1

Center for Biological Diversity

Dine CARE

Dooda (NO) Desert Rock

Environmental Defense Fund

Grand Canyon Trust

National Parks Conservation Association

Natural Resources Defense Council

San Juan Citizens Alliance

Sierra Club

Western Resources Advocates

October 28, 2009

Via email: lee.anita@epa.gov

Anita Lee

Air Division

Environmental Protection Agency, Region IX

75 Hawthorne Street

San Francisco, CA 94105

RE: Comments on EPA’s Advanced Notice of Proposed Rulemaking regarding 

Best Available Retrofit Technology (BART) for the Navajo Generating 

Station and the Four Corners Power Plant [EPA-R09-OAR-2009-0598]

Dear Ms. Lee:

The undersigned parties respectfully submit the following comments on the 

EPA’s Advanced Notice of Proposed Rulemaking (“ANPR”) best available retrofit 

technology (“BART”) analyses submitted by Salt River Project (“SRP”) for the Navajo 

Generating Station (“Navajo” or “NGS”) and by Arizona Public Service (“APS”) for the 

Four Corners Power Plant (“Four Corners” or “FCPP”). Both of these facilities are 

located on Navajo Nation land and, accordingly, EPA is required to promulgate BART 

requirements for these sources. 

In 1977, over thirty years ago, the Clean Air Act propounded as a national goal 

the prevention of any future and the remedying of any existing anthropogenic visibility 

impairment in “class I” national parks and wilderness areas.1

 1 42 U.S.C. §7491(a)(1). 

 The legal centerpiece of 

the program is the mandate for each applicable implementation plan in which these 

protected areas are located to contain “emission limits, schedules of compliance and other 

measures as may be necessary to make reasonable progress toward meeting the national 
2

goal” including two essential elements: (1) the installation of “best available retrofit 

technology” for sources of specified age, size and type, and (2) a long-term strategy for 

making reasonable progress toward the national goal. 

The ANPR examines emissions from two large coal-fired power plants in the 

“Golden Circle” of national parks and wildernesses, a region endowed with unparalleled 

landforms, stunning geologic features, scenic vistas and fragile life zones. The Four 

Corners Power Plant, a 2,060 MW coal burning power plant, is located approximately 50 

kilometers from Mesa Verde National Park. The Navajo Generating Station, located 20 

kilometers from Grand Canyon National Park, is a 2,250 megawatt coal burning power 

plant. The Golden Circle of sixteen class I areas includes the crown jewels of the 

national park, national monument and wilderness preservation system: Arches National 

Park; Bandelier National Monument; Black Canyon of the Gunnison Wilderness; 

Canyonlands National Park; Capitol Reef National Park; Grand Canyon National Park; 

Great Sand Dunes National Park; La Garita Wilderness; Maroon Bells-Snowmass; Mesa 

Verde National Park; Pecos Wilderness; Petrified Forest National Park; San Pedro Parks 

Wilderness Area; West Elk Wilderness Area; Weminuche Wilderness Area; and Wheeler 

Park Wilderness Area. 

Each year, the sixteen class I areas in this Golden Circle receive over seven

million visitors who travel from all over the globe to visit these spectacular areas. The 

economies of nearby communities and “gateway” towns depend heavily on visitation to 

these class I areas. 

The Four Corners Power Plant and Navajo Generating Station are among the 

single largest sources of NOx pollution in the nation. Indeed, the Four Corners Power 

Plant stands alone as the highest NOx emitter in the United States: 

Based on 2006 emissions data from the EPA Clean Air Markets Division, FCPP is 

the largest source of NOx emissions in the United States (nearly 45,000 tons per 

year (tpy) of NOx).

See 74 Fed. Reg. at 44,315. Navajo Generating Station is the “fourth largest source of 

NOx emissions in the United States (nearly 35,000 tpy).”2 The exceptionally high level 

of NOx pollution emitted from these facilities reflects emission rates that far exceed those 

achieved in practice at modern coal-fired power plants. 

The extensive volume of NOx emissions from these smokestacks has immediate

adverse impacts in the vicinity of the facilities and drifts tens and hundreds of miles 

downwind causing a cascade of costly effects to human health and the environment. 

EPA has found that gaseous air pollutants such as NOx that transform in the atmosphere 

to secondary particulate pollution are in a size range that has potent adverse impacts on 

visibility and “can be six times more effective at impairing visibility” than direct 

 2 74 Fed. Reg. 44,317. 
3

particulate pollution.3

 EPA modeling analysis shows that the NOx emissions from these 

facilities obscures the grand vistas of numerous protected class I areas. 

These same NOx emissions contribute to elevated concentrations of ozone 

(“smog”) and deleterious particulate pollution. Ground-level ozone, for example, is 

associated with “an increase in school absenteeism; increases in respiratory hospital 

emergency department visits among asthmatics and patients with other respiratory 

diseases; an increase in hospitalizations for respiratory illnesses; an increase in symptoms 

associated with adverse health effects, including chest tightness and medication usage; 

and an increase in mortality (non-accidental, cardiorespiratory deaths) reported at 

exposure levels well below the current standard.”4

 

These coal-fired power plants also emit substantial levels of mercury emissions 

into the ambient air.5

 Mercury is a toxic heavy metal that contaminates water bodies, 

threatens the development of newborns and children, and contributes to the risk of heart 

disease.6

 The Four Corners Power Plant releases approximately 550-600 pounds of 

mercury annually, one of the largest sources of mercury emissions in the western 

electricity grid.7

 

In addition to the imperative to protect human health and grand vistas in the 

region from these extraordinary levels of NOx emissions, we also respectfully request 

that EPA undertake a rigorous and thorough BART analysis of the direct particulate 

matter pollution levels from these facilities.

 3 74 Fed. Reg. 44,316. 

4 See Clean Air Scientific Advisory Committee correspondence with EPA Administrator Stephen Johnson 

(Oct. 24, 2006) (“Clean Air Scientific Advisory Committee’s (CASAC) Peer Review of the Agency’s 2nd

Draft Ozone Staff Paper”) (Ex. 59). 5 Mercury vented into ambient air deposits from the atmosphere in precipitation or attached particles, and 

through runoff or deposition can end up in lakes, rivers and the ocean. Toxic methylmercury results from 

the transformation of mercury by microorganisms in the sediments of water bodies. The methylated 

mercury readily accumulates in the aquatic food chain with the concentrations increasing at each level in 

the food chain.

6

See, e.g., Leonardo Trasande, Philip J. Landrigan, and Clyde Schechter, Public Health and Economic 

Consequences of Methyl Mercury Toxicity to the Developing Brain, Environmental Health Perspectives, 

Vol. 113, No. 5 (May 2005); Kathryn Mahaffey, Ph.D., U.S. EPA, Methylmercury: Epidemiology Update

(Fish Forum 2004); U.S. EPA, Methylmercury Exposure at www.epa.gov/mercury/exposure.htm; National 

Academy of Sciences’ National Research Council, Toxicological Effects of Methylmercury (2000); 

Castoldi, Coccini, Ceccatelli, and Manzo, Neurotoxicity and molecular effects of methylmercury, Brain 

Res. Bull., 55:197–203 (2001); Alan Stern, “A review of the studies of the cardiovascular health effects of 

methylmercury with consideration of their suitability for risk assessment,” Environmental Research, Vol. 

98, Issue 1 (May 2005) ps. 133-142; Gerald J. Keeler, Matthew S. Landis, Gary A. Norris, Emily M. 

Christianson, and J. Timothy Dvonch, Sources of Mercury Wet Deposition in Eastern Ohio, USA, Environ. 

Sci. Technol., Article 10.1021/es060377q S0013-936X(06)00377-4 (published on web Sept. 8, 2006).

7 See Data Table for Four Corners Area Electric Generating Units [DRAFT V.10], at 

http://www.nmenv.state.nm.us/aqb/4C/Docs/4CAQTF_PowerPlant_WorkGroup_FacilityDataTableV10.pd

f
4

The regional haze program is designed, consonant with statutory imperatives, to 

prevent and remedy visibility impairment from multiple sources that emit visibilityimpairing air pollution across a broad region.8

 In addition to having serious adverse 

impacts in the immediate vicinity of the plants, EPA has documented the adverse 

visibility impacts on “class I” areas in Arizona, Colorado, New Mexico, and Utah. The 

failure of the Agency to remedy these adverse effects would contravene the Agency’s 

manifest legal responsibilities to abate these adverse cross-boundary air pollution 

impacts.9 

Accordingly, we respectfully request that the Agency carry out legal 

responsibilities forged in law over a quarter century ago to protect the people and places, 

in the immediate vicinity and downwind, that have been and continue to be adversely

impacted by the extensive levels of air pollution from these facilities. 

We note, with great hope, that there may be constructive solutions, forged on a 

government-to-government basis with the Navajo Nation, Hopi Tribe and U.S. 

Government, and supported by the owners and customers of these power plants and 

concerned citizens that reflect the common cause shared by all in ensuring economic 

prosperity and environmental protection. There is reason for optimism. In 1991, diverse 

interests came together in a landmark agreement, to chart a common sense path forward 

in addressing the sulfur dioxide emissions from the Navajo Generating Station. The 

following comments are offered with that history in mind. 

We incorporate by reference the documents cited to herein as part of the 

administrative record for this proceeding and provide some of those documents as 

exhibits for administrative convenience. 

 8 See 64 Fed. Reg. 35,765 (April 22, 1999). 

9 See, e.g., Clean Air Act §§ 110(a)(2)(D), 126, 169, 169A, 169B. 
5

I. EPA Must Require the Installation of BART to Address the Emissions from the 

Four Corners Power Plant and Navajo Generating Station that Contribute to 

Regional Haze Visibility Impairment in the Numerous “Golden Circle” of Class I 

Areas. 

Since 1977 the Clean Air Act has included a visibility program designed to protect 

scenic vistas in the country’s premier national parks and wilderness areas.10 To guide the 

administration of the visibility protection program, Congress declared and codified a 

national visibility goal that calls for “the prevention of any future, and the remedying of 

any existing, impairment of visibility in mandatory class I Federal areas which 

impairment results from manmade air pollution.”11 

The national goal delineates several key elements of the visibility protection 

program. First, the program protects mandatory class I Federal areas where visibility has 

been determined to be an important value. Second, the program is both preventive and 

remedial, designed to prevent prospective impairment and redress existing visibility 

impairment. Third, manmade sources of visibility impairment are targeted and“any” 

manmade impairment is of concern. “Manmade air pollution” is defined broadly to 

include air pollution that results directly or indirectly from human activities.12 “Visibility 

impairment” includes reduction in visual range and atmospheric discoloration.13

Congress adopted the visibility program to protect the “intrinsic beauty and 

historical and archeological treasures” of certain federal lands, observing that “areas such 

as the Grand Canyon and Yellowstone Park are areas of breathtaking panorama; millions 

of tourists each year are attracted to enjoy the scenic vistas.”14 Congress sought to 

address the problem of “hazes” due to pollution from “regionally distributed sources.”15 

To curb regional haze, Congress required existing, large and poorly-controlled industrial 

sources contributing to visibility impairment to install BART expeditiously.16 Congress 

recognized that impairment “is caused primarily by . . . inadequate[ly] controlled 

sources.”17 Congress also observed that “emissions from powerplants have cast, or 

threaten to cast, a pall in the atmosphere that drastically interferes with good visibility.”18

Visibility impairment is caused by small particles that scatter and absorb 

sunlight, diminishing or altogether eliminating the color, clarity, and perception of a 

scenic vista.19

 10 See Pub. L. No. 95-95, 91 Stat. 685, 742-45 (1977). For a detailed examination of the programs in the 

1977 amendments affecting visibility protection, with a focus on visual air quality in the southwestern 

United States, see Jerome Ostrov, Visibility Protection Under the Clean Air Act: Preserving Scenic and 

Parkland Areas in the Southwest, 10 ECOLOGY L.Q. 397 (1982).

 Fine particles are discharged directly into the atmosphere and as gaseous 

11 CAA § 169A(a)(1). 12 CAA § 169A(g)(3). 13 CAA § 169A(g)(6). 14 See H.R. REP. NO. 95-294, at 203–04 (1977). 15 1977 LH 2671 (Report of the House Committee on Interstate and Foreign Commerce). 16 CAA §§ 169A(b)(2)(A), (g)(2), (g)(4), & (g)(7). 17 1977 LH 2671 (Report of the House Committee on Interstate and Foreign Commerce). 18 Id. 19 EPA, Protecting Visibility: An EPA Report to Congress (EPA 450/5-79-008 Oct. 1979). 
6

precursors, such as sulfur dioxide and oxides of nitrogen, that transform into fine 

particles. These fine particles are buoyant, can remain in the atmosphere for several 

days, and can be transported hundreds of kilometers from their origin by prevailing 

winds.20 Regional haze is formed when fine particles from a variety of sources across a 

broad area are transported, mix together and cause a widespread haze. 

The legal centerpiece of the visibility protection provisions is the mandate for 

the EPA to promulgate regulations to assure “reasonable progress” toward meeting the 

national visibility goal.21 The regulations must require that each applicable 

implementation plan (see CAA §302(q)) containing a mandatory class I area where 

visibility is an important value, and upwind jurisdictions with emissions that may 

reasonably be anticipated to cause or contribute to visibility impairment in a mandatory 

class I area, develop and submit a plan containing “emission limits, schedules of compliance and other measures as may be necessary to make reasonable progress toward 

meeting the national goal.”

Section 169A specifically requires visibility implementation plan to include (1) 

best available retrofit technology (BART) for certain existing stationary sources that emit 

pollutants that “may reasonably be anticipated to cause or contribute” to visibility 

impairment in a mandatory class I area for the purpose of eliminating or reducing any 

such impairment, and (2) a long-term (ten to fifteen years) strategy for making reasonable 

progress toward meeting the national goal.22 

In 1999, EPA promulgated a final rule requiring applicable implementation 

plans to carry out these core obligations to prevent and remedy regional haze in protected 

class I areas.

23 The rules apply to all states, as defined in section 302(d) of the CAA, 

except Guam, Puerto Rico, American Samoa and the Mariana Islands.24 The overarching 

framework of the rule is the requirement that states develop plans for each of their class I 

areas that establish dual “reasonable progress goals:” providing for an improvement in 

visibility for the most impaired days over the period of the implementation plan and 

ensuring no degradation in visibility for the least impaired days over the same period.”25 

The “most impaired days” are, in turn, defined to mean the average visibility impairment 

for the twenty percent of monitored days in a calendar year with the highest amount of 

visibility impairment.26 Conversely, the “least impaired days” are the twenty percent of 

monitored days with the lowest amount of visibility impairment.27

 20 EPA, Air Quality Criteria for Particulate Matter, vol. 1 at 3-99 (EPA/600/P-95/001aF April 1996). 

 The period that the 

plan must cover is generally a ten year long-term strategy period beginning from the 

deadline that the original regional haze SIPs are due. So, states must adopt ten-year long 

plans that prohibit deterioration of visibility for the cleanest days and establish a goal for 

improving visibility on the dirtiest days. 

21 CAA § 169A(a)(4). 22 CAA § 169A(b)(2). 23 64 Fed. Reg. 35,714 (1999). 24 40 C.F.R. § 51.300(b)(3); see also 64 Fed. Reg. at 35,720-22. 25 40 C.F.R. § 51.308(d)(1). 26 40 C.F.R. § 51.301. 27 Id. 
7

The rules pointedly elaborate on the prong of the “reasonable progress goals” 

requiring states to improve visibility in the 20 percent dirtiest days. First, the affected 

states are required to establish a projected glidepath based on the rate of uniform progress 

that would be needed to restore visibility to natural conditions by 2064.28 And, if an 

affected state establishes a reasonable progress goal that is slower than the projected rate 

of progress to restore natural conditions by 2064 the state must demonstrate, consistent 

with a number of factors, why the goal of attaining natural conditions by 2064 is not 

reasonable.29 To provide public transparency for an alternative decision by the state, the 

rule requires the state to “provide to the public for review as part of its implementation 

plan an assessment of the number of years it would take to attain natural conditions if 

visibility improvement continues at the rate of progress selected by the State as 

reasonable.”30 

The CAA requirement for certain major stationary sources to install “best 

available retrofit technology” (BART) is one of the core control strategies under the 

regional haze rule for states to achieve the reasonable progress goals.31 By statute, 

BART applies to 26 listed source categories of industrial facilities constructed between 

1962-1977 that emit “any air pollutant which may reasonably be anticipated to cause or 

contribute to any impairment of visibility in any” class I area.32 The CAA also delineates 

the factors that govern the states’ determination of BART including: “the costs of 

compliance, the energy and nonair quality environmental impacts of compliance, any 

existing pollution control technology in use at the source, the remaining useful life of the 

source, and the degree of improvement in visibility which may reasonably be anticipated 

to result from the use of such technology.”33 

Congress provided limited immunity for sources more than fifteen years old at the 

time of the 1977 amendments. The EPA “may not require States to apply the best retrofit 

technology to sources which have been in existence more than 15 years. States may do so 

if they choose but could not be required by the administrator.”34 Accordingly, sources 

operating before August 7, 1962, are excluded from the BART requirement. BART must 

be installed and operated no later than five years after SIP approval.35

The term “major stationary source” is defined to include the following 26 

stationary sources in existence on August 7, 1977, with the potential to emit at least 250 

tons per year of any pollutant: fossil fuel-fired steam electric plants of more than 250 

million BTUs-per-hour heat input; coal cleaning plants (thermal dryers); kraft pulp mills; 

Portland Cement plants; primary zinc smelters; iron and steel mill plants; primary 

aluminum ore reduction plants; primary copper smelters; municipal incinerators capable 

 28 40 C.F.R. § 51.308(d)(1)(i)(B). 

29 40 C.F.R. § 51.308(d)(1)(ii). 30 Id. . 31 40 C.F.R. § 51.308(e). 32 CAA § 169A(b)(2)(A) & (g)(7). 33 CAA § 169A(g)(2). 34 See H.R. REP. NO. 294 at 206. 35 40 C.F.R. § 51.302(c)(4)(iv).
8

of charging more than 250 tons of refuse per day; hydrofluoric, sulfuric, and nitric acid 

plants; petroleum refineries; lime plants; phosphate rock processing plants; coke oven 

batteries; sulfur recovery plants; carbon black plants (furnace process); primary lead 

smelters; fuel conversion plants; sintering plants; secondary metal production facilities; 

chemical process plants; fossil fuel boilers of more than 250 million BTUs-per-hour heat 

input; petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels; 

taconite ore processing facilities; glass fiber processing plants; and charcoal production facilities.36

The regional haze rule provides that states “must submit an implementation plan 

containing emission limitations representing BART and schedules for compliance with 

BART for each BART-eligible source that may reasonably be anticipated to cause or 

contribute to any impairment of visibility in any Class I Federal area.”37 The rule goes 

on to lay out specific procedures and considerations that govern the states’ BART 

determination. 

A haze abatement strategy is not, however, limited to BART. BART is only one 

specific element of a visibility protection program that includes emission limitations, 

schedules of compliance, and other measures that are necessary to make reasonable 

progress toward the national goal.38 States must, therefore, consider the full suite of 

anthropogenic sources of visibility impairment in designing a long-term strategy 

including “major and minor stationary sources, mobile sources and area sources.”39 

In 2005, EPA revised certain requirements of the regional haze rule including 

addressing the proper consideration of a BART determination factor and the 

establishment of the deadline for submitting regional haze plans, pursuant to the 

Consolidated Appropriations Act for Fiscal Year 2004, Public Law 108-199, January 23, 

2004, establishing a December 17, 2007 statutory deadline for plan submittal. 

Where EPA is administering the haze program on behalf of a tribe, EPA is 

fulfilling its “obligation under the CAA to ensure the protection of air quality throughout 

the nation, including throughout Indian country.”40 The final Tribal Authority Rule 

requires EPA to promulgate “without unreasonable delay such [FIP] provisions as are 

necessary or appropriate to protect air quality ... if a tribe does not submit a tribal 

implementation plan ... or does not receive EPA approval of a submitted tribal 

implementation plan.”41

 36 CAA § 169A(g)(7). Potential to emit is the maximum capacity of a source to emit a pollutant under its 

physical and operational design, including consideration of federally enforceable emission limitations. 

Secondary emissions, emissions that occur as a result of the construction or operation of a facility, but not 

from the facility itself, are not counted. See 40 C.F.R. § 51.301(r), (u). Fugitive emissions (emissions that 

could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening) must be 

counted, to the extent quantifiable, in determining potential to emit. See 40 C.F.R. § 51.301(e), (j).

 Because the Navajo Nation has not submitted a tribal 

implementation plan to EPA for approval, there are currently gaps in regulation of air 

37 40 C.F.R. § 51.308(e). 38 CAA § 169A(b)(2); 40 C.F.R. §§ 51.302(c)(2)(i) & 51.306(c)(4).

39 40 C.F.R. § 51.308(d)(3)(iv). 40 63 Fed. Reg. 7254, 7265 (1998). 41 40 C.F.R. § 49.11(a). 
9

quality on the Navajo Nation. EPA’s decision to promulgate regional haze FIPs for NGS 

and FCPP seeks to address some of these gaps and to regulate sources which would 

otherwise go unregulated. Because there is no EPA-approved tribal implementation plan 

for sources on the Navajo Nation, EPA’s regulation of NGS and FCPP is mandatory 

under the CAA. Accordingly, EPA’s regulation of NGS and FCPP through FIPs is 

required.42 By comparison, EPA has triggered the mandatory deadline for adoption of a 

federal implementation plan to protect scenic vistas at class I areas in some 37 states that 

failed to timely submit a visibility protection plan for regional haze.43 

II. The NOx and Other Airborne Contaminants Discharged by the Four Corners 

Power Plant and Navajo Generating Station Contribute to Haze Air Pollution 

in Class I Areas and Have a Suite of Adverse Effects on Human Health and the 

Environment. 

The Four Corners Power Plant and Navajo Generating Station are among the 

single largest sources of NOx pollution in the nation. Indeed, the Four Corners Power 

Plant stands alone as the highest NOx emitter in the United States. On average, the Four 

Corners Power Plant emits approximately 42,000 tons of NOx per year and the Navajo 

Generating Station emits approximately 34,000 tons of NOx per year.

44 Although wet 

scrubbers were installed to reduce SO2 emissions at the three Navajo units in the 1990’s 

and the SO2 controls were improved in recent years at Four Corners, these power plants 

still have substandard pollution controls for NOx. Emissions of NOx at the Navajo units 

are primarily controlled by good combustion practices and close-coupled overfire air. 

Four out of the five Four Corners units have older low NOx burners and Unit 1 has had 

burner modifications to control NOx emissions. 

The extensive volume of NOx emissions from these smokestacks have immediate 

adverse impacts in the vicinity of the facilities and drift tens and hundreds of miles 

 42 Section 110(c)(1) of the CAA calls for the EPA to promulgate a FIP within two years of finding that a 

state has failed to submit an approvable visibility plan. See CAA § 169A(b)(2)(A) (BART is determined by 

the state “or the Administrator in the case of a plan promulgated under section 110(c)”). The legislative 

history suggests that Congress deliberately conferred on the EPA the FIP authority for visibility:

The conferees . . . rejected a motion to delete EPA’s supervisory role under section 110 to assure that 

the required progress toward [the national visibility goal] will be achieved by the revised State plan. If 

a State visibility protection plan is not adequate to assure such progress, then the Administrator must 

disapprove that portion of the SIP and promulgate a visibility protection plan under section 110(c).

See Senate Comm. on Environment and Public Works, 95th Cong., 2d Sess., A LEGISLATIVE HISTORY OF 

THE CLEAN AIR ACT AMENDMENTS OF 1977, vol. 3 at 320–21 (Comm. Print 1978) (Statement of 

Congressman Rogers during House consideration of Conference Committee Report, Aug. 4, 1977). The 

EPA has additional supervisory authority under the CAA. If the EPA determines that a SIP is substantially 

inadequate to comply with a requirement of the CAA, including the visibility protection provisions, then 

the EPA may require the state to revise the SIP to correct the inadequacies. See CAA § 110(k)(5). 43 See 74 Fed. Reg. 2392 (“Finding of Failure to Submit State Implementation Plants Required by Regional 

Haze Rule”) (Jan. 15, 2009).

44 NOx emissions for FCPP from Table 2-3 “Baseline Emissions” of FCPP BART Engineering Analysis, 

averaged from the last five years (dated December 4, 2007, EPA-R09-OAR-2009-0598-0004.3). NOx 

emissions for NGS from EPA’s Clean Air Markets Database, averaged over 2001 to 2003.
10

downwind where they have a cascade of effects. EPA has found that gaseous air 

pollutants such as NOx that transform in the atmosphere to secondary particulate 

pollution are in a size range that has potent adverse impacts on visibility and “can be six 

times more effective at impairing visibility” than direct particulate pollution. 74 Fed. 

Reg. 44,316. 

The U.S. Department of the Interior (for the National Park Service and Fish and 

Wildlife Service) has certified the existence of visibility impairment in all class I areas in 

the lower forty-eight states. See 52 Fed. Reg. 45,132 at 45,133-34 (Nov. 24, 1987). The 

National Park Service recently documented the continuing serious visibility impairment 

at protected class I areas: 

“Annual mean deciview values on the haziest days at the 29 NPS locations during 

the period 2005-2007 ranged from 1.5 dv to 22 dv higher than estimated natural 

conditions and averaged approximately 8.5 dv higher than estimated natural 

conditions.” 

* * *

“Visibility conditions on the best days are also impaired, although to a lesser 

degree. At all NPS sites with data during 2005-2007, mean deciview values on 

the clearest days ranged from 0.3 to 12 dv above estimated natural conditions, and 

averaged roughly 3-5 dv above estimated natural conditions.”

See National Park Service, Air Quality in National Parks: 2008 Annual Performance & 

Progress Report, Natural Resource Report NPS/NRPC/ARD/NRR—2009/151 at ps. 20

& 22 (Ex. 58).

Further, EPA modeling analysis indicates that the NOx emissions from the Four 

Corners Power Plant and Navajo Generating Station obscure the grand vistas of 

numerous protected class I areas and that NOx reductions will have considerable 

perceptible benefits in remedying visibility impairment,

45 thereby requiring corrective 

action to address the legal obligation to meet BART and a long-term strategy that assures 

reasonable progress in preventing and remedying regional haze visibility impairment. 

Elevated Ozone Levels in the Area Threaten Human Health and the Environment.

Not only is visibility impaired in the Colorado Plateau region, but ozone levels are 

reaching unhealthy levels throughout the area – including within the Class I areas. The 

extensive NOx emissions from the Four Corners Power Plant and Navajo Generating 

Station are implicated in these serious ozone concentrations. The Four Corners area has 

been experiencing very high ozone concentrations for years and, in 2008, the Navajo 

Lake ozone monitor in New Mexico registered a violation of the 8-hour average 75 parts 

per billion (“ppb”) national ambient air quality standard (“NAAQS”). Other monitors in 

 45 See, e.g., 74 Fed. Reg. at 44,327 (Table 26, including PM) and 44,332 (Table 35),
11

the Four Corners region have registered ozone concentrations within 5% of the level 

considered to be a violation of the ozone NAAQS, including Flagstaff for which the 3-

year average of the 4th highest concentration was 74 ppb in 2008. Mesa Verde National 

Park, Canyonlands National Park, and Petrified Forest National Monument each had 3-

year averages of the 4th high ozone concentrations of 71 ppb as of 2008. Monitors in 

Grand Canyon National Park and Farmington, New Mexico had a 3 year average of the 

4th highest ozone concentration equal to 70 ppb as of 2008. (All monitor values and 

averages obtained from EPA’s AirData website).

The New Mexico Environment Department has been implementing a voluntary 

program for emission controls in the New Mexico portion of the Four Corners region 

pursuant to the Early Action Compact that the State of New Mexico entered into with the 

U.S. EPA.

46 However, elevated ozone levels continue to be a problem in the Four 

Corners region as the recent violation at Navajo Lake demonstrates. In its 2009 

recommendations for the 8-hour ozone NAAQS recently submitted to EPA, the 

Colorado Department of Public Health and Environment stated that “[t]here is substantial 

reason to believe the ozone non-attainment issue in San Juan County, New Mexico could 

be fully mitigated without further action if EPA were to require the installation of 

appropriate emissions controls at the facilities located on the Navajo Reservation, 

particularly the Four Corners Power Plant, which emits over 40,000 tons of nitrogen 

oxides into the atmosphere annually.”47 

On September 16, 2009, EPA announced it will reconsider both primary and 

secondary ozone standards to ensure they are scientifically sound and protective of 

human health and welfare.48 EPA is scheduled to propose revisions to the ozone standard 

by December 2009 and issue a final decision by August 2010. EPA will be reviewing the 

science that guided the 2008 decision as well as the findings of EPA’s independent Clean 

Air Scientific Advisory Committee (“CASAC”) which unanimously recommended 

decreasing the primary standard to within the range of 0.060–0.070 ppm. As discussed 

above and as shown by the analyses below, ozone levels in the vicinity of Navajo and 

Four Corners are already in the range of ozone levels deemed to be harmful to human 

health by CASAC.

49 

CASAC found that elevated ozone concentrations are associated with “an increase 

in school absenteeism; increases in respiratory hospital emergency department visits among 

asthmatics and patients with other respiratory diseases; an increase in hospitalizations for 

respiratory illnesses; an increase in symptoms associated with adverse health effects, 

 46 The Early Action Compact was approved by EPA as part of the SIP on August 17, 2005 (70 Fed.Reg. 

48285). 

47 See March 11, 2009 letter from the Colorado Department of Public Health and Environment to EPA 

Region VIII regarding 2009 Colorado designations for 8-hour ozone NAAQS at 2 (Ex. 38). 48 http://www.epa.gov/groundlevelozone. 49 See Clean Air Scientific Advisory Committee correspondence with EPA Administrator Stephen Johnson 

(Oct. 24, 2006) (“Clean Air Scientific Advisory Committee’s (CASAC) Peer Review of the Agency’s 2

nd 

Draft Ozone Staff Paper”). 
12

including chest tightness and medication usage; and an increase in mortality (non-accidental, 

cardiorespiratory deaths) reported at exposure levels well below the current standard.”50 

Further, as indicated in the most recently published National Park Service’s trend 

report, ozone is at harmful levels throughout the intermountain west:

 50 See Id.
13

A recent study in the New England Journal of Medicine provides confirmation 

that that long-term exposure to ozone increases the risk of death from respiratory 

causes.51 In a long-term study of nearly 500,000 participants, the study found a 4% 

increase in death for respiratory causes for every 10-ppb increase in exposure to ozone. 

The risk of dying from respiratory causes in the highest-ozone areas was nearly three 

times that in the lowest-exposure areas. Moreover, negative respiratory effects have been 

confirmed in a recent study by the New Mexico Depart of Heath. Summertime ozone 

concentrations in rural San Juan County, New Mexico can be as high as those in Seattle 

or Santa Clara County, California.52 These ambient ozone concentrations have been 

associated with an increase in both the likelihood and number of athsma-related medical 

visits within the days after exposure to a high-ozone level.53

Nitrogen Deposition Is Also a Major Threat to Ecosystems in the Region.

Nitrogen deposition, caused by wet and dry deposition of nitrates derived from 

NOx emissions, causes well known adverse impacts on ecological systems. Critical loads 

(i.e., the amount of nitrogen deposition that an ecosystem can tolerate, above which the 

system become adversely impacted) are likely to soon be used to formally inform policy 

 51 Jerrett, Michael et al., “Long Term Ozone Exposure and Mortality,” NE J Medicine 2009; 360, 1085-

1095 (Ex. 57).

52 The Association between Ambient Air Quality Ozone Levels and Medical Visits for Asthma in San Juan 

County, Myers, Orin et al., NM Dept. of Health, August 2007 (Ex. 56).

53 Id. 
14

developments (e.g., NADP-CLAD Meeting, Pensacola, FL Spring 2009). Scientific 

investigations have already demonstrated that nitrogen is saturating the soil, plants and 

water of Rocky Mountain National Park at levels at least twice the "critical load" the 

ecosystem can tolerate. Attention to nitrogen deposition is the intermountain west is 

likely to intensify, as nitrogen deposition is increasing throughout the region, as 

demonstrated by recent trends analysis by the National Park Service. These worrisome 

increases provide an additional basis for prompt action in dealing effectively with major 

sources of NOx emissions in the region.

Mercury Emissions are a Threat to Endangered Species in the Region

These plants also release significant levels of mercury emissions. For example, 

the Four Corners Power Plant is one of the top 50 polluting power plants in the nation for 

total tons of CO2 and mercury emitted, pounds of NOx/MWh, and the worst in the 

country for total tons of NOx emitted.54

Mercury emissions from these two plants and other sources are believed to be 

contributing to numerous fish consumption advisories on the Navajo Nation and in 

Arizona, Colorado, Utah, and New Mexico. The National Park Service recently notified 

EPA Region 9 that it has “concerns about mercury emission[s] from NGS and its impacts 

 54 Dirty Kilowatts: America’s Most Polluting Plants, Environmental Integrity Project, 2007 (Ex. 55)
15

upon the ecosystems of Lake Powell, Lake Mead, and other water bodies in the Four 

Corners region.”55 As NPS pointed out to EPA, the State of Colorado has human health 

advisories at three reservoirs in the Four Corners Area for fish consumption due to 

mercury exceeding EPA’s risk thresholds of 0.3 ppm for women of childbearing years, 

and 2005 data from Lake Powell indicated that five out of 11 striped bass sampled 

exceeded this threshold.56 In addition, as the U.S. Fish and Wildlife Service and State of 

New Mexico recognize, endangered fish species – including the Colorado pikeminnow 

and razorback sucker, both of which are protected as “endangered” pursuant to the 

Endangered Species Act, 16 U.S.C. § 1531, et seq. – are adversely affected by exposure 

to mercury in the Four Corners region.57 Accordingly, reduction of mercury emissions 

from NGS and FCPP through the use of SCR and baghouses could beneficially impact 

the health and viability of fish species in the region

All of this data and information show the significant need to address the major 

NOx emitters in this delicate region. We urge EPA to take into account all of the adverse 

health and environmental effects due in part to the significant NOx emissions in the 

region when evaluating BART for Navajo and Four Corners.

III. The Cost and Emission Reductions Analysis for the NOx BART Options 

Evaluated for the Navajo and Four Corners Power Plants Are Flawed.

In Section II.A. of the ANPR, EPA requests comment on the estimated cost of 

BART controls for NOx and PM at both the Navajo Generating Station and the Four 

Corners Power Plant. 74 Fed.Reg. 44316-22. APS evaluated several options for NOx 

reductions including new low NOx burners (“LNBs”), overfire air (“OFA”), selective 

non-catalytic reduction (“SNCR”), selective catalytic reduction (“SCR”), and 

combinations of these combustion and add-on controls. SRP evaluated new LNBs and 

separated overfire air (“SOFA”), LNBs/SOFA with SNCR, and LNBs/SOFA with SCR. 

Inherent to any determination of cost-effectiveness is a discussion of the emission 

rates achievable with the suite of pollution controls to be analyzed for BART. We have 

reviewed the BART analyses submitted by SRP and APS. We have found that the NOx 

emission rates that SRP and APS have proposed as achievable with the various NOx 

BART controls analyzed do not reflect the lowest emission rates achievable at Navajo or 

Four Corners. Further, the NOx emission reductions assumed by EPA in its cost 

effectiveness calculations also fail to reflect the NOx emission rates achievable with the 

NOx controls being analyzed as BART for these sources. In addition, the cost analyses 

of SCR submitted both by SRP and APS significantly overestimate the costs of this 

equipment and installation. SCR systems have been retrofitted at coal-fired electrical 

generating units (“EGUs”) across the country, most notably at EGUs in the eastern 

United States pursuant to the NOx State Implementation Plan (“SIP”) call and/or 

pursuant to the requirements of the prior Clear Skies Initiative. Both of these programs 

 55 Letter from National Park Service to EPA regarding BART analysis, July 24, 2009 (Ex. 52). 56 Id. 57 Letter from Fish and Wildlife Service to EPA Region 9, Feb. 26, 2009 (Ex. 53); Letter from State of New 

Mexico to Administrator Jackson, Sept. 11, 2009 (Ex. 54). 
16

relied on market-based incentives for sources of NOx pollution to reduce emissions. The 

multitude of EGUs at which SCR was installed demonstrates the cost-effectiveness of

SCR retrofits. 

A. SCR Costs at Four Corners Power Plant Are Inflated.

APS submitted SCR cost estimates to EPA Region IX prepared by Black & 

Veatch in a December 4, 2007 BART Engineering Analysis. 12/4/07 Black & Veatch

BART Report.58 Subsequently, in March 2009, APS updated the estimates for SCR and 

SNCR, claiming costs for steel, concrete, other building materials, and construction costs

had increased significantly since 2007. 3/16/09 B&V BART Report.

59 Both the 2007 

and the 2009 estimates significantly overstate the cost of installing SCR at Four Corners

for purposes of BART. 

A comparison of the LNB/OFA/SCR controls at Four Corners Units 4 and 5 to the 

projected costs for the similarly sized Navajo Units 1, 2, and 3, provides an indication of 

these overestimates. The annual per unit cost estimates for this suite of controls at Four 

Corners Units 4 and 5 is 67% higher than the cost estimates of this same suite of controls 

for the Navajo units. Furthermore, as described below, it appears that the cost estimates 

for this suite of controls at the Navajo units are also higher than they should be.

We first compare the Black & Veatch costs to actual install costs at other similar 

plants. We then explain on an item by item basis why we believe the Black & Veatch

costs are too high. Our cost critique below is based on the cost to install just SCR, as 

reported in the 3/16/09 Black & Veatch Report, Appendix A, SCR option for Units 1-5. 

However, these comments apply to all of the options that include SCR that were costed 

by Black & Veatch.

1. Total Capital Costs Are Higher Than Reported By Others.

Capital costs for pollution control equipment are commonly reported on a dollar 

per kilowatt of capacity basis. The unit capital costs estimated by Black & Veatch for 

Four Corners are summarized in Table 1 below.

Table 1

Summary of SCR Capital Cost

Four Corners Power Plant

Unit Capital

Cost ($)

Size

MW

$/

kW

1 110,664,000 185 598

 58 Black & Veatch, Arizona Public Service Company, Four Corners Generating Plant Units 1 through 5, 

Best Available Retrofit Technology Engineering Analysis, December 4, 2007, Rev. 3, [EPA-R09-OAR2009-0598-0004.3.]

59 Letter from David L. Saliba, Plant Manager, Four Corners Power Plant, to Anita Lee, USEPA Region 9, 

Re: EPA's BART Analysis Information Request, March 16, 2009 [EPA-R09-OAR-2009-0598-0011].
17

2 119,010,000 185 643

3 113,084,000 235 481

4 265,406,000 790 336

5 265,406,000 790 336

Five industry studies conducted between 2002 and 2007 have reported the 

installed unit capital cost of SCRs,60 or the costs actually incurred by owners, expressed 

in dollars per kilowatt. These actual costs are lower than estimated by Black & Veatch 

for Four Corners.

The first study evaluated the installed costs of more than 20 SCR retrofits from 

1999 to 2001. The installed capital cost ranged from $116 to $233/kW, converted to 

2008 dollars.61 Note that these comparisons use 2008 dollars because the Black & 

Veatch revised costs are reported as of September 2008. Costs are escalated through 

using the Chemical Engineering Plant Cost Index ("CEPCI"). 

The second survey of 40 installations at 24 stations reported a cost range of $83 to 

$265/kW, converted to 2008 dollars.62 The third study, by the Electric Utility Cost 

Group, surveyed 72 units totaling 41 GW, or 39% of installed SCR systems in the U.S. 

This study reported a cost range of $145/kW to $321/kW, converted to 2008 dollars.63 

A fourth study, presented in a course at PowerGen 2005, reported an upper bound range 

of $197/kW to $221/kW, converted to 2008 dollars.64 A fifth summary study, focused 

on recent applications that become operational in 2006 or were scheduled to start up in 

2007 or 2008, reported costs in excess of $200/kW on a routine basis, with the highest 

application slated for startup in 2009 at $300/kW.65 

 60 J. Edward Cichanowicz, Current Capital Cost and Cost Effectiveness of Power Plant Emissions Control 

Technologies, June 2007. Ex. 1.

61 Bill Hoskins, Uniqueness of SCR Retrofits Translates into Broad Cost Variations, Power Engineering, 

May 2003. Ex. 2. The reported range of $80 to $160/kW $123 - $246/kW was converted to 2008 dollars 

($116 - $233/kW) using the ratio of CEPCI in 2008 to 2002: 575.4/395.6. 

62 J. Edward Cichanowicz, Why are SCR Costs Still Rising?, Power, April 2004, Ex. 3; Jerry Burkett, 

Readers Talk Back, Power, August 2004, Ex. 4. The reported range of $56/kW - $185/kW was converted 

to 2008 dollars ($83 - $265/kw)using the ratio of CEPCI for 2008 to 1999 (575.4/.390.6) for lower end of 

the range and 2008 to 2003 (575.4/401.7) for upper end of range, based on Figure 3.

63 M. Marano, Estimating SCR Installation Costs, Power, January/February 2006. Ex. 5. The reported 

range of $100 - $221/kW was converted to 2008 dollars ($130 - $286/kW) using the ratio of CEPCI for 

2008 to 2004: 575.4/444,2. 

http://findarticles.com/p/articles/mi_qa5392/is_200602/ai_n21409717/print?tag=artBody;col1

64 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, Competitive Power 

College, by Babcock Power, Inc. and LG&E Energy, December 2005, Ex. 6. The reported range of $160 -

$180/kW) was converted to 2008 dollars ($197 - $221/kW) using the ratio of CEPCI for 2008 to 2005 

(575.4/468.2).

65 J. Edward Cichanowicz, Current Capital Cost and Cost-Effectiveness of Power Plant Emissions Control 

Technologies, June 2007, pp. 28-29, Figure 7-1 (Ex. 1).
18

Thus, the overall range for these industry studies is $83/kW to $300/kW. The 

upper end of this range is for highly complex retrofits with severe space constraints, such 

as Belews Creek, reported to cost $290/kW,

66 or Cinergy's Gibson Units 2-4. Gibson, a 

highly complex, space-constrained retrofit in which the SCR was built 230 feet above the 

power station using the largest crane in the world,67 only cost $275/kW in 2008 dollars.68 

This data indicates that Black & Veatch's estimates of capital cost to retrofit SCR 

at Four Corners ($336/kW - $643/kW) are higher than the actual installed costs for 

existing retrofit SCRs, including those with extreme retrofit difficulty. 

Further, the Black & Veatch estimates are much higher than other recent 

estimates. Wisconsin Electric estimated the cost to retrofit SCR on Oak Creek Units 5-8 

to be $205/kW69 for a cold-side SCR. This cost was certified in July 2008 for 

construction by the Wisconsin Public Services Commission.

70 Wisconsin Power and 

Light estimated the cost to retrofit SCR on the 430-MW Edgewater Unit 5 to be 

$324/kW in January 2008.71 The Edgewater case is pending before the Wisconsin Public 

Services Commission. Similarly, American Electric Power (AEP) estimated that the 

average capital cost to install SCRs to remove 85-93% of the NOx from many of its units 

was $162/kW.72 

These recent estimates, prepared around the same time as those by Black & 

Veatch, are reasonable upper bounds for the smaller Four Corners units (1-3) as they are 

for larger units (which generally have higher unit costs) and Oak Creek is a tail-end SCR, 

which generally costs slightly more than the hot-side SCR assumed for Four Corners. 

The following sections discuss why we believe Black & Veatch's costs are excessive.

2. Cost Estimates Are Not Supported.

 66 Steve Blankinship, SCR = Supremely Complex Retrofit, Power Engineering, November 2002, Ex. 7. 

The unit cost: ( $325,000,000/1,120,000 kW)(608.8/395.6) = $290/kW. 

http://pepei.pennnet.com/display_article/162367/6/ARTCL/none/none/1/SCR-=-Supremely-ComplexRetrofit/

67 Standing on the Shoulder of Giants, Modern Power Systems, July 2002, Ex. 8.

68 McIlvaine, NOX Market Update, August 2004, Ex. 9. SCR was retrofit on Gibson Units 2-4 in 2002 and 

2003 at $179/kW. Assuming 2002 dollars, this escalates to ($179/kW)(608.8/395.6) = $275.5/kW. 

http://www.mcilvainecompany.com/sampleupdates/NoxMarketUpdateSample.htm

69 Wisconsin Electric Power Company's Application to Install Wet Flue Gas Desulfurization and Selective 

Catalytic Reduction Facilities and Associated Equipment on Oak Creek Power Plant Units 5, 6, 7 & 8 for 

Control of Sulfur Dioxide and Nitrogen Oxide Emissions, Appendix C, Emission Reduction Study, Volume 

1, Addendum August 20, 2007. Unit cost = ($190,500,000/1,135,000 kW)(608.8/499.6) = $204.5 kW

70 Certificate and Order, Application to Install Wet Flue Gas Desulfurization and Selective Catalytic 

Reduction Facilities and Associated Equipment on Oak Creek Power Plant Units 5, 6, 7 & 8 for Control of 

Sulfur Dioxide and Nitrogen Oxide Emissions, Case 6630-CE-299, July 10, 2008.

71 Wisconsin Power & Light Co., Certificate of Authority Application, Edgewater Generating Station Unit 

5 NOx Reduction Project, Project Description and Justification, November 2008, PSC Ref#: 105618, p. 11. 

Ex. 10. The unit cost was calculated from the total project cost minus escalation divided by gross 

generating capacity or: ($153,944,000 - $14,695,000)/430 MW = $323.8/kW. 72 AEP, 2008 Fact Book, 43rd Financial Conference, Phoenix, AZ, p. 94. Ex. 11.
19

The Black & Veatch reports and EPA's ANPR do not provide sufficient 

information to support the claimed costs. We are unable to confirm the cost estimates as 

several critical pieces of information are missing.

First, the cost of an SCR is determined by its design basis. The design parameters 

for an SCR include the ammonia-to-NOx molar ratio, the pressure drop across the SCR, 

catalyst life, the catalyst management plan, space velocity, and flue gas flow rate, among 

others.73 The Black & Veatch reports and EPA's summary thereof do not disclose the 

ammonia-to-NOx molar ratio, space velocity, or catalyst life. In fact, the Black & Veatch 

"Design Concept Definitions" for SCR in the 2007 report indicate that the ammonia 

injection rate and energy consumption are both "TBD" or to be determined.74 Thus, it is 

not possible to critically evaluate the costs at a detailed level.

Second, the capital cost estimates include costs for new air preheaters based on 

the claim that existing secondary air heaters must be demolished to allow room for

ductwork.75 The supporting documents do not include any plot plans of the existing 

facility, which is required to confirm that the site is so space constrained that existing 

equipment must be demolished. There may be cheaper options, such as an elevated SCR 

reactor or tail-end reactor that could more economically address any site constraints. 

EPA should visit each site and confirm the stated congestion. The supporting documents 

also do not include a plot plan showing the proposed SCR arrangement. EPA should 

require plot plans to confirm arrangement assumptions.

Third, the capital costs are based on two types of calculations, called "Eng. 

Estimate" (engineering estimate) and "adjusted from CUECost." CUECost is an EPA 

model. The underlying CUECost runs and the calculations showing the adjustments 

thereto are not in the record. Further, the supporting calculations for the "Eng. 

Estimates" are also not in the record. An engineering estimate involves calculations that 

rely on many assumptions as to the design of the system. These calculations and 

assumptions are also not in the record.76 Such assumptions would include vendor quotes 

for equipment, such as fans and air preheaters, and supplies, such as the catalyst. No 

supporting information is available. Thus, we cannot confirm the proffered costs without 

designing the SCR system from scratch, an unfair burden for members of the public.

Fourth, the costs are presented in a series of spreadsheets, which likely are 

available in Excel format but are not in the record. The calculations assumed in these 

spreadsheets cannot be verified without reverse engineering the calculations, which is an 

unfair and excessive burden for commenters. Providing access to Excel spreadsheets 

would allow commenters to inspect the formulae used and change assumptions to explore 

their impact on the bottom line. The EPA should require that APS produce the unaltered 

spreadsheets (i.e., not password protected and with all formulas).

 73 70 FR 39166 (7/6/05); OAQPS Manual, Sec. 4.2. 74 Black & Veatch 2007, pp. C-4, C-15, C-26, C-37. 75 Black & Veatch 2007, pp. C-4, C-15, C-26, 76 See, for example, the calculations in OAQPS Manual, Sec. 4.2.
20

3. Improper Cost Method Was Used.

There are several methods for estimating cost. Costs for BART analyses use the 

total annual cost approach.

77 This approach has been used for BACT cost effectiveness 

analyses since about 1977. The approach estimates costs of various control options by 

calculating costs equalized annually over the life of the control. These costs are real or 

constant-dollar estimates in that the effect of inflation has been removed. 

A standardized approach is used to assure a level playing field and consistency in 

estimating costs, as the significance of cost effectiveness values is determined by 

comparing the costs for a given project to costs at other similar sources. This method 

was selected by the EPA because it determines the "economic" cost of air pollution 

control, i.e., the true cost to society, it is simple to use, and it allows alternative control 

systems with different economic lives to be compared. This approach has been adopted 

for BART determinations and the BART guidance specifically recommends the use of 

the EPA Control Cost Manual, which uses the total annual cost approach.78

Black & Veatch did not use this approach and thus their cost effectiveness values 

are not comparable for purposes of determining cost effectiveness of the various BART 

options, especially SCR. Instead, Black & Veatch appears to have used EPRI's levelized 

cost method, which overestimates control costs compared to the annualized cost method. 

Further, Black & Veatch included costs for items that are not to be addressed according 

to OAQPS’s Control Cost Manual.79

The National Park Service calculated the cost effectiveness of SCR+LNB+SOFA 

based on the Control Cost Manual which EPA provided in Table 9 of the ANPR. Those 

costs are significantly lower than the capital and annual costs provided by APS (provided 

in Table 3 of the ANPR). Given that EPA has recommended all BART cost analyses to 

be based on the Control Cost Manual to improve consistency and that other EGU owners 

are complying with that recommendation, EPA should rely on these cost calculations 

provided by the National Park Service that in turn are based on EPA recommended 

procedures. 

4. Direct Capital Costs (“CC”) Are Overestimated.

 77 This method is also called the equivalent uniform annual cost method. See 70 FR 39166 - 39167 

(7/6/05) which notes the EPA Control Cost Manual should be used where possible. This Manual uses the 

total annual cost approach.

78 70 FR 39166. 79 See 74 FR 44318.
21

The analysis of unit costs presented above demonstrates that the claimed costs for 

SCR on the five Four Corners units are overestimated. The following subsections discuss 

some of the factors that contribute to this overestimate.

APS’s 2009 Costs Revision

APS submitted revised SCR retrofit costs in March 2009 to address increases in 

the price for steel, concrete, other building materials, and overall construction costs. 

These revised costs are 8 – 24% higher than the previous estimate.80 Given the downturn 

in the economy and the resulting decreased demand for raw materials, these cost estimate 

increases seem unnecessary and inappropriate. The Chemical Engineering Plant Cost 

Index ("CEPCI") for 2008 is 575.4. The June 2009 index is 508.9, a 12% decline in 6 

months. 

Further, the difference in costs between the 2007 estimate and the 2009 estimate 

appears to be due to more than inflation. The method used to calculate the costs also 

changed. In the 2007 estimate, CUECost, an EPA costing model was used to estimate 

some components of the cost. Many of these CUECost components were replaced by 

unsupported engineering estimates in the 2009 revision. As no support is provided for 

either the 2007 or the 2009 estimates, it is impossible to determine for the reason for the 

cost increase.

Air Preheaters

The capital cost estimates include costs for new air preheaters of about $3 million 

for Units 1-3 and $16 million for Units 4-5. This amounts to about $13/kW to $20/kW. 

Depending on the design and physical condition of the air preheater, its heat exchange 

baskets may need to be upgraded to work with an SCR system. This can add $2/kW to 

$4/kW to the cost of an SCR. However, air preheaters are not part of SCRs and new air 

preheaters are unusual.

The 2007 Black & Veatch report claims that existing air preheaters must be 

demolished to allow room for ductwork connections. However, the record contains no 

plot plans supporting such site constraints. If present, site constraints could be addressed 

in other ways, such as locating the SCR above the air preheater or using a cold-side SCR. 

A cold-side SCR is located downstream of the air preheater, thus avoiding the spaceconstrained area between the boiler outlet and the inlet to the air preheater. Alternatively, 

the SCR could be located in the vicinity of the stack, which is not generally congested or 

outboard of the units, as for Navajo. The record contains no evidence that these options 

were considered.

Fans

The capital costs include costs for new forced draft and induced draft fans of 

about $8 million for Units 1 and 2, $9 million for Unit 4, and $16 million for Units 4 and 

 80 3/16/09 Black & Veatch, Cover Letter and Tables 1-2.
22

5. This amounts to about $20/kW to $44/kW, or 20% to 29% of the capital cost for each 

unit. These costs are outside of the normal ranges for SCR retrofits, which typically 

include a booster fan if needed. They also appear to be inconsistent with the estimates of 

auxiliary and ID fan power costs estimated elsewhere in the costing spreadsheets. 

The new ductwork and catalyst layers create backpressure, which must be 

overcome by fans. To maintain the same flow rate through the duct work, existing fans 

must provide additional pressure, which, depending upon the capacity of existing fans, 

may require fan upgrades or booster fans. In all cases, SCR systems require only about 

0.3% of the plant's electrical output.81 The claimed costs for new fans seems excessive 

and should be supported.

The record contains no information on the existing fans or any calculations 

supporting the increase in fan capacity that would justify these out of bound costs. We 

recommend that EPA request information for the existing fans, including their design 

basis, current loads, and increased loads required to support the SCRs and evidence that 

layout constraints require new fans.

Electrical Equipment

The capital cost estimate include about $3 million for Units 1-3 and $10 million

for Units 4-5 for electrical equipment. The record does not disclose what equipment is 

being costed. This amount to about $12/kW to $15/kW. This is two to three times higher 

than electrical equipment costs for other SCRs.82 These costs apparently assume a 

substantial auxiliary electric system upgrade for each unit. However, SCRs do not 

require large amounts of electricity and generally do not require substantial auxiliary 

system upgrades. The record contains no support justifying these upgrades. In fact, the 

2007 Black & Veatch analysis reports the energy demand of the SCRs as "TBD." It is 

unclear how the need for upgraded electrical systems was determined without 

determining electrical load. We recommend that EPA request design information on the 

existing auxiliary power system, current loads, and the increase in load from the new 

SCRs.

Taxes

The capital cost estimates includes taxes calculated as 10% of the capital cost 

(CC) and an additional 10% of the direct installation costs. This amounts to about $6 to 

$7 million for Units 1-3 and $16 million for Units 4-5. Pollution control equipment is 

typically exempt from property and sales taxes, which are usually assumed to be zero.83 

SRP assumed taxes were not applicable to Navajo.

84

 81 OAQPS Control Cost Manual, 2002, Section 4.2, p. 2-28.

 

82 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, p. 33. Ex. 6. 83 OAQPS Control Cost Manual, 2002, Section 4.2, p. 2-48 ("In many cases property taxes do not apply to 

capital improvements such as air pollution control equipment...")

84 E-mail from Barbara J. Sprungl to Anita Lee, EPA Region 9, Re: Cost Information, August 20, 2008. 

EPA-R09-OAR-2009-0598-0008.
23

5. Direct Installation Costs Are Overestimated.

The capital cost estimate includes direct installation costs - foundation & 

supports, handling & erection, electrical, piping, insulation, painting, demolition, and 

relocation - which are estimated as a percentage of the total cost (PEC). No support is 

provided for the assumed percentages. Many of these costs appear to be high and should 

be supported.

Initial Catalyst

The APS cost estimates include costs for the initial charge of catalyst. However, 

as catalyst is replaced every few years, the initial cost is set equal to zero and the annual 

cost is calculated from future worth when using the total annual cost method in the 

Control Cost Manual.85

Foundations and Supports

Foundations and supports are estimated as 20% to 35% of the PEC. The basis for 

assuming 20% to 35% of the PEC should be provided. The resulting costs range from 

$23/kW to $63/kW. These are very high compared to upper bound costs reported for 

other similar retrofits, which range from $9/kW to $11/kW in 2008 dollars.86 These cost 

should be justified in the record.

Handling and Erection

Handling and erection is estimated as 25% to 40% of PEC. The basis for 

assuming 25% to 40% of PEC should be provided. The resulting costs range from 

$38/kW - $47/kW. These costs are roughly double those for upper bound costs reported 

for other similar retrofits, which range from $25/kW to $30/kW.87 These costs should be 

justified in the record.

Electrical Installation

Electrical installation is estimated as 20% of PEC. The basis for this assumption 

should be provided. The resulting costs range from $17/kW to $40/kW. As discussed 

above, electrical equipment costs range from about $12/kW to $15/kW. Thus, total 

electrical costs range from $29/kW to $55/kW. The total costs for electrical equipment 

plus installation typically ranges from $9/kW to $11/kW. 88

 85 U.S. EPA, OAQPS Control Cost Manual, 4th Ed., January 1990, pp. 2-5 to 2-9; U.S. EPA, EPA Air 

Pollution Control Cost Manual, 6th Edition, January 2002, Section 4.2, Table 2.5 (I=0) and p. 2-47.

 Thus, electrical costs are 

substantially outside of the normal expected range and are wholly unsupported in the 

record. The EPA should require support for these excessive costs.

86 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, p. 25, Ex. 6. 87 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, p. 29. 88 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, p. 30.
24

Relocation 

The indirect costs include certain "relocation costs," estimated as 10% of the PEC. 

The record does not disclose anything about these relocation costs, which range from 

about $3 million to $8 million. These costs appear to be double counted as they are likely 

covered by the generous allotments for foundations, supports, handling, and erection 

discussed above. The EPA should require that APS identify each piece of relocated 

equipment, demonstrate through site visits and plot plans that relocation is necessary, and 

provide engineering estimates that support the assumed 10% of PEC estimate.

6. Indirect Costs Are Overestimated.

The EPA noted that APS’ indirect costs include owner's costs, which are not 

included in the Control Cost Manual.89 We agree. The Control Cost Manual does 

include "home office fees." All owners do not manage and implement capital projects, 

but rather retain engineering firms, called the owner's engineer, to perform these 

functions. Other owner activities would be part of its overhead. Cost factors used to 

estimate capital costs are ordinarily reported all in and would include these costs.

Further, these costs, if not directly part of the project, are outside of the battery limits of a 

control project and would be part of the owner's overhead. Thus, they are not usually 

separately included in cost effectiveness analyses. 

7. Unintended Consequences Should Not Be Included.

The EPA correctly noted that APS’ cost analysis includes a cost category called 

"unintended consequences" that is not included in the Control Cost Manual

90 and should 

not be included in cost effectiveness analyses. This category includes mitigation for SO3

removal, lost revenue from extended outages, new continuous emissions monitoring 

systems (“CEMS”), and relative accuracy test audits (“RATA”) for the new CEMS. We 

agree these costs should not be included in the cost effectiveness analysis.

First, this equipment is outside of the battery limits of the SCR and is not part of 

the SCR. The CEMS and RATA are compliance costs incurred to comply with other 

regulatory programs, e.g., acid rain. Thus, these costs should not be included in the cost 

of an SCR to comply with BART. Further, the facility currently has CEMS. 

Second, lost revenue for extended outages to install the SCRs, ranging from $2 to 

$14 million dollars, are included. These costs are not warranted as most of the required 

work can be completed while the plant is operating. The final tie in is normally 

scheduled to occur during a routinely scheduled maintenance outage. Thus, even 

assuming this cost were valid, which it is not, it would not be incurred.

 89 74 FR 44318 (8/28/09).

90 74 FR 44318 (8/28/09).
25

Regardless, these costs are not supported. For example, with respect to Four 

Corners Units 4 and 5, the Black & Veatch report includes two sentences to justify the 

cost estimates for SCR at these units – i.e., that due to the arrangement of the primary and 

secondary air heaters and ductwork, the SCR retrofit would be extremely costly and 

require 14 weeks of downtime.91 It is not clear if this was 14 weeks of downtime per 

unit (or perhaps both units would be down at the same time), but this seems an elevated 

assumption given that no justification was provided for why 14 weeks would be needed. 

The Black & Veatch Reports did not specify the cost of replacement power, claiming it 

was confidential information, and did not provide an estimate of replacement power in its 

cost calculations. So it is not clear whether appropriate assumptions about capacity were 

used or not. EPA should verify this information if lost revenue for extended outages is 

allowed.

Third, cost for Units 4 and 5 include about $7 million for SO3 removal plus 

annual operating costs of $220,000. The record is silent as to what controls are costed or 

how this estimate was calculated. Separate controls to remove SO3 are not required if a 

low SO2-to-SO3 catalyst is selected. The ANPR indicates that APS used a 1% conversion 

rate for the SCR catalyst. EPA determined APS could use a catalyst with a 0.5% 

conversion rate. However, SCR catalyst is available and commonly specified and 

guaranteed with a conversion rate of 0.1%. This would eliminate the need for separate 

controls for SO3. We urge EPA to estimate both costs and visibility impacts assuming a 

0.1% conversion catalyst. 

Further, it is not clear why SO3 controls were included for Units 4 and 5, which 

are equipped with a wet lime scrubber for SO2 control, but not Units 1-3, which use 

venturi scrubbers for SO2 control. The wet lime scrubber is much more effective at 

removing SO3 than the venturi scrubber. An on-the-record explanation for this strange 

set of assumptions is required.

8. Annual Costs Are Overestimated.

Total annual cost (“TAC”) are calculated from the sum of annualized capital plus 

operating and maintenance costs. In reviewing Black & Veatch's cost estimates, EPA 

found that the ratio of the annual costs to the total capital costs for all control 

technologies is considerably higher than those projected by other facilities that were 

amortized over the same 20 year time frame. Thus, EPA recalculated total annual costs 

based on an annual to capital cost ratio of 15%.92 However, EPA made no attempt to 

explore the reasons for the substantial overestimate of annual costs at Four Corners or 

confirm that 15% was reasonable for Four Corners. We investigated the reasons and 

discovered that EPA's 15% factor overestimates annual costs. Our analyses, presented 

below, indicate that the ratio of annual to capital for the five Four Corners units is less 

than 10%.

Annual Capital Costs

 91 12/4/07 Black & Veatch Report, p. 7-4.

92 74 FR 44318 (8/28/09).
26

Total capital investment or TCI includes all costs required to purchase equipment 

needed for a control system, the costs of labor and materials for installing the equipment, 

costs for site preparation and buildings, and certain other indirect installation costs.93

Cost effectiveness is determined by converting the total capital investment into an annual 

cash flow, adding annual operating and maintenance costs, and dividing by the tons of 

pollution removed. This process results in an estimate of cost effectiveness expressed in 

dollars per ton. The Black & Veatch analysis substantially overestimated annual capital 

costs, one of the two key inputs to the cost effectiveness analysis.

Capital Recovery Factor

The total capital investment is converted into annual costs by multiplying by a 

capital recovery factor or CRF. The CRF is given by:

CRF - [ i(1+i)n]/[(1+i)n -1 ]

where i is the interest rate and n is the life of the pollution control equipment. In essence, 

annualization establishes an annual payment sufficient to finance the capital investment 

for its entire life.94 

The CRF depends on two factors, the interest rate and lifetime of the control 

system. The higher the interest rate and the lower the lifetime, the higher the CRF and 

the higher the ratio of annual to total capital costs. Black & Veatch substantially 

overestimated the interest rate and underestimate the equipment lifetime, thus 

substantially overestimating the CRF and annual capital costs. This is one of the key 

factors resulting in APS's substantial overestimate of annual costs.

Interest Rate

First, the Black & Veatch analyses for all pollution control options, including 

SCR, were based on an interest rate of 15%.95 This is more than double the 7% interest 

rate routinely recommended by the EPA and used in cost effectiveness analyses. An 

attachment to a memo setting forth details for BACT analysis procedures prepared by 

John Seitz, Director of the U.S. EPA Office of Air Quality Planning and Standards, on 

January 19, 2001, states that “An assumed interest rate of 7 percent . . . was used for 

computing annualized costs. The interest rate chosen (7 percent) is consistent with EPA 

guidance for control costing and PSD assessments.”96

 93 Control Cost Manual, pp. 2-5 to 2-10.

 A 7% interest rate is also required 

94 Control Cost Manual, January 2002, Section 1, p. 2-21.

95 3/19/09 Black & Veatch, Appx. A. 96 Eastern Research Group, Inc, prepared for the U.S. EPA, Manufacturing, Energy and Transportation 

Division. “Petroleum Refinery Tier 2 BACT Report.” January 16, 2001, attached to Memorandum from 

John S. Seitz, Director, Office of Air Quality Planning and Standards, to Air Division Directors, Regions IX. “BACT and LAER for Emissions of Nitrogen Oxides and Volatile Organic Compounds at Tier 

2/Gasoline Sulfur Recovery Projects.” January 19, 2001. p. 3-22. Found on the Internet at 

http://www.epa.gov/rgytgrnj/programs/artd/air/nsr/nsrmemos/t2bact.pdf. 
27

in the Control Cost Manual.97 Documentation is required if an interest rate other than 7% 

is used. The record contains no such documentation.

EPA Region IV rejected a draft PSD/Title V permit for installing three new 

combustion turbines submitted by the Calvert City Power facility in Calvert City, 

Kentucky, stating that the draft permit “contains a questionable cost evaluation.”98 EPA 

criticized:

The interest rate of 10 percent used to calculate a capital recovery cost. 

The 10 percent rate differs from the 7 percent interest rate referenced in 

the current edition of EPA’s OAQPS Control Cost Manual (EPA 453/B96-001, Fifth Edition). The applicant’s explanation for the 10 percent

interest rate is that it reflects the applicant’s “true cost of capital.” No 

supporting information is provided to verify this statement.99

Finally, an interest rate of 15% is clearly not reflective of interest rates as of today. 

SCR Lifetime

Second, Black & Veatch assumed a lifetime of 20 years for the SCR. The default 

lifetime for SCR used in EPA's CUECost Manual is 30 years. This cost model was used 

for portions of Black & Veatch's cost analyses, including for SCR. A 30-year service life 

is consistent with actual experience with existing SCRs and with the nature of the 

equipment. 

An SCR system should last as long as the plant it is installed on. It is a stationary 

device with no moving parts and uses few pieces of rotating equipment, e.g., pumps. It 

consists of ducting, a metal frame that is filled with blocks of catalyst, an ammonia 

delivery system (tank, pumps, piping),a control system, and instrumentation. The major 

components are stationary and have no moving parts. The catalyst is changed out every 

2-3 years. The ducting and metal frame are similar to the balance of the plant and should 

last as long as the plant itself with proper maintenance. The ammonia injection system, 

accounting for a tiny fraction of the overall cost, should also last as long as the plant if 

wearable parts are replaced as part of routine maintenance. Thus, on a new facility, it 

would be expected to last 50+ years, or the life of the plant.

 97 OAQPS Control Cost Manual, 2002, Section 1, pp. 2-12 to 2-13.

98 Enclosure A of Letter from Winston Smith, U.S. EPA Region IV, Director, Air, Pesticides & Toxics 

Management Division, to John E. Hornback, Kentucky Department for Environmental Protection, Air 

Quality Division Director, Frankfort, KY, August 23, 1999. p. 7. Found on the Internet at 

http://www.epa.gov/Region 7/programs/artd/air/nsr/nsrmemos/calvert.pdf. 99 Enclosure A of Letter from Winston Smith, U.S. EPA Region IV, Director, Air, Pesticides & Toxics 

Management Division, to John E. Hornback, Kentucky Department for Environmental Protection, Air 

Quality Division Director, Frankfort, KY, August 23, 1999. p. 8. Found on the Internet at 

http://www.epa.gov/Region 7/programs/artd/air/nsr/nsrmemos/calvert.pdf.
28

Vendor experience lists identify a number of SCR units that were installed more 

than 30 years ago in Japan that are still in service.100 In the United Stated, Mitsubishi, for 

example, installed three SCR systems on process heaters at the Chevron Richmond 

Refinery in California in 1984. These units are still in service. There have been no 

maintenance, operational or compliance problems, and the original catalyst has not been 

changed out. These SCRs currently have a demonstrated life of 25 years with 

expectation for many more. 

Further, the equipment life for an SCR based on a financial risk study conducted

by Stephen Unwin, et al. for SCRs installed at the Monroe Power Plant outside of Detroit 

concluded a 30-year life was reasonable. This study was designed to examine the 

economic risks from operating SCR at this plant, including siting characteristics and 

operating/maintenance strategy and their effect on SCR system lifetime. The authors’ 

choice of a 30-year life for the SCR system is an important parameter in their study.

101 

On a retrofit, such as these, SCR would be expected to last for the remaining 

useful life of the plant. The 2007 Black & Veatch analysis reported the remaining useful 

life of Units 1 -5 as at least 20 years.102 

The cost analysis assumes only 20 years as the service life of the SCR. However, 

clearly, it could be much longer. The record does not disclose the remaining useful life 

of the Four Corners units or the basis for selecting only 20 years when the remaining 

useful life is admittedly longer and SCRs in operation today have been in service for 

longer times. As remaining useful life has a significant impact on annual cost, an 

enforceable condition should be included in the permit requiring the facility to shutdown 

20 years if SCR is found not to be cost effective due to this assumption. 

The capital recovery factor for Black & Veatch's assumptions (i=15%, n = 20 yrs) 

is 0.1598. The capital recovery factor assuming an interest rate of 7%, as required by 

EPA, and 30 years, is 0.0806 or half that estimated by Black & Veatch. This change 

would reduce the annual cost for Units 1-3 by about $9 million and for Units 4-5 by $21 

million.

Catalyst Replacement

The annual catalyst replacement costs are estimated to be about one-third of the 

cost of the initial catalyst charge, included in the capital cost estimate. This method of 

estimating catalyst replacement cost is incorrect. As explained in the Control Cost 

Manual, the annual cost of catalyst replacement is a function of the future worth of the 

 100 McIlvaine Company, Worldwide Utility Plans, NOx Installation and Component Suppliers (Ex. 12); 

Vendor Experience Lists for Hitachi and Mitsubishi. Exs. 13 and 14. 101 Unwin, Stephen D., Johnston, Robert W., and Rudy, Steven W. and Delargey, James E. and Rogers, 

William. “Selective Catalytic Reduction (SCR) System Design and Operations: Quantitative Risk 

Analysis of Options,” presented at CCPS 17th Annual International Conference: Risk, Reliability, and 

Security. p. 3. Found on the Internet at http://www.unwin-co.com/files%5CSCR-Risk-Paper,CCPSRRS2002.pdf,. 102 12/4/07 Black & Veatch, p. 6-2.
29

catalyst because catalyst is replaced every few years. Future worth is used because the 

annual catalyst replacement cost is accrued starting in the first year of operation, while 

catalyst replacement purchases occur every few years.103 This substantially reduces 

annual catalyst replacement cost.

Assuming a typical catalyst life of 24,000 hours, three active layers and one 

spare,104 the future worth factor is 0.31.105 The replacement cost is then calculated by 

dividing the initial cost by 3 layers and multiplying by the future worth factor. Thus, 

replacement costs were overestimated by about a factor of three. Assuming the cost of 

the initial charge is correct, the catalyst replacement cost is as reported in Table 2.

Table 2

Revised Catalyst Replacement Cost

($$ M)

Unit B&V

2009

Revised

1&2 706 264

3 909 264

4&5 2,279 821

Further, catalyst replacement cost did not consider catalyst regeneration, which 

has become an attractive alternative to purchasing new catalyst since the Control Cost 

Manual was last updated. The cost of purchasing new catalyst normally varies between 

$3,500 and $6,500 per m3, while the cost to regenerate is about 60% of this price.106

Catalyst Disposal

The APS annual costs include catalyst disposal costs, ranging from $272,000 per 

year for Units 1 and 2 to $877,000 per year for Units 4 and 5. These costs are 

unwarranted as the cost of disposal is included in the purchase price of the catalyst, which 

is returned to the vendor. The default, for example, for the CUECost model, which was 

used to estimate this cost, is zero.

107 The assumed cost should be supported by a vendor 

quote or the cost set equal to zero.

Operating Labor

The APS annual costs include operating labor for the SCR, ranging from $68,000 

to $163,000. An SCR is a stationary device with no moving parts. It includes few pieces 

of rotating equipment, e.g., pumps, motors, that would require operating labor. 

 103 Control Cost Manual, Sec. 4.2, p. 2-47. 104 12/4/07 Black & Veatch, pp. C-4, C-15, C-26, C-37. 105 Future Worth Factor = 0.07[1/[(1+0.07)3 - 1] and Y = 24,000 hrs/8760hrx0.9 = 3 106 Mike Cooper, New Life for Catalyst, Power Engineering, March 2006. Ex. 15. 107 U.S. EPA, Coal Utility Environmental Cost (CUECost) Workbook User's Manual, p. D-4.
30

Therefore, the existing plant staff can operate the SCR from an existing control room. In 

general, operation of an SCR does not require any additional operating or supervisory 

labor.108 This value should be zero.

Maintenance Labor and Materials

The Black & Veatch study estimated costs for maintenance labor and materials as 

3% of direct costs. The Control Cost Manual indicates these costs should be calculated 

as 1.5% of the total capital investment. Thus, these costs are overestimated by a little less 

than a factor of two.

Levelization Factor

The total direct annual costs and total annual costs were both increased by 

multiplying them by a "levelization factor." The factor used for direct annual costs was 

1.45129 and for total annual cost, 1.1021. No explanation is provided for this factor or

the reason it differs for these two cost components. Further, the variables used to 

calculate it are not identified.

Levelization escalates costs. The constant levelization factor is generally used to 

express the relationship between the value of an expenditure at the beginning of the first 

year and an equivalent annuity, or levelized value. It depends on both the annual cost of 

money or the discount rate and the nominal escalation rate,109 which are not reported in 

the record. 

Cost effectiveness analyses do not include escalation. The total annual cost 

method used in cost effectiveness analysis, as laid out in the Control Cost Manual, 

expresses costs in real dollars. Thus, they are based on the "real" interest rate, which 

does not include inflation.110 Inflation is not included in BACT cost effectiveness 

analyses as they rely on the most accurate information available at current prices and do 

not try to extrapolate those prices into the future.111

 

 Regardless, no basis is provided for 

the various escalation factors that were used.

9. Alternative SCR Arrangements Were Not Considered.

The 2007 Black & Veatch BART analysis claims "extreme retrofit difficulty" for 

the SCR located in the hot-side position, between the boiler outlet and the air preheater112

 108 OAQPS Control Cost Manual, Sec. 4.2, p. 2-45.

and includes costs to rip out and replace existing equipment. In this situation, high 

retrofit costs due to space constraints, it is common to evaluate alternatives to the 

conventional arrangement. Alternative arrangements include: an elevated hot-side SCR; 

109 A 3% escalation rate was reported in the 12/4/07 Black & Veatch Engineering Analysis, Table ES-2. 

However, the revised 3/16/09 Black & Veatch Engineering Analysis did not report any escalation rate or 

discount rate.

110 Control Cost Manual, 3rd Edition, February 1987, pp. 2-13 to 2-14. 111 See, e.g., Control Cost Manual, 6th Edition, January 2002, Section 1, p. 2-36. 112 12/4/07 Black & Veatch Report, p. 7-1.
31

an outboard arrangement, as proposed for Navajo; a low-dust SCR (located after the 

particulate control device); and a tail-end SCR, located at the tail end, following all 

pollution control devices. These latter alternative arrangements are attractive as the SCR 

is located downstream of the air preheater, thus avoiding the space-constrained area 

between the boiler outlet and the inlet to the air preheater. Further, they result in a longer 

catalyst life and greater fuel flexibility. Subsets of these alternatives include ducting 

together two or more units. There is no evidence that any alternative arrangements were 

considered.

Only a high dust SCR was evaluated which, according to the Black & Veatch 

report, would require new forced draft fans, air heaters, and ID fans.

113 However, 

retrofitting of a low dust or tail end SCR may be a more cost effective retrofit –

especially if combined with upgraded particulate matter controls for these units. 

Recently, Wisconsin Energies decided it was more cost effective to retrofit Oak Creek 

Units 5-8 with low dust/tail-end SCRs, rather than the more traditional high dust 

SCRs.114 Tail-end SCR units can be smaller than high dust units, have longer catalyst 

life and can use less expensive catalysts.115 Further, the time to accomplish the retrofit 

would be much lower. Thus, EPA should require evaluation of these other SCR 

configuration for the FCPP.

10. Revised Costs.

We revised those portions of the cost analysis that could be addressed by 

eliminating an invalid cost or adjusting a cost, without designing the system from scratch. 

We were not able to redesign and recost completely because the record is missing critical 

information that is required for an accurate estimate, including plot plans and key design 

parameters. Our revised costs start with Black & Veatch's 3/16/09 estimate of TCI and 

DAC, subtract invalid costs as discussed supra (taxes, intended consequences, initial 

catalyst, owners cost, catalyst disposal, overestimated catalyst disposal, and escalation), 

and recalculate the capital recovery factor and hence annualized capital costs. 

Our revised costs are summarized in Exhibit 18. They show that revised annual 

costs are 10% of the total capital, compared to EPA's estimate of 15%, based on other 

BART analyses. In our opinion, other BART analyses are not a reasonable basis for 

estimating cost effectiveness for Four Corners as these other analyses, which we did not 

find in the record, were likely performed by applicants with a motivation to overestimate 

costs, and thus probably have many of the flaws discussed here. We encourage the EPA 

to require APS to revise their costs, following the Control Cost Manual and specifically 

addressing the issues we raise above.

 113 12/4/07 Black & Veatch Report, pp. 7-2 to 7-3. 114 See August 24, 2007 letter from Wisconsin Energies to the Public Service Commission regarding the 

Oak Creek Power Plant, Appendix C August 20, 2007 Addendum Emission Reduction Study, and 

Appendix C NOx/SO2 Emission Reduction Study. These document are all included as Exhibit 16 to this 

letter.

115 See January 2009 FGD and DeNOx Newsletter. Ex. 17.
32

We agree with EPA that APS's reported total capital costs should be reduced by at 

least 15%. In our opinion, the actual annual costs would be less than 10% of total capital

if all of the overestimates discussed above were considered. There are some components 

of the total capital cost estimate that we were unable to correct due to the inadequate 

record, e.g., foundation & supports, handling & erection, electrical justifying an 

adjustment below 10%. 

The National Park Service calculated capital and annual costs and cost 

effectiveness of SCR based on EPA’s Air Pollution Control Cost Manual. See Table 9 of 

the ANPR. Those costs estimates are significantly less than the cost estimates provided 

by APS in either its March 2009 submittal or in the 2007 Black & Veatch report. Given 

that EPA has recommended all BART cost analyses be based on EPA’s Control Cost 

Manual to improve consistency and that other EGU owners are complying with that 

recommendation, EPA should rely on the National Park Service cost calculations.

Further, while EPA attempted to address some of the issues we discuss above for 

SCR by recalculating total annual costs based on a ratio of 15% annual to capital costs, 

EPA did not account for discrepancies in the capital cost calculations for SCR plus other 

NOx controls, e.g., SCR + LNB and SCR+LNB+OFA. 74 Fed.Reg. 44138. EPA should 

also adjust the capital costs for SCR plus other NOx controls, especially given APS’s 

increases in the capital cost estimates that it provided in March 2009 do not appear to be 

justified. 

B. SCR Costs at the Navajo Generating Station Are Inflated.

The Salt River Project (SRP) relied on cost analyses provided by Sargent & 

Lundy.116 These were updated in January 2009 by ENSR Corporation. 2009 ENSR 

Report.117 The following comments focus on the option that includes SCR on all three 

units, Option 1A in the Sargent & Lundy analysis and Option 4 in the ENSR analysis 

(LNB/SOFA&SCR on Units 1-3).

1. Total Capital Costs for SCR Options Are Higher than Reported by Others.

As explained for Four Corners, capital costs for pollution control equipment are 

commonly reported on a dollar per kilowatt of capacity basis. The unit capital costs, 

based on the costs presented in the ANPR for Navajo118 are summarized in Table 3.

Table 3

Summary of SCR Capital Cost

Navajo Generating Station

 116 July 25, 2008 Sargent & Lundy Report “Salt River Project Navajo Generating Station, SCR and SNCR 

Cost Study, Final Report,” submitted by SRP to EPA on July 29, 2008 (EPA-R09-OAR-2009-0598-0007). 117 ENSR Corporation, Revised BART Analysis for the Navajo Generating Station Units 1-3, Prepared for: 

Salt River Project - Navajo Generating Station, January 2009. (EPA-R09-OAR-2009-0598-0010). 118 74 FR 44320, Table 12.
33

Unit Capital

Cost ($)

Size

MW

$/

kW

1 212,000,000 750 283

2 281,000,000 750 375

3 212,000,000 750 283

These costs are at the upper end of the range (Units 1, 3) or slightly higher than 

the highest reported cost for other similar facilities ($83/kW - $323/kW), based on the 

studies and other information reviewed above for Four Corners. Thus, we believe the 

Navajo costs are high, but not wildly out of bounds like the costs for Four Corners. We 

discuss some of the factors that lead to these overestimates below. We can only identify 

some of the contributing factors as the Sargent & Lundy cost estimate is inadequately 

documented in the record.

2. Cost Estimates Are Not Supported.

The EPA’s BART Guidelines require that cost analyses for BART determinations 

be documented with data supplied by an equipment vendor or by a referenced source 

such as EPA’s OAQPS Control Cost Manual. They also require that the design basis be 

provided. The Navajo analysis did not include any references or basis for its 

assumptions. 

First, the ANPR claims these costs are based on the Sargent & Lundy report. 

However, the costs in the ANPR are apparently based on the 2009 ENSR report as they 

both sum to $705 million.119 This sum is 28% higher than the corresponding Sargent & 

Lundy estimate.120 No explanation is provided for this increase in capital cost between 

July 2008 and January 2009.

Second, the revised capital costs reported in 2009 by ENSR do not break out the 

costs by generating unit, but rather only report one lump sum number for the entire 

station, $705 million. No supporting calculations or vendor quotes are presented for 

anything. The Sargent & Lundy Report, for example, notes that retrofit difficulty was 

factored into the cost estimates,121 but no information on how this was done is provided. 

This prevents any meaningful evaluation of the claims as to the retrofit difficulty of Unit 

2. A detailed accounting of the costs should be provided for all three units. This 

accounting should include itemized costs for engineering, piling and foundations, 

structural steel, SCR reactor housing, ammonia injection system, catalyst, ductwork, 

booster fans, electrical/instrumentation and controls, among others. 

Third, the costs were estimated assuming "an overall degree of difficulty" to 

retrofit SCR.122

 119 2009 ENSR Report, Tables ES-1 and Table 4-2; 74 FR 44320, Table 12.

 This "difficulty" factor was not identified. Generally, a retrofit factor is 

120 7/25/08 Sargent & Lundy Report, Table 7-1. 121 7/25/08 Sargent & Lundy Report, p. 4. 122 7/25/08 Sargent & Lundy Report, p. 9.
34

used to adjust costs for site constraints. The increase in costs due to any site constraints 

should be broken out and justified.

Fourth, as explained for Four Corners, the cost of an SCR is determined by its 

design basis. The design parameters for an SCR include the ammonia-to-NOx molar 

ratio, the pressure drop, catalyst life, catalyst management plan, space velocity, and flue 

gas flow rate, among others.123 The ENSR and Sargent & Lundy reports and EPA's 

summary thereof contain none of this information. Thus, it is not possible to critically 

evaluate the costs.

Fifth, the record contains no support for the cost effectiveness values proferred in 

the ANPR. These values appear to have been calculated by annualizing the unsupported 

capital costs using a cost recovery factor of 0.1179124 and adding the operating and 

maintenance costs. 125 Support should be provided for the components of the O&M costs 

and the inputs to the capital recovery factor.

3. Improper Cost Method Was Used.

The Sargent & Lundy Report indicates that costs were developed using an internal 

S&L cost database, adjusted for differences in ductwork, structural steel, and 

constructability issues.126 However, the BART Guidelines do not recognize this as one 

of the acceptable methods for developing BART cost estimates, particularly since it is not 

transparent and documented in the record.

The National Park Service calculated the cost effectiveness of SCR+LNB+SOFA 

based on EPA’s Control Cost Manual, which EPA provided in Table 15 of the ANPR. 

Those costs are lower than the capital and annual costs provided by SRP (provided in 

Table 9 of the ANPR). Given that EPA has recommended all BART cost analyses to be 

based on EPA’s Control Cost Manual to improve consistency and that other EGU owners 

are complying with that recommendation, EPA should rely on these cost calculations 

provided by the National Park Service that in turn are based on EPA recommended 

procedures. 

4. Capital Costs Are Overestimated.

The Sargent & Lundy Report states that "the objective of this study is not to 

develop conceptual designs for retrofitting these new control technologies, but to come 

up with high level arrangements." Elsewhere, the review is characterized as "high level 

review of feasibility..." and the costs as "high level costs."127

 123 70 FR 39166 (7/6/05; OAQPS Manual, Sec. 4.2.

 We take this to mean a 

worst-case cost estimate. In our opinion, a worst-case cost estimate is not a reasonable 

basis to evaluate BART cost effectiveness.

124 2009 ENSR Report, Table 4-2, note (a). 125 7/25/08 Sargent & Lundy Report, p. 10. 126 7/25/09 Sargent & Lundy Report, p. 8. 127 7/25/08 Sargent & Lundy Report, p. 2
35

The capital costs for Navajo improperly included cost for lost generation at each 

unit due to an additional 4 weeks128 of unit downtime to tie-in the SCR. The cost of 

buying replacement power was estimated to be $23 million for Units 1 and 3 and $34 

million for Unit 2, based on operation at 100% capacity at $45/MWh.

129 This is more 

than 10% of the estimated capital cost of an SCR at each unit. This is not one of the cost 

items included in the Control Cost Manual. Regardless, it is overestimated.

First, it assumes each unit will operate at 100% capacity during the 4 week period. 

Outages are generally scheduled for slow periods when demand is at the lowest. Further, 

due to hourly fluctuations in demand, units ramp down during evening hours and rarely 

would operate at 100% capacity. Rather, an 85-90% capacity factor would be typical. In 

fact, EPA assumed an 85% capacity factor for Navajo in estimating the increase in 

electricity generation costs.130 A 100% capacity factor during an outage is wholly 

unjustified and should not be allowed.

Second, no justification was provided regarding the $45/MWh replacement power 

cost provided by SRP.

 

Third, it appears that the cost of replacement power did not consider the reduction 

in Navajo's operating costs during the additional 4 week shutdown (i.e., other O&M costs 

that would not be incurred, such as ash and gypsum disposal). 

Fourth, no justification has been provided by SRP that the additional 4 – 6 weeks 

will even be necessary. It was just stated as an assumption that the modification/tie-in 

work would take 9-12 weeks for Units 1 and 3, and an additional 2 weeks for Unit 2. It is 

unclear whether the SCR would be tied in to the precipitator inlet (where there is 

congestion) or the outlet, where there appears to be little congestion. It appears SRP 

assumed the worst case in determining costs of SCR installation131. Other SCR 

modification/tie ins have been completed within an 8 week outage,

132 which is typical.133 

Because of the uncertainty as to whether additional down time will even be required for 

any SCR retrofits at Navajo, it does not seem appropriate for SRP to include estimates for 

the purchase of replacement power for down time beyond an 8-week outage. 

5. Annual Costs Are Overestimated.

The record does not disclose how annual costs summarized in the ANPR were 

estimated. The supporting BART analyses suggest annual costs were calculated as the 

 128 The Sargent & Lundy Report states at 9 that a 4 weeks extended outage was assumed for each unit. 

However, at 7, it states 6 weeks would be required for Unit 2. We do not know which was assumed as no 

supporting calculations were provided.

129 7/25/08 Sargent & Lundy Report, pp. 9-10. 130 74 FR 44322. 131 7/25/08 Sargent & Lundy Report, pp. 6-7. 132 See, e.g., http://www.enerfab.com/power/retrofit.htm. 133 Institute of Clean Air Companies, Typical Installation Timelines for NOx Emissions Control 

Technologies on Industrial Sources, December 4, 2006, p. 8. Ex. 19.
36

sum of operating and maintenance134 costs plus annualized capital, assuming an interest 

rate of 9.8% and a lifetime of 20 years.135 This overestimates annual costs.

As explained above, an interest rate of 7% and a lifetime of 30 years should have 

been used. The capital recovery factor assuming an interest rate of 7% and 30 years, is 

0.0806. This reduces annualized capital costs by 70%. The effect on cost effectiveness is 

summarized in Table 4.

Table 4

Impact of Capital Recovery Factor on

Cost Effectiveness

($/ton)

Unit ANPR Cost

Effectiveness

Revised

Cost

Effectiveness136

1 1,833 1,360

2 2,419 1,771

3 1,900 1,410

These revised cost effectiveness values are consistent with those estimated by the NPS 

for Navajo ($1,059/ton - $1,528/ton) using the Control Cost Manual, within the error of 

the estimate (+/-30%). They are also well within the range of costs that have been found 

to satisfy BART in other cases. 

6. EPA's NOx Emission Reductions Overstate Cost Effectiveness Values.

The ANPR reduced SRP's estimated NOx emission reductions to adjust the 

averaging time from 24-hour to annual average. The ANPR then calculated revised cost 

effectiveness values from SRP's estimates of annual costs and the lowered emission 

reductions. This had the effect of artificially increasing cost effectiveness values from a 

range of $1,833/ton - $2,419/ton to $3,002/ton - $3,736/ton.137

 134 7/25/08 Sargent & Lundy Report, p. 10 (0.42 + 4.158 MM$/yr).

 This is incorrect. The 

cost of an SCR system depends upon the amount of NOx that it has to remove. The EPA 

should have reduced the capital and O&M costs of the SCR system in accord with the 

reduction in NOx emissions. This would lower the cost effectiveness values to within the 

range estimated by SRP, as corrected below in Table 5.

135 2009 ENSR Report, Table 4-2, note (a). We note that an 8/20/08 e-mail from Barbara Sprungl to Anita 

Lee claims that a 7% interest rate was used, but we were unable to find any support for this assertion in the 

documents available in the docket.

136 Calculated as: (capital cost from ANPR, Table 12)(0.0806) + $4,400,000/(NOx Emission Reduction

from ANPR, Table 13). The annual O&M of $4,400,000 was back calculated from the ANPR, Table 12, 

assuming a CRF of 0.1159. This is close to the O&M cost estimated in 7/25/08 Sargent & Lundy Report at 

10, but differs substantially from the O&M cost in the cover letter to the Sargent & Lundy Report, which 

reported $12,474,000/yr. The numerous discrepancies in the record should be resolved.

137 74 FR 44321, Table 14.
37

7. Alternative SCR Arrangements Were Not Considered.

Sargent & Lundy proposed to locate the SCRs outboard of the units (off to the 

side) and tie them in to the precipitator outlet,138 a low-dust configuration. SRP claims 

that installation of an SCR at Unit 2 will be difficult due to the limited room for 

installation.139 However, it appears from the plot plans in Attachment 1 that the spaceconstrained area is between the furnace and the air preheaters, a high-dust location, not at 

the outlet of the precipitators.

The Sargent & Lundy report mentions the possibility for a high-dust SCR, but 

then provides no cost estimates for that option. SRP also did not evaluate the possibility 

of a tail-end SCR, after the scrubber. Other arrangements are also feasible, such as in an 

elevated structure over the precipitators or on the boiler house. EPA should require the 

evaluation of these and other options.

C. The NOx Emission Reductions Achievable with the Suite of NOx BART 

Controls Has Been Underestimated.

1. Lower NOx Emission Rates Can Be Achieved with State-of-the-Art NOx 

Controls at Navajo.

SRP has stated that the Navajo units could meet a NOx emission limit of 0.24 

lb/MMBtu, with a possible reduction down to 0.20 lb/MMBtu, with new low NOx

burners and separated overfire air. See, e.g., SRP’s January 2009 BART Proposal [EPAR09-OAR-2009-0598-0010.1] at 6-1. SRP should be able to at least meet a NOx limit of 

0.20 lb/MMBtu or lower with state-of-the-art ultra low NOx burners and separated 

overfire air (LNBs/SOFA). Although SRP claims that lower NOx emission rates have 

only been achieved at facilities burning Powder River Basin coal, SRP has not provided 

any legitimate reason why it could not achieve similar levels of NOx emissions with the 

coal it currently burns at Navajo. 

Many other existing coal-fired units are achieving lower NOx emission rates with 

these controls. Exhibit 20 to this letter includes a spreadsheet with NOx emissions data 

from 2004-2006 that provides numerous examples of tangentially-fired boilers with low 

NOx burners and overfire air meeting lower NOx emission rates than 0.20-0.24 

lb/MMBtu. 

Thus, while SRP has indicated it was not sure whether the Navajo units can meet 

a NOx limit of 0.20 lb/MMBtu NOx emission limits with just LNBs/SOFA, it seems quite 

possible that these units could readily meet that limit and even achieve lower NOx

emissions with ultra low NOx burners and modified overfire air. EPA should not rely on 

 138 7/25/08 Sargent & Lundy Report, p. 6.

139 7/25/08 Sargent & Lundy Report, p. 6 (states modifications at precipitator outlet would be difficult, but 

then proceeds to describe the ductwork between the boiler and precipitator, which is not the outlet of the 

precipitator.) Further, the plot plans in Attachment 1 suggest the tie-in is to the precipitator inlet. We 

wonder whether both arrangement were considered at one point and the text not fully modified?
38

SRP’s assessment of the NOx emission rates presumed to be achievable at the Navajo

units with new LNBs and SOFA and should instead re-evaluate the NOx emission levels 

achievable with new LNBs/SOFA at the Navajo units.

With SCR added in, SRP estimates it could achieve a NOx emission rate of 0.08 

lb/MMBtu. This only reflects between 60-67% removal from the emission rates SRP 

claims it could meet at Navajo with LNBs/SOFA. 

A review of recent SCR retrofits most definitively shows that very high levels of 

NOx removal are being achieved by recent SCR retrofit installations. NOx emission rates 

less than 0.05 lb/MMBtu are routinely achieved, and NOx removal efficiencies are 

typically around 90%.140 Permitting agencies have required lower NOx limits in recent 

BACT determinations, with many proposed and required BACT limits of 0.05-0.06 

lb/MMBtu. For example, the Dry Fork power plant will be a subbituminous coal-fired 

power plant with low NOx burners and overfire air for combustion controls along with an 

SCR, and it is subject to a NOx BACT emission limit of 0.05 lb/MMBtu. With the stateof-the-art low NOx burners and overfire air on this unit, it is very likely that NOx

concentration exiting the Dry Fork boiler will be in the 150 ppmdv range, and yet this 

unit is subject to a NOx BACT limit that likely reflects over 80% control. There are other 

examples of proposed subbituminous coal-fired power plants that will meet similar levels 

of NOx control including Plant Washington to be located in Georgia and Wygen 3 in 

Wyoming. 

There are also several proposed bituminous coal-fired power plants planning to 

utilize low NOx burners, overfire air and SCR with proposed or required NOx limits 

lower than 0.08 lb/MMBtu as well as several NOx limits that are lower than 0.06 

lb/MMBtu. We have attached a spreadsheet of NOx BACT rankings obtained from the 

National Park Service Air Resources Division that provides several examples of lower 

NOx BACT limits. Ex. 22. Further, EPA Region 9 has required the proposed Desert 

Rock power plant to meet a NOx BACT limit as low as 0.035 lb/MMBtu.141 The Desert 

Rock facility will burn western bituminous coal from the same region as the coal utilized 

at Navajo. 

In the ANPR, EPA indicated that it revised the Navajo baseline NOx emission 

rates used in SRP’s cost effectiveness calculations for NOx BART, but EPA did not 

question the achievable NOx rates assumed by SRP for LNB+SOFA or for 

LNB+SOFA+SCR. See 74 Fed.Reg. 44321-2. As stated above, SRP’s assumed 0.08 

lb/MMBtu emission rate achievable with LNB+SOFA+SCR only reflects 60-67% NOx 

 140 See Erickson, Clayton A. et al., Selective Catalytic Reduction System Performance and Reliability 

Review, The 2006 MEGA Symposium, Paper # 121. Ex. 21. 141 The Desert Rock Energy Facility permit requires the facility to achieve, after a NOx optimization 

period, a NOx emission rate of 0.035 lb/MMBtu on a 365 day rolling average and an emission rate of 0.05 

lb/MMBtu on a 30-day rolling average. A copy of the Desert Rock PSD permit is included as Ex. 23 to this 

letter. (Although EPA recently has sought and obtained a voluntary remand of the Desert Rock permit, 

EPA did not identify the NOx limits of the permit as something it intended to modify.) See also the 

National Park Service spreadsheet on BACT limits for New PC Power Plants (Ex. 22).
39

removal with SCR.142 Yet, with respect to the Four Corners Power plant, EPA stated in 

the ANPR that 80% removal with SCR could be achieved. See 74 Fed.Reg. 44319. 

Eighty percent NOx removal with SCR at each of the Navajo units would equate to 

emission rates of 0.04 – 0.05 lb/MMBtu. In its July 2009 submittal to Region IX, the 

National Park Service provided its opinion that a NOx emission rate of 0.05 lb/MMBtu 

was achievable with LNB+SOFA+SCR at the Navajo units. See July 24, 2009 Submittal 

from the National Park Service to EPA Region IX, Attachment at 3 and Appendix A143. 

We agree that 0.05 lb/MMBtu would be achievable and likely, even lower NOx emission 

rates would be achievable with upgraded LNBs/SOFA and SCR at the Navajo units. 

EPA has requested comment on the use of an SCR for half of the gas stream from 

Navajo Unit 2. 74 Fed.Reg. 44322. This is because the flue gas stream from Navajo

Unit 2 is split due to the physical layout of Unit 2, and so SRP has estimated the SCR 

retrofit costs at Unit 2 to be much higher than Units 1 or 3. Thus, EPA has proposed use 

of an SCR on half of the gas stream at Unit 2 as a BART option in the ANPR with a 

controlled NOx emission rate of 0.14 lb/MMBtu. Id. Based on the above comments, 

even if only half the gas stream of Unit 2 is routed through an SCR system but the unit 

also has upgraded LNBs + SOFA, the unit should be able to achieve lower emission rates

on the order of 0.12 lb/MMBtu or lower. More importantly, based on the National Park 

Service comments, it appears that retrofitting of SCR to the entire Unit 2 gas stream is 

more readily achievable than presented by SRP. The National Park Service investigated 

this and determined that one SCR reactor chamber could be located adjacent to one of the 

Unit 2 electrostatic precipitators with the other reactor chamber located above the other 

ESP. See July 2009 letter from National Park Service to EPA Region IX [EPA-R09-

OAR-2009-0598-0017], Attachment at 5-6. Thus, it is questionable whether EPA should 

evaluate the “half-SCR” option at all for Navajo Unit 2, since much greater NOx 

reductions would be achievable with a full SCR system.

In summary, the emission reductions that SRP and EPA relied on in the cost 

effectiveness calculations are much lower than the NOx reductions that could be achieved 

at the Navajo units. This means that the cost effectiveness calculations presented both by 

SRP and EPA overestimate the cost effectiveness of the NOx BART controls being 

evaluated. Further, as stated above, the costs of SCR were overestimated by SRP, which 

adds to the overestimate of the cost effectiveness of NOx controls. In addition, the 

visibility modeling assessment associated with the NOx BART controls underestimates 

the visibility benefit because it fails to reflect the NOx reductions that would be achieved 

with the various NOx BART options. Thus, EPA should require the evaluation of NOx 

BART controls, especially the control option of LNBs+SOFA+SCR, to be based on the 

best emission rates that have been achieved in practice and that are achievable at the 

Navajo units. 

 142 Interestingly, in the visibility modeling for the SCR options, EPA remodeled visibility impacts based on 

a NOx emission rate of 0.06 lb/MMBtu. 74 Fed.Reg. 44329 (8/28/09). This clearly shows that EPA is 

aware lower NOx emission rates are achievable with upgraded combustion controls and SCR at Navajo.

143 The National Park Service’s July 24, 2009 letter and attachment are in the docket at EPA-R09-OAR2009-0598-0017. However, Appendix A to the National Park Service’s letter is not in the docket, so we 

have included it as Exhibits 51A-E to this letter.
40

2. Lower NOx Emission Rates Can Be Achieved with State-of-the-Art NOx 

Controls at Four Corners.

In the cost analysis for the NOx BART controls evaluated, the 2007 Black & 

Veatch BART Engineering Report indicated that NOx emission rates of 0.43 lb/MMBtu 

for Units 1 and 2 could be achieved with upgraded LNBs. That report also indicated that 

NOx emission rates of 0.33 lb/MMBtu for Unit 3 and 0.35 lb/MMBtu for Units 4 and 5 

could be achieved with new low NOx burners and overfire air. These emission rates are 

much higher than what SRP assumed for application of these NOx controls to the Navajo

units. Based on the information discussed above and attached to this comment letter, 

lower NOx emission rates should be achievable with state-of-the-art low NOx burners and 

overfire air at these Four Corners units. For Units 1 and 2, these emission rates are not 

even reflective of EPA’s presumptive NOx BART limits of 0.39 lb/MMBtu. Thus, EPA 

should more closely evaluate the achievable NOx emission rates at each of the Four 

Corners units based on the available combustion controls for these units.

In evaluating SCR for the Four Corners facility, the Black & Veatch report 

evaluates a NOx emission rate of 0.06 lb/MMBtu for SCR by itself, with new LNBs, or 

with new LNBs/OFA. Tables 5-1 and 5-2 of 2007 Black & Veatch report. While this 

NOx emission rate is lower than assumed by SRP in its analysis for the Navajo units, it 

still does not reflect the maximum degree of emission reduction achievable with an SCR 

system.

For some reason, EPA believes this assumed emission rate for SCR plus upgraded 

LNBs/OFA at the FCPP is too high. Specifically, EPA stated that APS estimated that 

SCR could achieve NOx control of 90% or better, but EPA believes that only 80% 

control from SCR along is achievable for SCR retrofits. 74 Fed.Reg. 44319. EPA cited 

to a White Paper on SCR issued by the Institute of Clean Air Companies (“ICAC”) as 

part of its reasoning [EPA-R09-OAR-2009-0598-0032], apparently claiming that 90% 

reduction with SCR is only achievable at new coal-fired boilers. Based on this ICAC 

paper and the 75% NOx reduction rate that the Arizona Department of Environmental 

Quality determined to be achievable for the Coronado Station, EPA determined that 80% 

control with SCR is more appropriate than SRP’s assumed 90% control level. The ICAC 

paper supports SRP’s claims and does not indicate that retrofits cannot achieve 90% NOx 

control. Specifically, the ICAC paper states

Most SCRs for coal-fired boilers are designed for about 90 percent NOx 

removal and very low ammonia slip (typically less than 2 ppm).144

The data on SCR retrofits and attached to this letter show this to be true. NOx

emission rates less than 0.05 lb/MMBtu are routinely achieved, and NOx removal 

efficiencies are typically around 90%.145

 144 ICAC White Paper at 12.

 As discussed above, permitting agencies 

145 See Erickson, Clayton A. et al., Selective Catalytic Reduction System Performance and Reliability 

Review, The 2006 MEGA Symposium, Paper # 121. Ex. 21.
41

including Region IX have required lower NOx limits in recent BACT determinations, 

with many proposed and required BACT limits of 0.035-0.06 lb/MMBtu.

Thus, EPA should require the evaluation of a NOx emission rate reflective of the 

maximum degree of NOx emission reduction that can be achieved at the Four Corners

units with combustion controls and with combustion controls and SCR. The available 

information overwhelmingly supports a lower NOx emission limit for these controls than 

assumed by either APS or EPA. Further, the costs estimates and the modeling must be 

redone for the SCR options with such lower NOx emission limits.

C. The Cost Effectiveness of SCR is Reasonable.

Cost effectiveness is the annual cost of a control option in dollars divided by the 

tons of pollution that is removed. Annual costs are calculated in a particular way, set out 

in the Control Cost Manual and discussed above, to assure a level playing field when 

comparing control technologies. Cost effectiveness (dollars per ton of pollutant 

removed) values that are disproportionately high compared to the cost of control borne by 

others indicates that the cost is not reasonable. We compared the cost effectiveness 

values estimated by the companies, EPA and NPS with costs to control NOx borne by 

others or that have been found to be cost effective by other agencies. This analysis is 

summarized in Table 5. It shows that even APS' and SRP's overestimated costs for SCR 

are well within the costs to control NOx incurred by others or found by others to be 

reasonable. Thus, SCR is per se cost effective for all of the Four Corners and Navajo 

units.

Table 5

Cost Effectiveness Summary

($/ton)

Four

Corners

Navajo

Company 4,343-5,484 1,833-2,419

EPA 3,646-4,803 3,002-3,736

NPS 1,185-1,684 1,059-1,528

Others >4,500-24,500 <4,500-24,500

One of the earliest SCRs on a coal-fired power plant in the United States was 

permitted in 1991 in New Jersey at the Logan Generating Plant.146

 146 Award-winning Logan Generating Plant Celebrates Five Years of Operating Excellence, Business Wire, 

September 30, 1999. 

The permit gave the 

facility the option of installing either an SCR, estimated to cost $13,196/ton, or an SNCR 

http://www.allbusiness.com/energy-utilities/utilities-industry-electricpower/6710358-1.html (Ex. 24); D.W. Bullock, Long-term SCR Operating Experience at PG&E 

Generating's Coal-Fueled Plants, ICAC Forum 2000, March 2000 (Ex. 25).
42

estimated to cost $3,980/ton.147 The facility was built with an SCR, started up in 

September 1994, and continues to operate with SCR.148 The SCR cost effectiveness 

value from 1991 escalates to $21,016/ton in 2008 dollars. In 1992, an SCR was 

permitted at the Stanton coal-fired power plant in Florida. The cost effectiveness was

$4,262/ton for 70% NOX removal and a 2 year catalyst life.149 This is $6,846/ton in 2008 

dollars.150 An application is currently pending before the Wisconsin Public Services 

Commission to retrofit an SCR on the 430 MW Edgewater Unit 5, estimated to cost 

$15,400/ton.151 Arizona, where Navajo is located, wrote that it had determined that a 

cost effectiveness value of more than $4,489/ton of NOx reduced is cost effective.152

Four Corners and Navajo are located in EPA Region IX. Several air districts in 

Region IX have established cost effectiveness thresholds for NOx. They are summarized 

in Table 6.

Table 6

Region IX

Cost Effectiveness Thresholds

($/ton)

Region153 NOx

Threshold

SJVAPCD 24,500

SMAQMD 24,500

YSAQMD 24,500

SCAQMD 19,100

SDAPCD 18,000

BAAQMD 17,500

The EPA has used $10,000/ton as a benchmark to assess cost effectiveness of 

NOx controls.

154

 147 http//cfpub1.epa.gov/rblc/htm/b102.cfm, Keystone Cogeneration Systems, Inc., Permit No. 01-89-3983 

(Ex. 26).

 In April 1999, EPA Region V wrote to the Indiana Department of 

148 Paul Wagner and others, Selective Catalytic Reduction: Successful Commercial Performance on Two 

U.S. Coal-fired Boilers, EPRI, 2001.

149 Memorandum from Greg Worley to Brian Beals, U.S. EPA, Re: Review of the Cypress Energy Project 

PSD Application, September 25, 1992, EPA4PER054453 at 54454. Ex. 27.

150 2008 dollars = ($4,262/ton)(575.4/358.2) = $6,846.2/ton. 151 Wisconsin Power & Light Co., Certificate of Authority Application, Edgewater Generating Station Unit 

5 NOx Reduction Project, November 2008, p. 12. Ex. 10.

152 Letter from Arizona Department of Environmental Quality to Steve Fry, EPA Region IX, Re: 

Consultation Regarding Best Available Retrofit Technology Analyses for the Four Corners Power Plant 

and Navajo Generating Station, May 12, 2008. [EPA-R09-OAR-2009-0598-0014]. 153 Ex. 28. SJVAPCD = San Joaquin Valley Air Pollution Control District; SMAQMD = Sacramento 

Metropolitan Air Quality Management District; YSAQMD = Yolo-Solano Air Quality Management 

District; SCAQMD = South Coast Air Quality Management District; SDAPCD = San Diego County Air 

Pollution Control District; BAAQMD = Bay Area Air Quality Management District.
43

Environmental Management in conjunction with the permitting of a new steel mill, 

stating that EPA had previously permitted "many controls for various units that have 

exceeded $7500/ton of pollutant removed."155 Extrapolating this value to 2008 dollars 

yields acceptable costs in excess of $11,000/ton.156 Cost effectiveness rejection 

thresholds for NOx subsequently used in Indiana for several facilities are summarized in 

Table 7.

Table 7

Indiana

Average Cost Effectiveness

Rejection Thresholds

Facility Permit

Date

Average

Cost

($/ton)

CEI157 Adjusted

Cost

($/ton)

AK Steel 4/15/07 9,514 1.15 11,941

AK Steel 8/5/05 16,802 1.30 21,843

SDI-Columbia 1/10/01 14,044 1.46 20,504

Eli Lilly SCR 2004 12,270 1.43 17,546

Eli Lilly SNCR 2004 11,500 1.43 16,445

The highest cost effectiveness values for SCR reported by any party (ranging 

from $4,343 - $5,484 for Four Corners and from $3,002 -$3,736/ton for Navajo), are 

much less than these cost effectiveness values. Thus, SCR is cost effective at Four 

Corners and Navajo.

Further, SCR has been found to be cost effective in other BART determinations at 

costs similar to those reported by EPA, NSPS, and in many cases, even the companies' 

inflated costs. For example, the Wyoming Department of Environmental Quality 

recently proposed installation of SCR along with upgraded combustion controls as BART 

for Naughton Unit 3, for which the company projected a cost effectiveness of $2,830 per 

 154 Delaware Air Regulation Development, Regulation 1142 Section 2, Control of NOx Emissions from 

Large Boilers and Process Heaters at Petroleum Refineries, Committee Meeting #2 Minutes, April 19, 

2006, Final Version as of May 11, 2006, EPA-HQ-OAR-2007-0011-0279. 155 E-mail from Kushal Som, EPA, to Marco, R5CHG.in."bsheets@idem.state.in.us," Re: Steel Dynamics, 

Inc., April 5, 1999, cited at In re: Steel Dynamics, Inc., PSD Appeal Nos. 99-4 & 99-5 (June 22, 2000), p. 

46.

156 2008 dollars = ($7,500)(575.4/390.6) =$11,049/ton. 157 Escalated costs based on Chemical Engineering Plant Cost Index = CEPCI for 2008/CEPCI for the year 

prior to the year of the permit. For the 4/15/07 AKI Steel project: 575.4/499.6 = 1.15. For the 8/5/05 AKI 

Steel project: 575.4/444.237 = 1.30; For the 1/10/01 SDI-Columbia: 575.4/394.1 = 1.46; For the 2004 Eli 

Lilly SCR: 575.4/402=1.43; For the 2004 Eli Lilly SNCR: 575.4/402 = 1.43. The historic CEPCI values 

come from the spreadsheet captioned CE Plant Cost Index Report 1947 - 2006 (Cost Index PCI Annual 

1947-2000.xls. For methodology, see Vatavuk 1990, Chapter 8.
44

ton of NOx removed based on an emission rate of 0.07 lb/MMBtu.158,159 The Wyoming 

Department of Environmental Quality also proposed to require SCR installation at Jim 

Bridger Units 1 - 4 to meet long term strategy/reasonable progress requirements.160 The 

state of Wyoming determined that SCR installation along with upgraded combustion 

controls was cost effective at a cost of $2,258 - $4,275 (for Unit 2) per ton of NOx 

reduced at each unit.161, 162

The Oregon Department of Environmental Quality has required as BART the 

installation of a semidry flue gas desulfurization (“FGD”) system for SO2 at the 

Boardman Power Plant.

163 This was based on a cost effectiveness of $3,055/ton/year.164 

The Oregon Department of Environmental Quality also is requiring installation of SCR in 

addition to upgraded LNBs/OFA for the Boardman Power Plant to meet reasonable 

progress requirements.

165 The projected cost effectiveness for SCR controls at Boardman 

was determined by Oregon to be $3,096/ton.

166 The Oregon Department of 

Environmental Quality found SCR to be cost effective for Boardman.

In addition, the Alaska Department of Environmental Conservation has proposed 

installation of SCR as BART for the Healy power plant.167 This was based on a cost per 

ton estimate determined by Enviroplan Consulting for the state to be $3,373/ton.

168

EPA recently entered into a settlement with SRP regarding air emission 

reductions at its Coronado Power Plant in Arizona. See United States of America v. Salt 

 158 See May 28, 2009 Wyoming Department of Environmental Quality BART Application Analysis (AP6042) for the Naughton Power Plant at 15, 49 (Ex. 30).

159 It must be noted that numerous environmental organizations including the National Parks and 

Conservation Association and the Wyoming Sierra Club submitted comments to Wyoming DEQ that it 

must require installation of SCR at all of the Naughton units as BART, given that WYDEQ determined the 

cost of SCR to be cost-effective and given this facility’s impacts on visibility in Class I areas. See August 

4, 2009 comments submitted by Sierra Club to WY DEQ at 12 (Ex. 30).

160 See May 28, 2009 Wyoming Department of Environmental Quality BART Application Analysis (AP6042) for the Jim Bridger Power Plant at 55-6 (Ex. 32). 161 Id. at 14-15.

162 It must be noted that numerous environmental organizations including the National Parks and 

Conservation Association and the Wyoming Sierra Club submitted comments to Wyoming DEQ that it 

must require installation of SCR at all four Jim Bridger units to meet BART, given that the state found the 

SCR costs to be cost effective and given the significant improvement in visibility in affected Class I areas 

that would result from installation of SCR at all four Jim Bridger units. See August 4, 2009 comments 

submitted by Sierra Club to WY DEQ at 3-4 (Ex. 31). 163 See Oregon Regional Haze Plan adopted by the Environmental Quality Commission June 19, 2009 (Ex. 

33) at 153-4. 164 See Table 15 of Oregon DEQ BART Report for the Boardman Power Plant, December 2008 (Ex. 34). 165 See Oregon Regional Haze Plan adopted by the Environmental Quality Commission (Ex. 33) at 154. 166 Table 15 (at page 19) of Oregon Department of Environmental Quality BART Report for the Boardman 

Power Plan, December 2008 (Ex. 34). 

167 See 5/12/09 Proposal to Issue a Preliminary Best Available Retrofit Technology Determination, Golden 

Valley Electric Association, Healy Power Plant, Unit 1 (Ex. 35).

168 See Enviroplan Consulting, Final Findings Report, Golden Valley Electric Association, Best Available 

Retrofit Technology Evaluation, Prepared for the State of Alaska Department of Environmental 

Conservation, April 27, 2009 (Ex. 36) at 18.
45

River Project Agricultural Improvement and Power District, Civil Action No. CV 08-

1479-PHX-JAT Consent Decree (Ex. 37 ). EPA had previously filed a complaint 

alleging that the Coronado plant had been modified without obtaining prior prevention of 

significant deterioration (PSD) permits. Coronado Consent Decree at 4. The Coronado 

power plant is a two unit facility, each unit has a generating capacity of roughly 450 

megawatts, and the boilers for each unit are wall-fired and burn bituminous coal. The

Coronado Consent Decree requires installation of SCR along with a low NOx combustion 

system at each unit and a NOx emission limit for each unit of 0.08 lb/MMBtu (30 day 

average) be met. Id. at 14. The Consent Decree resolves all civil claims brought by the 

EPA, thus one can presume that the costs of installation of SCR and combustion controls 

were determined by EPA to be reasonable even as a retrofit to an existing facility. The 

Coronado Consent Decree thus provides strong evidence that the costs of retrofitting SCR 

to a western coal-fired power plant are reasonable. EPA must take this Consent Decree 

into consideration in determining whether the costs of SCR installation at Navajo and at 

Four Corners are reasonable.

If similar facilities have had to bear similar costs for control of visibility 

impairing pollutants in meeting BART, regional haze, prevention of significant 

deterioration, and other Clean Air Act requirements, then such costs should not be 

considered unreasonable for the Navajo or the Four Corners units. Given that the Navajo

and Four Corners units impact so many Class I areas and given the myriad other 

problems that NOx emissions contribute to in the region, the costs of SCR at the Navajo

and Four Corners units, even at the high end estimate provided by the owners of these 

facilities, should be considered reasonable.

D. SRP and APS Failed to Analyze Methods to Reduce Sulfuric Acid Mist and 

Sulfate Emissions from SCR Which Both Parties Claim Will Cause a Visibility 

Disbenefit with SCR.

SRP states that SCR will cause an increase in directly emitted sulfate emissions as 

well as an increases in sulfuric acid mist (“SAM”). January 2009 SPR BART Submittal 

at 4-5. Further, SRP claims that these increased sulfate and SAM emissions will harm 

visibility, creating a disbenefit to the use of SCR for NOx reductions. Id. at 5-2. APS 

makes similar claims. January 2008 BART Modeling Analysis for APS Four Corners 

Power Plant Units 1-5 at 6-6. However, SRP’s and APS’s BART submittals fail to 

discuss in detail available options for limiting the creation of sulfates or SAM when SCR 

is used at a coal-fired power plant.

For example, the injection of alkali into the furnace can significantly reduce 

sulfate formation.169 The addition of limestone to the coal before pulverizing has shown 

a 50% reduction in sulfate formation.170 The injection of calcium and magnesium based 

slurries has also been shown to reduce sulfate formation by 40-80%.171

 169 R.K.Srivastava et al., Emissions of Sulfur-Trioxide from Coal-Fired Power Plants, J. Air & Waste 

Manage. Assoc., 54: 750-762 at 758-759, June 2004. (Ex. 39).

 The injection of 

alkaline materials after the furnace has also been shown to reduce sulfate formation by 40 

170 Id. 171 Id.
46

– 90%, such as hydrated lime, limestone, magnesium oxide and sodium carbonate.172 In 

its recent BACT determination of the Desert Rock power plant, EPA Region 9 required 

hydrated lime injection to reduce SAM and sulfates.173

Ammonia injection before the electrostatic precipitator (“ESP”) has also been 

shown to reduce sulfate formation by high levels.174 Another option that could be used to 

reduce sulfate and SAM emissions would be the addition of a wet ESP. Wet ESPs have 

been shown to reduce sulfates by 90% and result in very low opacity of plumes.175 

Further, wet ESPs can capture other pollutants such as mercury.176 

Another option that should be evaluated is a low SO2 to SO3 conversion catalyst 

for the SCRs. For example, the CX Series type catalyst developed by Babcock- Hitachi 

has achieved SO2 to SO3 conversion rates as low as 0.1%.177 

EPA in its ANPR apparently is only taking into consideration a low SO2 to SO3

conversion catalyst with an SO2 to SO3 conversion rate of 0.5%. 74 Fed.Reg. 44326, 29. 

As shown above and in the relevant attachments to this letter, much lower conversions 

are possible through various techniques including the CX Series type catalyst developed 

by Babcock- Hitachi that has achieved SO2 to SO3 conversion rates as low as 0.1%.

In addition, neither SRP or APS evaluated the addition of a COHPAC polishing

baghouse that could be added into the pollution control train at the Navajo units and at 

the Four Corners units without baghouses to aid in the removal of SAM emissions. 

These and other options are readily available to reduce sulfate and SAM 

formation due to the installation of SCRs at the Navajo and Four Corners units, and EPA 

should evaluate the feasibility of these options in its determination of BART for these

units.

IV. BART for PM Must Be Fully Evaluated for Four Corners and Navajo.

Neither SRP or APS adequately evaluated BART for particulate matter control. 

The Navajo units are only equipped with hot-side ESPs, and these units have high 

filterable PM emission rates of 0.0210 to 0.0310 lb/MMBtu with short term peak 

emission rates of up to 0.05 lb/MMBtu. See January 2009 BART Analysis for Navajo at 

 172 Id. 173 July 31, 2008 Prevention of Significant Deterioration Permit issued to Desert Rock Energy Company, 

Condition IX.B.2.b. (Ex. 23). 174 R.K.Srivastava et al. at 759-80 (Ex. 39). 175 Id. at 760; see also, e.g., K.S. Kumar et al., Wet ESP for controlling sulfuric acid plume following an 

SCR system, presented at the 2002 ICAC Forum. (Ex. 40).

176 Id. 177 Anthony C. Favale et al., Application and Operating Results of Low SO2 to SO3 Conversion Rate 

Catalyst for DeNOx Application at AEP Gavin Unit 1, Proceedings of the 2006 Environmental Controls 

Conference, U.S. Department of Energy, National Energy Technology Laboratory (Ex. 41). See also, 

Keiichuro Kai et al., SCR Catalyst with High Mercury Oxidation and Low SO2 to SO3 Conversion, Paper 

#86. Ex. 42.
47

1-2, 3-3. The Four Corners units 1-3 are equipped with only venturi scrubbers for 

particulate matter control and emit filterable PM at rates 0.037 to 0.041 lb/MMBtu. See 

November 2008 BART Modeling Analysis for APS Four Corners at 5-3. According to 

the Four Corners BART Analysis, these are worst case daily emission rates. Id. EPA’s 

ANPR identifies the PM emissions of Four Corners Units 1-3 as ranging from 0.025-0.05

lb/MMBtu. 74 Fed.Reg. 44319. Four Corners Units 4 and 5 are equipped with fabric 

filter baghouses. 

With baghouses for PM control, these units should be able to significantly reduce 

filterable PM emissions – down to 0.012 lb/MMBtu if not lower.178 Current BACT limits 

for new coal-fired power plants equipped with baghouses are routinely 0.012 lb/MMBtu 

or lower. For example, in the Desert Rock PSD permit, EPA Region 9 set the filterable 

PM10 BACT limit for this facility at 0.010 lb/MMBtu (24-hour average).179 In addition to 

achieving lower PM emission rates, baghouses have additional benefits such as 

controlling SAM as well as significantly improved mercury and other toxic emissions

control. Thus, baghouses at these units could improve visibility impacts and regional 

haze at Class I areas in the region and, accordingly, PM BART must be fully evaluated 

for these facilities.

A. SRP Must Be Required to Conduct a PM BART Analysis for Navajo.

SRP failed to conduct any BART analysis for PM emissions, stating that 

“CALPUFF modeling results indicate that filterable PM emissions are generally 

responsible for less than 10% of the visibility impairment at the modeled Class I areas.” 

January 2009 BART Analysis for Navajo at 1-2. This is not adequate justification for 

SRP’s failure to evaluate PM BART for the Navajo units, especially given the proximity 

of Navajo to Grand Canyon National Park. Even if it is true that the Navajo PM 

emissions do not account for a large portion of visibility impairing pollution at Class I 

areas in the region, its PM emissions that are 2-5 times higher than the filterable PM 

emission rates achievable with a baghouse presumably do impact visibility to some extent

and some visibility improvement could be gained with improved PM controls at the NGS 

units. Not only could baghouses reduce PM but baghouses would also effectively capture 

SAM emissions from the Navajo units. Further, installation of baghouses will improve 

mercury and other air toxics control. Thus, EPA must require SRP to evaluate BART for 

PM control at the Navajo units. In evaluating the visibility benefits of a baghouse for PM 

BART, EPA should require the modeling of the PM BART option with the NOx options, 

since the baghouse will also reduce the SAM emissions that SRP claims will increase 

with SNCR and SCR.

 178 As indicated in the Four Corners BART Modeling analysis, Unit 5 of the FCPP achieves a filterable PM 

rate of 0.012 lb/MMBtu with a baghouse. November 2008 BART Modeling Analysis for APS Four 

Corners at 5-3. It is not clear why Four Corners Unit 4, which is also equipped with a baghouse, is 

identified as emitting filterable PM at a much higher rate of 0.025 lb/MMBtu.

179 See Condition IX.H.1.b. of Desert Rock PSD Permit (Ex. 23).
48

B. The BART Analysis for PM at Four Corners Must Be Updated to Reflect More 

Accurate Baghouse Retrofit Cost Data and to Reflect Achievable PM Emission 

Rates.

APS evaluated baghouses for Four Corners Units 1-3 as BART in its visibility 

modeling analyses, but it assumed higher emission rates than achievable with a baghouse

in its modeling analysis. Specifically, it assumed filterable PM emission rates ranging 

from 0.014 to 0.017 lb/MMBtu. See November 2008 BART Modeling Analysis for APS 

FCPP at 6-3. As stated above, these units should be able to achieve 0.012 lb/MMBtu or 

lower, and APS failed to provide sufficient justification for not evaluating lower limits. 

Even the Black & Veatch BART engineering report identified a lower emission rate of 

0.012 lb/MMBtu PM emission rate as achievable with pulse jet fabric filters at Four 

Corners Units 1-3 in determining cost effectiveness. See 2007 Black & Veatch BART 

Engineering Report for FCPP at 5-4 (Table 5-3). APS must be required to model the 

visibility impacts of a PM emission rate lowered to the same rate determined achievable 

in the PM BART cost analysis. 

In addition, APS did not adequately evaluate whether lower PM emission rates 

could be achieved at FCPP Unit 4 with an upgraded baghouse (e.g., use of different bags 

with high particulate capture), given that it is currently emitting at a filterable PM 

emission rate of 0.025 lb/MMBtu.180

In the cost analysis, APS relied on higher PM emission rates than what is 

achievable with a state-of-the-art baghouse. Significantly higher PM reductions could be 

achieved with a baghouse designed to meet a PM limit of 0.012 lb/MMBtu or lower. In 

addition, APS overestimated the costs of a baghouse for PM control at Units 1-3 as 

acknowledged by EPA in the ANPR. Many of the same flaws that exist in APS’s NOx 

BART also apply to APS’s PM BART analysis. 

The PM BART modeling analysis for Four Corners should not be relied on in 

making any PM BART determinations for the FCPP units because it assumed higher PM 

emissions rates than what is actually achievable at FCPP Units 1-3 with a baghouse and 

at FCPP Unit 4 with upgraded (membrane) bags. Further, because the baghouses will 

greatly help reduce emissions of SAM, APS should have modeled the visibility benefit of 

using baghouses for particulate control along with the SNCR and SCR options for NOx

control at Four Corners.

V. In Addition to Failing to Adequately Evaluate the Costs of Control, the 

Evaluation of the Factors that Need to be Addressed in a BART Analysis is 

Inadequate and/or Incomplete.

Cost of control is just one of the five factors that need to be considered in 

determining BART for a source. There are other factors that need to be taken into 

account that neither SRP or APS addressed adequately or fully including:

 180 For some unexplained reason, this option was not considered to provide any emission reduction benefit 

in the Black & Veatch BART engineering report for FCPP (at 4-4).
49

• The energy and nonair quality impacts of compliance

• The remaining useful life of the source

• The degree of improvement in visibility which may reasonably be anticipated to 

result from the use of the BART technology being evaluated

Below we offer information that EPA should either require APS and SRP to address or 

that EPA should take into account when determining BART for Four Corners and 

Navajo.

A. Installation of SCRs and Baghouses Will Significantly Reduce Mercury 

Emissions from Navajo and Four Corners.

Based on data collected by EPA in 1999, the mercury emissions estimate for the 

Four Corners power plant was the highest of all western coal-fired power plants at 0.5258 

tons per year or 1,052 pounds per year181. Navajo was estimated to emit less mercury at 

0.1517 tons per year or 303.4 pounds per year.182 However, even Navajo’s mercury 

emissions are significant when compared to a new coal-fired power plant with state of the 

art pollution controls for SO2, NOx, and PM and without additional mercury-specific 

control technology such as activated carbon injection. For example, the formerly 

proposed Unit 3 of the Intermountain Power Plant, which was to be a 950 MW unit 

burning western bituminous coal and equipped with an SCR, baghouse and wet scrubber, 

was projected to emit only 0.0413 tons per year of mercury (or 82.6 pounds per year)183. 

In fact, one of the existing Intermountain Power Plant units achieved 84% removal of 

mercury with its wet scrubber and baghouse in the 1999 mercury Information Collection 

Request (“ICR”) testing required by EPA.184 Indeed, the 1999 ICR test data show that 

boilers with baghouses achieved some of the lowest mercury emission rates.185

Further, the use of an SCR helps to oxidize the mercury so it is more readily 

captured in a particulate control device.186 SCR catalysts can act to oxidize elemental 

mercury (e.g., to HgCl2) making it easier to capture downstream in wet FGD systems or 

particulate matter collection devices. Currently, several industry improvements in SCR 

technology are being developed that would enhance mercury oxidation across an SCR 

catalyst for all coal types.187 Combine the addition of an SCR with a baghouse designed 

for state-of-the-art particulate control, and significant mercury reductions are a likely cobenefit of these BART controls.188

 181 See EPA’s Emissions of Mercury By Plant – 1999, downloaded from 

http://www.epa.gov/ttnatw01/combust/utiltox/utoxpg.html. (Ex. 43). 182 Id. 183 See Approval Order for Intermountain Power Plant Unit 3 (Ex. 44). 184 See spreadsheet of mercury test results from 1999 ICR testing, attached, downloaded from 

http://www.epa.gov/ttnatw01/combust/utiltox/utoxpg.html (Ex. 45). 185 See EPA’s Performance and Cost of Mercury and MultiPollutant Emission Control Technology 

Applications on Electric Utility Boilers, EPA-600/R-03-110, October, 2003, Table 1 (Ex. 46). 186 Id. at 5, 9-15. 187 June 29, 2004 letter from ICAC to EPA, pp. 15-17. (Ex. 47). 188 See discussion of mercury emissions at page 13 and Ex. 52-54.
50

Not only would use of a baghouse significantly reduce mercury emissions from 

Navajo and Four Corners, but a baghouse would more effectively control other nonmercury metal hazardous air pollutants than an electrostatic precipitator or a venturi 

scrubber. 

It is important to note that the highest nationwide atmospheric mercury 

concentration in 2001 was measured in New Mexico.189 Studies sponsored by EPA

demonstrate that up to 70 percent of local deposition of mercury from power plants and 

industrial sources can be linked to local sources during wet deposition events.190 While 

the Navajo and Four Corners power plants are located in a generally dry region, episodes 

of wet deposition do occur with some frequency, with the result that there are already 

high levels of mercury in nearby water bodies. Specifically, fish consumption advisories 

due to mercury contamination have been issued for the San Juan River, the Lake 

Farmington Reservoir and the Navajo Reservoir, as well as for Narraguinnep and 

McPhee Reservoirs in southwest Colorado. 191 

Mercury emitted into the air becomes methylmercury in the environment, which 

accumulates in the foodchain and is toxic in even minute amounts. Methylmercury is a 

potent neurotoxin, affecting the central nervous system. Symptoms include loss of 

memory, excitability, fever, and local tremors that can progress to the entire body, 

encephalitis and loss of general senses.192

A Mt. Sinai Medical School study has quantified the economic impacts of 

mercury exposure, specifically on lost productivity due to reductions in IQ.

 According to the FDA standard, it would only 

take 1 pound of methylmercury to contaminate 500,000 pounds of fish, which, when 

consumed by humans and wildlife, increases their mercury levels. The U.S. EPA has 

found that 1 in 6 women has levels of mercury in her blood above the safe standard, 

putting her future children at risk for learning and behavioral problems associated with 

mercury poisoning. 

193

 189 National Atmospheric Deposition Program (NRSP-3)/Mercury Deposition Network. (2003). NADP 

Program Office, Illinois State Water Survey, 2204 Griffith Drive, Champaign, IL 61820. Available at 

 The cost 

in lost productivity from methylmercury exposure (largely through the consumption of 

contaminated fish) is estimated to be $8.7 billion annually with $1.3 billion of this cost 

attributable to U.S. power plants. These costs, which measure only the costs from 

reduced productivity in adulthood due to reduction in IQ, do not consider the additional 

costs associated with IQ reduction, for example: poverty, out-of wedlock birth, lowhttp://nadp.sws.uiuc.edu/mdn/

190 Gerald Keeler, Matthew Landis, et al., Sources of Mercury Wet Deposition in Eastern Ohio, USA, 40 

Envtl. Sci. & Tech. 5874-5881 (Sept. 2006). 191 EPA 2002 and data from National Listing of Fish and Wildlife Advisories. Available at 

http://map1.epa.gov/

192 Philip Wexler, Encyclopedia of Toxicology, v. 2, 1998, pp. 288-289.

193 Kathleen Schuler, MPH, and Christopher S Williams, MD, Institute for Agriculture and Trade Policy, 

March 8, 2005, Protecting Children from Mercury Exposure Is Cost Effective, available online at 

http://www.iatp.org/iatp/library/admin/uploadedfiles/Protecting_Children_From_Mercury_Exposure_is_C.

pdf 
51

weight births, welfare recipiency, dropping out of high school, and special education 

costs.

EPA must take these significant non-air quality benefits into account when 

evaluating SCR and/or baghouses for BART at Navajo and Four Corners. Not only will 

these control technologies improve visibility at the national parks and wilderness areas of 

the Colorado Plateau, but the mercury reductions achieved with these controls will 

improve the health of the population in the region and of the ecosystems and fisheries in 

the region.

B. The Remaining Useful Life of the Navajo and Four Corners Units.

1. Absent an Enforceable Commitment to Retire the Plant, the Remaining 

Useful Life of the Facilities Is Likely to Be Greater Than Twenty Years.

The remaining useful life of the facility should not be invoked to relax BART 

standards for either the Four Corners or Navajo plants. Absent an enforceable 

commitment to cease operations, see Section V.B.2., below, both Four Corners and 

Navajo are likely to continue operating for as long, or longer, than the lifespan of the 

prescribed pollution control technologies. Coal-fired power plants have proven 

remarkably long-lived. Some functioning plants were placed in operation eighty years 

ago, or more (e.g., Citizens’ Thermal Energy CC Perry K Plant, in Indiana, and Interstate 

Power & Light Co.’s Dubuque Plant, in Iowa). Several large plants continue to run after 

nearly seventy years (e.g., Duke Carolinas’ Cliffside Plant). 

The Navajo Generating Station’s units began operating between 1974 and 1976. 

BART Analysis for the Navajo Generating Station Units 1-3 (ENSR Corp 2007) at ES-1 

(Docket No. EPA-R09-OAR-2009-0598-003). An estimated life-span of seventy-five 

years provides those units with a remaining life of forty years. The Four Corners Plant’s 

units 1-3 were completed in 1963 and 1964, while units 4-5 were completed 1969 and 

1970. http://www.srpnet.com/about/stations/fourcorners.aspx (visited September 14, 

2009). The same estimated life-span would permit thirty years of continued operations.

Under those circumstances, the full benefit of the pollution-controls will be 

realized, and the “remaining useful life” element of the BART analysis should not be 

used to justify less-than-maximal controls. “If the remaining useful life [of the source will 

clearly exceed [the life of the prescribed pollution-control], the remaining useful life has 

essentially no effect on control costs and the BART determination process.” Regional 

Haze Regulations and Guidelines for Best Available Retrofit Technology (BART); Final 

Rule, 70 Fed. Reg. 39,104, 39,169 (July 5, 2005). Should the BART limits reflect 

anticipated shut-down of any units on a particular date, that shut-down “should be 

assured by a federally- or State-enforceable restriction preventing further operation.”194

 194 In the alternative, the agency should establish maximally stringent BART limits that would go into 

effect if the unit remains in operation longer than expected. See 70 Fed. Reg. at 39,127, 39,170 (agency 

“may identify, and include as part of the BART emission limitation, the more stringent level of control that 

Id.
52

To the extent that the applicants’ analyses of costs and benefits assumes that the 

installed pollution controls will be in operation for only twenty years, they may

substantially overstate those controls’ cost, and understate the benefits. EPA’s Cost 

Control Manual provides a useful life of twenty years in its sample cost-benefit 

calculations for pollution controls; that figure, however, is not based upon any rigorous 

examination of the durability of the specific technologies that will be installed as BART. 

EPA Air Pollution Control Cost Manual § 4 at p. 2-48 (assuming economic lifetime of 20 

years, without further analysis), § 6 at p. 1-48 (6th ed. 2002) (“For fabric filters, the 

system lifetime varies from 5 to 40 years, with 20 years being typical.”). SCR systems 

can last thirty years or more.195 The agency’s cost-benefit analysis calculations should 

incorporate an anticipated lifetime reflecting the real anticipated lifetime of the required 

controls (and plants) – in all likelihood, longer than twenty years.

C. The Visibility Modeling Analyses Conducted for the NOx BART Options at 

Both Navajo and Four Corners Power Plants Underestimated the Visibility 

Improvement that Can Be Reasonably Anticipated to Occur with the 

Installation of SCR along with Combustion Controls.

SRP’s and APS’s visibility modeling is flawed in many respects. EPA has 

identified some of the flaws in the company’s modeling in its ANPR. For the most part, 

we agree with EPA’s changes to each company’s modeling except as noted below. 

However, we do not agree with EPA’s metric in evaluating the visibility benefits of the 

various BART choices as discussed further below.

A. SRP and APS Overestimated Sulfuric Acid Mist Emissions from the NGS Units 

and the FCPP Units in the Modeling of the SCR Options.

SRP relied on EPRI’s Report “Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants” in determining SAM emissions with the SCR control options, 

which assume that the SCR will convert some SO2 to SO3 which with then form SAM. 

 

would be required as BART if there were no assumption that reduced the remaining useful life,” and “if a 

source does operate after the 5-year mark without [the more stringent] BART in place, the source is 

considered to be in violation of the BART emissions limit for each day of operations”).

195 An SCR system comprises ducting, a metal frame that is stuffed with blocks of catalyst, an ammonia 

delivery system (tank, pumps, and piping), a control system, and instrumentation. The major components

have no moving parts. The catalyst, accounting for the bulk of the value (80%), is changed out every 2-3 

years. The ducting and metal frame should, with standard maintenance, last as long as the plant. The 

ammonia injection system, accounting for a tiny fraction of the overall cost, should also last as long as the 

plant, so long as wearable parts are replaced during routine maintenance. Many SCR units were installed 

more than twenty years ago, and are still in service. Mitsubishi, for example, installed three SCR systems 

on process heaters at the Chevron Richmond Refinery in California in 1984. Those SCR systems remain in 

service. There have been no reported maintenance, operational or compliance problems, and the original 

catalyst has not been changed out. After 25 years of operations, these SCRs are expected to remain 

operational for many more. Mitsubishi also installed the first SCR that we are aware of at Kyushu Electric 

in Japan in 1978. To the best of our knowledge, this SCR is still in operation 32 years later. See Ex. 48 at 

60 (Kyushu Electric Power Company Annual Report 2008) Other SCRs, installed in Japan in 1980; they 

remain operational after 29 years. See Ex. 14 (Mitsubishi SCR System Supply List (June 2005)).
53

SRP provided no justification for the assumed 1% SO2 to SO3 conversion rate across the 

SCR. See January 2009 SRP BART Analysis at 4-16 (footnote i of Table 4-7). The 

EPRI paper states that the oxidation rate varies from 0.3% to 3% but provides no further 

justification for the appropriate conversion rate to use.196 Other studies have shown 

much lower SO2 to SO3 conversion rates than 1%, especially for western coals.197 In 

addition, as discussed above, low SO2 to SO3 conversion catalysts are available that could 

be used at NGS. Thus, SRP relied on a too high of an SO2 to SO3 conversion rate and, as 

a result, the visibility modeling for the SCR BART options overestimated the visibility 

“disbenefit” from the use of SCR at Navajo.

Interestingly, the emission estimates for Four Corners with the use of SCR appear 

to have relied on a lower SO2 to SO3 conversion rate of 0.5%. November 2008 BART 

Modeling Analyses for APS FCPP at 6-7, Table 6-4 (footnotes g and h). However, APS 

also did not provide any justification for its SO2 to SO3 conversion rate and, based on the 

Hardman paper cited in this document, even that conversion rate may overestimate SO3

conversion with the SCR. 

B. SRP, APS, and EPA Overestimated NOx Emissions with the SCR Options 

Modeled. 

As discussed above, SRP improperly assumed that SCRs in addition to 

LNBs/MOFA on the Navajo units could only achieve a NOx emission rate of 0.08 

lb/MMBtu. This emission rate only reflects 60- 67% NOx removal across the SCR, when 

80-90% NOx removal should be achievable. Thus, it is much more realistic to assume a 

NOx emission rate of 0.05 lb/MMBtu or even lower. Because SRP overestimated NOx

emissions with SCR, its visibility modeling overestimated impacts under Options 3 and 4 

– in addition to already overestimating visibility impacts due to an overestimate of SAM 

emissions from the Navajo units with SCR. 

APS assumed NOx emission rates with SCR at the Four Corners units of 0.06 to 

0.075 lb/MMBtu. While these emission rates are lower than the 0.08 lb/MMBtu emission 

rate assumed by SRP at the Navajo units, it still fails to reflect the maximum degree of 

emission reduction that can be achieved with SCR and upgraded low NOx

burners/overfire air at the Four Corners units as discussed in our comments above. It is 

much more realistic to assume a NOx emission rate of 0.05 lb/MMBtu or even lower. 

Inexplicably, EPA stated in the ANPR that it projected NOx emission rates at Four 

Corners to be even higher than modeled by APS. See 74 Fed.Reg. 44319. As discussed 

above, there is no justification for assuming higher NOx rates with SCR than modeled by 

APS; indeed NOx emission rates with SCR at the Four Corners units could be even lower 

than 0.06 lb/MMBtu as discussed more fully above. Because APS overestimated NOx

 196 EPRI’s Report “Estimating Total Sulfuric Acid Emissions from Stationary Power Plants” at 4-7. (Ex. 

49).

197 Hardman et al, Estimating Sulfuric Acid Aerosol Emissions from Coal-Fired Power Plants, March 1998, 

at 4 (and at footnotes 10 and 11 which reference an EPA-documented study that indicates the SO2 to SO3 

conversion rate of 0.4% with conversion rates ranging from non-detectable to 0.67% and lower rates being 

found with western coals). Ex. 50.
54

emissions with SCR and upgraded low NOx burners/overfire air, its visibility modeling 

overestimated impacts with the SCR options – in addition to already overestimating 

visibility impacts due to an overestimate of SAM emissions from the Four Corners units 

with SCR. EPA’s modeling is also flawed due to an overestimate of achievable NOx 

emission rates with SCR.

C. SRP and APS Inappropriately Relied on Lower Ammonia Background Levels in

its Visibility Impacts Modeling.

The CALPUFF model was used for modeling the visibility impacts of the BART 

options by both SRP and APS (as well as by EPA). The model requires input of an 

assumed background level for ammonia; the level of ammonia assumed present 

determines the levels of ammonium nitrate aerosol produced at receptor sites. The 

WRAP BART protocol modeling specifies 1 part per billion (“ppb”) for background 

ammonia. The selection is based on IWAQM Phase II recommendations of 10 ppb for 

grasslands, 1 ppb for arid lands, and 0.5 ppb for forest. Most of the western U.S. is 

characterized by arid lands and grasslands. The FLAG guidance also states that the 

IWAQM background ammonia levels of 1.0 ppb for arid lands should be used unless 

“better data are available for the specific modeling domain.” FLAG at 140. 

Both SRP and APS relied on lower ammonia background levels than 

recommended by IWAQM as required in the FLAG guidance198. Specifically, SRP and 

APS used background ammonia concentrations of 0.2 ppb in January to February, 0.5 

ppb in March to April, 1.0 ppb in May through September, 0.5 ppb October through 

November, and 0.2 ppb in December. See Table A-2 in Appendix A of SRP’s January 

2009 Revised BART Analysis for NGS; Table 3-1 of November 2008 BART Visibility 

Modeling Report for the Arizona Public Service Four Corners Power Plant 

(Supplemental). To address concerns raised by APS that the IWAQM default 

background levels overestimated ammonia background concentrations in the area, EPA 

developed its own ammonia background values for all of the Class I areas except Mesa 

Verde based on IMPROVE data. For Mesa Verde, EPA also developed background 

ammonia values based on measured ammonia concentrations in the Four Corners area. 

74 Fed.Reg. 44326.

As pointed out in the “Explanation of Changes in the April 2007 Revised Final Modeling Analysis”

developed by the WRAP Regional Modeling Center (May 18, 2007), the CALPUFF modeling system has a 

very simplistic treatment of background ammonia concentrations. Despite the fact that atmospheric 

ammonia concentrations are known to have a high temporal and spatial variability, the CALPUFF 

modeling system assumes a single background ammonia concentration that is spatially and temporally 

invariant. CALPUFF represents a continuous plume by a series of overlapping puffs. A CALPUFF 

simulation may include many sources and each puff from each source uses the total background ammonia 

concentrations independently of the other puffs to partition the total nitrate formed into particle NO3 and 

gaseous HNO3 using the user-specific background ammonia and estimated SO4 for that puff and an 

SO4/NO3NH4 equilibrium equation. The total concentration impact at a given receptor (e.g., Class I area) 

is obtained by summing up all the impacts from all of the overlapping puffs from all the sources. This 

 198 Federal Land Managers Air Quality Related Values Workgroup (FLAG) Phase I Report, December 

2000, at 140.
55

approach in effect “double counts” the background ammonia concentration across overlapping puffs in the 

partitioning of total nitrate to particle NO3 and gaseous HNO3. The POSTUTIL postprocessor recalculates 

the partitioning of total nitrate to NO3 and HNO3 using the combined SO4 and total nitrate from all 

CALPUFF overlapping puffs at a receptor with the user defined background ammonia concentration, 

therefore eliminating the “double counting” of ammonia.

The use of POSTUTIL to eliminate the “double counting” of ammonia in the CALPUFF simulation sounds 

like better science. In reality, background ammonia has so much spatial and temporal variability that the 

assumption of a single value can not always be valid. The Interagency Workgroup on Air Quality 

Modeling (IWAQM, 1998) recommends three background values for CALPUFF modeling: 0.5 ppb for 

forested lands; 1.0 ppb for arid lands; and 10 ppb for grasslands.

Most of the western U.S. Class I areas are characterized by arid and forested lands, consequently a 1.0 ppb 

background ammonia value was selected for the WRAP RMC BART CALPUFF modeling. Ammonia 

measurements are difficult to make and very few have been taken in the western U.S. The CDPHE 

collected measurements in eastern Colorado and for their BART modeling recommended background 

ammonia values ranging from 1 ppb to 44 ppb (CDPHE, 2005). The selection of the 1 ppb background 

value used in the WRAP BART CALPUFF modeling, although justified based on IWAQM (1998) 

recommendations, is highly uncertain. The pre-April/post-April POSTUTIL analysis suggests that the 

whether the CALPUFF estimated visibility impacts at Class I areas is greater than 0.5 dv or not is not that 

sensitive to the user-specific background ammonia value, which is reassuring.

http://pah.cert.ucr.edu/aqm/308/bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf

Ammonia Observations Used to Improve Background Estimates. The EPA

ammonia background specifications are reasonable, as is indicated by recent observations 

showing ammonia levels varying around 1ppb in the vicinity of Navajo and Four 

Corners. These recent ammonia observations (Sather et al, 2008) also illustrate the 

seasonal and spatial variability of ammonia and serve as a valid guideline for improving 

estimates of ammonia background levels used in CALPUFF modeling of visibility 

benefits of reducing NOx emissions from Navajo and Four Corners: 

Baseline ambient gaseous ammonia concentrations in the Four Corners area and eastern Oklahoma, 

USA Mark E. Sather et al 2008 J. Environ. Monit., 2008 DOI: 10.1039/b807984f

Ambient ammonia monitoring using Ogawa passive samplers was conducted in the Four Corners area and 

eastern Oklahoma, USA during 2007. The resulting data will be useful in the multipollutant management of 

ozone, nitrogen oxides, and visibility (atmospheric regional haze) in the Four Corners area, an area with 

growing oil/gas production and increasing coal-based power plant construction. The passive monitoring 

data also add new ambient ammonia concentration information for the U.S. and will be useful to scientists 

involved in present and future visibility modeling exercises. Three week integrated passive ammonia 

samples were taken at five sites in the Four Corners area and two sites in eastern Oklahoma from 

December, 2006 through December, 2007 (January, 2008 for two sites). Results show significantly higher 

regional background ammonia concentrations in eastern Oklahoma (1.8 parts per billion (ppb) arithmetic 

mean) compared to the Four Corners area (0.2 ppb arithmetic mean). Annual mean ammonia 

concentrations for all Four Corners area sites for the 2007 study ranged from 0.2 ppb to 1.5 ppb. Peak 

ambient ammonia concentrations occurred in the spring and summer in both areas. The passive samplers 

deployed at the Stilwell, Oklahoma site compared favorably with other passive samplers and a continuous 

ammonia monitoring instrument.

As illustrated in the figures from Sather et al, and as have been noted by EPA, the higher 

ammonia levels were measured closer to the source areas and lower levels are measured 
56

near the receptor areas. Since much of the available ammonia is likely to have been 

converted to aerosol (i.e., ammonium sulfate and ammonium nitrate) in the areas near the 

receptors (e.g., Mesa Verde NP), the ammonia levels closer to the source areas (e.g., 

Farmington Airport) are more representative of the ammonia levels available for 

producing ammonium nitrate. This reasoning strongly supports EPA’s background 

ammonia levels.

Additional Support for EPA’s Ammonia Background Levels. EPA also did back 

calculations to develop a sense of the levels of ammonia that must have been present in 

order to have the observed ammonium nitrate at the receptor locations. These estimates 

support use of ammonia background levels that vary seasonally, with values higher and 

lower than 1ppb, depending on the time of the year, and the estimates are consistent with 

the observations of ammonia. 

Increasing Nitrate Trends Underscore Need for Prompt Action. Trends analysis 

indicate a continuing upward trend for ammonium nitrate, the NOx emission related 

contributor to visibility degradation at national parks and wilderness areas. As illustrated 

below, nitrate contributions to visibility degradation are increasing throughout the 

intermountain west.
57

The FLAG guidance states that the IWAQM background ammonia levels of 1.0 

ppb for arid lands should be used unless “better data are available for the specific 

modeling domain.” FLAG at 140. Neither SRP or APS collected background ammonia 

data for the modeling domain around the power plants. Thus, neither SRP or APS has 

justification for deviating from IWAQM guidance on ammonia background for the arid 

lands around Navajo and Four Corners. If EPA is to allow use of different background 

ammonia concentrations based on its analysis background ammonia as presented in the 

ANPR, we believe EPA’s approach seems reasonable and justified. However, we caution 

EPA about allowing for deviations in the background ammonia concentrations used in 

determining the visibility benefits of any BART options. Clearly, modeling lower 

background ammonia levels could result in an underestimate of visibility impacts in 

nearby Class I areas. By requiring all BART analyses to be based on IWAQM 

background levels, EPA creates a level playing field between all of the various sources 

subject to BART across the U.S. for at least this aspect of the BART analysis. 

D. SRP and APS Improperly Compared SNCR and SCR Options to the Low NOx

Burner/Overfire Air Option rather than to Baseline Impacts in Determining Cost 

Effectiveness in Dollar per Deciview.

In its evaluations of its various BART options, both SRP and APS determined 

incremental visibility improvement for the SNCR and SCR options based on a 
58

comparison of the visibility impacts of the low NOx burner/overfire air option (Option 1a 

for NGS and Option 1 for FCPP). Then, cost effectiveness for the SNCR and SCR 

options were determined based on dollar per deciview. See January 2009 SRP BART 

Analysis at 5-1 to 5-9; November 2008 BART Visibility Modeling Report for the 

Arizona Public Service Four Corners Power Plant (Supplemental) at 6-9 to 6-17. 

However, the annual cost per year data used in this analysis was based on the cost of the 

suite of NOx controls in options 2, 3 and 4.199 In addition to the issues discussed above, 

this analysis has the effect of improperly inflating the cost per deciview improvement of 

the SNCR and SCR BART options. Instead, the deciview improvement of each BART 

option should be compared to baseline impacts, and the cost per deciview calculated 

accordingly. 

SRP and APS also improperly determined visibility improvement averaged across 

all Class I areas for the SNCR and SCR options as compared to the LNB/OFA option 

rather than baseline conditions. See Table 5-1 of SRP’s January 2009 BART analysis; 

Table 6-5 of November 2008 BART Visibility Modeling Report for the Arizona Public 

Service Four Corners Power Plant (Supplemental). Further, given the numerous Class I 

areas impacted by these two power plants and the varying distances of each Class I area 

from the power plants, EPA should not rely on any analysis of visibility improvements 

due to the various BART options that are averaged across all the numerous Class I areas 

impacted by these facilities. Yet, EPA appears to agree that this metric may be 

appropriate. See 74 Fed.Reg. 44328. Such an analysis will minimize the visibility 

benefits that will be obtained with strict BART controls at the Class I areas that are closer 

to Navajo and Four Corners.

E. In Any Evaluations of a “Visibility Disbenefit” from the Use of SNCR or SCR at 

NGS and at FCPP, Changes in Visibility Across each Class I Area Should be 

Evaluated Rather than Just Focusing on Results at One Receptor.

For the various reasons discussed above, we question the validity of APS’s and 

SRP’s claims of disbenefit to visibility due to the use of SNCR or SCR at Navajo and 

Four Corners. However, if EPA believes that SAM emissions will increase as a result of 

SNCR or SCR to the extent of causing a visibility disbenefit, EPA should conduct a 

thorough evaluation of impacts at all of the various receptors in each Class I area rather 

than just focusing on the 8th highest delta deciview which presumably just reflects just 

one receptor for each Class I area - as SRP did in its analysis. See, e.g., Tables 5-1 and 5-

2 of SRP’s January 2009 BART Analysis for NGS. Because NOx often does not form 

into visibility impairing particulates for a significant distance downwind of a stack, it 

seems likely that any visibility disbenefit may only occur near to the Navajo units, and 

that the benefit from the significant NOx reductions achievable with SNCR or SCR would 

be seen at farther receptors in the same Class I area. Thus, in evaluating any visibility 

 199 E.g., Table 4-2 of SRP’s January 2009 BART analysis (at page 4-8) shows the total cost of 

LNBs/MOFA/SCR for all three units at $94,848,000. Based on a review of the costs of LNB/OFA/SCR at 

each unit from the Black & Veatch December 2007 FCPP BART Engineering Analysis (i.e., Tables 6-2 to 

6-5), it appears that the total cost of these controls was taken into account in the FCPP cost/deciview 

analysis as well.
59

disbenefit, EPA should analyze visibility impacts across each Class I area in making a 

determination of BART for the NGS units.

F. EPA’s Visibility Metric of Taking Into Account the Size of the Class I Area in 

Evaluating BART Options is Improper.

EPA has proposed an option to evaluate the visibility impacts of the various 

BART options being considered for Four Corners and Navajo. Specifically, EPA 

determined the visibility impact per area for the baseline conditions and the various 

BART options that were evaluated and then summed up the resulting dv-km2

improvement. See 74 Fed.Reg. 44328-9 (Table 27) and 44331-2 (Table 31). This 

visibility metric is improper, as it gives greater weight to the larger Class I areas as 

compared to the smaller Class I areas. Nothing in the Clean Air Act gives larger Class I 

areas more rights to visibility protection than smaller Class I areas are to receive. All 

Class I areas are to be treated equally. Thus, this visibility metric has no place in the 

BART analyses for Four Corners and Navajo and EPA should not rely on it.
60

VIII. Endangered Species Act Issues and Consultation 

As noted above on page 13, it is now believed that endangered fish species – including 

the Colorado pikeminnow and razorback sucker, both of which are protected as 

“endangered” pursuant to the Endangered Species Act, 16 U.S.C. § 1531, et seq. – are 

being adversely affected by exposure to mercury in the Four Corners region.200 Since 

NGS and FCPP release some of the highest and significant levels of mercury, their 

operations are likely contributing to these adverse effects.

EPA must consider the effects of the NGS and FCPP on species that are listed as 

threatened or endangered pursuant to the Endangered Species Act, 16 U.S.C. § 1531, et 

seq. This includes all of the effects of the plants’ operations, not just the effects of their 

NOx emissions or impacts to visibility. Accordingly, when developing the FIPs for NOx, 

EPA must consider, e.g., the effects of these sources’ emissions of mercury, selenium, 

and other pollutants to threatened and endangered species including the Colorado 

pikeminnow and razorback sucker as well as the southwestern willow flycatcher, and 

these species’ designated critical habitat, in accordance with the affirmative duties set 

forth in section 7(a)(2) of the Endangered Species Act, 16 U.S.C. § 1536(a)(2) and the 

implementing regulations for this provision set forth at 50 C.F.R. Part 400.

Thank you for consideration of our comments.

Sincerely,

Amy Atwood

Center for Biological Diversity

P.O. Box 11374

Portland, OR 97211

(503) 283-5474

atwood@biologicaldiversity.org

Lori Goodman

Dine CARE

10A Town Plaza, PMB 138

Durango, CO 81301

970-259-0199

kiyaani@frontier.net

Elouise Brown

President

Dooda (NO) Desert Rock

PO Box 7838

 200 See Ex. 52-54.
61

NewComb, New Mexico 87455

505-947-6159

thebrownmachine@gmail.com

Vickie Patton

Deputy General Counsel

Pamela Campos

Attorney

Environmental Defense Fund

2334 N. Broadway

Boulder, CO 80304

303-447-7216

vpatton@edf.org

pcampos@edf.org

Roger Clark

Air & Energy Director

Grand Canyon Trust

2601 N. Fort Valley Rd.

Flagstaff, Arizona 86001

928-774-7488, ext. 214

rclark@grandcanyontrust.org

Stephanie Kodish

Clean Air Counsel

National Parks Conservation Association

706 Walnut Street, Suite 200

Knoxville, TN 37902

P:865-329-2424 F:865-329-2422

skodish@npca.org

Laura E. Sanchez, Esq.

Natural Resources Defense Council (NRDC)

PO Box 287, 

Albuquerque, NM 87103

505-352-7408

lsanchez@nrdc.org

Mike Eisenfeld

New Mexico Energy Coordinator

San Juan Citizens Alliance

108 N. Behrend, Suite I

Farmington, New Mexico 87401

(505) 360-8994

meisenfeld@frontier.net
62

Sanjay Narayan

Sierra Club

85 Second Street, 2nd Floor

San Francisco, CA 94105

(415) 977-5769

sanjay.narayan@sierraclub.org

John Nielsen

Energy Program Director

Western Resources Advocates

2260 Baseline Road, Suite 200 

Boulder, CO 80302

303.444.1188 x232

jnielsen@westernresources.org