modeling analysis. (See Permit Application Analysis at 40.) It 

appears that, in making this determination, WYDEQ utilized the Class I significant impact levels 

that were proposed by EPA in a July 23, 1996 proposed rulemaking (61 Fed.Reg. 38292), but the 

Class I significant impact levels were never promulgated by EPA or adopted into Wyoming rules 
43

and the state implementation plan. In addition, EPA has previously made clear that, in an area 

with existing increment violations, any impact by a new source is considered to contribute to 

those increment violations. Specifically, EPA Region VIII stated in an April 12, 2002 letter to 

the North Dakota Department of Health that the use of significant impact levels to allow a PSD 

permit to be issued in the case of an area showing increment violations is not consistent with the 

intent of the Clean Air Act’s PSD program.115 In addition, EPA’s longstanding 

contemporaneous interpretation of the statutory and regulatory provisions for the PSD 

increments clearly mandate that, in an area with existing PSD increment violations, the 

violations “must be entirely corrected before PSD sources which affect the area can be 

approved.” (See 45 Fed.Reg. 52678, August 7, 1980). WYDEQ has known about these existing 

SO2 increment violations at least since the permitting of Wygen 3. Thus, because the Dry Fork 

facility will contribute to the violations of the 24-hour SO2 increment at NCIR, Wyoming and 

federal law prohibit issuance of this permit to the Dry Fork facility. 

Specifically, Wyoming regulation mandates that a cumulative impacts increment analysis be 

conducted by a PSD permit applicant to determine the “total deterioration of air quality from the 

baseline concentrations” and that a permit can only be issued “if the predicted impact (over and 

above the baseline concentration) of emissions. . .is less than the maximum allowable increment 

shown in Table 1 [of Chapter 6, Section 4 of the WAQSR] for the classification of the area in 

which the impact is predicted. . . .” WAQSR Chapter 6, Section 4(b)(i)(A)(I). Further, 

Wyoming’s regulations also provide that no permit can be issued unless the permit applicant 

shows that it won’t emit pollutants “in amounts [which] will. . . interfere with measures required 

by the 

Federal Clean Air Act to be included in the applicable Implementation Plan for any other state 

to prevent significant deterioration of air quality. . . .” WAQSR, Chapter 6, Section 2(c)(viii)(ii). 

It also appears that Basin Electric’s cumulative Class I SO2 increment analysis for NCIR did not 

include all increment-consuming emissions and thus any evaluation of the extent of existing 

increment violations is incomplete. For example, Basin Electric failed to include SO2 emissions 

from the Yellowstone Energy Limited Partnership (YELP) facility which has increased SO2

emissions by 1,932 tons per year since 1977 according to the Final Environmental Impact 

Statement for the Roundup Power Project.116 Further, Basin Electric failed to include any of the 

SO2 increment consuming sources from North Dakota, or the increment consuming emissions 

from Billings, Montana sources. In addition, Basin Electric only modeled the 90th percentile 

maximum 3-hour and 24-hour average SO2 emission rates from Colstrip Units 3 and 4, rather 

than the maximum 3-hour and 24-hour average emission rates from these units which is required 

by the NSR Workshop Manual (at C.49). Thus, Basin Electric must be required to revise its SO2

increment analyses for the NCIR Class I area to include all increment consuming emissions and 

sources, as mandated by EPA policy and regulation. 

In any case, there is sufficient documentation at this point to mandate that WYDEQ deny the 

proposed permit for Dry Fork due to Dry Fork’s contribution to the existing SO2 increment 

 

115 See April 12, 2002 letter from EPA, Region VIII to the North Dakota Department of Health, Attachment 23. 116 Final EIS for Roundup Power Project is available on the Montana Department of Environmental Quality’s 

internet site at www.deq.state.mt.us/eis/Roundup_EIS/RndupPwrPrjCmpltFEIS.pdf. 
44

violations at NCIR pursuant to WAQSR Chapter 6, Section 4(b)(i)(A)(I) and Chapter 6, Section 

2(c)(viii)(ii). 

12. THE CLEAN AIR ACT REQUIRES A COMPLETE ANALYSIS OF THE 

IMPACT OF THE PROPOSED PROJECT ON SOILS AND VEGETATION 

The CAA’s PSD requirements include a specific obligation for permitting authorities and permit 

applicants to evaluate soils and vegetation (in addition to ambient air quality) in any area that 

will be affected by any aspect of the proposed project (including construction): 

[T]he analysis required under this subsection . . . shall require an analysis of the ambient 

air quality, climate and meteorology, terrain, soils and vegetation, and visibility at the site 

of the proposed major emitting facility and in the area potentially affected by the 

emissions from such facility for each pollutant regulated under this chapter which will be 

emitted, or which results from the construction or operation of, such facility. 

CAA § 165(e)(3)(B). 

The obligation to consider impacts on soil and vegetation is a long-standing requirement of the 

PSD program, and includes an obligation to perform a site-specific inventory of soils and 

vegetation before the issuance of a draft permit and prior to the date of any public hearing. Such 

analysis must consider the variety of soils and vegetation in the area, the possibility of adverse 

impacts on soils and vegetation for PSD-regulated pollutants (including the possibility of adverse 

impacts at ambient concentrations that are lower than the applicable NAAQS, the impact of PSD 

pollutants – like fluoride – for which there is no NAAQS, and impacts from concentrations of 

pollutants that are lower than generalized screening levels),117 the possibility of adverse impact 

from non-PSD regulated pollutants, and the potential for any other site-specific environmental 

effects. See In re Indeck-Elwood, PSD Appeal 03-04, slip op at 31-52 (EAB Sept. 27, 2006).118

As a result, permitting authorities (including WYDEQ) are obligated to perform (or require of 

applicants) an analysis that specifically inventories the various soils and plant life (including but 

not limited to threatened or endangered species) in the vicinity of the proposed facility and in any 

other area affected by the construction or operation of the proposed facility. The analysis must 

then determine whether such soils or vegetation will be adversely affected by any of the plant’s 

emissions (during construction or operation). At least, such analysis must include the full range 

of PSD pollutants (including fluoride), as well as any relevant non-PSD pollutants (including 

sulfuric acid mist, mercury, beryllium, etc.).119 

 

117 In particular, permitting authorities cannot blindly rely on the 1980 Screening Procedure for the Impacts of Air 

Pollution Sources on Plants, Soils, and Animals (“1980 Screening Levels). For example, EPA’s NSR Manual 

specifically recognizes that “there are sensitive species which may be harmed by long term exposure to low 

concentrations of pollutants for which there are no NAAQS” and that under certain circumstances soil and 

vegetation analysis “has to go beyond a simple screening.” See In re Indeck-Elwood, PSD Appeal 03-04, slip op at 

38 (EAB Sept. 27, 2006). 

118 It is worth noting that the requirement to evaluate impacts on soil and vegetation apply not only to the coal-fired 

steam boilers but to all sources at the proposed plant, individually and in the aggregate. 

119 Among other things, acidic pollutants (or precursors), such as SO2, NOx, and hydrogen chloride can directly 

affect soil chemistry and have significant impacts on important habitat, vegetation, and potentially animal life 
45

Significantly, the soil/vegetation analysis must be completed before a draft permit can 

appropriately issue, among other things to allow the public and others a meaningful opportunity 

to comment on the analysis and any possible or likely impacts. 

The EAB has made clear that in conducting this analysis reference simply to the primary and 

secondary NAAQS and PSD increments as evidence that proposed major source will not harm 

soils or vegetation would essentially write the soils and vegetation analysis out of the Act – 

making it an unnecessary redundancy. This reading is contrary to fundamental principles of 

statutory interpretation; rather, permitting authorities must require or conduct an actual, sitespecific analysis of potential impacts on soil and vegetation. Permitting authorities may not 

substitute a discussion of compliance with NAAQS and PSD increments for an actual evaluation 

based on an inventory and assessment of the impacts to soils and plant life in the area of a 

proposed major source.120 

Secondly, permit applicants and permitting authorities may not blindly rely on the EPA’s 1980 

Screening Levels. The EAB has recognized that: 

there is ample indication in the Screening Procedure itself that, in keeping with a concept 

of a “screening” tool, the analysis provided in the Screening Procedure may in some 

cases be incomplete and preliminary. In its overview section, for example, the 1980 

Screening Procedure states as follows: 

In keeping with the screening approach, the procedure provides conservative, not 

definitive results. * * * The estimation of potential impacts on plants, animals, and 

soils is extremely difficult. The screening concentrations provided here are not 

necessarily safe levels nor are they levels above which concentrations will 

necessarily cause harm in a particular situation. However, a source which passes 

through the screen without being flagged for detailed analysis cannot necessarily 

be considered safe.

121

Additionally, there are indications that the Screening Procedure does not purport to be 

complete in its coverage. The guidance observes in this regard, “[i]deally, the screening 

procedure should address the impacts of all the pollutants currently regulated under the 

[CAA], but as shown in Table 2.1, screening concentrations were found for only half of 

the regulated pollutants.” Id. at 4. In fact, the guidance can only be used to screen for 

potential effects caused by concentrations of the pollutants in the ambient air for only 

seven pollutants because, at the time the guidance was developed, there were only 

sufficient data for those seven pollutants. Id. at 5; see also id. at 11, tbl. 3.1 (listing 

vegetation sensitivity levels for seven pollutants: sulfur dioxide, ozone, nitrogen oxide, 

 (especially aquatic life). The applicants must examine the full range of these possible effects in connection with this 

PSD permit application. 

120 Nor can a permitting authority (or the permit applicant) rely on vague generalizations, such as assertions that 

emission of a particular kind are “trivial,” without evaluating what those emissions will be and why they are 

expected to have no adverse impacts. See Indeck-Elwood, slip op at 40. 121 Citing 1980 Screening Procedure at 2-3 (emphasis added). 
46

carbon monoxide, sulfuric acid, ethylene, and fluorine). Also, the guidance notes that 

there was a lack of data on chronic effects when it was developed. In short, the 1980 

Screening Procedure does not purport to address a number of pollutants with respect to 

which concerns have been raised here, including sulfuric acid mist, volatile organic 

materials (VOM), hydrogen chloride, and beryllium, and it does not consider the kinds of 

chronic effects that may be germane to a protected area like the Midewin. 

Indeck-Elwood, slip op at 43-45. 

The EAB observed as well that the data upon which the screen limits are based are more than 26 

years old and did not even rely on native species for their analysis. Id at 45. In sum, the 

statutory requirement for a thorough evaluation of soils and vegetation is not satisfied by mere 

assertion or by the application of a screening tool or other analysis that is incomplete. 

The 1990 NSR Manual, which reflects the Agency’s more recent thinking about how to evaluate 

impacts on soil and vegetation, states that such analysis “should be based on an inventory of the 

soils and vegetation types found in the impact area,” and an applicant must “determine the 

sensitivities of the plant species listed in the inventory to the applicable pollutants that would be 

emitted from the facility and compare this information to the estimates of pollutant 

concentrations calculated in the air quality modeling analysis (conducted pursuant to 40 C.F.R. § 

52.21(m)) in order to determine whether there are any local plant species that may potentially be 

sensitive to the facility’s projected emissions. . . . For those plants that show potential 

sensitivity, a more careful examination would be conducted. . . . Plainly, the NSR Manual 

contemplates the development of site-specific information that goes beyond the scope of simple 

screening under the 1980 Screening Procedure.” Indeck-Elwood, slip op at 46 (citing and 

quoting the NSR Manual). As the EAB has explained, the soils and vegetation component of the 

PSD requirements “contemplates a comparative analysis of some kind between the existing 

baseline conditions of soils and vegetation at the site and in the potentially affected area, and the 

effects of the emissions on such baseline conditions” that “shall be available at the time of the 

public hearing on the application for such permit.” Indeck-Elwood, slip op at 42-43. 

The draft permit is defective because there was an inadequate analysis of the effect of emission 

of pollutants on soils and vegetation. For example, the methodology used in the permit 

application was a simple screening of research papers. There was no site specific inventory of 

soils or vegetation performed as part of the permit application. Therefore, it is impossible to 

know whether any endangered, threatened, or sensitive species are located in or around the plant 

site. Further, the permit application screening methodology was limited to the criteria pollutants 

of SOx and NOx. There permit application failed to analyze the potential impacts of emissions 

of the following pollutants: fluorine, sulfuric acid, mercury, beryllium, ozone, hydrogen 

chloride, carbon monoxide, and ethylene. Moreover, the permit application did not appear to 

analyze emissions from all sources—and instead it appears that the analysis was limited to 

emissions from the stack. 

This abdication of a critical substantive obligation demonstrates that WYDEQ has not taken 

seriously its solemn responsibility to fully evaluate the impact of this new major source. In so 

doing WYDEQ has denied the public its ability to meaningfully comment on its decision making 
47

process, and contribute constructively to the permit determination. As a result, WYDEQ must 

withdraw the draft permit, prepare an appropriate soils and vegetation analysis, and provide an 

adequate opportunity for public comment (including public hearing) as the PSD provisions 

require. 

Thank you for considering our comments. Please include all of the groups signed below on the 

mailing lists for any future actions by WYDEQ regarding Basin Electric’s application to 

construct the Dry Fork power plant. 

Sincerely, 

__________________________________ 

Kevin Lind, Director 

Powder River Basin Resource Council 

934 North Main 

Sheridan, WY 82801 

(307) 672-5809 

__________________________________ 

Bruce Pendery, Program Director 

Wyoming Outdoor Council 

444 East 800 North 

Logan, Utah 84321 

435-752-2111 

 

__________________________________ 

Liz Howell, Director 

Wyoming Wilderness Association 

PO Box 6588 

Sheridan, WY 82801 

307 672-2751 office 

 

____________________________________ 

Steve Thomas, Regional Director 

Wyoming Chapter of the Sierra Club 

45 E. Loucks St. #109 

Sheridan Wy. 82801 

(307)672-0425 

Attachments 

 _______________________________ 

Erik Molvar, Director 

Biodiversity Conservation Alliance 

P.O. Box 1512 

Laramie, WY 82073 

(307) 742-7978 

_______________________________ 

John Nielsen 

Energy Program Director 

Western Resource Advocates 

2260 Baseline Rd, Suite 200 

Boulder, CO 80302 

303-444-1188 x232 

__________________________________ 

Patrice L. Simms 

Senior Attorney 

Natural Resources Defense Council 

1200 New York Avenue NW, Suite 400 

Washington, DC 20005 

202-289-2437