### 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. 25 th 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, Wy oming Outdoor Council, Wyoming Wilderness Association, Powder River Basin Resource C ouncil, Western Resource Advocates and the Natural Resources Defense Council respectf ully submit the following comments on the Wyoming Department of Environmental Quality’s (WYDEQ’s) proposal to approve construction of a 422 megawatt (gross) coal-fir ed 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 Regulatio ns (WAQSR) including the prevention of significant dete rioration (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 en ergy 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 The Dry Fork coal project proposes utilizing hundred-year-old, pulverized coal (P C) technology that is obsolete even before the plant is built, when Westerne rs are calling for renewable energy and energy efficiency-and at the very least clean coal t echnologies-to meet our goals. How will Wyoming2 meet these goals and encourage new and innova tive 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 he ld with opportunity for interested persons. . .including representatives of the Administrator to app ear and submit written or oral presentations on the air quality impact of such source, alternatives th ereto, control technology requirements, and other appropriate consideratio ns.” In EPA’s implementing regulations for PSD SIPs, it is stated that th e public notice for a proposed perm it 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 provi ding data at only one location, al beit the one with the greatest projected consumption. Different pot ential commentors may have an in terest in different areas to be impacted and would want, and would reasonab ly be entitled to, available data on increment consumption at the area of their particular concern. Otherwise th eir 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 (SO 2 ) increment consumption “near the plant site .” WYDEQ did not identify the degree of increment consumption for NO 2 or PM 10 . Further, WYDEQ did not identify the degree of increment consumption expected in any Class I areas. This omissi on seems particularly egregious for the Northern Cheyenne Indian Reserv ation Class I area, especially considering that

Basin Electric’s cumulative SO 2 increment analysis shows that there would be SO 2 increment

violations in that area and that Dry Fork would contribute to SO 2 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 incremen t consumption at specific Class I areas flows directly from the core statutory purposes of th e 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 hi storic 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 af ter careful evaluation of all the consequences of such a decision and after ade quate procedural opportunities for informed public participation in the decisionmaking process.” CAA Sec. 160(5). Adequate notice is a necessary predicate to informed public par ticipation 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 pr oposed facility and, accordingly, WYDEQ must re-issue its public notice to comp ly with public participation requirements.

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

APPLICATION FAIL TO ADDRESS CARBON DIOXIDE AND OTHER

GREENHOUSE GAS EMISSIONS

Basin Electric’s permit app lication for Dry Fork did not address carbon dioxide (CO 2 ) 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 signifi cant from coal-fired boilers. Based on information in the permit app lication 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 Wy oming have a legal oblig ation to regulate CO 2 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 asso ciated with climate cha nge 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 CO 2 emission is being considered by Congress, and many states (incl uding California) are incr easingly attempting to regulate CO 2 emissions.

At the minimum, WYDEQ should have requ ired consideration of emissions of CO 2 in the Dry Fork best available control technology (BACT) analysis. However, neither Basin Electric or WYDEQ considered CO 2 or other greenhouse gases in the BA CT 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 Admi nistrator stated in that case:

Region IX’s [asserts] that EPA lacks the auth ority to “consider” po llutants 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 unr egulated pollutants. EPA clear ly has no such authority over emissions of unregulated polluta nts. 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 polluta nts in the course of making a BACT determination for the regulated pollutants. EPA’s authority in that resp ect is clear. . . . Hence, if application of a

1 Emissions of CO 2 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 rel ease (or removal) of po llutants that are not currently regulated under the Act, the net en vironmental impact of such emissions is eligible for consideration in making the BACT determination. The an alysis 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. Depe nding upon what weight is assigned to the environmental impact of a particular cont rol system, the control system proposed as BACT may have to be modified or be rejected in favor of a nother system. In other words, EPA may ultimately choose more stringent emis sion limitations for a regulated pollutant

than it would otherwise have chos en 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 concl ude (erroneously in our view) that CO 2 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 impact s 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 th at are otherwise unregulated u nder the PSD provisions – and the

statute is clear on its face that th is inquiry is not limited exclusively to “pollutants” that the CAA otherwise regulates, but encompasses environmen tal 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 phen omenon 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 nume rous and particularly severe adverse public health and environmental conseque nces, including direct heat-related effects, extreme weather events, climate-sensitive disease imp acts, air quality effects, agricultural effects (and related impacts on nutrition), wildlife and ha bitat 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) rece ntly 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 co sts, human health effects, and impact s on habitat, species, ecosystems, and biodiversity. See S CIENTIFIC A MERICAN , 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 warmi ng with increases in a variety of serious environmental, health, econo mic, and ecological impacts. 8

In the BACT context, there is also no reas on to dismiss important considerations of CO 2 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, envir onmental, energy, and welfare consequences of global warm ing are profound. Reducing CO 2 emissions, especially those associated with coal-fired power plants, is th e single most important strategy to fight these

effects. 10 Because coal-fired power plants are the single largest source of CO 2 emissions, they are a critical part of any efforts to address the effects of global warming.

In short, the consideratio n of the consequence of CO 2 emissions as a collateral environmental impact in the BACT analysis is completely independent of CO 2 ’s status as a pollutant under the Clean Air Act or Wyoming law, and considering CO 2 emissions when a new coal plant is

8 The Los Angeles Times recently reported on a new study th at 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-climate20oct2 0,0,4849957.story?c oll=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: Poten tial Impacts on U.S. Forest Resources

, Coastal and Marine Ecosystems and Global Climate Cha nge: Potential Effects on U.S. Resources

, Aquatic Ecosystems and Global Climate Change: Potential Impacts on Inland Fres hwater 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 Impact s 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 Im pacts to U.S. Agricultural Resources . S TERN R EVIEW ON THE E CONOMICS

OF C LIMATE C HANGE , 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 polluta nts. There are other examples as well (e.g., SO 2 reductions under the acid rain program, and the regulations of emission from mobile sources). As a former EPA Assistant General Counsel puts it, ignoring CO 2 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 CO 2 as well. Rather, sizable sources su ch as coal-fired power plants mu st be viewed in terms of their contribution to the cumulative problem of climate ch ange and the need—at least in the absence of a comprehensive regulatory program of CO 2 control—to mitigate that contribution. Foote, 34 ELR at 10665. See also Foote, 34 ELR 10663-665 (discussing among other things why consideration of

CO 2 in this context would not have unintended negative environmental effects). (This paper is included as Attachment 2 to this letter).

10 See, e.g ., S CIENTIFIC A MERICAN , 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 pro cess of pre-construction review), is by farthe most costeffective stage to evaluate the possibility of achieving reductions. 11

Given the potential for extremely severe enviro nmental and public health related impacts from global warming; given that the phenomenon of global warming is undeniably connected to anthropogenic releases of CO 2 ; given that electric power produc tion is the single most significant

source of CO 2 emissions in the U.S. and the world; and given that coal fired power plants (such as the one proposed by Basin Electric) contri bute the vast majority of energy-sector CO 2 emissions; it is simply untenable that the effect s of global warming would be inherently outside the scope of the “collateral impacts” that pe rmit applicants and permitting authorities must

consider in connection with the issuance of PSD permits. Thus, any assertion that CO 2 emissions (and global warming) are someho w beyond the broad mandate to consider “environmental impacts” under the PSD program must be rejected.

At a minimum, therefore, WYDEQ must consider emissions of CO 2 in its BACT analysis for the Dry Fork facility. In fact, the EPA's Oc tober 1990 New Source Review (NSR) Workshop Manual specifically states that "[s]ignificant di fferences in noise levels, radiant heat, or dissipated static electrical en ergy, or greenhouse gas emissions ma y 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 CO 2 Emissions from New Power Plants through New Source Review by Gregory B. Foote (Attachment 2) discu sses the regulatory background to support consideration of CO 2 impacts when permitting a new source and, in par ticular, a new coal-fired power plant. This paper indicates that it is entirely appropriate to consider CO 2 emissions when evaluating environmental impacts under the new source review permit program, and the paper also suggested approaches for evaluating technologies in terms of CO 2 emissions.

As discussed further below, there are technologi es available that produce electricity from coal more efficiently (burning less coal and thus emitting less CO 2 to produce the same amount of electricity) as well as technol ogies that more readily accomm odate carbon sequestration. The Dry Fork permit must not be issued by WYDE Q without such thorough and unbiased evaluation of these other technologies.

Permitting authorities’ obligation to consider co llateral environmental impacts extends not only

to emission of CO 2 , but also to other potential environmen tal impacts, such as the consequences of water use, impacts from the generation of hazardous wastes, and impacts on species and habitat. These obligations gr ow directly from the definiti on of BACT at CAA § 169(3).

The permitting authority, here WYDEQ, must cons ider the full range of potential collateral environmental impacts. This includes consid eration of impacts rela ted to water use and generation and disposal of solid waste products. One of the benefits of IGCC compared with antiquated conventional co al technology is dramatically lowe r water requirements – which may have a variety of environmental benefits (re lated to both water intake requirements and wastewater discharges). Add itionally, IGCC generates consider able 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 CO 2 emissions (by installing CO2 capture and control equipment for example).7 conventional PC plants, and that waste is in a fo rm 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 CO 2 benefits, in the context of an

evaluation of collateral e nvironmental 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 es tablishing 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 incl ude ESA-identified impacts to endangered or threatened species. . . . We therefore conc lude 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 appli cation 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, unde niably, “environmental impacts” – and therefore must be considered in connection with an applic ant’s collateral impacts analysis. Moreover, this obligation exists above and beyond a permitting au thority’s affirmative obligation to assess impacts on soils and vegetation.

The U.S. Fish and Wildlife Service lists 56 threat ened or endangered plant and animal species in the mountain prairie region (including Wyomin g), and another 11 candidates for listing. See http://mountain-prairie.fws.gov/wy.html . Clearly, therefore, an anal ysis of potential impacts on species and habitat is an important part of the information to wh ich the public is entitled during the public comment period (especially where ther e are competing technologies – as discussed herein – that may have significantly different environmental impacts).

Indeed, where competing BACT technologies w ould have significantly different collateral environmental impacts – that would have distinct affects on soils, vegeta tion, and/or threatened or endangered species – the EAB has made clear that this analysis is espe cially 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 specifi cally 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/coa ltech/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 asse ssments and selection (for both primary and secondary emission units); and other collateral envi ronmental effects (such as water, solid waste, and non-PSD air pollutants) – especially when the relative benefits of ot her 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 compone nt of the statutory decision-making process.

3. WYDEQ/BASIN ELECTRIC MUST CO NSIDER THE COLLATERAL COSTS OF

FUTURE CO 2 REGULATION IN THE BACT ANALYSIS

BACT also requires consideration of costs that are relevant to th e selections of one BACT option over another. In this context, costs associat ed with the future regulation of carbon dioxide emissions from power plants should be consider ed in deciding between BACT options for the Dry Fork facility, and BACT options that are less intense emitters of CO 2 should be given preference.

The regulation of CO 2 emissions in the U.S. in the very ne ar 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 Co nvention 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 emi ssion 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 addr essing 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 se nsible course of action; for example, the Stern Report 19

concluded that while the cost of inaction could range from 5 pe rcent to 20 percent of global GDP, the cost of stabilizing ambien t concentrations at 450 to 550 ppm CO 2 -equivalent can be accomplished for about 1 percent of GDP. Accordi ng to the report, the key policies required to meet this goal are the implem entation of carbon emission regulations (such as cap and trade measures), the deployment of low-carbon-tech nologies and further low-carbon innovation, and the removal of barriers to energy efficiency.

15 In this context, relevant difference may include differenc e in the quantity or nature of air emissions, such as NOx, SO2, CO, PM, and mercury, as well as impacts related to ot her 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 climat e change resolution proposed by Senators Bingaman, Specter, Domenici, Alexander, Cantwell, Lieberman, La utenberg, 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 Ap propriations 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 S TERN R EVIEW ON THE E CONOMICS OF C LIMATE C HANGE , available at: http://www.hmtreasury.gov.uk/Independent_Reviews/stern_review_economics_climate_change/sternreview_index.cfm

..9 The general consensus in th e U.S. is that federal CO 2 emission controls are inevitable. Notably, the utility industry as well has begun to recognize that nationa l carbon emission limits are both necessary and desirable; for example, executi ves 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 acti on to address global warming. 20 Tellingly, a diverse group of entities (incl uding utilities, environmental groups, petroleum and chemical companies and others – including BP, Duke Ener gy, DuPont, and the Natural Resources Defense Council) recently formed the U.S. Climate Ac tion Partnership (“USCAP”), calling for “the prompt enactment of national legislation in th e 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 CO 2 in the United States (accounting for nearly 40 percent of U.S. emission), th is industry – and coal-fired power generation in particular – is certain to be among the fi rst industry sectors affected by carbon-related regulation.

As the momentum to regulate greenhouse gas em issions continues to grow around the country and internationally, businesses ar e increasingly recognizing the mone tary 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 ca rbon dioxide emissions will be regulated within the thirty y ear 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 Environm entally Responsible Economies (CERES) convened a Dialogue among experts from the power sector, environmental groups, and the investment community fo cusing on climate change. The Dialogue participants found that greenhouse gas emi ssions will be regulated in the U.S.,

and that the “issue is not whether th e U.S. government will regulate these emissions, but when and how.” 22

• Utility shareholders are recognizing th at the likelihood of regulation of carbon emissions represents a real financial risk, and are asking utilities to disclose those risks. Thirteen major public pension f unds, which manage $800 billion in assets, recently asked the Securities and Excha nge Commission to require companies to disclose the financial risks they face from climate change. 23 Meanwhile, in 2004

alone institutional share holder groups filed 29 pr oposals asking individual companies to outline their response to global warming.

20 See, e.g

., http://www.cleartheair.org/proactiv e/newsroom/release.vtml?id=25835

. 21 See PacifiCorp, “2003 Integrated Resource Plan,” www.pacificorp.com . Idaho Power Company, “Draft 2004 Integrated Resource Plan,” www.idahop ower.com/energycenter/2004irpdraft.htm.

22 Coalition for Environmentally Responsible Economies, “El ectric 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 ta king this financial risk quite seriously. 24

In short, the costs associated w ith the imminent regulation of CO 2 (certainly within the lifetime of the proposed Dry Fork facility) should be expressly considered in connection with the

selection of BACT. Because Ba sin Electric proposes to use a carbon-intensive PC technology, and because other BACT options have significantly better CO 2 emissions performance (in particular IGCC, as discussed below – especial ly when used in conjunction with carbon capture and disposal), 25 the cost of future CO 2 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 PRO DUCTION PROCESSES AND AVAILABLE METHODS, SYSTEMS AND TECHNI QUES TO LOWER AIRBORNE

CONTAMINANTS

24 Moreover, emission allowances that effectively “grandfather” the CO 2 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 a dopt legislation in the near term that

is consistent with the 2005 U.S. Senate resolution callin g 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 CO 2 than pulverized coal tec hnologies because of its great er efficiency, but it also provides the ability to capture and dispose of CO 2 in order to reduce CO 2 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 CO 2 , beginning in 2004 and escalated at 5 percent per year, in lo ng-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 Rega rding 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 CO 2 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 CO 2 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 emissi on from a facility like Dry Fo rk could create a significant

financial burden.11 Section 165(a)(4) of the Clean Ai r Act (CAA) provides that “no ma jor emitting facility on which construction is commenced after August 7, 1977, ma y be constructed in an y area to which this part applies unless...the facility is subject to the best ava ilable control technology for each pollutant subject to regulation under this chap ter 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 th e 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 t echnology. Additionally, it requir es 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 econo mically infeasible.

BACT is specifically defined under Wyoming law as follows:

an emission limitation (including a visi ble emission standard) based on the maximum degree of reduction of each pollutant subjec t 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 Administ rator, on a case-by-case basis, taking into account energy, environmental, a nd economic impacts and other costs,

determines is achievable for such sour ce 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 th e 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 t echnologies improve and ne w 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 source s, pollution control methods could be

27 42 U.S.C. §7475(a)(4).12 efficiently and cost-effectively engin eered 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 “r apid adoption” of improvements in emissions control technology. 29

The definition of BACT includes coal gasification. The legislat ive history of the amendment adding the term “innovative fuel combustion techni ques” to the Clean Air Act’s definition of “BACT” is clear. Coal gasifica tion must be considered. The rele vant passage of the debate is excerpted below:

Mr. HUDDLESTON. Mr. President, the pr oposed provisions for application of best available control technology to a ll new major emission sources, although having the admirable intent of achievi ng consistently clean air through the required use of best controls, if not prope rly 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 applicati on of production processes and available methods systems, and t echniques, including fuel cleaning or treatment.” And I believe it is likely th at the concept of BACT is intended to include such technologies as low Btu ga sification and fluidized bed combustion. But, this intention is not explicitly spe lled out, and I am co ncerned that without clarification, the possibility of misinterpretation would re main. 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, gasificati on, 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 ju st 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 mana gers 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 thi nk 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 a nd 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 cons ideration 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 (includi ng specifically innovative combustion techniques such as coal gasification). Ind eed, 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 great er 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 availabl e methods, systems, and techniques, including fuel cleaning, clean fuels, or treatment or i nnovative fuel combustion techniques.” CAA Sec. 169(3).

EPA and federal courts have consistently inte rpreted the BACT provisions found in the Clean Air Act and the EPA’s regulations as embodying cer tain core criteria th at require the permit applicant either to implement the most effectiv e available means for minimizing air pollution or justify its selection of less e ffective 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 ‘m aximum’ and ‘achievable.’” Alaska v. EPA, 540 U.S. 461 (2004).

In Citizens for Clean Air v. EPA

, 32 the Ninth Circuit held that “in itially the burden rests with the PSD applicant to identify the best available cont rol.” As stated in long-standing EPA guidance, “[r]egardless of the specif ic methodology used for determining BACT, be it ‘top-down,’ ‘bottom-up,’ or otherwise, the same core criteria apply to any BACT anal ysis: the applicant must consider all available alternatives, and [either se lect 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 di smissing any available technologies.

Consistent with these core criteria, the EPA’ s NSR Workshop Manual esta blishes 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" s hould 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 mechanis ms for reducing emission of hazardou s 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 (9 th 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" contro l 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 technol ogies and techniques incl ude the application of production process or available methods, systems, and techniques , including fuel cleaning or treatment or innovative fuel co mbustion techniques for control of the affected pollutant. This includes tech nologies employed outside of the United States. As discussed later, in some circumstances inhere ntly lower-polluting processes are appropriate for considerat ion as available control alternatives. 34

EPA further explains that potential control options can be categor ized 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 pro cesses, EPA explains that “[l]ower-polluting processes should be considered based on demonstrations made on the basis of manufacturing identical or si milar 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 ch annels or is otherwise ava ilable within th e common sense meaning of the term.’” 37 In keeping with the stringent na ture 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, applican ts must apply the best available control technology unless they can demonstrate that th e 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 appl y the best technology available.” 39 That is, a BACT review

34 NSR 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 most15 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 ava ilable technologies, including the mo st stringent, and to provide adequate justification in the administrative reco rd for dismissing any of the technologies based on relevant statutory fact ors – must be satisfied. 40

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

all available control measures. IGCC is co mmercially available t oday and it reflects an inherently lower emitting process for producing elect ricity from coal. Therefore, this technology should have been thoroughly ev aluated 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 construc tion permit application, Ba sin 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 combusti on 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 genera ting electricity from coal th at could significantly reduce emissions from the facility. 41 This decision on the part of WY DEQ flies in the face of the plain language of the Clean Air Act, the clear expressi ons of Congressional inte nt, and the rulings of

the EAB.

EPA has argued in other contexts that the concep t of “redefining the s ource” 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 in terpretation 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 conj unction with a new coal mine, needed to consider (as an element of its BACT an alysis) using coal that was lower in sulfur than the coal that the co-located mine would pr oduce. 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 T he 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 availa ble, 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 NO

x , SO

x , CO, VOC, and PM. See, e.g., Permit Application for Nuece s 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 so me other source of coal instead would defeat the purpose of the original perm it 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 re quire Prairie State to redefine the fundamental purpose or basic design of its proposed Facility, and that, therefore, low-sulfur coal could appr opriately be rejected fr om further BACT analysis at step 1 of the topdown review method.” Prairie State at 36-37.

Even assuming that the Board’s de cision in Prairie State was consis tent with the Clean Air Act, that decision clearly demonstrat es that WYDEQ’s failure to re quire considerat ion of innovative combustion technologies as process options for co ntrolling emission from the Dry Fork plant is fundamentally flawed. First, the EAB’s ruli ng recognized that the default assumption under the Clean Air Act’s PSD provisions is that the use of potentially cleaner fuel s (such as low-sulfur coal) will normally be a require d part of the BACT analysis. 43 Only where some unique element of the facility’s basic purpose made th e 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 deci sion in Prairie State reflects an understanding that the concept of redefining the source must be subordinate to the primary obj ectives of the BACT analysis. That is, the specific requirements inherent in th e definition of BACT will define the obligations of permit applicants and permitting authorities, un less some specific fundamental conflict exists. Moreover, while the Board concluded that the perm it issuer should look “in the first instance” at “how the permit applicant, in pr oposing the facility, defines the goals, objectives, purposes, or basic design for the proposed facility,” the pe rmit applicant cannot mani pulate the definition of the facility as a mechanism to a void appropriate BACT analysis. Prairie State at 29-30. In evaluating the permit, the permit issuer must “dis cern which design elements are inherent to [the] purpose [of the facility], articulated for reason s independent of air quality permitting, and which design elements may be changed to achieve pollu tant emissions reduction s without disrupting the applicant’s basic busin ess purpose for the pr oposed 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 consid er 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 lif e. 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 ov er 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; simila rly, “the business objective of avoi ding risk associated with new,

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

State at 30 n.23. Rather, cost and risk considerati ons are appropriately ad dressed 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 co ncept of “redefining the source,” as well as Wyoming law. First, as discussed above, th e Clean Air Act and Wyoming’s PSD regulations specifically calls for considera tion of “the application of production processes and available methods, systems, and technique s, 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, requ ires as a part of the BACT analysis the

consideration of innovative tec hnologies 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 mu nicipal waste combustor and, instead, require the county to dispose of its waste by co-firi ng 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 opt ion 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 petiti oner was asking EPA to “redefine the source” from a waste combustor to a power plant. 46 The Administrator subs equently 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 hi story 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 obj ections 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 Administrato r 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 po lluting process and cleaner fu el – as part of a BACT

determination. Id. The Administrator specifically reject ed the idea that requiring consideration of cleaner fuel constitutes “redefining the sour ce” 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 pr ior Administrator interpretations in Pennsauken and Hibbing , which constitute the agency’s official pos ition, the draft Manual is not entitled to any

deference. 49

Because the Clean Air Act specifi cally 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 fundament ally at odds with the primary objective of the project, based on appropriate co nsiderations 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 petroleu m coke-fired plant], is seekin g 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 thei r 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 Hibb ing 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 app lication of the “redefining the source” policy is due no

deference because it conflicts with th e 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 (4 th 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 confir ms 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 processe s 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 reas ons 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 arti culated 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 ap plicants to consider

IGCC.

In Prairie State , the Petitioners argued that the scope of EPA’s “redefinin g the source” policy lacked any “principled standard s,” and would therefore allow pe rmit 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 s ubmit 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, bu t 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] a pplication of the policy against redefining the design of the source through applic ation 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 F acility, 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 t echnology 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 analys is inadequate, WYDEQ’s failure to specifically identify why IGCC was not evaluated in the BACT analysis has depr ived 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 auth ority to require consideration of IGCC, such consideration must be within the permitting authority’s discretion under the statutory de finition 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, Illinoi s EPA to Diana Tickner, Prairie State (March 29, 2003), that letter is incorporated by reference here.

54 In its analysis, the Board specifica lly recognized that EPA guidance requires consideration of process-related technology advances like IGCC. Prairie State at 33 (“The NSR Manual also st ates with respect to production processes, that where ‘a given production process or emissi on 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 expl ain 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 ma y be improved to reduce its pollutant emissions.” Id at 33- 34. By “hard look” it is clear that th e Board means a real, substantive BACT ex amination 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 perm it 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 analys is 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” ex emption – WYDEQ has not taken a “hard look” at whether20 In contrast, for the Dry Fork facility, WYDE Q has completely abrogated its BACT-related responsibilities when it comes to iden tifying “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 requi red at the facility,

that determination resulted from the Board’s conc lusion that IGCC was esse ntially equivalent to the proposed boiler technology in terms of its potential emission contro l 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 capab le of achieving a level of emissions performance for virtually every regulated PSD pollutant that is significantly be tter than the performance of a

PC boiler. 55 Moreover, as discussed already, IGCC plants have a multitude of collateral environmental benefits: they provide opportuni ty for higher reductions in hazardous air pollutants like mercury, they pr oduce less solid waste, they use less water, and they both emit

less CO 2 and provide the ability to capture CO 2 emissions for permanent storage to help address global warming. Accordingly, the Board’s justification for reject ing 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 recogni zed IGCC as an “inherently low-polluting process/practice,” 57 and has reaffirmed its view that IG CC is an available method for cleaning and treating coal to remove air pollutants prior to combustion:

One approach to controlling SO 2 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-tr eat 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 NO

x , 0.017 for SO 2 , 0.037 for CO, 0.003 for VOC, 0.006 for PM and PM 10 , and 0.001

for H 2 SO 4 . There are other recent permit applications in th e record that also dem onstrate 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 Po wer Plants, available at: http://www.netl.doe.gov/c oal/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 BA CT 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 T echnologies 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 ap art into its chemical constituents (typically a mixture of carbon monoxide, hydroge n, and other gaseous compounds) prior to combustion. The product gas is then cleaned of contaminants prior to combustion. Gasification reduces SO 2 emissions by over 99

percent. 58

As a result of fuel cleaning, IGCC un its “will inherently have only trace SO 2 emissions because over 99 percent of the sulfur a ssociated 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 st atutory intent of reducing emissions through process changes, available methods and sy stems and techniques, innovative combustion techniques, and fuel cleaning, and because WYDE Q failed entirely to conduct an analysis of IGCC as a possible control opti on, 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 w ithdrawn, and WYDEQ must ev aluate in detail the potential for applying IGCC and make its determin ation and its justificat ion 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 ap proval of equivalent st ate 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 el ectric generation facility to conduct a robust analysis of IGCC as a core element of its BACT analysis:

Additional material must be pr ovided in the BACT demonstr ation to address Integrated Gasification Coal Combustion (IG CC) as it is a `production pro cess’ that can be used to produce electricity from coal. In this rega rd, the Illinois EPA has determined that IGCC qualifies as an alternative emission control tech nique 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 U tility 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 feas ible production process.

Accordingly, Indeck must provide deta iled information addressing the emission performance levels of IGCC, in terms of e xpected emissions rates and possible emission reductions, and the economic, environmen tal and/or energy impacts that would accompany application of IGCC to the proposed plant. This information must be accompanied by copies of relevant document s that are the basis of or otherwise substantiate the facts, statements and repr esentations 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 an alysis 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 En ergy Station, also relied, in part , on the failure of the permit applicant to consider cleaner co al combustion technology in finding th e 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 techno logies 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 fo r a new coal-fired pow er 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-specifi c analysis of IGCC and CFB in order to make a determination regarding BACT fo r the proposed facility.” The New Mexico determination goes on to provide: “The analysis must include a discu ssion of the technical feas ibility and availability of IGCC and CFB for the proposed site in McKi nley County, including a discussion of existing IGCC and CFB systems.” 64

On August 29, 2003, New Mexico issued its eval uation of the applicant’s response. New Mexico found that the applicant’s BACT anal ysis had in fact indicated that IGCC is commercially available but that the applicant ha d 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 Pres ident, 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 technicall y feasible control options for the Mustang site. After careful review of the revised BACT analysis, as well as information gathered from independent s ources, 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 to p 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 availa ble 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 in dicates 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 av ailable 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; Reli ant 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 technica lly feasible when the

resolution of technical difficulties is a matter of cost. See NSR Manual at B.19-20. Mustang’s revised BACT analys is indicates that the resolution of

technical difficulties for both IGCC and CF B are a matter of cost. These costs do not support a finding of technical in feasibility, but may be considered during Step 4 of the t op down BACT methodology. See NSR Manual at

B.26. 65

In addition, the Montana Board of Environmental Review found that the M ontana Department of Environmental Quality must consider IGCC as an available technology in the BACT review for a coal-fired power plant. Specifically, the Boar d of Environmental Review stated “. . .the Department should require applican ts to consider innovative fuel combustion techniques in their BACT analysis and the Departme nt should evaluate such techni ques 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, wh ile some of these states were operating under SIP-approved PSD programs, the definition of BACT that applied in all cases is vi rtually identical to the federal definition of BACT (as is Wyoming’s) with resp ect to consideration of inherently lower emitting processes. It is noteworthy that these states determined it was entirely appropriate, indeed necessary, to require considerati on of IGCC in the BACT review for a coal-fired power plant.

The aforementioned state determinati ons 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 NEVC O Energy’s Sevier Powe r Company Project in which EPA requested that furthe r documentation on costs be pr ovided 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 po lluting 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 consid er IGCC in the BACT analysis.

Thus, for all of the reasons described above, WY DEQ 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 ANALYS IS 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 CO 2 , that cause global warming, and a general increase in efficiency over other co al burning technologies. However, the permit application for Dry Fork does not evaluate coal technology and instead focused solely on the construction of PC coal co mbustion. 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 th e 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 fe deral case law, EPA adju dicatory decisions, and the NSR Workshop Manual, demonstrate that an available technique su ch as IGCC must be

identified and evaluated as a c ontrol 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 tec hnology is a commercially available and proven process. IGCC units generate electricity by inte grating a coal gasifier with combined cycle (combustion turbine and steam tu rbine) 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 gasifica tion process and IGCC is r eadily 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 techno logy 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 th at “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 genera te electricity, or as a basic raw material to produce chemicals and li quid fuels.” A prime source of information is

available on the GTC website includ ing papers and presentations co mpiled into an on-line library

68 The Department of Energy also has a website dedicated to gasification: http://www.netl.doe.gov/technologies/coalpow er/gasification/database/database.html

.27 that can function as an important resour ce for both utilities and regulators. See http://www.gasification.org/library.htm . Among the important resources on this website is information about gasification generally, IG CC, and use of IGCC with low-rank coals; 69

information about the readiness of IGCC t echnology 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 presenta tions about gasifica tion and IGCC technology. 73

In the face of the remarkable wealth of available informati on, WYDEQ has made the clearly arbitrary decision to ignore IGCC entirely as a possible option for th e proposed Dry Fork facility. Even a cursory examination would demonstrate th at 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 for ce in the utility industry – for example, in July 2006 EPA issued a report entitled Environmental Footprints and Co sts of Coal-Based Integrated Gasification Combined Cycle and Pulverized Coal Technologies, 76 which examined various aspects of IGCC. 77 Given the wealth of available info rmation, the fact that WYDEQ has failed utterly to examine the possibi lity of employing IGCC as a technology option for the proposed Dry Fork plant is demonstrably at od ds with its statutory responsibilities. 78

69 http://www.gasification.org/Do cs/Bismarck%2006/02Amick.pdf ; http://www.gasification.org/Docs/Bismarck%2006/01Phillips.pdf

. 70 http://www.gasification.or g/Docs/Tampa%2006/Ely.pdf

. 71 http://www.gasification.org/Docs/Bismarck%2006/03RJones.pdf ; http://www.gasification.org/Do cs/Bismarck%2006/05pan.pdf

. 72 http://www.gasification.org/Do cs/Bismarck%2006/07Smet.pdf ;

73 http://www.gasification.or g/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/seq uestration/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 seri ously 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 direct ed at refining the technolo gy, making it cheaper, more reliable, and more commercially attrac tive, 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/c oal/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 (P SD 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 effectiv e 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 IG CC Facility with Add-On Polluti on Controls is Inherently Less Polluting than Producing El ectricity with a Pulv erized Coal Facility

The coal gasification fuel-processing step in IGCC power plants results in superior environmental performance and lower emissions co mpared 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 per cent can also be achieved using currently available control technologies with IGCC. 80 DOE states that “an IGCC power pl ant has the potential of achieving very high mercury removal performance with es tablished technology” an d 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 perm it 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 equiva lent 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/Synaps ePaper.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/Sy napseReport.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/i ssues/gambling_with_coal.pdf (Union of Concerned Scientists Report); S TERN R EVIEW ON THE E CONOMICS OF C LIMATE C HANGE , 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/coa lpower/gasification/pubs/pdf/C oal%20Gasificati on%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 Dr y 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)

NO

x 0.05 (12 month rolling) 0.0246 (24-hour average)

VOC 0.0037 (limit not in draft permit 82 ) 0.006

PM 10 0.012 (filterable) 0.0063

CO 0.15 0.036

Sulfuric Acid Mist SO 2 limit is surrogate for BACT 0.0026

SO 2 0.08 (12 month rolling) 0.0117 (3-hour average)

Hg 0.0000102 83 0.0000019 84

* All IGCC emission rates for the BACT analys is 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 ra te. As discussed in footnote 84, the mercury emission rate is from the Christian County Ge neration permit application for the Taylorville IGCC facility. A copy of the proposed permit is in cluded 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 NO

x , SO 2 , PM 10 , CO, and mercury, as well as significantly lower amounts of the climate changing emissions of CO 2 . As previously stated, IGCC facilities are typically more efficient than pulverized coal-fir ed boilers, thus producing less CO 2 compared to a PC boiler producing the same amo unt of electricity. 85 Furthermore, IGCC allo ws for an option to make even deeper cuts in carbon dioxide that conventional coal plants cannot do. The CO 2 in the syngas can be captured and sequestered at a fr action 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 ge nerating 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 Pu lverized Coal Technologies,” at ES-7. Attachment 13.30 The waste leaving an IGCC plant is vitrified, th ereby potentially reducin g some of the solid waste disposal issues associat ed 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 th e environmental impacts of the solid waste

associated with different technology options.

IGCC is clearly an available method, system and technique for producing el ectricity from coal and thus must be fully and fairly evaluated in th e Dry Fork BACT analysis. Basin Electric and/or WYDEQ must develop average and incremental co sts for each pollutant removed and compare these costs to the proposed configur ation 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 cons truction 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 per cent to 17 percent less coal to produce the same amount of electricity 88 . Thus, supercritical boilers em it less carbon dioxide emissions than

conventional subcritical PC boilers to produce the same amount of electricity. Further, such supercritical boilers achieve up to 17 percen t lower emission rates of carbon monoxide (CO), nitrogen oxides (NO

x ) and sulfur oxides (SO

x ), 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 NO

x , SO 2 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 boile rs, 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 Rive r 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 envi ronment [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 Ta ble ES-1 of EPA’s Final Report entitled “Environmental Footprints and Costs of Coal-Based In tegrated Gasification Combined Cycle an d 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 Pu lverized 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 significantl y flawed without evaluating supercritical boiler technology for the Dry Fork power plant. W YDEQ and Basin Electric must evaluate the installation of both a supercritical and an ultra supercritical boile r at Dry Fork as inherently lower emitting processes and a more environmentally beneficial technologies, with lower hourly

and annual emissions of a ll pollutants including CO 2 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 propos ed limits aren’t consistent with the averaging times of the NAAQS and other PSD standards, WYDEQ has not proposed BACT limits on all regulated pollu tants, and that the proposed lim its 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 H ave 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

NO

x 0.05 lb/MMBtu (annual average) 190.1 lb/hr (30 day average)

SO 2 0.08 lb/MMBtu (annual average) 304.1 lb/hr (30 day average)

PM/PM 10 (filterable) 0.012 lb/MMBtu (no averag ing time indicated)

CO 0.15 lb/MMBtu (no averaging time indicated)

EPA’s NSR Workshop Manual and ot her 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 al so November 24, 1986 EPA memo with subject

“Need for Short-term Best Available Contro l 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 c ontinuous 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 tim es do not effectively en sure that the control technology will be used to limit emissions of air pollutants to the maximum extent achievable on32 a continuous basis. Such long averaging times w ill allow Basin Electric to operate the Dry Fork facility at uncontrolled emission rates for so me periods and still comply with the proposed annual average or 30 day average emission limits.

Accordingly, WYDEQ must impose BACT limits w ith 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 SO 2 BACT limit must be based on a 3-hour averaging time, the PM 10 limit must be based on a 24-hour averaging time, and the CO lim it must be based on an 8-hour averaging time.

Further, in assessing compliance with visibil ity protection requirement s 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. Th is would pertain to the BACT limits for NO

x , SO 2 , and PM 10

.

As demonstrated below in our specific commen ts 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 NO

x BACT Limit Does Not Reflect the Maximum Degree of Reduction

that Can Be Achieved at a Pulverized Coal-Fired Boiler

As previously cited, the WAQS R define “BACT” as follows:

an emission limitation (including a visi ble emission standard) based on the maximum degree of reduction of each pollutant subjec t 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 Administ rator, on a case-by-case basis, taking into account energy, environmental, a nd 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 NO

x BACT limits do not reflect the maximum degree of

reduction in NO

x 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 NO

x burners with overfire air and selective catalytic re duction (SCR) to control NO

x .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 seve ral Texas coal-fired el ectrical generating

units to determine emission rates reflective of NO

x BACT for Dry Fork. Consideration of this type of data is extremely import ant in a BACT determin ation, but WYDEQ should have also gathered and considered other av ailable data on pollution reduction capabilities from control technology vendors, consultants, and technical journals and reports. See NSR Workshop Manual, Octobe r 1990 Draft, at B.11.

First, Basin Electric indi cated that the outlet NO

x 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, techni cal papers and vendor

information indicate that much lower NO

x emission rates can be achieved with current

state-of-the-art low NO

x burners and overfire air. For example, available vendor

information for ultra low NO

x burners with overfire air indicates that boiler outlet NO

x 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 subbitumi nous Powder River Ba sin coal showed NO

x emission rates with ultra low NO

x burners and overfire air th at were generally less than

0.13 lb/MMBtu. 93 Basin Electric has indi cated that the planned PC boiler at Dry Fork will be either tangentially-fired or wall-f ired. See November 10, 2005 Application for Permit to Construct Dry Fork Station Projec t at 2-5. Even with a wall-fired boiler burning subbituminous coal, similar low NO

x emission rates have been met with current

state-of-the-art low NO

x burners and overfire air. Fo r example, a study conducted at a 600 MW wall-fired subbituminous coal burning boiler found that NO

x emission rates of 0.15 lb/MMBtu or lower (as low as 0.138 lb/MMBtu) were achieved with Low NO

x Dual

Air Zone CCV® Burners and overfire air. 94

Further, neither Basin Electric nor W YDEQ evaluated the maximum degree of NO

x reduction that can be achieved with SCR at Dry Fo rk. Assuming Basin El ectric’s claim of NO

x emission rates exiting the boiler of 0.20-0.25 lb/MMBtu (which we think is too high, as discussed above),

the NO

x BACT emission limit proposed by Basin Elect ric of 0.07 lb/MMBtu only reflects a 65 percent to 72 percent reduction in NO

x 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 refl ects 80 percent control from the SCR. If the

NO

x emission rates exiting the boile r are 0.15 lb/MMBtu or lower, which is most likely if current

state-of-the-art low NO

x burners are used, then a NO

x BACT limit of 0.05 lb/MMBtu only reflects a 67 percent NO

x reduction from the SCR. Yet, SCR systems can reduce NO

x 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 NO

x 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 NO

x 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 NO

x Emissions to Below 0.15 lb/10 6 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 NO

x reductions can be achieved with low ammonia slip. 95 Indeed,

Babcock & Wilcox states that up to 95 percent NO

x control can be achieved with SCR.

Using Basin Electric’ s projections of NO

x emissions exiting the boiler of 0.20 to 0.25 lb/MMBtu, 90 percent control with the SCR system would equate to a NO

x emission rate of 0.020 to 0.025 lb/MMBtu. However, as shown above and in the attached documents, a NO

x rate exiting of the boiler of 0.15 lb/MMBtu (or lower) can be ach ieved with state-of-the-art ultra low NO

x burners

and overfire air at a subbituminous coal-fired PC boiler. Thus , with 90 percent control with SCR, a NO

x emission rate of 0.015 lb/MMBtu could be met. WYDEQ failed to require Basin

Electric to evaluate either of these NO

x emission rates, and thus WY DEQ failed to require Basin Electric to evaluate the maximum degree of NO

x emission reduction that can be achieved, as required by the WAQSR BACT rules.

Further, the lb/MMBtu NO

x BACT limit for Dry Fork must apply on a shorter averaging time than the proposed 12-month rolli ng average limit. Not only is it important for the averaging time of the BACT limit to be equal to or shorter than the most stri ngent averaging time of the NAAQS or PSD standards (which in the case of NO

x 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 NO

x pollution control equipment in a manner consistent with achieving the maximum reduction in emissions on a continuous basis. Further, a rolling 12 month average NO

x 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 maximu m 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/MMB tu 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 lim it will allow emission levels higher than 0.05 lb/MMBtu. Thus, to more effectively ensure th at 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 propos ed 12-month rolling average.

It is for these reasons th at annual average or even 12-month rolling average NO

x BACT limits are virtually unheard of in any recent PSD permitti ng actions for new coal-fired power plants. At most, NO

x BACT limits have been imposed with rolling 30-day averaging times, and more commonly, NO

x 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 Manua l, 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, Pr esented 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 NO

x BACT limit than has typically been required in recent PSD permitting actions for new coal-fired power pl ants, that does not just ify a longer averaging time. Indeed, WYDEQ’s own research found th at such a limit was being met on a shorter averaging time. WYDEQ Permit A pplication Analysis at 5. As we have shown above, even

lower emission limits could be met with ultra low NO

x burners, overfire air, and an SCR system operated to achieve the maximu m degree of reduction in NO

x emissions that is achievable.

Thus, for all of the above reasons, WYDEQ must revise the proposed NO

x BACT limit for Dry Fork to be reflective of the maximum degree of NO

x reduction that can be ach ieved. Further, the

revised NO

x BACT limit must be based on an averaging time that requires the NO

x control equipment to be operated to achieve the maximum amount of con tinuous reduction in NO

x emissions that is achievable.

c. The Proposed SO 2 BACT Limit Does Not Reflect the Maximum Degree of Reduction

that Can Be Achieved at a Pulverized Coal-Fired Boiler

WYDEQ has proposed a SO 2 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 averag e. Neither WYDEQ nor Basin Electric has sufficiently demonstrated that these emission limits reflect the maximum degree of SO 2 emission reduction that is achievable at the proposed Dry Fork facility.

First, WYDEQ notes that the Newmont Nevada TS power plant has a lower SO 2 BACT emission limit. Specifically, the Newmont PSD permit has an SO 2 limit of 0.065 lb/MMBtu that applies on a 24-hour averaging time, along with a SO 2 removal efficiency requ irement 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 statemen ts that it could not obtain a vendor guarantee for an SO 2 emission rate of less than 0.08 lb/MMBtu when another similar plant burning similar coal and using si milar pollution control equipment apparently could obtain a vendor guarantee for a lower emission lim it (or, at the least, Newmont Nevada has not appealed its PSD permit that requires th e power plant to meet these lower SO 2 emission limits) provides ample reason why it is no t 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 gua rantee 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 SO 2 removal efficiency required. The Newmont Nevada TS Power facility SO 2 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 bur ning coal with sulfur content equal to or greater th an 0.45 percent, the SO 2 BACT emission requirements are 0.09 lb/MMBtu, 24-hour average basis, and a minimum of 95 pe rcent control, 30 day average basis. See36 Attachment 20 with May 5, 2005 Newmont Nevada Energy Investment Class I Air Quality Operating Permit to Construct. WYDEQ’s proposed SO 2 BACT limit of 0.08 lb/MMBtu that would apply on a 12-month rolling average is nowh ere near as stringent as the Newmont limits. Even when coal with 0.45 percent sulfur cont ent or greater is burned, the proposed Dry Fork

limit of 0.08 lb/MMBtu with its l ong 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 Fork 96 , as compared to the minimum 95 percent SO 2 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 SO 2 emission rate expected at Dry Fork. 97 Worse yet, the proposed Dry Fork SO 2 BACT limit only reflects 86.7 per cent control from the lowest

uncontrolled SO 2 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 Perm it Application Analysis is of little importance given that much more stringent SO 2 requirements have been requi red as BACT at the Newmont Nevada TS power plant - a facility that will be equipped with similar SO 2 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 sour ces 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 unusua l 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 em ission rates less than 0.08 lb/MMBtu which, as discussed above, is unpersuasive.

In addition to the proposed Dry Fork SO 2 limits being less stringent than the Newmont Nevada TS power plant limits, the WYDEQ’s proposed SO 2 BACT emission limit for Dry Fork also fails to reflect the degree of SO 2 reduction that can be achieved acr oss a spray dryer/absorber. Using

AP-42 emission factors to es timate the uncontrolled SO 2 emissions exiting the proposed Dry

Fork boiler 101 , the worst case uncontrolled emission ra te would be 1.05 lb/MMBtu, the average

96 Uncontrolled SO 2 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 SO 2 emission rate expected at Dry Fork wa s 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 uncontro lled 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 SO 2 emission rates provided in Ba sin 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 re flect 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 SO 2 removal efficiency across the spray dr yer/absorber at best, an 88.9 percent SO 2 removal efficiency on average, and an 84.8 perc ent removal efficiency when lowest sulfur, highest heating value coal is burned. As indicated in WYDEQ’s Permit Application Analysis,

Basin Electric has indicated that th e “lowest emission guarantee available for SDA [spray dryer/absorber] is 94 percent.” (WYDEQ Pe rmit Application Analysis at 11 (emphasis added). There is ample indication in PSD permit applicat ions that spray dry absorbers can achieve at least 90 percent SO 2 removal even with low sulfur coals. 103 Indeed, as found by EPA in its

review of the New Source Performance Standards fo r coal-fired electric utility boilers, a spray dryer/absorber can generally achieve greater than 90 percent SO 2 removal. See 70 Fed.Reg. 9711 (February 28, 2005).

WYDEQ must also take into ac count other impacts in settin g BACT including environmental impacts. In the case of Dry Fork, this facility will contribute to SO 2 increment violations at the Northern Cheyenne Indian Reservation Class I area. Although WYDEQ cl aims the facility’s impacts will be less than the pr oposed “Class I significant impact le vels,” that is irrelevant for two reasons: First, the Class I significant impact s levels are not authorized in any state PSD regulation. Second, even if use of such significant impact levels we re authorized under state law, EPA Region VIII has previously indicated that any impact in an area with existing increment

violations must be c onsidered significant. 104 WYDEQ has known about these predicted SO 2 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 Fede ral Land Managers’ (FLM) deposition analysis thresholds (DATs) at Wind Cave National Pa rk and at the Northern Cheyenne Indian Reservation. Further, Basin Electric’s modeli ng 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 envi ronmental impacts into account in setting SO 2 BACT limits for Dry Fork.

For all of the above reasons, SO 2 BACT for Dry Fork must be at least as stringent as the SO 2 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 SO 2 removal efficiency

102 These emission rates were calculated using AP-42 SO 2 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 pr ovided 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 SO 2 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 SO 2 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 SO 2 emission limit to ensure that the control equipment will be operated to achieve the maximum degree of emissi on reduction over all of the varying levels of

uncontrolled SO 2 emissions expected at the Dry Fork facili ty. It is also im portant to note that there are no exemptions from the SO 2 BACT limits in the Newm ont Nevada TS power plant permit. Thus, there is also absolutely no jus tification for adding a safety margin to the limits that have been imposed at the similarly confi gured Newmont Nevada TS power plant. WYDEQ must revise its proposed BACT emission limit fo r Dry Fork and impose emission limitations and requirements that ensure the ma ximum degree of reduction in SO 2 emissions that can be achieved with the spray dry/absorber will actually be achieved at Dry Fork.

c. The Proposed Mercury BACT Limit Do es 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 li mit that applies under the New Source Performance Standards. WYDEQ’s proposed permit also requ ires Basin Electric to undertake a mercury reduction optimization study with a ta rget emission rate of 20 x 10 -6 lb/MWh, and to install “a mercury control system.” Based on the optimi zation study, the mercury limit would be revised.

WYDEQ provided no justification for this approach to setting mercury BACT in its permit application analysis. Instea d, 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, economi cs 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 menti oned installation of a sorbent injection system and even stated it would leave space available for inst allation 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 informati on indicating that sorb ent injection is an

available and effective control measur e for reducing mercury emissions.

For example, the owners of two new coal-fired power plants in Montana have agreed to use activated carbon injection fo r mercury control (i.e., the Hardin and Roundup power plants 105 ).

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, wh ich 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 Tec hnical Support Document for MidAmerican Energies’ Unit 4 at the Council Bluffs Energy Cent er 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 pl anned criteria pollutant control technologies. 108
Not only will all of these facilities be burning su bbituminous coal, but they will also be equipped with SCRs, spray dryer/absorber s 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 cons idered 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 mercur y-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 me rcury at subbituminous power plants, especially those equipped w ith spray dryer absorbers (SDA). The SDA may remove halogens in the flue ga s that are needed for the adsorp tion of elementary mercury with

untreated activated carbon. With a halogenated carbon injection sy stem 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 th e 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 ca rbon (B-PAC) is a halogenated sorbent that ha s also shown high levels of mercury control acro ss a range of coals. For exampl e, full-scale tests of B-PAC at the St. Clair power plant in De troit, Michigan, which burns at least 85 percent subbituminous coal blended with bituminous coal and is equipped with an electrostatic pr ecipitator, showed that greater than 90 percent mercury removal could be routinely achieved. 110

Basin Electric provided averag e coal mercury contents of 0.0 5 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 pe rmit application in A ppendix B under “Criteria Pollutant Potential to Emit”), these values eq uate to uncontrolled mercury emission rates of

62.2 to 100.2 x 10 -6 lb/net MWh. Thus, WYDEQ’s propos ed 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 re vised permit pursuant to the mercury reduction optimization study currently proposed for Dry Fork) only reflects 68 pe rcent 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 achie vable 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 Te chnologies 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 Tes ting 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 correspondi ng emission limits ranging from 6.26 to 10.02 x10 -

6 lb/net MW (based on Basin Electric’s range of me rcury 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 evalua ted as reflecting BACT for Dry Fork. WYDEQ should also re quire 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 additi on 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 cont rol 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 ac hieved 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 fo r 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 re duction 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 (H 2 SO 4 ) 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 fo r 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 Emissi on Limit Reflective of BACT at the Dry Fork Facility

The Wyoming definition of BACT explicitly st ates that BACT includes a “visible emission standard.” Chapter 6, Section 4(i) of the WAQS R. Yet, WYDEQ has not evaluated or proposed

a visible emission standard refl ective 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 PM 10 control, an opacity BACT limit should be at least 10 percent. Indeed, the recently permitted Intermount ain 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 syst em (COMS) must be required.

8. WYDEQ MUST IMPOSE A LIMIT ON TOTAL PM 10 CONSISTENT WITH PM 10 AND VISIBILITY MODELING CONDUCTED FOR DRY FORK

While WYDEQ proposed a BACT emission limit for filterable PM 10 emissions at Dry Fork, WYDEQ has failed to propose any limit on total PM 10 emissions, i.e., filterable plus condensable emissions. Yet, condensable PM 10 emissions affect PM 10 concentrations as well as visibility. 114
Indeed, WYDEQ required consideration of condensable PM 10 emissions in the modeling analyses conducted for Dry Fork. See WY DEQ Permit Application Analysis at 22. Accordingly, WYDEQ must impose an emission limit on total PM 10 emissions reflective of the

level of PM 10 emissions modeled for Dry Fork in its ne ar field and far fiel d analyses. Without

such a limit on total PM 10 , Basin Electric must be required to model condensable PM 10 emissions at the allowable emission rates – i.e., uncontrolled emissions of these pollutants.

9. WYDEQ MUST ADDRESS PM 2.5 IN THE DRY FORK PERMIT

WYDEQ has not addressed the PM 2.5 emissions to be emitted by the Dry Fork facility in its proposed PSD permit or permit application analysis. Yet, PM 2.5 is subject to PSD permitting requirements as a regulated pollutant. Specifi cally, 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 PM 2.5 . 62 Fed. Reg. 38,652 (July 18, 1997); revised at 71 Fed.Reg. 61144-61233 (October 17, 2006). Wyoming’s PSD regulations list si gnificance levels for a number of “regulated NSR pollutants,”

but not PM 2.5 . See definition of “significant” in WAQSR Chapter 6, Section 4(a). When a significance level has not been id entified for a regulated NSR pollutant, the significance level is any emission rate over zero. See WAQSR Chap ter 6, Section 4(a), s ubsection (ii) of the definition of “significant.” A lthough there is no analysis in th e Dry Fork permit application, the proposed permit conditions, or th e permit analysis regarding PM 2.5 , a facility of this size will undoubtedly be emitting PM 2.5 in substantial amounts. Conse quently, Basin Electric is required to comply with all PSD requirements, incl uding monitoring, modeli ng, and BACT regarding

PM 2.5 . WYDEQ cannot issue a PSD permit for this f acility 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 providi ng that sources would be allowed to use implementation of a PM 10 program as a surrogate for meeting PM 2.5 NSR requirements. John Seitz, “Interim Implementation for the Ne w Source Review Requirements for PM[ 2.5 ],” (October 23, 1997). The purpose of that guidance was to pr ovide time for the development of necessary

tools to calculate the emissions of PM 2.5 and related precursors, ade quate modeling techniques to project ambient impacts, and PM 2.5 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 fac ility 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 a ny description of how it will be designed. WYDEQ must issue a permit th at 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 th at 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 gene rating 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 Electri c could potentially be allowed to build a very different source than what WYDEQ review ed under its permitting regulations.

11. WYDEQ CANNOT ISSUE A PERMIT TO DRY FORK BECAUSE IT WOULD

CONTRIBUTE TO VIOLATIONS OF THE SO 2 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 SO 2 PSD increments occurring at the Northern Cheye nne Indian Reservation Class I area (NCIR) (as discussed in WYDEQ’s Permit Application Analys is at 40), and the Dry Fork facility will

contribute to the increment viola tions. Consequently, Wyoming’s PSD regulations provide that the permit for Dry Fork must be denied.

Although WYDEQ provided analyses to determine wh ether the Dry Fork fac ility’s impact on the predicted increment violations would be “signi ficant,” such an approach to discounting the impacts of the Dry Fork facility are not grounded in state or fede ral law. Specifically, WYDEQ evaluated Dry Fork’s contribution to the predicted exceedances of the SO 2 PSD increment concentrations at the NCIR Class I area, and then determined that the Dry Fork facility’s impacts would not be “significant” at t hose receptors and time periods dur ing which increment violations were shown to occur in the modeling analysis. (See Permit Application Analysis at 40.) It appears that, in making this determination, WYDE Q 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 rules43 and the state implementation plan. In addition, EP A 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 Re gion 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 stat utory and regulatory pr ovisions for the PSD increments clearly mandate that, in an area with existing PSD increment violations, the violations “must be entirely corrected befo re PSD sources which affect the area can be approved.” (See 45 Fed.Reg. 52678, August 7, 1980) . WYDEQ has known about these existing

SO 2 increment violations at least since the permitting of Wygen 3. Thus, because the Dry Fork facility will contribute to th e violations of the 24-hour SO 2 increment at NCIR, Wyoming and federal law prohibit issuance of this pe rmit to the Dry Fork facility.

Specifically, Wyoming regulation mandates that a cumulative impacts increment analysis be conducted by a PSD permit applicant to determine th e “total deterioration of air quality from the baseline concentrations” and that a permit can onl y be issued “if the pred icted 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 th e WAQSR] for the classi fication 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 pe rmit can be issued unless the permit applicant shows that it won’t emit pollutants “in amounts [whi ch] will. . . interfere with measures required by the Federal Clean Air Act to be included in the ap plicable Implementation Plan for any other state to prevent significant deterioration of air quality. . . .” WAQSR, Ch apter 6, Section 2(c)(viii)(ii).

It also appears that Basin Electric’s cumulative Class I SO 2 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 ex ample, Basin Electric failed to include SO 2 emissions from the Yellowstone Energy Limited Partners hip (YELP) facility which has increased SO 2 emissions by 1,932 tons per year since 1977 accor ding to the Final Environmental Impact Statement for the Roundup Power Project. 116 Further, Basin Electric fa iled to include any of the

SO 2 increment consuming sources from North Dakot a, or the increment consuming emissions from Billings, Montana sources. In addition, Basin Electric only modeled the 90 th percentile maximum 3-hour and 24-hour average SO 2 emission rates from Colstr ip Units 3 and 4, rather than the maximum 3-hour and 24-hour average emi ssion rates from these units which is required by the NSR Workshop Manual (at C.49). Thus, Basin Electric must be required to revise its SO 2 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 manda te that WYDEQ deny the proposed permit for Dry Fork due to Dry Fork’s contribution to the existing SO 2 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/ei s/Roundup_EIS/RndupPwrPrjCmpltFEIS.pdf.44 violations at NCIR pursuant to WAQSR Chapte r 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 a nd vegetation (in addition to ambien t air quality) in any area that will be affected by any aspect of the pr oposed project (including construction):

[T]he analysis required under this subsection . . . shall require an an alysis 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 cons truction or operation of, such facility.

CAA § 165(e)(3)(B).

The obligation to consider impacts on soil and ve getation is a long-standi ng requirement of the PSD program, and includes an obligation to pe rform a site-specific inventory of soils and vegetation before the issuance of a draft perm it and prior to the date of any public hearing. Such analysis must consider the variet y of soils and vegetation in the area, the possibility of adverse impacts on soils and vegetation for PSD-regulated po llutants (including the po ssibility of adverse impacts at ambient concentrations that are lower than the app licable 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 poten tial for any other site-s pecific 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 WYDE Q) are obligated to perform (or require of applicants) an analysis that specifically inventories th e 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 op eration). At least, such anal ysis must include the full range of PSD pollutants (including fluor ide), as well as any releva nt non-PSD pollutants (including sulfuric acid mist, me rcury, 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 certa in 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 imp acts on soil and vegetation apply not only to the coal-fired steam boilers but to all sources at the propos ed 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 impor tant habitat, vegetation, and potentially animal life45 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 eviden ce that proposed major source will not harm soils or vegetation would essent ially write the soils and vegeta tion 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 comp liance with NAAQS and PSD increments for an actual evaluation based on an inventory and assessment of the imp acts 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 Proc edure itself that, in keeping with a concept of a “screening” tool, the analysis provide d 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 approac h, the procedure provides conservative, not definitive results . * * * The estimation of potential impacts on plants, animals, and soils is extremely difficult. The screeni ng concentrations provided here are not necessarily safe levels nor are they le vels above which c oncentrations will necessarily cause harm in a pa rticular situation. However, a source which passes through the screen without being flagged fo r detailed analysis cannot necessarily be considered safe

. 121

Additionally, there are indications that the Screening Pr ocedure does not purport to be complete in its coverage. The guidance observe s 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, scr eening 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 guidan ce 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 polluta nts: sulfur dioxide, ozone, nitrogen oxide,

(especially aquatic life). The applicants must examine the full range of these po ssible effects in connection with this PSD permit application.

120 Nor can a permitting authority (or the permit applicant) re ly on vague generalizations, such as assertions that emission of a particular kind are “trivial,” without ev aluating 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). Als o, 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 addr ess a number of pollutants with respect to which concerns have been raised here, in cluding sulfuric acid mist, volatile organic materials (VOM), hydrogen chloride, and berylliu m, 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 th at the data upon which the sc reen limits are based are more than 26 years old and did not even rely on nativ e species for their analysis. Id at 45. In sum, the statutory requirement for a thor ough evaluation of soils and vegeta tion is not satisfied by mere assertion or by the application of a screening to ol 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 an alysis “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 a pplicable pollutants that would be emitted from the facility and compare this information to the estimates of pollutant concentrations calculated in the air quality m odeling 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 exam ination 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 explai ned, the soils and vegetation component of the PSD requirements “contemplates a comparative analysis of some kind between the existing

baseline conditions of soils and ve getation at the site and in the pot entially affected area, and the

effects of the emissions on such baselin e 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 becau se there was an inadequate anal ysis 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 applicat ion. Therefore, it is impossible to know whether any endangered, threatened, or sens itive species are located in or around the plant site. Further, the permit applic ation screening methodology was lim ited to the criteria pollutants of SOx and NOx. There permit appl ication failed to analyze the potential impacts of emissions of the following pollutants: fluorine, sulfur ic acid, mercury, beryllium, ozone, hydrogen chloride, carbon monoxide, and ethylene. Moreov er, 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 oblig ation 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 making47 process, and contribute constructively to the pe rmit determination. As a result, WYDEQ must withdraw the draft permit, prepar e an appropriate soils and vege tation analysis, and provide an adequate opportunity for public comment (inc luding 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 WYDE Q 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