1 

March 26, 2012 

VIA ELECTRONIC MAIL 

Keith Rose 

EPA Region 10, Office of Air, Waste and Toxics 

AWT-107, 1200 Sixth Avenue, Suite 900 

Seattle, WA 98101 

R10-Public_Comments@epa.gov 

Re: Approval and Promulgation of Implementation Plans; State of Alaska; 

Regional Haze State Implementation Plan, EPA Regional Haze State Implementation Plan, EPA-R10-OAR-2011-0367 

Sierra Club, National Parks Conservation Association, Cook InletKeeper, 

Northern Alaska Environmental Center, and Alaska Community Action on 

Toxics submit the following comments on the Environmental Protection 

Agency’s (EPA) proposed rule approving Alaska’s regional haze plan. 77 Fed. 

Reg. 11022 (Feb. 24, 2012). Our organizations represent thousands of 

members in Alaska and hundreds of thousands of others throughout the 

nation that care deeply about protecting public health, air quality at national 

parks and wilderness areas, and local economies supported by recreation and 

tourism. 

Golden Valley Electric Association’s Healy Unit No. 1 plant is a 25 

megawatt (MW) coal-fired boiler that was constructed over forty years ago. 

Healy Unit No. 2 is a 50 MW coal-fired unit that has operated intermittingly 

since 1989. Healy’s emissions cause substantial visibility impairment in 

Denali National Park, and around the region. Home to North America's 

highest mountain, Denali is one of the nation’s most magnificent national 

parks. Denali is a popular tourist destination that encompasses more 

than six million acres of open tundra gleaning with wildflowers, spruce trees, 

and valleys with glacier-fed rivers and lakes. Denali’s visitors bring in 

significant economic benefits to the area. In 2010, Denali visitors spent more 

than $140 million, directly supporting more than 1,800 jobs in the area.1

 

 

1 Data from National Park Service (http://www.mgm2impact.com/)
2 

 

As EPA has recognized in its proposed rule, because Healy contributes to 

visibility impairment in Denali, it is subject to “Best Available Retrofit 

Technology” (BART) limits under EPA’s Regional Haze Rule. 40 C.F.R. §§ 

51.300.-.309. EPA’s proposed rule, however, does not require meaningful 

emission reductions from this outdated coal plant. The limits proposed for 

sulfur dioxide and nitrogen oxides at Healy do not represent the “degree of 

reduction achievable through the application of the best system of continuous 

emission reduction” required by law.” 40 C.F.R. § 51.301 (defining BART). 

See also 18 AAC 50.260(q)(1) (adopting federal definition). Moreover, EPA’s 

proposal fails to account for haze-causing emissions from Healy Unit 2, 

resulting in an inaccurate conclusion that the State is on the “glide path” to 

achieving its regional haze goals. Alaska’s failed to include Healy Unit 2 in 

its reasonable progress analysis, a facility which is projected to come on line 

in the near term. Unit 2 will cause excessive haze forming emissions, is in the 

same footprint as Healy Unit 1 and may prevent reasonable progress toward 

achieving the elimination of regional haze at Denali. 

EPA must impose lower BART emissions limits for sulfur dioxide and 

nitrogen oxides at Healy unit 1 that are consistent with modern pollution control 

technology to meet the requirements of the regional haze program and protect 

public health, the environment and Denali National Park. In addition, EPA must 

issue adequate emission limits for Healy Unit 2 to ensure reasonable progress not 

be thwarted by anticipated haze causing emissions. In the long term, Alaska’s 

energy future is best founded on clean, efficient energy – not coal. 

A. EPAMustImposea Lower a Lower a Lower Nitrogen Nitrogen Nitrogen Oxides (NOx) BART Emissions Emissions 

Limit. 

EPA’s proposed rule includes a NOx emission limit of 0.20 pounds per 

million British thermal units (“lb/MMBtu”) for BART at Healy, based on 

emissions reductions that can be achieved by adding a selective non-catalytic 

reduction pollution-control device (SNCR). This limit does not meet the 

Clean Air Act’s requirements. EPA must impose a lower NOx limit based on 

SCR (selective catalytic reduction) – a much more effective control 

technology. EPA’s rejection of SCR is based on a flawed cost effectiveness 

analysis. 

1. EPA’s Proposed EPA’s Proposed Proposed NOx Emissions Limit of 0.20 lb/mmbtu is NOx Emissions Limit of 0.20 lb/mmbtu is NOx Emissions Limit of 0.20 lb/mmbtu is Not 

BART 

 

BART for Healy Unit 1 requires the installation and operation of SCR 

and a 0.035 lb/mmbtu limit. SCR technology is the industry standard for 
3 

NOx removal. EPA has found, for example, that BART for NOx is 0.05 

lbs/mmbtu in other determinations. For the San Juan coal-fired Generating 

Station in New Mexico, EPA imposed a 0.05 lbs/mmbtu BART limit. 76 Fed. 

Reg. 52,388, 52,439 (Aug. 22, 2011). The Desert Rock final permit imposed a 

limit of 0.035 lbs/mmbtu,2 and many other facilities are achieving this limit, 

as shown in evidence Sierra Club submitted in comments on the San Juan 

Generating Station.3 Other states have required SCRs in their BART plans.4

 An SCR at Healy would achieve significant emissions reductions and 

visibility improvement at Denali compared with SNCR. According to 

Alaska’s analysis, SNCR with an emissions limit of 0.20 lb/mmbtu will reduce 

119 tons of NOx emissions annually. Alaska did not evaluate the visibility 

improvement resulting from a 0.20 lb/mmbtu emissions limit; however, it will 

be slightly worse than the .19 emissions limit it did evaluate. At 0.19 

lbs/mmbtu, a SNCR will improve visibility by 0.620 dv on 51 days. By 

comparison, a SCR can achieve a 0.035 lb/mmbtu emissions limit, as 

explained above, or at the very least a 0.05 lb/mmbtu emissions limit as EPA 

recently found in the San Juan determination. Neither the state nor EPA, 

however, evaluated the true visibility benefits that could result from an SCR 

at Healy. Instead of using 0.035 or 0.05 lb/mmbtu, EPA considered a 0.07 

lb/mmbtu emissions limit, which it determined would reduce 313 tons of NOx 

every year and improve visibility by 0.786 dv on 71 days. See EPA Memo, 

“Review of ADEC BART Determination Support Document for Golden Valley 

Electric Association (GVEA) – Healy Unit 1 Power Plant” (Dec. 8, 2011) at 5 

(“Dec 8 2011 Memo”)5. In fact, an SCR can achieve much greater reductions 

and visibility benefits. See also National Park Service Comments at 1. 

 Though a NOx emissions limit of 0.19 lb/mmbtu is far too high to be 

BART, EPA did not provide adequate justification for using a 0.20 lb/mmbtu 

emissions limit instead of 0.19 lb/mmbtu. Alaska found that SNCR could 

achieve a 0.19 lb/mmbtu emission limit at Healy, but then allowed a 5% 

higher emission rate for “operating variability.” 77 Fed. Reg. 11034. EPA 

accepted this determination without further analysis. There is no data 

 

2

 PSD permit for Desert Rock (Ex. 1). 

3 See Technical Support Document, NM041.003-2 TSD Attachment 2 - Exhibit 1 - Revised 

Cost Analyses for SCR at the San Juan Generating Station (Jan. 5, 2011). Found on the 

Internet at http://www.regulations.gov/#!documentDetail;D=EPA-R06-OAR-2010-0846-0003. 

See also San Juan Citizens Alliance et al. Comments to EPA on Docket No. EPA-R06-OAR2010-0846 (Apr. 4, 2011). 

4 E.g., South Dakota proposed SIP, 76 Fed. Reg. 76646 (Dec. 8, 2011) (requiring SCR for Big 

Stone coal plant); Wyoming BART Appeal Settlement Agreement, (agreeing to install SCR at 

Jim Bridger plant), http://deq.state.wy.us/eqc/Docket/10-

2801%20PacifiCorp/BART%20Appeal%20Settlement%20Agreement.pdf

5 See Review of ADEC BART Determination Support Document for Golden Valley Electric 

Association (GVEA) – Healy Unit 1 Power Plant” (Dec. 8, 2011). Found on the Internet at 

http://www.regulations.gov/#!documentDetail;D=EPA-R10-OAR-2011-0367-0004. 
4 

showing that this variability necessarily exists, and furthermore, neither 

Alaska nor EPA conducted a visibility analysis based on the 0.19 lb/mmbtu 

emission limit. EPA concluded – without any modeling evidence - that this 

change would not significantly affect visibility impairment at Denali. 

Because it is not justified by sufficient supporting data or modeling analysis, 

EPA’s allowance of a 5% increase for operating variability does not constitute 

BART because it is not based on “the degree of reduction achievable....” See

40 C.F.R. 51.301. 

 

2. EPA Erroneously Reduced the Cost Effectiveness of S EPA Erroneously Reduced the Cost Effectiveness of SCR By 

Shortening Shorteningthe Remaining Useful Life the Remaining Useful Life the Remaining Useful Life of the Control of the Control of the Control 

EPA uses 15 years to estimate the remaining useful life of control 

technologies at Healy – a decision for which the Agency has no acceptable 

rationale. In its BART determination for the San Juan plant, EPA recently 

used a lifetime of 30 years. 76 Fed. Reg. 52388 at 52401-2.6 In fact, the 

expected life of an SCR is well in excess of 30 years. As EPA stated the final 

San Juan rule: “The lifetime of an SCR, which is a metal frame packed with 

catalyst modules, is equal to the lifetime of the boiler, which might easily be 

over 60 years.” Id. Vendor experience lists identify a number of SCR units 

that were installed more than 30 years ago in Japan that are still in service.7 

In the United States, for example, the Chevron Richmond Refinery in 

California has three Mitsubishi SCR systems that have been operating with 

the original catalysts, and without any problems, since 1984. These SCRs 

currently have a demonstrated life of 25 years with expectation for many 

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

conducted by Stephen Unwin, et al. for SCRs installed at the Monroe Power 

Plant outside of Detroit concluded a 30-year life was reasonable.8

EPA offers no plausible basis for its contrary conclusion of a 15-year 

useful life for an SCR (or SNCR) at Healy except the vague reasoning of 

harsh Alaskan climate. Neither EPA nor Alaska provides justification for 

how a cold climate would reduce the useful life of a contained SCR system. 

An SCR is a stationary device with no moving parts, essentially a metal 

 

6 The EPA Cost Manual assumes 20 years as the useful life for both SCR and SCNR in its 

examples, but EPA recently rejected that calculation in its San Juan BART determination. 

EPA Air Pollution Control Cost Manual, EPA/452/B-02-001 (2002), at p. 1-37, 2-48. 

7 McIlvaine Company, Worldwide Utility Plans, NOx Installation and Component Suppliers 

(Ex. 2); Vendor Experience Lists for Hitachi and Mitsubishi. (Exs. 3 & 4). 

8 Unwin, Stephen D., Johnston, Robert W., and Rudy, Steven W. and Delargey, James E. and 

Rogers, William. “Selective Catalytic Reduction (SCR) System Design and Operations: 

Quantitative Risk Analysis of Options,” presented at CCPS 17th Annual International 

Conference: Risk, Reliability, and Security, p. 3. Found on the Internet at http://www.unwinco.com/files%5CSCR-Risk-Paper,CCPS-RRS2002.pdf. 
5 

frame that is filled with blocks of catalyst, so it is not apparent how a cold 

climate would affect its wear. 

EPA’s use of a shorter useful life artificially reduces the cost-effectiveness 

of the control options by reducing the amortization period over which the cost 

of the controls is spread. The shorter life therefore contributes to a less 

stringent and erroneous BART determination for NOx.

Nor can EPA rely on a 15-year life for the Healy plant itself.9 As EPA 

recognizes in the proposed rule, only an enforceable retirement date can be 

considered in a BART determination. As clearly defined by the BART 

guidelines, “the remaining useful life” of a facility is the difference between 

the date controls are installed and the date the facility permanently ends its 

operations.” 70 Fed. Reg. at 39169 (July 6, 2005). The guidelines further 

explain that “this date should be assured by a federally-or State-enforceable 

restriction preventing further operation.” Id. Healy is not subject to any 

enforceable commitment to shutdown in 15 years. “EPA recognizes that the 

2024 shutdown date ...is not enforceable.” 77 Fed. Reg. at 11034. 

3. EPA Did Not Verify Cost Estimates for the Control T EPA Did Not Verify Cost Estimates for the Control Technologies the Control Technologies echnologies 

EPA failed to conduct an adequate review of Alaska’s cost projections for 

SCR technology. EPA relied on Alaska’s submission of a single vendor’s quote 

for the cost of an SCR. See EPA’s Dec 8, 2011 memo at 4. The cost of an SCR 

can vary significantly depending on the vendor and its specifications, and 

EPA did not even review the details in this vendor’s estimate. “Efforts to 

obtain the detailed cost calculations performed using CUECost from the 

State of Alaska and Enviroplan were not successful due to a combination of 

staff turnover, destruction of hard copies (by a fire at Enviroplan’s offices), 

and concerns regarding confidential business information.” Id. at 4. EPA 

cannot reject SCR on cost effectiveness grounds without more sufficient 

factual support. See, e.g., 76 Fed. Reg. 491, 501-2 (Jan. 5, 2011) & TSD 

(EPA’s cost effectiveness analysis of SCR and SNCR at San Juan Generating 

Station).10

Enviroplan’s cost analysis for SCR suffers from other serious flaws. The 

National Park Service points these out in its Comments in this docket on 

 

9 EPA’s use of 15 years is at least an improvement on Alaska’s proposal to use 8 years as the 

remaining useful life at Healy. Alaska used 8 years based on the assumption that Healy 

would retire in 2024. 

10 See Technical Support Document, NM041.003-2 TSD Attachment 2 - Exhibit 1 - Revised 

Cost Analyses for SCR at the San Juan Generating Station (Jan. 5, 2011). Found on the 

Internet at http://www.regulations.gov/#!documentDetail;D=EPA-R06-OAR-2010-0846-0003. 

See also San Juan Citizens Alliance et al. Comments to EPA on Docket No. EPA-R06-OAR2010-0846 (Apr. 4, 2011). 
6 

pages 4-6. The EPA adopted an SCR cost analysis that is contrary to EPA’s 

Control Cost Manual. For example, the flawed analysis used an 8% interest 

rate instead of the 7% rate used in the cost manual and underestimates the 

amount of NOx removal that an SCR can achieve. 

B. EPA Should Impose a EPA Should Impose a Impose aStricter Sulfur Dioxide Stricter Sulfur Dioxide Stricter Sulfur Dioxide Limit 

EPA proposed that the current sulfur dioxide emissions limit of 0.30 

lb/mmbtu is BART. EPA erroneously rejected optimization of the dry sorbent 

injection (DSI) system, which could achieve a 0.18 lb/mmbtu emission limit. 

This lower emissions limit would result in significant reduction in sulfur 

dioxide emissions and greatly improve visibility at Denali. According to EPA, 

optimization of the DSI would result in reduction of 179 tons per year of 

sulfur dioxide and a .250 dv visibility improvement over 39 days. Dec 8, 2011 

Memo at 8. EPA found that DSI optimization is cost-effective, however, it 

rejected this more stringent limit based on its concerns about a “brown 

plume” effect. 77 Fed. Reg. at 11034. 

“Brown Plume” describes the accelerated conversion of NO to NO2, which 

is brown in color, prior to discharge from the stack. There is no 

demonstration that more rapid conversion to NO2 nearer to the source, rather 

than later in the atmosphere, will make any difference to visibility in Denali 

National Park. EPA stated its agreement with Alaska that “frequency of 

brown plume events and impacts to visibility at Denali National Park is not 

possible to predict precisely, although there is anecdotal evidence that such 

events occur at a small minority of facilities that utilize DSI for SO2 control.” 

Dec 8, 2011 Memo at 11. It is improper for EPA to dismiss this control 

possibility based on anecdotal evidence, which is not even linked to plantspecific characteristics present at Healy. See 40 C.F.R. § 51.301. 

C. EPA Must Consider Emissions from Healy Unit 2 in Alaska’s 

Reasonable Progress Analysis Reasonable Progress Analysis 

Alaska’s Long-Term Strategy (“LTS”) fails to satisfy obligations under the 

Regional Haze Rule toward achieving natural visibility conditions at Denali. 

The Clean Air Act requires states to submit implementation plans that 

“contain such emission limits, schedules of compliance and other measures as 

may be necessary to make reasonable progress toward meeting the national 

goal” of achieving natural visibility conditions at all Class I Areas. 42 U.S.C. 

§ 7491(a)(1), (b)(2); 40 C.F.R. § 51.308(d)(3). These implementation plans 

must contain a LTS for making reasonable progress toward the national 

visibility goal. 40 C.F.R. § 51.308(d)(3). The LTS is a crucial mechanism for 

preventing and remedying existing visibility impairment in Class I Areas by 

2064. 
7 

In order to complete a proper assessment, inter alia, a state must identify 

all human-caused sources of visibility impairment, including major and 

minor stationary sources, mobile sources, and area sources. 40 C.F.R. § 

51.308(d)(3)(iv). Alaska’s plan does not fulfill this requirement because it 

does not include emissions from Healy unit #2. 77 Fed. Reg. at 11036. The 

National Park Service commented that it is “very concerned” about the 

exclusion of Unit 2 emissions from Alaska’s plan. 

Healy Unit 2 will have a significant impact on visibility at Denali. Healy 

Unit 2 is a 50 MW coal-fired boiler that has higher emissions limits than Unit 

1, and it is twice the size. Healy Unit 2 will emit substantial amounts of 

nitrogen oxide and sulfur dioxide emissions that will cause greater visibility 

impairment at Denali than Unit 1. EPA and Alaska even recognized that 

“emissions from Healy 2 could have an impact on visibility in Denali.” 77 Fed. 

Reg. at 11036. Alaska noted in its submission to EPA that if the Unit 2 

emissions had been included in its analysis, SO2 and NOx emissions from the 

Denali sector would be 2.8 and 4.0 times greater, respectively, than what was 

ultimately presented. See National Park Service Comments. 

EPA attempts to justify the exclusion of Healy Unit 2 by explaining that 

the unit has not operated for a number of years. This reasoning fails, 

however, because Alaska recently issued Healy a Title V permit in order to 

allow the unit to restart. Alaska’s promise to reassess Healy Unit 2 emissions 

if or when the unit begins operating again is insufficient. Healy’s emissions 

must be considered as part of this regional haze action. 

 

By failing to accurately account for emissions from Healy Unit 2, Alaska’s 

plan does meet the requirements of the Clean Air Act or ensure reasonable 

progress toward achieving the elimination of regional haze in Alaska. 

In sum, we urge EPA to reconsider its proposed BART determinations for 

sulfur dioxide and nitrogen oxide emissions from Healy unit 1, as well as its 

failure to include emissions from Healy Unit 2 in its reasonable progress 

goals and long term strategy. Do not hesitate to contact me if you have any 

questions or concerns, at (415) 977-5544, or andrea.issod@sierraclub.org. 
8 

 Sincerely, 

 

 Andrea Issod, staff attorney 

 Sierra Club 

 85 Second St, Second Floor 

 San Francisco, CA 94105 

 415-977-5544 

 andrea.issod@sierraclub.org 

Emily Fehrenbacher 

Sierra Club 

750 W 2nd Ave, Suite 100 

Anchorage, AK 99501 

(907)276-4060

emily.fehrenbacher@sierraclub.org 

Stephanie Kodish, Clean Air Counsel 

National Parks Conservation Association 

W: 865-329-2424 

C: 865-964-1774 

F: 865-329-2422 

skodish@npca.org

Joan Frankevich 

Program Manager, Alaska Region 

National Parks Conservation Association 

750 W. 2nd Ave. Suite 205 

Anchorage, Alaska 99501 

(907) 344-4544

Bob Shavelson 

Cook Inletkeeper 

P.O. Box 3269 

3734 Ben Walters Lane 

Homer, AK 99603 

p. 907.235.4068 x22

c. 907.299.3277

f. 907.235.4069

skype: Inletkeeper 

bob@inletkeeper.org
9 

Karen Max Kelly, Executive Director 

Northern Alaska Environmental Center 

830 College Road 

Fairbanks, Alaska 99701 

(907) 452-5021

Pamela K. Miller, Executive Director 

Alaska Community Action on Toxics 

505 West Northern Lights Boulevard, Suite 205 

Anchorage, Alaska 99503 

Phone (907) 222-7714; Fax (907) 222-7715 

www.akaction.org 
UNITED STATES E:NVIRONMENTAL PROTECTION AGENCY 

REGION IX 

7!; Hawthorne Street 

San Fl'ancisco, CA 94105-3901 

Dirk Straussfeld 

Desert Rock Energy Company, LLC 

Three Riverway, Suite 1100 

Houston, TX 77056 

Dear Mr. Straussfeld: 

July 31,2008 

In accordance with the provisions of the Clean Air Act, as amended (42 U.S.C. 7401 et 

seq.), the Environmental Protection Agency has reviewed the application for the 

proposed Desert Rock Energy Facility,. located on Navajo Nation tribal land 

approximately 25 miles southwest of Farmington, NM. 

A request for public comment regarding EPA's proposed action on the above application 

was published on July 27,2006. During the public comment period, EPA received a 

substantial number of comments. Enclosed is a copy of our responses to those 

comments. The attachments cited in the responses to comments are available 

electronically on our website and are not included in hard copy with this letter because 

they are voluminous. After consideration of the expressed view of all interested persons, 

the pertinent federal statues and regulations, and additional material relevant to the 

application and contained in our Administrative Record, EPA hereby issues the enclosed 

Prevention of Significant Deterioration (PSD) Permit for the facility described above. 

The Administrative Record for this pe:rmit is available online at 

http://www.epa.gov/region09/air/permit/desertrock/index.html. 

Within 30 days after the service of notice ofthe permit decision (which is the date of this 

letter), any person who filed comments on the proposed permit or participated in the 

public hearings may petition the Environmental Appeals Board (EAB) to review any 

condition of the final permit. The petition must include a statement of the reasons for 

requesting review by the EAB including a demonstration that any issues being raised 

were raised during the public comment period and, when appropriate, a showing that the 

conditions in question are based on 1) a finding of fact or conclusion of law which is 

erroneous, or 2) an exercise of discretion or an important policy consideration which the 

EAB should, in its discretion, review. All petitions must be sent to the EAB at one of the 

following addresses, based on the method of delivery. Please see 40 CFR 124.19 and 

visit http://www.epa.gov/eab/ for more information regarding the procedure for appeal to 

the EAB. 

Printed on Recvc/ed Paper 
·-----~---· 

Mt r-~~----~--------~--~---- AII documents that are sent through the U.S. P 

Service (except by Express Mail) 

~~~~----~~--~--------~"~d( U.S. Environmental Protection Agency 

Clerk of the Board, Environmental Appeal~; Be 

(MC I I 038) 

Ariel Rios Building 

1200 Pennsylvania Avenue, N.W. 

Washington, D.C. 20460-0001 

~thod of Delivery 

ostal Documents that are hand-carried in person, 

delivered via courier, mailed by Express Mail, or 

delivered by anon-U.S. Postal Service carrier (e.g., 

Federal Express or UPS) 

lress for Petitions 

U.S. Environmental Protection Agency 

1ard Clerk of the Board, Environmental Appeals Board 

Colorado Building 

1341 G Street, N.W., Suite 600 

Washington, D.C. 20005 

This PSD permit shall take effect thirty (30) days from the date of service of notice unless 

a petition for appeal is properly and timely filed with the EAB. In the event a petition for 

review is filed, construction of the facility can not begin until resolution of the EAB 

petitions. 

If you have any questions regarding this matter, please contact Gerardo C. Rios of our 

Permits Office at (415) 972-3974. 

Sincerely, 

Director, 

!l~ Air Division 

Enclosures ( 4) 

I 
PREVENTION OF SIGNlFICANT DETERIORATION PERMIT 

ISSUED lflURSUANT TO THE 

REQUIREMENTS AT 40 CFR § 52.21 

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION 9 

PSD PERMIT NUMEER: AZP 04-01 

PERMITTEE: Desert Rock Energy Comp;my, LLC 

(a subsidiary of Sithe Global Power, 

LLC) 

Three Riverway, Suite 11 01) 

Houston, TX 77056 

FACILITY LOCATION: Approximately 25 miles southwest 

of Farmington, New Mexico in the 

Navajo Indian Reservation. 

This permit is issued pursuant to the Prevention of Significant Deterioration (PSD) requirements 

of the Clean Air Act, as amended, 42 U.S.C. §§ 7401 - 7671, et seq. The D(:sert Rock Energy 

Company, LLC is granted this PSD permit as described herein, in accordance with the permit 

application, federal regulations governing the Prevention of Significant Deterioration of Air 

Quality ( 40 CFR § 52.21 ), and other term~: and conditions set forth in the pe ·mit. 

Failure to comply with any condition or term set forth in this PSD permit is mbject to 

enforcement action pursuant to Section 113 of the Clean Air Act. 

This PSD permit does not relieve the Permittee from the responsibility to comply w[th any other 

applicable provisions of the Clean Air Act and other federal requirements. 

This permit shall become effective 30 days after the service of notice of the :inal permit decision 

unless review ofthe permit is requested under 40 CFR 124.19. Notice ofth1~ final permit 

decision is served on the date below. 

July 31, 2008 

Date 

Director, Air Division 

- 1 -
 - 2 - 

DESERT ROCK ENERGY FACILITY (AZP 04-01)

PERMIT CONDITIONS 

I. Permit Expiration 

This permit shall become invalid if: 1) construction is not commenced (as defined in 40 

CFR 52.21(b)(9)) within 18 months after the approval takes effect, or 2) construction is 

discontinued for a period of 18 months or more, or 3) construction is not completed 

within a reasonable time. 

II. Commencement of Construction and Startup 

A. Construction under this permit may not commence until EPA notifies the 

Permittee that it has satisfied any consultation obligations under Section 7(a)(2) 

of the Endangered Species Act with respect to the issuance of the permit. EPA 

shall have the power to reopen and amend the permit, or request that the Permittee 

amend its permit application, to address any alternatives, conservation measures, 

reasonable and prudent measures, or terms and conditions deemed by EPA to be 

appropriate as a result of the ESA consultation process. 

B. The Permittee must notify EPA in writing of: 1) the anticipated date of initial 

startup of the Desert Rock Energy Facility not more than sixty (60) days nor less 

than thirty (30) days prior to such date, and 2) the actual date of commencement 

of construction and initial startup within fifteen (15) days after each has occurred. 

 For all purposes of this permit, ‘construction’ includes, but is not limited to, 

activities such as refractory curing, steam generator boilout, and steam blowing; 

and >initial startup= shall mean the setting in operation of an affected facility for 

the first time after construction for any purpose. >Affected facility= is further 

defined as any apparatus, equipment, or emission unit subject to a standard in this 

permit or in the applicable Performance for New Stationary Sources regulations 

found at 40 CFR 60 Subparts A and Da. 

III. Facility Operation 

All equipment, facilities, and systems installed or used to achieve compliance with the 

terms and conditions of this permit must at all times be maintained in good working order 

and be operated as intended so as to minimize air pollutant emissions. 

IV. Malfunction Reporting 

The Permittee must notify EPA by telephone, facsimile, or electronic mail transmission 

within two working days following the discovery of 1) failure of any continuous 

emissions monitoring system to operate in a normal manner, and 2) any failure of air 

pollution control equipment, process equipment, or of a process to operate in a normal 

manner, which results in an increase in emissions above any allowable emission limit 
 - 3 - 

stated in Section IX this permit. In addition, the Permittee must notify EPA in writing 

within fifteen (15) days of any such failure. The notification shall include a description 

of the malfunctioning equipment or abnormal operation, the date of the initial 

malfunction, the period of time over which emissions were increased due to the failure, 

the cause of the failure, the estimated resultant emissions in excess of those allowed in 

Section IX, and the methods utilized to mitigate emissions and restore normal operations. 

 Compliance with this malfunction notification provision shall not excuse or otherwise 

constitute a defense to any violation of this permit or of any law or regulation that such 

malfunction may cause.

V. Right of Entry 

The EPA Regional Administrator, and/or his authorized representative, upon the 

presentation of credentials, must be permitted: 

A. to enter the premises where the source is located or where any records are 

required to be kept under the terms and conditions of this permit; 

B. at reasonable times to have access to and copy any records required to be kept 

under the terms and conditions of this permit; 

C. to inspect any equipment, operation, or method required in this permit; and 

D. to sample emissions from the source(s). 

VI. Transfer of Ownership 

In the event of any changes in control or ownership of the facilities to be constructed, the 

permit must be binding on all subsequent owners and operators. The Permittee must 

notify the succeeding owner and operator of the existence of this permit and its 

conditions by letter, a copy of which must be forwarded to the EPA. 

VII. Severability 

The provisions of this permit are severable, and, if any provision of the permit is held 

invalid, the remainder of this permit shall be unaffected. 

VIII. Other Applicable Regulations

The Permittee must construct and operate the proposed power plant in compliance with 

all other applicable provisions of 40 CFR Parts 51, 52, 60, 63, 72 through 75, and all 

other applicable federal, state, and local air quality regulations. 
 - 4 - 

IX. Special Conditions 

A. Certification 

The Permittee must notify the EPA in writing of compliance with Conditions 

IX.B.2 and IX.Q below, and must make such notification within fifteen (15) days 

of such compliance. The letter must be signed by a responsible official of the 

Permittee. 

B. Emission Units and Air Pollution Control Measures and Equipment 

1. The following emission units are subject to one or more conditions or 

requirements in this permit: 

Quantity Description 

2 Pulverized coal-fired supercritical boiler; 6,810 MMBtu/hr 

maximum heat input (“PC boiler”); with steam turbine generator 

and associated systems 

3 Fuel-oil fired auxiliary boiler; 86.4 MMBtu/hr 

2 Emergency generator; diesel-fuelled; 1,000 kW 

2 Emergency fire pump; diesel-fuelled; 284 hp 

1 1.1 million gallon storage tank, storing ultra-low sulfur diesel 

fuel for use in the emergency generators and emergency fire 

pumps 

Multiple Coal, limestone, lime, and ash handling equipment consisting of 

various conveyors, transfer houses, bunkers, silos, and a passive 

coal storage pile 

2. On or before the date of initial startup of the power plant (as defined in 

Condition II of this permit), and thereafter, the Permittee shall install, 

continuously operate, and maintain the following controls: 

a. Low NOx burners and a selective catalytic reduction (SCR) system for the 

control of NOx emissions from the PC boilers. During startup and 

shutdown events, the SCR system shall be operated in accordance with 

good engineering practice and the manufacturer’s recommendations for 

minimizing NOx and ammonia emissions to the extent practicable. 

b. Hydrated lime injection and wet limestone desulfurization for the control 

of SO2, H2SO4, and HF emissions from the PC boilers. 

c. A baghouse for the control of PM and PM10 emissions from the PC 

boilers. 
 - 5 - 

d. Enclosures, and fabric filters for the control of PM and PM10 emissions 

from the coal, limestone, and lime handling systems. 

e. Measures for the inactive coal storage pile including the use of a soil 

covering or other crusting agents when it is not in use, and wetting or 

other chemical agents when coal is added to the pile or removed from it. 

The Permittee shall apply these methods sufficiently to prevent fugitive 

dust emissions. 

3. Prior to commencement of construction the Permittee shall pave or have 

caused the paving of all public and private roads used to access the facility at 

least within a 1.5 mile radius of the facility. The 1.5 mile radius shall be 

calculated from all points along the fence line of the property on which the 

facility is located. 

C. Performance Tests

1. Within 60 days after achieving the base load, but no later than 180 days after 

initial startup, the Permittee must conduct performance tests (as described in 

40 CFR 60.8) for SO2, NOx, CO, VOC, PM, PM10, H2SO4, HF and Pb on the 

exhaust stack gases from the PC boilers and for NOx, CO, VOC, PM, and 

PM10 on the exhaust stack gases from the auxiliary boilers. The Permittee 

shall repeat the aforementioned tests on an annual basis (within 30 days of the 

initial performance test) for emissions of VOC, PM10, H2SO4, HF, and Pb 

from the PC boilers. The Permittee must furnish the EPA with a written 

report of the results of all tests within 30 days of completion of each test. 

After the initial performance tests, upon written request from the Permittee, 

and adequate justification, EPA may waive a specific annual test and/or allow 

for testing to be done at less than maximum operating capacity. For emissions 

of SO2, NOx, CO, and PM from the PC boilers, the Permittee must install and 

operate continuous emissions monitoring systems as specified in Section 

IX.Q. 

2. The performance tests required by Section IX.C.1 must be performed in 

accordance with the test methods set forth in 40 CFR 60.8 and 40 CFR 60, 

Appendix A, unless otherwise noted or as modified below. The following test 

methods must be used: 

a. Performance tests for the emissions of SO2 shall be conducted using EPA 

Methods 1 through 4 and 6C. These methods shall also be used to conduct 

the Relative Accuracy Test Audits of the SO2 CEMS. 

b. Performance tests for the emissions of NOx shall be conducted using EPA 

Methods 1 through 4 and 7E. These methods shall also be used to conduct 

the Relative Accuracy Test Audits of the NOx CEMS. 
 - 6 - 

c. Performance tests for the emissions of CO shall be conducted using EPA 

Methods 1 through 4 and 10. These methods shall also be used to conduct 

the Relative Accuracy Test Audits of the CO CEMS. 

d. Performance tests for the emissions of VOC shall be conducted using EPA 

Methods 1 through 4 and 25A. 

e. Performance tests for the emissions of PM shall be conducted using EPA 

Methods 1 through 4 and Method 5I. These methods shall also be used to 

conduct the Relative Accuracy Test Audits of the PM CEMS. 

f. Performance tests for the emissions of PM10 shall be conducted using EPA 

Method 5I and Method 202 (40 CFR Part 51, Appendix M). When 

employing Method 202, the following procedures shall be used: 

i. a one hour nitrogen purge is required, 

ii. the alternative procedure described in Method 202, paragraph 8.1 to 

neutralize the sulfuric acid is required, and 

iii. the evaporation of the last 1 ml of the inorganic fraction by air drying 

following evaporation of the bulk of the impinger water in a 105 

degrees C oven as described in the first sentence of Method 202, 

section 5.3.2.3 is required. 

g. Performance tests for the emissions of H2SO4 shall be conducted using 

EPA Methods 1 through 4 and CTM-13B 

(http://www.epa.gov/ttn/emc/ctm/ctm013B.pdf). 

h. Performance tests for the emissions of hydrogen fluoride shall be 

conducted using EPA Methods 1 through 4 and 26. 

i. Performance tests for the emissions of lead shall be conducted using EPA 

Methods 1 through 4 and 12. 

j. Performance tests for the determination of the opacity of emissions shall 

be conducted using EPA Method 9. 

3. In lieu of the above-mentioned test methods, the Permittee may use equivalent 

methods with prior written approval from EPA. 

 The Permittee must notify EPA in writing at least 30 days prior to all tests to 

allow time for the development of an approvable performance test plan and to 

arrange for an observer to be present at the tests. The performance test plans 
 - 7 - 

shall address the conditions specified in IX.C.2, above. 

4. For performance test purposes, sampling ports, platforms, and access must be 

provided by the Permittee on the emission unit exhaust system in accordance 

with 40 CFR 60.8(e). 

D. Emission Limits and Conditions for SO2

1. On or after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of SO2 into the atmosphere from each PC boiler in excess 

of the following amounts: 

 a. 612 lb/hr, averaged over a 3-hour block period. 

 b. 0.060 lb/MMBtu, averaged over a 24-hour block period. 

 c. 378.5 lb/hr, averaged over a rolling 365-day period. 

2. The Permittee shall demonstrate initial compliance with the limits of 

Condition IX.D.1.a and IX.D.1.b by conducting an initial performance test in 

accordance with Condition IX.C. Continuous compliance with all limits of 

Condition IX.D.1 shall be demonstrated by continuously monitoring 

emissions using continuous emission monitors installed and operated pursuant 

to Condition IX.Q. 

3. The Permittee shall comply with the terms and conditions under the “Sulfur 

Dioxide Mitigation” section in Exhibit A of the Memorandum of 

Understanding between the Navajo Nation Environmental Protection Agency 

and Desert Rock Energy Company, LLC, to develop an enforceable Voluntary 

Emission Reduction Plan. 

E. Emission Limits and Conditions for NOx (calculated as NO2)

1. The 60-month period beginning with initial startup shall be considered the 

“NOx Optimization Period.” 

2. Prior to commencement of construction, the Permittee shall submit the 

following information to EPA: 

a. Design specifications from the boiler and SCR system vendors, which 

indicate that the boilers and SCR systems were designed to achieve a NOx 

emission rate of 0.035 lb/MMBtu on a rolling 365-day average. The 

specifications shall identify the parameters and conditions used for 

catalyst design such as: 

• Plant performance factors (e.g., fuel type and ash characteristics, 
 - 8 - 

combustion type, boiler performance, air heater design, particulate 

collection devices, and SCR soot blowers), 

• Operating conditions (e.g., plant load factor, flue gas flow rate, 

inlet NOx levels, temperature, and the impact of O2 and water 

content on catalytic potential), and 

• System scale-up factors (e.g., non-ideal flow distribution, 

temperature distribution, ammonia-to-NOx molar ratio 

distribution, and catalyst blockage). 

b. An SCR catalyst management plan which sets forth measures that will be 

taken to maintain the system and optimize its performance. Such 

measures shall include, but not be limited to: 

• Periodic SCR system evaluations and physical inspections of the 

catalyst, reactor, and ammonia injection system; 

• The collection of performance and operational data such as inlet 

NOx levels, removal efficiency, ammonia-in-ash levels, number of 

system starts/stops, operational load range, total hours, fuel data, 

and ash data; and 

• Periodic testing of catalyst samples to assess catalyst activity and 

measure it against design deactivation rates. Such tests may 

include a catalyst activity test to determine the catalyst activity 

under specific plant conditions, a physical properties test to 

evaluate the physical properties such as catalyst surface area and 

porosity, and a chemical composition test to evaluate the impact of 

coal and ash properties on catalyst design and performance. 

 The maintenance plan shall also specify the records that will be 

maintained so EPA can determine whether the measures in the plan are 

being followed and whether the plant’s operating parameters and 

conditions are consistent with the catalyst design conditions. 

3. During the NOx Optimization Period, the Permittee shall not discharge or 

cause the discharge of NOx from each PC boiler into the atmosphere in excess 

of the following amounts: 

 a. 408 lb/hr, averaged over a 24-hour block period 

b. 0.060 lb/MMBtu, averaged over a 24-hour block period 

c. 0.05 lb/MMBtu, averaged over a rolling 365-day period 

d. 378.5 lb/hr, averaged over a rolling 365-day period 

The Permittee shall demonstrate initial compliance with the limits of 

Condition IX.E.3.a and IX.e.3.b by conducting an initial performance test in 
 - 9 - 

accordance with Condition IX.C. Continuous compliance with all limits of 

Condition IX.E.3 shall be demonstrated by continuously monitoring emissions 

using continuous emission monitors installed and operated pursuant to 

Condition IX.Q. 

4. Following the NOx Optimization Period, the Permittee shall not discharge or 

cause the discharge of NOx from each PC boiler into the atmosphere in excess 

of the following amounts except as specified in Condition IX.E.5: 

a. 0.060 lb/MMBtu, averaged over a 24-hour block period 

b. 0.05 lb/MMBtu, averaged over a rolling 30-day period 

c. 340.5 lb/hr, averaged over a rolling 30-day period 

d. 0.0385 lb/MMBtu, averaged over a rolling 365-day period 

e. 262.1 lb/hr, averaged over a rolling 365-day period. 

The Permittee shall demonstrate continuous compliance with the limits of 

Condition IX.E.4 by continuously monitoring emissions using continuous 

emission monitors installed and operated pursuant to Condition IX.Q. 

5. If, during the NOx Optimization Period, the Permittee determines that any of 

the NOx limits in Condition IX.E.4 are not feasible, the Permittee shall submit 

an application to EPA for an adjustment of those limits. 

a. The application shall, at a minimum, contain the following information: 

i. All validated CEMS data collected during the NOx Optimization 

Period for NOx emissions from each PC boiler. The CEMS data shall 

be recorded and reported in the units of lb/MMBtu on an hourly 

average 

ii. All records specified in the catalyst management plan 

iii. A report containing an analysis of: 

1. The extent to which the initial catalyst design conditions 

(identified in Condition IX.E.2.a) differ from actual operating 

parameters and conditions during the NOx Optimization Period, 

2. The impact any differences identified pursuant to the paragraph 

above have on the ability to comply with the NOx emission limits 

of Condition IX.E.4, and 
 - 10 - 

3. Actions taken to mitigate the impacts identified pursuant to the 

paragraph above. 

b. If, after the applicable review process following such a submission, it is 

demonstrated through data and information gathered during the NOx 

Optimization Period that a different NOx limit is necessary, the limits in 

Condition IX.E.4 shall be adjusted accordingly. 

 

c. If the application specified in this condition is postmarked prior to the end 

of the NOx Optimization Period, the emission limits in Condition IX.E.3 

shall remain in effect until EPA evaluates the application and makes a 

final decision regarding the adjustment to the limits in Condition IX.E.4. 

F. Emission Limits for CO

1. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of CO from each PC boiler into the atmosphere in excess 

of the following amounts: 

 a. 680 lb/hr, averaged over a 24-hour block period. 

 b. 0.10 lb/MMBtu, averaged over a 24-hour block period. 

 c. 631 lb/hr, averaged over a rolling 365-day period. 

2. The Permittee shall demonstrate initial compliance with the limits of 

Condition IX.F.1.a and IX.F.1.b by conducting an initial performance test in 

accordance with Condition IX.C. Continuous compliance with all limits of 

Condition IX.F.1 shall be demonstrated by continuously monitoring emissions 

using continuous emission monitors installed and operated pursuant to 

Condition IX.Q. 

G. Emission Limits for VOC 

1. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of VOC from each PC boiler into the atmosphere in 

excess of the following amounts: 

a. 20.4 lb/hr, averaged over a 3-hour block period. 

b. 0.0030 lb/MMBtu averaged over a 3-hour block period. 

 2. The Permittee shall demonstrate compliance with the limits of Condition 

IX.G.1 by conducting initial and annual performance tests in accordance with 
 - 11 - 

Condition IX.C. The performance tests shall consist of three 1-hour test runs. 

 3. Prior to initial startup of the facility, the Permittee shall submit to EPA a 

report that analyses the use of potential surrogate parameters (such as 

measured CO emissions) as an indicator of VOC emissions control. 

Following initial startup of the facility, the Permittee shall develop, through 

source testing, relationships between a measured CO emissions indicator level 

or other selected surrogate parameters and compliance with the VOC 

emissions limits. Within one year after initial startup, the Permittee shall 

submit a permit application to EPA to incorporate the established 

relationship(s) into this permit. 

H. Emission Limits for PM

1. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of PM from each PC boiler into the atmosphere in excess 

of the following amounts: 

 a. 66.4 lb/hr, averaged over a 24-hour block period. 

 b. 0.010 lb/MMBtu, averaged over a 24-hour block period. 

 2. The Permittee shall demonstrate initial compliance with the emission limits of 

Condition IX.H.1 by conducting an initial performance test in accordance 

with Condition IX.C. Continuous compliance with the limits of Condition 

IX.H.1 shall be demonstrated by using the continuous monitors installed and 

operated pursuant to Condition IX.Q of this permit. 

I. Emission Limits and Conditions for Total PM10

1. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of total PM10 from each PC boiler into the atmosphere in 

excess of the following amounts: 

 a. 132.8 lb/hr, averaged over a 3-hour block period. 

 b. 0.020 lb/MMBtu, averaged over a 3-hour block period. 

2. The Permittee shall demonstrate compliance with the emission limits of 

Condition IX.I.1 by conducting initial and annual performance tests in 

accordance with Condition IX.C. The performance tests shall consist of three 

1-hour test runs. 

3. At the end of an 18-month period immediately following initial startup, the 

Permittee may submit to EPA the performance testing data collected in this 
 - 12 - 

period for total PM10 for each PC boiler. The performance testing data shall 

be in raw and reduced or summarized form. If EPA determines from the 

performance testing data that the PC boilers and associated control devices 

have not achieved PM10 emissions lower than the limits prescribed in X.I., 

EPA may revise these conditions to reflect the equipment and control devices=

performance. 

J. Emission Limits and Conditions for Opacity

1. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge into the atmosphere from the PC boiler exhaust stack 

gases which exhibit opacity of 10% or greater averaged over any six minute 

period. The Permittee shall conduct monthly opacity readings using EPA 

Method 9 by a person certified to conduct Method 9. Emissions with opacity 

greater than 10% averaged over any six minute period shall be reported in 

accordance with Condition IX.R. 

2. On or after the date of initial startup, the Permittee shall not discharge or 

cause the discharge into the atmosphere from any coal, limestone or lime 

handling system gasses, which exhibit opacity of 10% or greater averaged 

over any six minute period. 

 3. For all baghouses and fabric filters that control emissions from the coal, 

limestone, or lime handling equipment, the Permittee shall take the following 

minimum measures to ensure their proper operation and maintenance: 

 a. On a weekly basis, conduct an inspection for visible emissions. If any 

visible emissions are observed, the Permittee shall conduct an opacity 

reading within 24 hours of such observation using EPA Method 9 by a 

person certified to conduct Method 9. If the emissions observed during 

the Method 9 test have opacity greater than 10% averaged over any six 

minute period, the Permittee shall 1) report the exceedance in accordance 

with Condition IV, and 2) inspect the bags/filters for holes, tears, leaks, 

wear, and other defects. If any defects are detected, the appropriate 

measures for remediation shall commence within 8 hours. A description 

of the corrective action shall be included in the malfunction report 

submitted in accordance with Condition IV. 

 b. On a quarterly basis, inspect the bags/filters for holes, tears, leaks, wear, 

and other defects. If any defects are detected, the appropriate measures 

for remediation shall commence within 8 hours. For each model of 

bag/filter used by the baghouses/fabric filters, one spare bag/filter shall be 

kept at all times on the premises where the source is located. The 

Permittee shall maintain a written record of the inspection and any action 

resulting from the inspection. Bag/fabric filter replacement shall be 
 - 13 - 

documented by identifying the date and time of the replacement and the 

location of the bag/fabric filter in relationship to the other bags/fabric 

filters. The location shall be identified on an overhead drawing of the 

bag/fabric filter layout in the device. 

c. On a semi-annual basis, inspect all structural components, housing, ducts, 

and hoods. If leaks or abnormal conditions are detected the appropriate 

measures for remediation shall commence within 8 hours. The Permittee 

shall maintain a written record of the inspection and any action resulting 

from the inspection. 

K. Emission Limits for H2SO4

1. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of H2SO4 from each PC boiler into the atmosphere in 

excess of the following amounts: 

 a. 26.6 lb/hr, averaged over a 3-hour block period. 

 b. 0.0040 lb/MMBtu, averaged over a 3-hour block period. 

 2. The Permittee shall demonstrate compliance with the limits of Condition 

IX.K.1 by conducting initial and annual performance tests in accordance with 

Condition IX.C. The performance tests shall consist of three 1-hour test runs. 

 3. Prior to initial startup of the facility, the Permittee shall submit to EPA a 

report that analyses the use of potential surrogate parameters (such as 

measured SO2 emissions) as an indicator of H2SO4 control. Following initial 

startup of the facility, the Permittee shall develop, through source testing, 

relationships between a measured SO2 emissions indicator level or other 

selected surrogate parameters and compliance with the H2SO4 emissions 

limits. Within one year after initial startup, the Permittee shall submit a 

permit application to EPA to incorporate the established relationship(s) into 

this permit. 

L. Emission Limits for Lead 

1. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of lead from each PC boiler into the atmosphere in excess 

of the more stringent of 1.33 lb/hr or 0.00020 lb/MMBtu, averaged over a 3-

hour block period. 

 2. The Permittee shall demonstrate compliance with the limits of Condition 

IX.L.1 by: 
 - 14 - 

 a. Conducting initial and annual performance tests in accordance with 

Condition IX.C. The performance tests shall consist of three 1-hour test 

runs. 

 b. Determining the lead and heat content of the coal consumed by the PC 

boilers by sampling the coal on a weekly basis using ASTM methods 3683 

and D3172, respectively. The Permittee shall keep a record of this 

analysis on site and utilize the results with the most recent performance 

testing data to determine the lead emissions during the week for which the 

coal sample was taken. 

M. Emission Limits for Fluorides (as Hydrogen Fluoride) 

1. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of hydrogen fluoride from each PC boiler into the 

atmosphere unless those discharges: 1) are reduced by 98% as measured at the 

outlet of each PC boiler prior to control, and prior to discharge through the 

stack after all control measures, or 2) do not exceed the more stringent of 1.6 

lb/hr or 0.00024 lb/MMBtu, averaged over a 3-hour block period. 

 2. The Permittee shall demonstrate compliance with the limits of Condition 

IX.M.1 by: 

 a. Conducting initial and annual performance tests in accordance with 

Condition IX.C. The performance tests shall consist of three 1-hour test 

runs. 

 b. Determining the fluoride and heat content of the coal consumed by the PC 

boilers by sampling the coal on a weekly basis using ASTM methods 

D3761 and D3172, respectively. The Permittee shall keep a record of this 

analysis on site and utilize the results with the most recent performance 

testing data to determine the hydrogen fluoride emissions during the week 

for which the coal sample was taken. 

N. Treatment of Emissions During Startup and Shutdown Events 

1. For the purposes of this section, a “startup event” shall be defined as the 

setting in operation of either of the PC boilers for any purpose after initial 

startup, beginning with ignition of the boiler, and ending when the flow of 

fuel oil to the auxiliary boilers has ceased or after 6.5 hours, whichever comes 

first. A startup event may last for longer than 6.5 hours if necessary to avoid 

equipment damage or unsafe operation in the event of a failed or faulty startup 

sequence. 

2. For the purposes of this section, a “shutdown event” shall be defined as the 
 - 15 - 

cessation of operation of either of the PC boilers for any purpose after initial 

startup, beginning with the lowering of the boiler from minimum load and 

curtailment of the fuel supply to the boiler, and ending after fuel flow to the 

boiler has ceased. A shutdown event shall not last longer than 5 hours. 

3. Emissions from the PC boilers during startup and shutdown events shall not 

be subject to the emission limits in this permit which are specified in units of 

lb/MMBtu but shall be subject to all other limits and shall be included in the 

calculations of emission rates for demonstrating compliance with those limits. 

4. The Permittee must operate the CEMS during startup and shutdown events. 

5. The Permittee must record the time, date and duration of each startup and 

shutdown event. The records must include calculations of emissions during 

each event based on the CEMS data. For startup events lasting longer than 

6.5 hours due to a failed or faulty startup sequence, the records shall specify 

the cause of the fault or failure and the measures that will be taken to prevent 

such faults or failures in the future. These records must be kept for five years 

following the date of such event. 

O. Auxiliary Boilers

1. The Permittee shall restrict fuel use for the operation of the auxiliary boilers 

to fuel oil with a sulfur content of no more than 0.0015% by weight. 

 2. The Permittee shall restrict operation of the auxiliary boilers to no more than 

142,560 MMBtu/year on a combined basis. A log reporting the date, time, 

and duration of the boilers= operation shall be maintained. This log must be 

kept for five years. 

3. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of SO2 from each of the auxiliary boilers into the 

atmosphere in excess of 0.14 lb/hr, averaged over 3-hour period, as calculated 

from the fuel sulfur content and heat input to the boilers. 

4. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of NOx from each of the auxiliary boilers into the 

atmosphere in excess of 8.64 lb/hr, based on the average of three one-hour 

source test runs. 

5. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of CO from each of the auxiliary boilers into the 

atmosphere in excess of 3.09 lb/hr, based on the average of three one-hour 

source test runs. 
 - 16 - 

6. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of VOC from each of the auxiliary boilers into the 

atmosphere in excess of 0.21 lb/hr, based on the average of three one-hour 

source test runs. 

7. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of PM from each of the auxiliary boilers into the 

atmosphere in excess of 1.23 lb/hr, based on the average of three one-hour 

source test runs. 

8. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of PM10 from each of the auxiliary boilers into the 

atmosphere in excess of 2.04 lb/hr, based on the average of three one-hour 

source test runs. 

9. On and after the date of initial startup, the Permittee shall not discharge or 

cause the discharge of H2SO4 from each of the auxiliary boilers into the 

atmosphere in excess of 0.003 lb/hr, as calculated from the fuel sulfur content 

and heat input to the boilers. 

P. 1000-kW Emergency Backup Generators and 180 kW Fire pumps 

1. The Permittee shall restrict fuel use for the emergency backup generators and 

the fire pump engines to diesel fuel with a maximum sulfur content of 

0.0015% by weight. 

2. The emergency backup generators shall be certified by the engine 

manufacturer to comply with the Tier 2 emission standards specified in 40 

CFR 94.8. 

3. The emergency fire pump engines shall be certified by the engine 

manufacturer to comply with the following emission standards: 

Pollutant Standard 

(g/hp-hr) 

NOx 6.5 

VOC 0.3 

CO 0.5 

PM 0.24 

4. The emergency backup generator and fire pump engines shall be used only for 

maintenance, testing, required regulatory purposes, and during emergency 

situations and shall not be used to increase the quantity of electricity 

generated for sale. The Permittee shall restrict the operation of the emergency 

backup generators and the fire pump engines to no more than 100 hours/year 
 - 17 - 

per generator or pump. This restriction is not applicable during emergency 

situations. “Emergency situations” are defined as any situation arising from 

sudden and reasonably unforeseeable events beyond the control of the 

Permittee, including acts of God, which situation requires immediate 

corrective action to restore normal operation. Emergency situations shall not 

include non-compliance with permit terms to the extent caused by improperly 

designed equipment, lack of preventative maintenance, careless or improper 

operation, or operator error. 

5. The Permittee shall install and maintain non-resettable elapsed time meters on 

each emergency generator and fire pump engine to accurately indicate the 

elapsed operating time of the generator or engine. 

Q. Continuous Emissions Monitoring Systems 

1. Prior to the date of initial performance testing or 60 days from initial startup, 

whichever is sooner, and continuously thereafter (including periods when the 

PC boilers are starting up or shutting down), the Permittee must install, 

maintain and operate the following continuous monitoring systems (CEMS) in 

the PC boiler exhaust system so as to demonstrate compliance with the 

emission limits set forth in conditions IX.D, IX.E, IX.F, and IX.H: 

a. Continuous monitoring systems to measure stack gas SO2, NOx, CO, 

diluent concentrations, and flow. The systems must meet the 

specifications, test procedures, and quality assurance and control 

procedures under 40 CFR Part 75, Appendices A and B, except that 

Performance Specification 4 of 40 CFR Part 60, Appendix B applies to the 

CO monitoring system where the requirements refer to Performance 

Specification 2 of 40 CFR Part 60, Appendix B. 

b. A continuous monitoring system to measure stack gas PM concentrations. 

 The monitor shall be operated according to performance specification 11 

of 40 CFR 60, Appendix B. 

c. Calculation of the SO2, NO2, CO and PM hourly emission rates shall use 

the pollutant and diluent monitors required in Condition Q.1.a and Q.1.b 

with stack flow monitoring adjusted for moisture. The stack flow 

monitoring system shall meet the requirements of 40 CFR 75 Appendix A. 

 

d. Not less than 90 days prior to the date of initial startup of the Facility, the 

Permittee shall submit to the EPA a quality assurance project plan for the 

certification and operation of the continuous emission monitors. Such a 

plan shall conform to EPA requirements contained in 40 CFR 60 Subpart 

Da and Appendix F for CO, SO2, NO2, and O2, and 40 CFR 75 Appendix 
 - 18 - 

B for stack flow. The plan shall be updated and resubmitted upon request 

by EPA. 

2. Prior to the date of startup and thereafter, the Permittee shall install, maintain 

and operate a transmissometer system for continuous measurement of the 

opacity of stack emissions. The system shall meet EPA monitoring 

performance specifications (40 CFR 60.13 and 40 CFR 60, Appendix B, 

Performance Specification 1). 

3. For purposes of demonstrating compliance with the emission limits in 

Conditions IX.D, IX.E, IX.F, and IX.H, the Permittee shall calculate all 

averages as follows, except as otherwise stated in this permit: 

 a. Compliance with all 3-hour block averages shall be determined by 

calculating the arithmetic average of the respective hourly emission rates 

that comprise the eight 3-hour blocks in a calendar day. 

 b. Compliance with all 24-hour block averages shall be determined by 

calculating the arithmetic average of all hourly emission rates for each 

calendar day. 

 c. Compliance with all 30-day rolling averages shall be determined by 

calculating the arithmetic average of all hourly emission rates for the 30 

successive calendar days. 

 d. Compliance with all 365-day rolling averages shall be determined by 

calculating the arithmetic average of all hourly emission rates for the 365 

successive calendar days. 

R. Reporting and Record Keeping

1. The Permittee must maintain a file of all records, data, measurements, reports, 

and documents related to the operation of the facility, including, but not 

limited to, the following: 

• all measurements or data pertaining to continuous monitoring systems 

evaluations; 

• all continuous emissions monitoring systems or monitoring device 

calibration checks; 

• all continuous emissions monitoring system data; 

• all adjustments and/or maintenance performed on any system or device 

at the Facility; 

• all records relating to performance tests; 

• for each fuel oil delivery, documents from the fuel supplier certifying 

compliance with the fuel sulfur content limit of Conditions IX.O.1 and 

IX.P.1; 
 - 19 - 

• all coal content analyses for Fluorine and lead; 

• for each emergency generator and fire pump engine, records of the 

date of operation and the associated elapsed operating time in hours; 

and 

• all other information required by this permit and 40 CFR 60 

Appendices A-B and 40 CFR 75, recorded in a permanent form 

suitable for inspection. 

The file must be retained for five years following the date of such 

measurements, maintenance, reports and/or records. 

2. The Permittee must notify EPA of the date on which the demonstration of the 

continuous monitoring system performance commences (40 CFR 60.13). This 

date must be within 60 days after commencing full load operation but not later 

than 180 days after initial startup. 

3. The Permittee must submit a written report of all excess emissions to EPA for 

every calendar quarter. The report must include the following: 

a. The magnitude of the excess emissions computed in accordance with 40 

CFR 60.13(h), any conversion factors used, the date and time of 

commencement, and compilation of each time period of excess emissions. 

b. Specific identification of each period of excess emissions that occurs 

during startups, shutdowns, and malfunctions of any equipment. The 

nature and cause of any malfunction (if known) and the corrective action 

taken or preventative measures adopted must also be reported. 

c. The date and time identifying each period during which the continuous 

emissions monitoring system was inoperative except for zero and span 

checks, and the nature of the system repairs or adjustments. 

d. When no excess emissions have occurred or the continuous monitoring 

system has not been inoperative, repaired, or adjusted, such information 

must be stated in the report. 

e. Excess emissions shall be defined as any period during which the average 

emissions of SO2, NOx, CO or PM as measured by the CEMS exceeds the 

maximum emission limits set forth in Conditions IX.D, E, F and H. 

4. Excess emissions indicated by the CEMS must be considered violations of the 

applicable emission limit for the purpose of this permit. 
 - 20 - 

S. New Source Performance Standards

The proposed power plant is subject to the federal regulations entitled Standards 

of Performance for New Stationary Sources (40 CFR 60). The Permittee must 

meet all applicable requirements of 40 CFR 60 Subparts A, Da, Dc, Kb, Y, OOO, 

and IIII. 

X. Agency Notifications 

All correspondence as required by this permit must be forwarded to: 

1) Director, Air Division (Attn: AIR-3) 

 EPA Region IX 

 75 Hawthorne Street 

 San Francisco, CA 94105-3901 

 e-mail: R9AirPermits@epa.gov

2) Environmental Department Director 

 Navajo Nation EPA 

 P.O. Box 9000 

 Window Rock, AZ 86515