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

O ctober 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 Te chnology (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 th e Navajo Generating Station (“Navajo” or “NGS” ) and by Arizona Public Service ( “ APS ” ) for th e 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 requi rements 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 rem edying of any existing anthropogenic visibility impairment in “class I” national parks and wilderness areas. 1

1 4 2 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 contai n “emission limits, schedules of compliance and other measures as may be necessary to make reasonable progress toward meeting the national2 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 Ge neratin g 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 c row n j ewels of the national park , national monum ent and wilderness preservatio n system: Arches Nationa l Park; Bandelier National Monumen t; 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

- Sno wmass; 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 Gold en 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 Pla nt and Navajo Generating Station are among the single largest sources of NOx pollution in the nation. Indeed, the Four Cor n ers 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 (n early 35,000 tpy).” 2 The exceptionally high level of NOx pollution emitted from these facilit i es reflects emission rates that far exceed those achieved in practice at modern coal

- fired power plants

.

The extensive volume of NOx emissions from these s mokestacks ha s immediate
adverse impacts in the vicinity o f the facilities and drift s tens and hundreds of mi les
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, f or 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 in crease 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 conta minates water bodies,
threa tens 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 regi on from the se 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 methylmercu ry 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, Methylmercu ry: 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 Me thylmercury (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 conside ration 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 Easte rn 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

f4 The regional haze program is designed, cons onant with statutory imperatives , to prevent and remedy visibility impairment from multiple sources that emit visibility

impairing 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 adve rse 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 adverse ly 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 fr om 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

sc enic 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 pre vention of any future, and the r emedying of any existing, impairment of visi bility 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 pr otects 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, manma de sources of visib ility 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 “V isibility impairment” includes r eduction 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 Yel lowstone 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 . . . inade quate[ly] controlled

sources.” 17 Congre ss 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, diminishi ng 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, Vi sibility Protection Under the Clean Air Act: Preserving Scenic and Parkland Areas in the Southwest, 10 E COLOGY 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. R EP

. N O

. 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 Co ngress (EPA 450/5

- 79

- 008 Oct. 1979).6 precursors, such as sulfur dioxide and oxides of nitrogen, that transform into fine particles. T hese 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 antici pated to cause or co ntribute to visibility impairment in a mandatory
class I area, develop and submit a plan containing “emission limits, schedules of com

pliance and other measures as may be necessary to make reasonable progress toward meeting the national goal.”

Section 1 69A speci fically requires visibility implementation plan to in clude (1) best available retrofit technology (BART) for certain existing station ary sources that emit pollutants that “may reasonably be anticipated to cause or contribute” to visibility impai rment 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 ru le 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 Sa moa 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 impa ired 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 perc ent 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). T he period that the plan must cov er 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 f or 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 res tore 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 req uires 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

rea sonable.” 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 stat ute, 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 a mendments. 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 be fore 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 poten tial 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 clean ing plants (thermal dryers); kraft pulp mills; Portland Cement pl ants; pri mary 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. R E P

. N O

. 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 ni tric acid plants; petr oleum refineries; lime plants; phosphate rock processing plants; coke oven batteries; sulfur recovery plants; carbon black plants (fur nace process); primary lead smelters; fuel conversion plants; sintering plants; secondary metal production facilities;
ch emical process plants; fossil fuel boil ers 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 charc oal production fa

cilities. 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 anti cipated 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, lim ited 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, there fore, 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 r egional 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, Janu ary 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

t he 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 imp lementation 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 limitation s. 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

count ed, 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 Nav ajo 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 f or 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 Stati on 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 NO

x per year and the Navajo Generating Station emits approximately 34,000 t ons of NO

x per year. 44 Although wet
scrubbers were installed to reduce SO 2 emissions at the three Navajo units in the 1990’s
and the SO 2 controls were improved in recent years at Four Corners, these power plants still have substandard pollution controls fo r NO

x . Emissions of NO

x 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 NO

x burners and Unit 1 has had
burner modifications to control NO

x em issions.

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 pl an 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 L EGISLATI VE H ISTORY OF

THE C LEAN A IR A CT A MENDMENTS 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. I f 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 y ears (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 a t 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 ran ged 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 sit es 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 a t p s . 20

& 22 (Ex. 58)

.

Further

, EPA modeling analysis indicates t hat 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

p erceptible 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 F our Corners area has been experiencing very high ozone concentrations for year s 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 qu ality standard ( “ NAAQ S ” ) . Other monitors in

45 S ee, 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 concent r ations within 5% of the level considered to be a violation of the ozone NAAQS, including Flagstaff for which the 3

- year average of the 4 th highest concentration was 74 ppb in 200 8. Mesa Verde National Park, Canyonlands National Park, and Petrified Forest Na tional Monument each had 3

- year average s of the 4 th high ozone concentrat ions of 71 ppb as of 2008. Monitors in Grand Canyon National Park and Farmington, New Mexico had a 3 y ear average of the

4 th high est ozone concentration equal to 70 ppb as of 2008

. (All monitor values and averages obtained from EPA’s AirData website).

T he New Mexico Environment Department has been implementing a vol untary program for emission controls i n the New Mexico portion of the Four Corners region pursuant to the Early Action Compact tha t 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 violati on 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 issu e 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 welf are. 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 Scientifi c 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 alread y 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

ast hmatics 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 C ompact 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 Com mittee’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 (n on

- 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 intermou nta in 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%
inc rease 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, C alifornia. 52 These ambient ozone concentrations have been

as sociated 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.

N itrogen deposition, caused by wet and dry deposit ion 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 impact ed) 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 Le vels 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 S pring 2009). Scientific investigations have already demonstrated that nitrogen is saturating the soil, plants and water of Rocky Mountain Nation al 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 r ecent trend s analysis by the National Park Service . These worrisome
increases provide an additional basis for prompt action in de aling effectively with major
sources of NOx emissions in the region

.

Mercury Emissions are a Threat to Endangered Species in the Regio n

These plants also release significant levels of mercury emissions. For example,
the F our 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 Pa rk 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 P olluting P lants, 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 s triped 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 “endangere d” pursuant to the Endangered Species Act, 16 U.S.C. § 1531, et seq

. – are adversely affected by exposure

to mer cury in the Four Corners region. 57 Accordingly, reduction of mercury emissions from NGS and FCPP through the use of SCR and baghouses could bene ficially 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 th is delicate region. We urge EPA to take into account all of the adverse
health and en vironmental 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 Powe r Plant s 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

r eductions 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 overf ire 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 . W e 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 b y SRP and APS significantly overestimate the cost s 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 e ast ern United States pursuant to t he 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 Servi ce 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 . T he
multitude of EGUs at whic h SCR was installed demonstrates th e cost

- effectiveness of
SCR retrofits.

A

. SCR Cost s at Four Corners Power Plant A re I nflated.

APS submitted SCR cost estimates to EPA Region IX prepared by Black & Veatch in a December 4, 2007 BART En gineering Analys is. 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 B ART 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
the se overestimate s

. T he 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 u nits. 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. W e then explain on a n 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.

Howeve r, these comments apply to all of the options that include SCR that were costed by Black & Veatch.

1. Total Capital Costs Are High er Than R eported By Others

.

Capital costs for pollution control equipment are commonly reported on a dollar per kilowatt of capacity basis . The uni t 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

- OAR

2009

- 0598

- 0004.3.]

59 Letter from David L. Saliba, Plant Manager, Four Corners Power Pla nt, 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

F ive 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 pe r kilowatt . These actual costs are lowe r 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 t hat 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 co st 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 th at become operational in 2006 or were scheduled to start up in

2007 or 2008 , reported cost s 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 200 8 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 reporte d 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 Cataly tic 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 2 005 (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 t o $ 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 estimate s of capital cost to retrofit SCR

at Four Corners ($336 /kW

- $643/kW ) are high er than the actual installed cost s 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 S CR on Oak Creek Units 5

- 8
to be $205 /kW 69 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 u nits was $162/kW. 72

These recent estimate s , prepared around the same time as those by Black & Veatch, are reasonable upper bound s for the smaller Four Corners units (1

- 3) as they are for larger units (which generally have higher uni t costs) and Oak Cr eek 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 , Novem ber 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

- Complex

Retrofit/

67 Standing on the Shoulder of Giants, Modern Power Systems, July 2 002, Ex. 8.

68 McIlvaine, NO X 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/sampleupdate s/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 Diox ide 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 S elective 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

ge nerating 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 Bl ack & Veatch repor ts and EPA's ANPR do not provide sufficient information to support the claimed costs. We ar e unable to confirm the cost estimate s as

s everal crit ical pieces of information are missing.

First, the cost of an SCR is determined by its design basis. The de sign 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 d o not disclose the
ammonia

- to

- NOx molar ratio , space velocity, or catalyst life. In fact, the Black & Veatch "Design Concept Definitions" for SCR i n the 2007 report indicate that the ammonia injection rate and energy consumption are both "TBD" or to be de termined. 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 sup porting documents
also do not i n c lude a plot pla n showing the proposed SCR arrangement. EPA s hould 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 run s 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 involve s 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 spreadsheet s , 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 inspec t the formula e used and change assumptions to explore their impact o n the bottom line. The EPA sho uld require th at 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 estimat ing 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
calculati ng 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 use d 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 t he 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, especial ly SCR. Instead, Black & Veatch appear s 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 S CR+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 prov ided by APS (provided
in Table 3 of the ANPR). Given that EPA has recommended all BART cos t 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 c ost 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 b e 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 cost s in March 2009 to address increases in the pric e for steel, concrete, other building materials, and overall construction costs.
These revised cost s 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 estima te increases seem unnecessary and inappropriate. The Chemical Engineering Plant Cost Index ("CEPCI") for 2008 i s 575.4. The June 2009 index is 508.9, a 12% decline in 6
month s

.

Further, the difference in costs betwee n the 2007 estimate and the 2009 e s timate 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
b askets 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 pre heaters 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 space

constrained 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 o r 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, a nd $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 throug h 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 claim ed costs for new fans seems excessive and should be supported.

The record contains no informa tion 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 reques t information for the existing fans, including their design basis, current loads, and increased lo ads required to support the SCRs and evidence that layout constraints require new fans.

Electrical Equipment

The capital cost estimate include about $3 mil lion 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 elec trical equipment costs for other S CRs. 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 suppo rt justifying these upgrades. In fact, the 2007 Black & Veatch analysis reports the energy demand of the SCR s 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 app licable to Navajo

. 84

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

- 28.

82 PowerGen 2005, Selective Catalyti c 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. Sprun gl 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 in i tial 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

F oundati ons 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 retr ofits, which range from $9/kW to $11/kW in 2008 dollars. 86 These cost should be justified in the record.

Handling and Erection

H andling and erection is estimated as 25% to 40% of PEC. T he basis for assuming 25% to 40% of PEC should be provided. The r esulting 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

E lec trical 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, S ection 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 Reduc tion: From Planning to Operation, p. 30.24 Relocation

T he 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 mi llion to $8 million. These costs appear to be double counted as they are likely covered by the generous allotments for foundation s , support s , handling, and erection
discussed above. The EPA should require that APS identify each piece of relocated equipme nt, 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, wh ich are not
included in the Control Cost Manual. 89 We agree. T he Control Cost Manual does
include "home office fees." A ll owners do not manage and implement capital projects, but rather retain engineering firms, called the owner's engineer, to p erform 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 outsid e 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 i ncluded in the Control Cost Man u a l 90 and should
not be included in cost effectiveness analyses. This category includes mitigation for SO 3 removal, lost revenue from exte nded outages, new continuous emissions monitoring systems (“ CEMS ”)

, and relative accuracy test audit s (“ RATA ”) for the new CEMS. We agree these costs should not be included in the cost effectiveness analysis.

First, t his equipment is outside of the batt ery 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

. Furthe r, 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 w ould 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 extre mely 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 we eks would be needed.
The Black & Veatch R eport s 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 a bout $7 million for SO 3 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 SO 3 are not requ ired if a
low SO 2 - to

- SO 3 catalyst is selected. The ANPR indicates that APS used a 1% conversion rate for the SCR catalyst. EPA det ermined 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 SO 3

. We urge EPA to estimate b oth costs and visibility impacts assuming a
0.1% convers ion catalyst.

Further, it is not clear why SO 3 controls were included for Units 4 and 5, which are equipped with a wet lime scrubber for SO 2 control, but not Units 1

- 3, which use
venturi scrubbers for SO 2 control. The wet lime scrubber is much more effective at removing SO 3 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 ca lculated 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 tha n 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 substantia l 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, present ed below, indicate that the ratio of ann ual 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 equ ipment, costs for site preparation and buildings, and certain other indirect installation costs. 93
Cost effectiveness is determined by converting t he total capital investment into an annual cash flow, adding annual operating and maintenance costs , and divi ding 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 ove restimated annual capital costs, one of the two key inputs to the cost effectivene ss 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 o f the pollution control equ i pment. 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 li fetime of the control system. The hi gh er the interest rate a nd 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 li f etime, thus substantially over estimating 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 a n interest rate of 15%. 95 This is more than double the 7% interest

rate routinely recommended b y 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 I

X. “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 In ternet 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/B

96

- 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

Seco nd, 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 analyse s , 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 i s 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, shou ld 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 Int ernet 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, Pesticid es & 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 b ased 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 pla nt, including siting characteristics and operating/maintenance strategy and thei r effect on SCR system lifetime. T he authors’
choice of a 30

- year life for the SCR system is an important parameter in their study

. 101

On a retrofit, su ch as these, SCR wou ld 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 assume s only 20 years as the service life of the SCR. Howeve r, 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 admi ttedly long er and SCRs in operation today have been in ser vice 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 B lack & 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 chan ge 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 th e 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 t he future worth of the

100 McIlvaine Company, Worldwide Utility Plans, NOx Installation and Component Suppliers (Ex. 12); Vendor Experience Lists for Hitachi and Mitsubishi. E xs. 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 17 th Annual International Conference: Risk, Reliability, and Security . p. 3. Found on the Internet at http://www.unwin

- co.com/files%5CSCR

- Risk

- Paper,CCPS

RRS2002.pdf

,. 102 12/4/07 Black & Veatch, p. 6

- 2.29 catalyst because catalyst is replaced eve ry 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,

r eplacement 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 c atalyst normally varies between $3,500 and $6,500 per m 3 , 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. I t 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 roo m. In general, operation of an SCR does not require any additional o perating or supervisory
labor. 108 This value should be zero.

Maintenance Labor and Materials

The Black & Veatch study estimated costs for maintenance labor and materials a s 3% of direct costs. The Control Cost Manual indicates these costs should be calc ulated 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 "levelizati on factor." The factor used for direct annual costs was 1.45129 and for total annual cost, 1.1021. No explanation is provided for this facto r or the reason it differs for these two cost components . Further, the variables used to
calculate it are not ide ntified.

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 bo th the annual cost of money or the discount rate and the nominal escalation rate, 109 which are not report ed in
the record.

C ost effectiveness ana lyses do not include escalation. The total annual cost

m ethod used in cost effectivenes s analysis, as laid o ut 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 informati on 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 A rrangements Were Not Considered.

The 2007 Black & Vea t c h BART analysis claims "extreme retrofit difficulty" for
the SCR located in the hot

- side position, between the boiler outlet and the air preheater 112

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 t o 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, Sectio n 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 alternat ives include ducting together two or more units. There is no evidence that any alternative arrangeme nts 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 retro fit

– 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 du st
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

co nfiguration 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 c ompletely because the record is missing critical information that is required for an accurat e estimate, including plot plan s and key design parameters. Our revised costs start with B lack & Veatch's 3/16/09 estimate of TCI and

DAC , sub tract invalid costs a s discussed supra (taxes, intended consequences, initial catalyst, owners cost, catalyst disposal, overestimate d catalyst disposal, and escalation ), and recalculate the capital recovery factor and hence annualized capital costs.

Our revised co sts are s ummarized in Exhibit 18 . They show that r evised 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 f or 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 revi se 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 Ad dendum 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 W e agree with EPA that APS's reported total capital costs should be reduced by at
least 15%. In our opin ion, the actual annual costs would be less t han 10% of total capital

i f all of the overestimates discussed above were considered. T here are some components of the total capital cost estimate that we were unable to correc t due to the inadequate

recor d, e.g., foundation & supports, handling & erecti on, electri cal 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 signif icantly 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 o f 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 con trols, 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 provi ded 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 analy sis (LNB/SOFA&SCR on Units 1

- 3).

1. Total Capital Costs for SCR Options A re Higher than Reported by Others

.

As explained for Four Corners, c apital costs for pollution control equipment are commonly reported on a dollar per kilowatt of capacity basis. T he unit capital costs, based on the costs presented in the ANPR for Navajo 118 are summarized in Table 3.

Table 3 Summary of SCR Capital Cost Navajo Generating Station

116 July 25, 2008 Sargent & Lundy Report “Salt River Projec t Navajo Generating Station, SCR and SNCR Cost Study, Final Report,” submitted by SRP to EPA on July 29, 2008 ( EPA

- R09

- OAR

- 2009

- 0598

- 00 07).

117 ENSR Corporation, Revised BART Analysis for the Navajo Generating Station Units 1

- 3, Prepared for: Salt River Proj ect

- 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. Th us, 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 co st 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

suc h 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, t he ANPR claims these costs are based on the Sargent & Lundy report.

H owever, 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

Ju ly 2008 and January 2009.

Second, t he 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 quo tes 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 t o 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 injecti on system, catalyst, ductwork, booster fans, electrical/instrumentation and controls, among others.

Third, the cost s 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 fo r 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 o f 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 capi tal costs using a cost recovery factor of 0.1179 124 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 Sar gent & Lundy Report indicates that cost s were developed using an internal S&L cost database, adjusted for differences in ductwork, structural steel, and constructability issues. 126 However, the BART G uidelines do not recognize this as one of the acceptable methods for de veloping 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 oth er 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 Repo rt 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. 235 The capital costs for Navajo improperly included cost for l ost generation at each
unit due to an additional 4 weeks 128 of unit downtime to tie

- in the SCR. T he 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 Th is 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 th e 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. R ather , an 85

- 90% capacity fact or 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 w as 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 wor st case i n determining costs of SCR installation 131 . 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 w ere estimated. The supporting BART analyses sugges t 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 maintenance 134 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 Tabl e 4

.

Table 4 Impact of Capital Recovery Factor on
Cost Effectiveness ($/ton)

Unit ANPR Cost
Effectiveness Revised

Cost
Effectiveness 136

1 1,833 1,360

2 2,419 1,771

3 1,900 1,410

These revised cost effectiveness values are consis tent 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 e stimates 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 depe nds 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 Sp rungl 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

t hat 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 space

constrained 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 the se 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 Stat e
- of

- the

- Art NOx Controls at Navajo

.

SRP has stated that the Navajo units could meet a NO

x emission limit of 0.24
lb/MMBtu

, with a possible reduction down to 0.20 lb/MMBtu

, w ith new low NO

x burners and separated overfire air. See, e.g., SRP’s January 2009 BART Proposal [EPA

R09

- OAR

- 2009

- 0598

- 0010.1] at 6

- 1. SRP should be able to at least meet a NO

x limit of
0.20 lb/MMBtu or lower with state

- of

- the

- art ultra low NO

x burners a nd separated overfire air (LNBs/SOFA). Although SRP claims that lower NO

x 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 NO

x emiss ions with the coal it currently burns at Navajo.

Many other existing coal

- fired units are achieving lower NO

x emission rates with
these controls. Exhibit 20 to this letter includes a spreadsheet with NO

x emissions data
from 2004

- 2006 that provides numer ous examples of tangentially

- fired boilers with low

NO

x burners and overfire air meeting lower NO

x 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 NO

x limit of 0.20 lb/MMBtu NO

x e mission limits with just LNBs/SOFA, it seems quite possible that these units could readily meet that limit and even achieve lower NO

x emissions with ultra low NO

x 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 modifi cations 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 precipita tor inlet. We wonder whether both arrangement were considered at one point and the text not fully modified?38 SRP’s assessment of the NO

x emissi on rates presumed to be achievable at the Navajo
units with new LNBs and SOFA and should instead re

- evaluate the NO

x emission levels
achievab le with new LNBs/SOFA at the Navajo units.

With SCR added in, SRP estimates it could achieve a NOx emission rate o f 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

NO

x removal are being achieved by rec ent SCR retrofit installations. NO

x emission rates less than 0.05 lb/MMBtu are routinely achieved, and NO

x removal efficiencies are typically around 90%. 140 Permitting agencies have required lower NO

x limits in recent BACT determinations, with many propos ed 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 NO

x burners and overfire air for combustion controls along with an SCR, and it is subject to a NO

x BACT emissi on limit of 0.05 lb/MMBtu. With the state

of

- the

- art low NO

x burners and overfire air on this unit, it is very likely that NO

x concentration exiting the Dry Fork boiler will be in the 150 ppmdv range, and yet this unit is subject to a NO

x 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 NO

x 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 NO

x burners, overfire air and SCR with proposed or required NO

x limits
lower than 0.08 lb/MMBtu as well as several NO

x limits that are lower than 0.06
lb/MMBtu. We have attached a spread sheet of NO

x BACT rankings obtained from the National Park Service Air Resources Division that provides several examples of lower

NO

x BACT limits. Ex. 22. Further, EPA Region 9 has required the proposed Desert Rock power plant to meet a NO

x BACT limit as low as 0.035 lb/MMBtu. 141 The Desert Rock facility will burn western bituminous coal from the same re gion as the coal utilized at Navajo

.

In the ANPR, EPA i ndicated 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 6 0

- 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 cop y 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 rem oval with SCR at each of the Navajo units would equate to

em ission 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 A 143

. We agree that 0.05 lb/MMBtu would be achievable and likely, even lower NOx emission rates would be achievable with upgra ded LNBs/SOFA and SCR at the Navajo units.

EPA has req uested comment on the use of an SCR for half of the gas stream from Navajo Unit 2. 74 Fed.Reg. 44322. This is beca use 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 t he 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 commen ts, 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
evalua te 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 th at SRP and EPA relied on in the cost
effectiveness calculations are much lower than the NOx reductions t hat 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 re flect 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 an d 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

- OAR

2009

- 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 achiev e d 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 ne w low NO

x burners and ov erfire 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 NO

x emission rat es should be achievable with state

- of

- the

- art low NO

x 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/M MBtu. T hus, EPA
should more close ly 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 NO

x 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

NO

x 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. Sp ecifically, 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

Mos t SCRs for coal

- fired boilers are designed for about 90 percent NO x removal and v ery low ammonia slip (typically less than 2 ppm). 144

The data on SCR retrofits a nd attached to this letter show this to be true

. NO

x emission rates less than 0.05 lb/MMBtu ar e routinely achieved, and NO

x removal efficiencies are typically around 90%. 145

144 ICAC White Paper at 12. As discussed above, p ermitting agencies

145 See Erickson, Clayton A. et al., Selective Catalytic Reduction System Performance and Rel iability Review, The 2006 MEGA Symposium, Paper # 121. Ex. 21.41 including Region IX have required lower NO

x 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 NO

x emission rate reflective of the maximum degree of NO

x emission reducti on that can be achieved at the Four Corners
units with combustion controls and with combustion controls and SCR . T he avail able information overwhelmingly supports a lower NO

x emission limit for these controls t han assumed by either APS or EPA . Further, the costs estimates and the modeling must be redone for the SCR options with such lower NO

x emission limits.

C. T he Cost E ffectiveness of SCR is R easonable.

Cost effectiveness is the annual cost of a control option in dollars divided by the tons of pollution that is removed. Annual costs are cal culated in a particular way , set out
in the Control Cost Manual and discussed a bove

, 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 rea sonable. W e 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 an alysis is
summarized in Table 5

. It shows that ev en APS' and SRP's overestimated costs for SCR
are well within the cost s 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 Su mmary ($/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 t he earliest SCR s on a coal

- fired power plant in the United States was permitted i n 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

- electric

power/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 cont inues to operate with SCR. 148 The SCR cost effectiveness value from 1991 escalates to $21,016/ton in 2008 dollars. In 1992, a n SCR was permitted at the Stanton co al

- fired power plant in Florida. The cost effectiveness was $4,262/ton for 70% NO X 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 c ost effectiveness thresholds for NOx. They are summarized
in Table 6.

Table 6 Region IX
Cost Effectiveness Thresholds ($/ton)

Region 153 NOx
Threshold

SJVAPCD 24,500 SMAQMD 24,500 YSAQMD 24,500 SCAQMD 19,100

SDAPCD 18,000 BAAQMD 17,500

The EPA ha s 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, 2 001.

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 Ava ilable 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 Qu ality 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 previousl y 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 us ed in Indiana for several facilit ies are summarized in
Table 7.

Table 7
Indiana Average Cost Effectiveness Rejection Thresholds

Facility Permit

Date Average
Cost ($/ton) CEI 157 Adjusted

Cost ($/ton)

AK Steel 4/15/07 9,514 1.15 11,941

AK Steel 8/5/05 16,8 02 1.30 2 1,843

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 c ost effectiveness values for SCR reported by any party (ranging from $4,343

- $5,484 for Four Corners an d from $3,002

- $3,736/ton for Navajo) , are much less than the se 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 re ported 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 t he company projected a cost effectiveness of $2,830 per

154 Delaware A ir 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

- m ail 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 Annu al

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 ins ta llation at Jim Bridger Units 1

- 4 to meet long ter m strategy/ re asonable progress requirements. 160 The state of Wyoming determined that SCR installation along with upgraded combustion
controls was cost ef fective at a cost of $2,258

- $4,275 (for Unit 2) per ton of NOx
reduced at each unit. 161

, 162

T he Oregon Department of Environmental Quality has required as BART the installation of a semidry flue gas desul furization ( “ FGD ” ) system for SO 2 at the
Boardman Power Plant

. 163 This was based on a cost effectiveness of $3,055/ton/year

. 164

The Or eg on Department of Env ironmental 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 c ost 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 base d 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 (AP

6042) for the Naughton Power Plant at 15, 49 (Ex. 30).

159 It must be noted that numerous environm ental 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 A nalysis (AP

6042) 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 Wy oming 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 fro m 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 Ta ble 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 BA RT 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 Consul ting, 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 sig nificant 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 NO

x combustion system at each unit and a NO

x 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 ret rofitting SCR
to a western coal

- fired power plant are reasonable

. EPA must take this Consent Decree into consideration in determining whether the costs of SC R installation at Navajo and at

Four Corners are reasonable.
If similar facilities have had to be ar 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 NO

x emissions contribute to in the region, the costs of SCR at the Navajo
and Four Corners units, even at the high end estima te provi ded by the owners of these
facilities , should be considered reasonable.

D . SRP and APS Failed to Analyze Methods to Reduce S ulfuric Acid Mist and
Sul fate Emissions from SCR Which Both Parties Claim Will Cause a Visibility
Disbenefit with SCR.

SR P 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
vis ibility, creating a disbenefit to the use of SCR for NO

x reductions. Id. at 5

- 2

. APS makes similar claims. January 2008 BART Modeling Analysis for APS Four Corners

Powe r Plant Units 1

- 5 at 6

- 6. However, SRP’s and APS’s BART submittal s fail to
discuss i n 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 sho wn 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
be en 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 SO 2 to SO 3 conversion catalyst for the SCRs. For example, t he CX Series type catalyst developed by Babcock

- Hitachi
has achieved SO 2 to SO 3 conversion rates as low as 0.1%. 177

EPA in its ANPR apparently is only taking into consideration a low SO 2 to SO 3 conversion catalyst with an SO 2 to SO 3 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 SO 2 to SO 3 conv ersion 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 po llution control train at the Navajo units and at
the Four Corners units without bagh ouses to aid in the remov al 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 opti ons 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

fi lterable 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 F our Corners at 5

- 3. According to the Four Corners BART Analysis, these are worst case daily emission rates. Id. EPA’s
ANPR identi fies 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 r educe
filterable PM emissions

– down to 0.0 12 lb/MMBtu if not lower. 178 Current BACT limits
for new coal

- fired power plants equipped wi th baghouses are routinely 0.012 lb/MMBtu or lower. For example, in the Desert Rock PSD permit, EPA Region 9 set the filt erable

PM 10 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 Clas s I areas in the region and, accordingly, PM BART must be fully evaluated
for these facilities.

A. SRP Must Be Require d 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.”

Ja nuar y 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, espec ially given the proximity of Navajo to Grand Canyon National Park. E ven 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 ca pture SAM emissions from the Navajo units

. Further, installation of baghouses will impr ove mercury and other air toxics control. Thus, EPA must require SRP to evaluat e BART for PM control at the Navajo units. I n evaluating the visibility benefits of a baghouse for PM BART, EPA should require the modeling of the PM BART option with the NO

x 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 wit h 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 Condit ion 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 emissio n 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 n ot evaluat ing 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 ev aluate 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 b e 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 bagh ouses 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 NO

x control at Four Corners

.

V. In A ddition to Failing to Adequately Evalua te 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 o ther 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 year 181 . 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 t he existing Intermountain Power Plant units a chieved 84% removal of mercury with its wet scrubber and baghouse in the 1999 mercury Information Collection Request (“ICR”) testing required by EPA. 184 Indeed, t he 1999 ICR test data show that boilers with baghouses achieved some of the lowest mercury emis sion 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 HgCl 2 ) making it easier to capture downstream in wet FGD s ystems 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 baghous e designed
for state

- of

- the

- art particulate control

, and significant mercury reductions are a likely co

benefit 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 sprea dsheet 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 M ercury 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 mercur y 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 w ould more effectively control other non

mercury 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 Me xico. 189 S tudies 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 loc ated 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 to xic 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 a nd 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 ha s 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, low

http://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 Wildlif e 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 fr om Mercury Exposure Is Cost Effective , available online at http://www.iatp.org/iatp/library/admin/uploadedfiles/Protecting_Children_From_Mercury_Exposure_is_C. pdf51 w eight 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
the se 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 fisheri es 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 lif e of the facility should not be invoked to relax BART standards for either the Four Corners or Navajo plants. A bsent 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 oper ation eighty years

ago, or more (e.g., Citizens’ Thermal Energy C C 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 betwee n 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 Cor ners 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 jus tify 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.” Regi onal 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

as sured by a federally

- or State

- enforceable restriction preventing further operation.” 194

194 In the alternative, the agency should establish maximally stringent BART limits that woul d 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 rigorou s 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 (6 th 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 NO
x 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 Overestimate d 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 SO 2 to SO 3 which with then form SAM.

would be required as BART if the re 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 operation s”).

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 instrument ation. The major components have no moving parts. The catalyst, accountin g for the bulk of the value (80%), i s 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 Che vron Richmond Refinery in California in 1984. Those SCR systems remain in
service. There have been no reported m aintenance, operational or compliance problems, and the original

cata lyst 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) O ther SCRs, installed in Japan in 1980 ; they remain operational after 29 years. See Ex. 14 (Mitsubishi SCR System Supply List (June 2005)).53 SRP provide d no justification for the assumed 1% SO 2 to SO 3 c onversion 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 SO 2 to SO 3 conversion rates than 1%, especially for western coals. 197 In addition, as discussed above, low SO 2 to SO 3 conversion catalysts are available that could
be used at NGS . Thus, SRP relied on a too high of an SO 2 to SO 3 conve rsion rate and, as a result, the visibility modeling for the SCR BART options overestimat ed the visibility
“disbe nefit” 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 SO 2 to SO 3 conversion rate of 0.5%. November 2008 BART Modeling Analyses for APS FCP P at 6

- 7, Table 6

- 4 (footnotes g and h). However, APS also did not provide any justification for its SO 2 to SO 3 conversion rate and, based on the Hardman paper cited in this document, even that conversion rate may overestimate SO 3 conversion with the SCR.

B . SRP
, APS , and EPA Overestimated NO
x 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 NO

x emission rate of 0.08
lb/MMBtu. This emission rate only reflects 60

- 67% NO

x removal across the SCR, when

80

- 90% NO

x removal should be achievable. Thus, it is much more realistic to assume a

NO

x emission rate of 0.05 lb/MMBtu or even lower. Because SRP overestimated NO

x emissions with SCR, its visi bility modeling overestimated impacts under Options 3 and 4

– in addition to already overestimating visibility impacts due to an overestima te of SAM emissions from the Navajo units with SCR.

APS assumed NO

x emis sion rates with SCR at the Four Corners un its of 0.06 to
0.075 lb/MMBtu. While these emissi on rates are lower than the 0.08 lb/MMBtu emissio n 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 NO

x burners/overfire air at the Four Corners units as discussed in our comments above. It is
much more realistic to assume a NO

x emission rate of 0.05 lb/MMBtu or even lower. Inexplicably, EPA stated in the ANPR that it projected NOx emission rates at Fo ur 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 NO

x

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 NO

x 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 fro m 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 Backg r ound Levels in
its Visibility Impacts Modeling

.

The CALPUFF model was us ed 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

assum ed 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 o f 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 gr asslands. 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 guidance 198 . 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; Ta ble 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 backgroun d 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

in variant. 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 t he 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 obtain ed 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 el iminating 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

assum ption 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 CALPUF F 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 ammo nia 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 vis ibility benefits of reducing NOx emissi ons 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 pa ssive 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 visi bility 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 significantl y 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 20 07 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

ammon ia 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 measured56 near the receptor areas. Since much of the availab le 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 t he year, and the estimates are consistent with
the observations of ammonia.

Increasing Nitrate Trends Underscore Need for Prompt Action. T rends 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 o f 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 backgrou nd 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

ANP R, 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 backgroun d 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 ac ross 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 NO
x Burner/Overfire Air Option rather than to Baseline Impacts in Determining Cost Effectiveness in Dollar per Deciview

.

I n its evaluations of its various BART options, both SRP and APS determined
incremental visibility improvement for the SNCR and SCR options based on a58 comparison of the visibility impacts of the low NO

x burner/overfire air option (Option 1a
for NGS and Opti on 1 for FCPP). Then, cost effectiveness for the SNCR and SCR options were d etermined b ased on dollar per deciview. See Janua ry 2009 SRP BART Analysis at 5

- 1 to 5

- 9 ; November 2008 BART Visibility Modeling Report for the
Arizona Public Service Four Corne rs 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 NO

x 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 B ART o ptions. 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

r ather than baseline conditions. See Table 5

- 1 of SRP’s January 2009 BART analysis ; Table 6

- 5 of November 2008 B ART Visibility Modeling Report for the Arizona Public Service Four Corners Power Plant (Supplemental) . Further, given the numero us Class I areas impacted by these two power plants and the varying distanc es of each Class I area from the power plants , EPA s hould not rely on any analysis of visibility improvements due to the various BART options tha t 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 SC R 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 vis ibility 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 v isibility 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 8 th 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 Janu ary 2009 BART Analysis for NGS. Because NO

x 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 ben efit from the significant NO

x 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 Ja nuary 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
det ermination 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

- km 2
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 pr otection 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 VI I I. E ndangered S pecies A ct 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 mer cury 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

NO x 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 pi keminnow 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 th e 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
thebrownmachi ne@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@ed f.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 871 03
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.net62 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