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AZ FIP_SIP_09182012-2 Comments_10152012.docx

October 15, 2012

Deborah Jordan (AIR-1) 

Director, Air Division 

USEPA Region 9 

75 Hawthorne St. 

San Francisco, CA. 94105

Re: Approval, Disapproval and Promulgation of Air Quality Implementation Plans; 

Arizona; Regional Haze State and Federal Implementation Plans, 77 Fed. Reg. 42834

(July 20, 2012) 

Dear Ms. Jordan:

Arizona Electric Power Cooperative, Inc. (AEPCO) previously submitted comments on 

September 18, 2012, to the Environmental Protection Agency (EPA) for the proposed partial 

approval and partial disapproval of the Arizona Regional Haze State Implementation Plan and 

proposed promulgation of a Federal Implementation Plan to impose the EPA’s preferred best 

available retrofit technology set forth in the July 20, 2012 Federal Register.

In those comments, AEPCO identified all of the information in the three attachments (exhibits) 

as confidential business information (CBI). At this time, AEPCO releases its CBI claim to all 

the exhibits referred to in the comments as:

Attachment 1 

Attachment 2 

Attachment 3

Please contact Ms. Michelle Freeark, AEPCO’s Director of Environmental Services, at 

(520) 586-5122 or mfreeark@ssw.coop if you have any questions or concerns.

Sincerely,

Dwight M. Whitley, Jr.

Corporate Counsel

cc: Colleen McKaughan, U.S. EPA Region IX

Eric Massey, ADEQ

Eric Hiser, Jorden, Bischoff & Hiser
September 18, 2012

FEDERAL EXPRESS and EMAIL Arizona_Regional_Haze@epa.gov

Thomas Webb

EPA Region 9, Air Division (AIR-2)

75 Hawthorne Street

San Francisco, CA 94105

Re: Approval, Disapproval and Promulgation of Air Quality Implementation Plans; 

Arizona; Regional Haze State and Federal Implementation Plans, 77 Fed. Reg.

42834 (July 20, 2012) 

Dear Mr. Webb:

Arizona Electric Power Cooperative, Inc. (AEPCO) submits comments on EPA’s proposed

partial approval and partial disapproval of the Arizona Regional Haze State Implementation Plan 

(AZ RH SIP) and proposed promulgation of a Federal Implementation Plan to impose EPA’s

preferred best available retrofit technology (BART) (the EPA BART FIP) set forth in the July

20, 2012 Federal Register. For the reasons set forth in this letter, AEPCO does not believe that

disapproval of the AZ RH SIP is appropriate and believes that promulgation of the proposed

EPA BART FIP at this time is inconsistent with the Clean Air Act and with the BART

requirements set forth in the Code of Federal Regulations.

Unlike the investor owned utilities and quasi-government agencies that comprise much of the 

power generation sector, AEPCO is a rural electric cooperative. AEPCO owns Apache 

Generating Station, which includes Steam Units 2 and 3 (ST2 and ST3), that supplies all or the 

major portion of the power needs of its six Class A Member distribution cooperatives under

wholesale power contracts approved by the Rural Utilities Service (RUS), a branch of the U.S.

Department of Agriculture. The Class A Member distribution cooperatives, which are also notfor-profit cooperatives, are Anza Electric Cooperative, Inc., Duncan Valley Electric Cooperative,

Inc., Graham County Electric Cooperative, Inc., Mohave Electric Cooperative, Inc., Sulphur 

Springs Valley Electric Cooperative, Inc., and Trico Electric Cooperative, Inc. The implications 

of AEPCO’s relationship to RUS and its member cooperatives are discussed later in these 

comments.
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

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AEPCO’s comments fall into the following areas:

• EPA has failed to accord sufficient deference to Arizona’s AZ RH SIP and has relied 

upon inappropriate factors in proposing to disapprove the NOx limits;

• EPA’s proposed nitrogen oxide BART for AEPCO’s ST2 and ST3 is unachievable and

therefore improper under EPA’s BART rules;

• EPA’s proposed nitrogen oxide BART for AEPCO’s ST2 and ST3 is unaffordable under

EPA’s BART rules; and

• Under the unique facts and circumstances pertaining to AEPCO, NOx BART for ST2 and

ST3 should be no more stringent than low NOx burners with over fire air (LNB+OFA).

AEPCO adopts the comments of the Arizona Utilities Group, Arizona Department of 

Environmental Quality and the National Rural Electric Cooperative Association and urges EPA

to accept them.

I. EPA has failed to accord sufficient deference to Arizona AZ RH SIP and has 

relied upon inappropriate factors in proposing to disapprove the AZ RH SIP

NOx limits.

EPA’s proposed BART determination of 0.05 lb/mmBtu NOx for ST2 and ST3 appears based

upon EPA’s notion of a “national uniformity” for BART and is unsupported by statute or rule.

EPA acknowledges in its SIP disapproval that “individual decisions from source to source or 

state to state may not have identical outcomes,” yet ignores Arizona’s individual BART

determinations for these units largely because they are not “consistent with...BART decisions 

that other states have made.” 77 Fed. Reg. 42836 (July 20, 2012). EPA ignores Arizona’s

comprehensive source-specific determination for these units and instead applies an emissions 

rate supported by “existing vendor literature and technical studies.” Id. at 42853. EPA’s “onesize fits all” approach to BART determinations is not supported by the Clean Air Act or rules

and certainly violates the spirit of the regional haze program.

The Clean Air Act and supporting rules create a program based on regional coordination, not 

national uniformity. Id. at 42837. State regional haze plans are the cornerstone of a regional

program. As EPA notes in its SIP disapproval, “we believe that it is preferable, and preferred in 

the provisions of the Clean Air Act, that these requirements be implemented through state plans.” 

Id. at 42836. Despite EPA’s acknowledgement of the statute’s clear deference to the states’ 

regional haze determinations, EPA has supplanted ADEQ’s BART determination with its own, 

seemingly because EPA does not agree with ADEQ’s reasoned determination even after

ADEQ’s carefully weighed analysis of the five BART factors.

EPA’s decision to disapprove the NOx BART determination for these units was largely based on 

its concern with ADEQ’s reliance on its own regional air partnership (Western Regional Air 

Partnership) model supporting its visibility analysis. Instead of deferring to ADEQ and its use of 

a regional air quality model to determine visibility impacts, EPA conducted its own visibility

analysis to reach its own conclusions. EPA compounded its disregard for ADEQ’s visibility

analysis by broadening its analysis to include the “cumulative” visibility impacts across multiple
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

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Class I areas, which is not even contemplated by the BART rules. As the U.S. Court of Appeals 

for the District of Columbia Circuit cautioned in American Corn Growers Ass’n v. EPA, the 

states, not EPA, “play the lead role in designing and implementing regional haze programs” and 

“have broad authority over BART determinations.” 291 F.3d 1, 2 & 8 (D.C. Cir. 2002).

Moreover, the U.S. Court of Appeals for the Fifth Circuit recently admonished EPA that

standards “created out of whole cloth” cannot be used as a basis for SIP disapproval. Luminant 

Generation Company v. EPA, 675 F.3d 917, 921 (5th Cir. 2012). Not only did EPA ignore

ADEQ’s lead, EPA based its disapproval on visibility impact factors it created, and which are

not supported by the BART rules, namely “national consistency” and “cumulative visibility

impact.” EPA cannot add these factors unilaterally to the BART process years after adoption of 

the BART rules and guidelines.

II. EPA’s proposed nitrogen oxide BART for AEPCO’s Apache Station Units ST2 and

ST3 is unachievable and improper under EPA’s BART rules

Section 169A of the Clean Air Act requires certain sources to apply “best available retrofit

technology” or BART. Section 169A (g) defines BART as follows:

“in determining best available retrofit technology the State (or the Administrator in determining

emission limitations which reflect such technology) shall take into consideration the costs of

compliance, the energy and non-air 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;”

Only emission limitations that can be achieved by a source can be BART. 40 C.F.R. § 51.301 

[definition of BART]. EPA disapproved ADEQ’s determination that BART for NOx on Units 

ST2 and ST3 is new LNBs and OFA system with a NOx emissions limit of 0.31 lb/mmBtu. 

Instead, EPA asserts that SCR technology with LNB and OFA and an emission rate of 0.05 

lb/mmBtu constitutes BART for these existing units. EPA’s BART determination is flawed

because it cannot be achieved by ST2 and ST3.

EPA bases its BART determination on evidence suggesting that “SCR is commonly installed as

an add-on post combustion control,” and that “existing vendor literature and technical studies

indicate that SCR systems are capable of achieving a 0.05 lb/mmBtu emission rate.” 77 Fed. 

Reg. at 42853. Anecdotal support cannot form the basis for a BART determination. BACT rules 

expressly provide that EPA does “not consider a vendor guarantee alone to be sufficient 

justification that a control option will work.” 40 C.F.R. Part 51, Appendix Y. EPA’s selection 

of 0.05 lb/mmBtu appears to be just that: a control option selected merely based on vendor

literature.

A review of the twelve most recent RACT/BACT/LAER determinations for coal-fired electric 

generating units in EPA’s RBLC database show no facility, existing or new, with a 30-day

average NOx limit below 0.06 lb/mmBtu. Existing unit limits for SCR retrofit control 

technology were established at no less than 0.07 lb/mmBtu. This supports ADEQ’s
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

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determination (based on engineering analyses) that SCR for ST2 and ST3 could achieve 0.07 

lb/mmBtu. 77 Fed. Reg. at 42845.

EPA’s presumption that SCR can achieve a 30-day average 0.05 lb/mmBtu NOx rate fails to take 

into consideration the operational realities of electric utilities. ST2 and ST3 do not operate

under steady-state conditions, but are load following units and are anticipated to see increased

cycling due to changes in AEPCO’s members’ requirements. Low-load cycling, start up and 

shut down are typical operating conditions for load following units. AEPCO must have the 

flexibility to cycle between units, and the reality is that 0.05 lb/mmBtu NOx cannot be achieved

during low load cycles. Based on RBLC data, even new coal-fired electric generating units with 

SCR are only required to achieve 0.05 lb/mmBtu averaged over 12-months. There is no way that

a retrofit coal-fired unit can achieve this limit over 30-days, despite what vendors represent.

III.EPA’s proposed nitrogen oxide BART for AEPCO’s Apache Station Units ST2 and

ST3 is unaffordable for AEPCO under EPA’s BART rules

Section 169A of the Act specifically directs EPA to consider the “costs of compliance,” 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.” ADEQ properly weighed

these factors in establishing BART for AEPCO’s ST2 and ST3 as low NOx burners plus overfire

air (LNB+OFA). EPA erred by disregarding ADEQ’s analysis, the initial cost estimates

prepared by AEPCO and its contractor, and by failing to review the affordability of the final cost 

on AEPCO as a single facility cooperative; instead, EPA examined only the cost per ton and per

deciview. In doing so, EPA failed to follow the requirements of the Clean Air Act, Section

51.308 and Appendix Y.

A. EPA has not considered the implications of AEPCO’s cooperative status and the 

limitation imposed by RUS funding restrictions

AEPCO’s assets are secured by a Consolidated Mortgage, Security Agreement and Financing

Statement, dated August 3, 2009, made by and among AEPCO, RUS and CFC (hereafter the

“2009 Consolidated Mortgage”). As principal holder of the mortgage, RUS exercises substantial

control and supervision over AEPCO’s operations requiring AEPCO to design rates that (1)

provide sufficient revenues to pay all fixed and variable expenses; (2) provide and maintain 

reasonable levels of working capital; and (3) achieve a Times Interest Earned Ratio (TIER) of

not less than 1.05 and a Debt Service Coverage Ratio (DSC) of not less than 1.00 on an annual

basis, based upon an average of the two out of three most recent years. The Arizona Corporation 

Commission (ACC) has historically established AEPCO’s equity level, consequently authorizing 

much higher TIER and DSC ratios than the RUS minimum. The 2009 Consolidated Mortgage 

prohibits AEPCO from financing system extensions except through Additional Notes and

requires express RUS approval of most debt decisions, among approximately 24 covenants that

AEPCO must maintain.

AEPCO notes that under the terms of the 2009 Consolidated Mortgage, it is obligated to pay

taxes and maintain insurance on the units and their appurtenances and therefore must consider
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

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these expenses. Similarly, AEPCO notes that the “margin” in its calculations is required by the

2009 Consolidated Mortgage TIER and DSC requirements and is an unavoidable cost.

RUS provides loans and loan guarantees through the Federal Financing Bank (FFB), which is 

AEPCO’s principal source of past and future funding. In order to secure future funding, AEPCO

must file a Construction Work Plan (CWP) containing the detail for the capital projects for 

which funding is requested and, if approved, a loan application with RUS. If approved, RUS 

prepares loan documents to be executed by AEPCO. Loan draws are generally based upon the 

cost of completed projects. The terms of each draw are based upon a maturity date established by

the loan documents, prepayment/refinancing options and an interest rate based upon the

equivalent treasury rate plus 1/8 percent interest. In addition to FFB financing, AEPCO may

also borrow from the National Rural Utilities Cooperative Finance Corporation (CFC) to either

supplement financing requirements or to provide interim financing needs until FFB loan funds 

can be drawn (after project completion – see above). CFC financing requires a lien 

accommodation from RUS in order to be secured by the mortgage. CFC loan interest rates are

between 100 to 250 basis points higher than RUS loans and also require the purchase of Equity

Term Certificates amounting to 14.29% of the loan amount. In addition to CFC loans, AEPCO

may work with CFC to obtain pollution control financing through revenue bonds issued through

the Pollution Control Corporation of Cochise County, Arizona.

The overlay of RUS, FFB and CFC requirements on AEPCO’s mortgage and the ACC approval

process severely restricts AEPCO’s financing flexibility. Further, as a cooperative, AEPCO has 

no access to equity markets and extremely limited access to bond markets. Finally, financing

from FFB as guaranteed by the RUS and to some degree CFC, is limited by congressional

appropriations. AEPCO anticipates continued high demand for FFB sourced funding as many

electric cooperatives seek RUS funding for improvements needed to address the EGU MACT, 

CSAPR/CAIR, SO2, NO2, PM2.5 and Ozone NAAQS updates in addition to regional haze

requirements.

B. EPA has underestimated the site-specific costs incurred by AEPCO in installing

SCR

AEPCO is concerned that EPA has substantially underestimated the cost of installing SCR at

AEPCO’s Apache Generating Station by substituting the site-specific data that AEPCO, its 

contractors and ADEQ used in the SIP process for the “one size fits all” IPM Model, which was

developed for the Eastern United States, where there is greater transmission capacity, less

distance, and greater availability generally of engineering, construction and technical support.

1. The Costs of SCR are higher than EPA has estimated

AEPCO has several concerns with EPA’s proposed cost calculations for AEPCO’s ST2 and ST3. 

These concerns apply at each stage of EPA’s calculations: base unit; bare module cost, capital, 

engineering and construction costs, and total project cost.
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

Page 6

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Base Unit. EPA has indicated that it calculated the cost of installing SCR on ST3 at

approximately $33,279,000. This is based upon EPA’s calculated cost for the base SCR island 

of $26,448,000 with a 25% reduction for “low dust.” AEPCO disagrees with this generic 

calculation from the IPM model. As set forth in the detailed cost demonstration in Attachment 1

(claimed as CBI), AEPCO’s vendors do not believe that there will be any substantial reduction in 

cost based upon putative “low dust.” Thus, even though AEPCO’s initial SCR island cost is 

lower, after installation costs and the unjustified “reduction” for “low dust” are removed, the 

actual SCR island cost is closer to $39,094,000.

Bare Module. EPA has provided only $3,753,000 for modifications. This is far below what will 

be needed. AEPCO agrees that the $3.7 million is approximately accurate for installation of ID

fan upgrades necessary to support SCR operation. However, EPA assumes that no other

upgrades are necessary. As outlined in Attachment 1 (claimed as CBI), much of Apache 

Station’s existing electrical equipment and buses are running at 90% or greater capacity and thus 

cannot support the additional electrical loads required by SCR. AEPCO will need to either run 

new electrical service or upgrade existing electrical service. Based upon these costs, detailed in 

Attachment 1 (claimed as CBI), AEPCO estimates that the bare module cost is closer to

$48,119,000 than the $25,599,000 that EPA has estimated using the generic IPM model.

Capital, Engineering, and Construction Costs. AEPCO agrees with EPA’s approximate 

percentages used to estimate these costs. Missing, however, are additional factors which will be 

included in the contractors EPC bid, such as the indirect costs incurred by the contractor (5%)

and contingency which will be included by the contractor and is not refundable if not used. 

AEPCO estimates a total of 46.5% as compared to EPA’s estimate of 30%. This amount applied

to the bare module cost brings AEPCO’s estimate, before owners cost and AFUDC, to

$74,260,000 as compared to EPA’s $33,279,000.

Total Project Cost. EPA has estimated total project cost at $33,279,000 per unit, without 

allowing any owners costs or “AFUDC” (allowance for funds during construction). Whatever

may be the merit of this approach for comparability purposes, it is not appropriate for AEPCO. 

As discussed in AEPCO’s response to EPA’s data request submitted on August 23, 2012, 

AEPCO has very limited working capital. As a result, AEPCO must borrow in the form of 

bridge financing the working capital necessary to install the proposed SCR control. This 

“interest during construction” or IDC is a legitimate cost that AEPCO must pay to outside third

parties and must be incurred by AEPCO’s members in their rates. AEPCO thus does not believe 

that EPA may disallow this cost. Similarly, AEPCO does not believe that “good air pollution 

engineering practice” allows construction without contingency allotments, taxes, and similar

necessary expenses. The specifics of these expenses are detailed in Attachment 1 (claimed as 

CBI). After considering these costs, AEPCO’s estimate, per SCR unit, is $85,666.000 versus

$33,279,000 for EPA.

Operation and Maintenance Cost. EPA estimates these costs at $1,822,463. Based on vendor

estimates, AEPCO estimates fixed costs at $466,000 and variable costs a bit lower than EPA at

$1,294,600 for a total cost of $1,760,000. The principal difference is a slightly higher allowance

for maintenance due to the duplicative systems required.
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

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Combined Costs. EPA’s estimated combined per unit cost is $33,279,000 versus AEPCO’s

estimate of $85,666,000. Doubling these (to account for the fact that both Unit ST2 and ST3 

must be addressed) results in a total cost of approximately $66.5 million for EPA and $171.3

million for AEPCO before operating costs. EPA needs to reevaluate its numbers in light of 

AEPCO’s site specific analysis. Appendix Y clearly favors the use of site-specific information 

to generic calculations so long as the information is presented in a compatible format. Appendix 

Y, § IV.D.4.a.5. In this case, AEPCO has submitted detailed, site specific information 

addressing issues unique to AEPCO such as electrical limitations.

2. Using the proper costs suggests that SCR is much more expensive on a

$/ton and $/deciview basis.

AEPCO’s estimated installed cost of SCR based on site specific information is more than double 

that of EPA’s. Adding this cost to EPA’s estimate for LNB and OFA will result in an annualized

cost of $3,508 per ton which is 1.2 to 1.5 times EPA’s estimates. On a maximum deciview (dv) 

improvement basis, AEPCO’s estimate will result in a cost of $13.9 million per dv which is 1.7 

times the EPA estimate. Overall, the cost burden to AEPCO for SCR is disproportional to the 

benefit with respect to the potential deciview improvement. See Attachment 2 (claimed as CBI)

for AEPCO’s calculations on a $/ton and $/deciview basis.

3. The cost of SNCR is burdensome in comparison to the benefit.

EPA estimated the total annual cost of SNCR+LNB+OFA at $5.6 million per year for both units 

as compared to $2.3 million for LNB+OFA, see Table 16 on page 45 of EPA’s Technical

Support Document. The additional cost of $3.3 million per year will result in a maximum

improvement from .53 dv to 1.0 dv (Chiricahua WA) according to Table 20 on page 51 in EPA’s

Technical Support Document. This incremental improvement of .47 dv is insignificant in 

comparison to the cost.

C. The cost of the proposed BART is unaffordable for AEPCO

As noted in previous AEPCO comments, AEPCO is a rural electric cooperative. AEPCO’s rural

electric cooperative status has several important implications for AEPCO’s ability to afford the

installation of controls such as the proposed SCR. AEPCO operates only a single station, the 

Apache Generating Station, and has only approximately 147,000 meters in the service population 

of its Class A members. The situation is further exacerbated by the fact that almost all of the 

effective power at the Apache Station (475 MW out of just over 600 MW capacity) are subject to 

BART requirements. As a result, AEPCO has little or no ability to “spread costs” over

unaffected units, other facilities, or a large system of units and ratepayers. Instead, the entire

cost is borne by a relatively small number of AEPCO Class A members and their members.

Among the other implications of AEPCO’s cooperative status are the following:

• AEPCO is owned by its members. Unlike an investor owned utility, where there is a

break between the owners and the ratepayers, AEPCO is owned by its members. As a
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

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result, AEPCO cannot undertake a project that raises its rates substantially above what its 

members would otherwise pay because the members will disapprove the project(s).

• AEPCO does not have access to capital markets. Because AEPCO is a cooperative, it

cannot sell stock or other equities and has extremely limited access to bond markets. 

Instead, AEPCO must seek long-term project financing from the Rural Utilities Service,

an agency of the United States government. RUS has a limited budget and AEPCO must 

compete against other cooperatives and rural utilities that are also seeking loans to make 

facility upgrades and install pollution control equipment as a result of CAIR, CSAPR,

other SIP initiatives, and the upcoming EGU MACT.

• AEPCO has limited internal resources. Because it is a cooperative, AEPCO has

relatively small capital reserves (called “patronage capital”) upon which to draw. 

Further, AEPCO’s working capital is low compared to many other businesses. As 

discussed above, limited working capital results in the need for additional bridge

financing and increases AEPCO’s total cost of any project.

• AEPCO cannot raise the money under its current RUS and CFC agreements without

prior government approval. As part of its agreement with RUS and CFC (which

provides bridging financing), AEPCO has entered into a mortgage agreement. That

agreement requires RUS and CFC approval before AEPCO can take on additional debt at

the levels necessary to apply SCR to ST2 and ST3. 2009 Consolidated Mortgage,

Section 3.01(c). AEPCO is also required by its Consolidated Mortgage to maintain a

TIER Rate (times interest earned rate) of at least 1.05 and a Debt Service Coverage

(DSC) rate of at least 1.0. Consolidated Mortgage, Section 4.15. The addition of the 

substantial financing costs that would be imposed by EPA would cause AEPCO to fail

both the TIER and DSC ratios test under the 2009 Consolidated Mortgage. AEPCO must 

then propose a plan to restore the ratios. If this plan is insufficient, certain of AEPCO’s

note holders may obtain injunctive relief to enforce the ratio. Consolidated Mortgage,

Sections 4.15(b)(4) and 5.02(c)(3). AEPCO estimates that the rate increase would need 

to be greater than 16 percent. It is not certain whether the ACC would grant such a rate 

increase and what the long term impact would be on AEPCO’s working capital and 

patronage capital.

1. The costs of SCR + LNB + OFA are unaffordable for AEPCO and its members.

• Operating Costs are unreasonable based upon AEPCO’s net revenues over expenses.

In 2011, AEPCO’s net revenue over expenses amounted to $1.9 million. The estimated

O&M cost of the SCR system alone using EPA’s estimate is $3.3 million, effectively

depriving AEPCO of any adequate revenues or working capital. While revenues in 2010

were higher, at approximately $9.5 million, even then nearly 35% ($3.3MM/$9.5MM) of 

AEPCO’s total available net revenues would be consumed by operating costs alone,

without regard to financing. Based on AEPCO’s estimate of annual costs, at $3.9 

million, over double AEPCO’s 2011, without allowance for financing costs.

• Financing costs are unreasonable based upon AEPCO’s resources. In total AEPCO

will need to raise $192,418,378 to install SCR with low NOx burners and overfire air to 

comply with the proposed BART for NOxon ST2 and ST3. See Attachment 3 (claimed 

as CBI). This represents a 98% increase in AEPCO’s long term debt balance of $195.6
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

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million as of the end of July 2012. AEPCO’s finance group has estimated that AEPCO

would need to increase revenues (rates) approximately $22.5 million a year, over and

above the $3.9 million a year for O&M expense, to finance SCR + LNB + OFA. This 

combined cost of $26.4 million is 14 times AEPCO’s net revenues in 2011 and 2.8 times

AEPCO’s net revenues in 2010, a much better year. Actual costs are higher as AEPCO

must also expend resources on the following Apache Station BART determinations, as 

well:

Unit ST1, NOx LNB+FGR $551,982

Unit ST2, SDAS and ESP upgrades Unspecified

Unit ST3, SDAS and ESP upgrades Unspecified

Based only on the addition of $26.4 million, AEPCO’s financial group has estimated that

AEPCO would need to raise its rates by more than 17.5% to maintain financial stability,

mortgage commitments, and RUS and ACC expectations.

• AEPCO’s membership base cannot bear the estimated financing costs. AEPCO is

composed of six “Class A” members, three full requirements members and three partial 

requirements members. All told, AEPCO and its member distribution cooperatives serve

only 147,643 metered customers. Further, many of these meters are in relatively

disadvantaged areas. As can be seen in the census data for AEPCO’s service ZIP codes, 

household income on a per capita basis is only $27,664, well below the Arizona average

of $34,999 and the United States average of $40,584 (2010 data). AEPCO’s per capita 

income is thus 31.8% below the national average. Increases in rates which might seem

trivial become more important as they consume more and more of the reduced per capita 

income.

2. The Cost of SNCR is not affordable by AEPCO and its members

While SNCR is considerably less expensive in terms of capital cost, its operating costs are

comparable to SCR. AEPCO estimates the annual operating costs (as they would impact

AEPCO’s members) of SNCR + LNB + OFA at $6.8 million. This represents over 3 times

AEPCO’s net revenue margin in 2011 and well over two-thirds of AEPCO’s net revenues in

2010, a much better year.

3. The Unit ST1 natural gas BART determination is not “costless”

EPA states in its Technical Support Document that the cost to AEPCO of switching from its 

current fuel mix to natural gas only is “0.” This is not true; once AEPCO loses the ability to use 

multiple fuels, its negotiating leverage with natural gas suppliers is greatly reduced and it is no 

longer able to obtain gas at reasonably competitive rates. This factor should be considered by

EPA in assessing the overall affordability of the BART determination for the Apache Station and 

AEPCO.
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

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4. The BART Guidelines support AEPCO’s concern about affordability

The Appendix Y BART Guidelines provide that the State and EPA must consider whether the 

proposed BART determination is “unaffordable” for the facility. The Guidelines state:

There may be unusual circumstances that justify taking into consideration the 

conditions of the plant and the economic effects of requiring the use of a given

control technology. These effects would include effects on product prices, the 

market share, and profitability of the source. Where there are such unusual

circumstances that are judged to affect plant operations, you may take into 

consideration the conditions of the plant and the economic effects of requiring the 

use of a control technology. Where these effects are judged to have a severe

impact on plant operations you may consider them in the selection process, but 

you may wish to provide an economic analysis that demonstrates, in sufficient 

detail for public review, the specific economic effects, parameters, and reasoning.

(We recognize that this review process must preserve the confidentiality of

sensitive business information). Any analysis may also consider whether other

competing plants in the same industry have been required to install BART

controls if this information is available.

40 C.F.R. Part 51, App. Y, § IV.E.3.2. AEPCO believes that it is exactly one of these “unusual

circumstances” that EPA must acknowledge.

Product price. AEPCO has estimated, in Attachment 3 (claimed as CBI), that its rates would 

need to rise by at least 17.5% to cover the cost of SCR, exclusive of ESP, SDAS retrofits and 

ST1BART controls. A 17.5% rate increase in a depressed economic region is significant and

harmful to AEPCO’s rural consumers and not-for-profit members. The rate increase is also 

large enough to create uncertainty about the ACC’s reaction and whether AEPCO would be able 

to immediately recover the entire amount necessary to finance the SCR installation. Delays in 

rate increases further increase AEPCO’s bridge financing costs with CFC.

Market Share and Profitability. As noted above, the addition of these costs would likely throw

both the Apache Station and AEPCO into a significant negative financial position, adversely

affecting the “profitability of the source” and probably requiring both a substantial rate increase 

and renegotiation of the existing 2009 Consolidated Mortgage as AEPCO would no longer meet

the TIER and DSC requirements of its covenants. The costs necessary to finance the SCR

systems, even if ultimately covered by a rate increase (which must be authorized by the ACC), 

would substantially increase AEPCO’s rates, creating downward pressure on AEPCO’s market

share. AEPCO must compete, however, not only with general power pooling (like other

utilities), but also with its partial requirements members, who may elect to purchase power

“against” the Apache Station units or, along with the all-requirements members, to shutdown 

those units in favor of a purchase power agreement (PPA) should the Apache Station’s costs go

unduly out of line with the cost of power on the open market.
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

Page 11

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To AZ FIP_SIP_09182012-2.Docx

Impact on Plant Operation. The proposed installation of SCR + LNB + OFA would increase 

AEPCO’s long term debt by 98%. It would severely reduce AEPCO’s working capital and

require bridge financing at additional expense. It would impose substantial additional burdens 

on AEPCO at a time when contracts on ST1 are expiring in a relatively short period. Upon 

contract expiration, many of AEPCO’s financial guarantees from its Class A Members are lost 

and AEPCO has no certainty that even its existing rate base (of 147,643 meters) would be

available to defray costs.

D. AEPCO requests that BART limits be set as emission limits only

In order to allow AEPCO the maximum flexibility moving forward, AEPCO requests that EPA

set the final BART limits in terms of lb/mmBtu only and not as a specified technology. As 

ADEQ and EPA noted, there will be some time passing between EPA’s decision and the final

installation and operation of the controls on units ST1, ST2 and ST3. This may allow minor 

changes in configuration of the optimal system to allow compliance at somewhat lower cost. 

AEPCO accordingly requests that the final determination be only in a lb/mmBtu format.

If EPA retains the SCR or SNCR limits, AEPCO requests that the SCR limits be set for 0.07

lb/mmBtu for the reasons set forth above and that if any lower limit is established, that it be set

as an annual average due to the load following, cycling nature of AEPCO’s units and the need to 

accommodate start ups and shutdowns in the limit. Similarly, for SNCR, AEPCO requests that

the limit be set at 0.23 lb/mmBtu to allow both units to achieve the limit. While there are some 

differences in past utilization, the units are functionally identical and based on the best 

information available to AEPCO, a limit of 0.23 lb/mmBtu is likely the best consistently

achievable limit given the load following, unit cycling and startup and shutdown issues that must 

be addressed as part of unit operation.

IV. Additional Comments

EPA should clarify that AEPCO has longer than180 days to comply with the non-SCR limits. In

particular, AEPCO is concerned about the 180 day requirement as it applies to ESP and SDAS

upgrades. AEPCO will need to make numerous changes in its operating practices, contracts, 

maintenance provisions and equipment configuration to address the various BART requirements 

for all required upgrades. Equipment lead time requirements for SCR, if required, or potential

scrubber upgrades will add considerable delay to implementation. AEPCO believes that a 5 year

period for all BART implementation is appropriate given the necessary changes, variables and

considerable engineering and testing to achieve the desired reductions.

In addition, AEPCO would like to address a couple of specific areas in EPA’s Technical Support

Document where EPA sought comment specifically to ST2 and ST3.

On page 23 of the Technical Support Document EPA is seeking comment on whether test 

methods other than EPA Method 201 and 202 should be allowed or required for establishing 

compliance with the PM10 limits being approved as part of the AZ RH SIP. AEPCO clearly

supports maintaining the use of EPA Method 201A to comply with proposed BART PM10 limits.
Comments of Arizona Electric Power Cooperative, Inc.

Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP

September 18, 2012

Page 12

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Additionally, on page 24 of the Technical Support Document EPA is seeking comments on

whether requiring 90 percent control efficiency in addition to the lb/MMBtu limit for SO2 would 

better assure proper operation of the upgraded scrubbers when burning some types of low-sulfur

western coal.

The Air Quality Control Permit issued by Arizona Department of Environmental Quality

contains the following material condition: At all times, including periods of startup, shutdown,

and malfunction, the Permittee shall, to the extent practicable, maintain and operate the sulfur

dioxide absorption systems in a manner consistent with good air pollution control practice for

minimizing sulfur dioxide emissions. [40 CFR 60.11(d)]

AEPCO believes that this condition provides the assurance that the scrubbers will be operated 

properly. Also, a control efficiency requirement would necessitate the modification of CEM’s to 

include the capability to measure scrubber inlet SO2 in addition to stack emissions. This would 

require additional capital expenditure for equipment, as well as additional ongoing expenditure

for day-to day operations and maintenance. This additional monitoring/measuring system would 

also have to be certified and subject to annual relative accuracy testing. Based on the above 

information AEPCO believes a scrubber control efficiency requirement in addition to a

lb/MMBtu sulfur dioxide limit is unwarranted

AEPCO appreciates the opportunity to provide these comments. Please contact Ms. Michelle 

Freeark, AEPCO’s Director of Environmental Services, at (520) 586-5122 or 

mfreeark@ssw.coop if you have any questions or concerns.

Sincerely,

Dwight M. Whitley, Jr.

Corporate Counsel

cc: Deborah Jordan, U.S. EPA Region IX

Colleen McKaughan, U.S. EPA Region IX

Eric Massey, ADEQ

Eric Hiser, Jorden Bischoff & Hiser
ATTACHMENT “1”
Memorandum

Date: September 13, 2012

Subject: AEPCO, Project 67286

SCR Cost Estimate Notes

EPA's estimate for SCR, not including low NOx burners and over fire air for Apache Station 

units ST2 and ST3 is $67,505,000. Burns and McDonnell's estimate for this same installation is

$171,332,000. This memo summarizes some of the key assumptions and basis in the Excel 

workbook (IPM Model SCR Costs**.xls) that compares the SCR cost estimate from EPA (i.e. 

Arizona Regional Haze Technical Support Document) with the Burns & McDonnell SCR cost 

estimate. The workbook contains three worksheets and other assumptions are included on the 

worksheets. These capital costs estimates are consistent with screening level percent accuracy (-

30/+50).

SCR COSTS BASED ON IPM COST MODEL (worksheet)

This worksheet recreates the Unit 2 and 3 capital costs estimated by the EPA subcontractor, 

which were used in the EPA’s Arizona Regional Haze Technical Support Document. It also 

shows another capital cost estimate that uses the same approach as EPA, but makes different 

assumptions regarding flue gas volume, retrofit factor, adjustment factor for going from high

dust SCR to low dust SCR, and EPC fee. These assumptions result in estimate SCR capital costs

that are about 110 percent higher than EPA’s estimated costs.

Retrofit Factor (Cell G6): A retrofit factor is incorporated into the model to adjust the cost 

estimate based on project specific requirements and considerations. According to the IPM 

model, an average retrofit has a retrofit factor of 1.0 and more difficult retrofits can increase the 

capital costs 30 to 50 percent. This factor is highly subjective because an “average” or “typical” 

retrofit has not been defined and each project has unique requirements.

Burns & McDonnell found that a retrofit factor of 1.65 had to be applied to this estimate to 

account for project specific requirements and differences including the following bulleted items. 

The retrofit factor results in capital costs that are comparable with those shown in the middle cost 

estimate (i.e. B&McD Estimate applied to IPM Model with EPA Assumptions) on the SCR 

Capital Cost Comparison Worksheet.

The auxiliary and start-up electrical system spare capacity is effectively non-existent 

and will need a major upgrade to support the upgraded ID fan capacity.

Without a specific design, it was assumed that the SCR reactor would have to be 

installed to the side of the precipitators instead of directly behind, where there would be

more structural constraints. This requires additional ductwork and associated steel and

foundations.

Low Dust Adjustment (Cell G30): Although not explicitly addressed by the IPM cost model 

notes, it appears that the IPM SCR pricing is based on high dust SCR applications, not low dust 

applications. The SCR cost estimate from EPA reduced the costs 25 percent to go from high
Memorandum (continued)

September 13, 2012

Page 2

dust SCR to low dust SCR. The magnitude of this reduction appears arbitrary since no basis for 

this factor was provided by the EPA subcontractor.

Babcock & Wilcox was consulted to determine the cost effects associated with going from high 

dust to low dust SCR applications. The differences are mainly attributable to ash and the 

associated impacts with ash cleaning and catalyst design/pitch. The impact on capital cost is 

project specific based on applicable parameters, and Babcock & Wilcox indicated going from 

high dust SCR to low dust SCR could decrease the capital cost 10 percent.

SCR COST COMPARISON (worksheet)

The SCR Cost Comparison table compares SCR cost estimates between EPA’s subcontractor and 

a couple other Burns & McDonnell cost estimates. The first B&McD estimate is based on cost 

assumptions that are similar with EPA (i.e., similar cost factors for engineering, contractor profit, 

etc. and not allowing AFUDC). The second estimate is based on B&McD cost assumptions, 

rather than EPA assumptions. The costs of Low NOx burners and over-fire air (OFA) are not 

included with these estimates in order for them to be comparable to EPA’s estimate. The Burns

& McDonnell estimates are based on the following assumptions:

Vendor quotes (Cell G5): The SCR and reagent preparation costs are based on indicative quotes 

from two SCR vendors for supply of SCR materials, with a factor of approximately 50 percent 

for installation and associated indirects for that subcontractor. The vendor proposals were 

similar in scope and value and based on 2012 dollars. The IPM model cost estimate from the 

EPA subcontractor is based on 2009 dollars and probably needs to be adjusted higher for 

escalation. One indicator of escalation is the Chemical Engineering Plant Cost Index (CEPCI),

which increased from 522 in 2009 to 596 in 2012, indicating escalation of 14% over the three 

year period. The CEPCI for 2009 and 2010 was lower than for 2008 as a result of general 

economic and construction conditions.

Concrete, Steel, Ductwork, Insulation (Cells G6 to G9): High level quantities of steel, ductwork, 

insulation, concrete and piling required for the SCR were estimated based on preliminary 

arrangements in combination with scaled estimates and comparisons with other SCR projects. 

Unit costs were applied to the estimated quantities to determine capital costs. The cost estimates 

were based on putting the SCR reactors to the side of the electrostatic precipitators. It may be 

feasible to install the reactors between the ESPs and the scrubber, but further evaluation is 

required to confirm feasibility. This arrangement could potentially decrease costs associated

with carbon steel ductwork, concrete and steel by 5 to 10 percent of the SCR Island Cost.

Civil, Architectural, Mechanical, Electrical, I&C (Cells G10 to G13): These costs were 

estimated based on cost data from prior SCR projects and scaled as a percentage of the SCR and 

Reagent Preparation costs. A unique cost factor was multiplied with the SCR and Reagent
Memorandum (continued)

September 13, 2012

Page 3

Preparation costs island cost for each discipline (e.g., mechanical, electrical, etc.) to estimate 

capital costs for that discipline. Electrical item costs do not include work associated with the 

auxiliary and startup transformers, since that is addressed on another line. The cost factors were 

determined from cost data from 5 to 6 other air pollution projects by comparing the discipline 

costs with other components of capital cost. The cost data for the other projects was derived 

from a combination of pricing from estimates and firm proposals.

ID Fan Upgrade Costs (Cell G23): Adding SCR will increase the head requirement of the ID fan 

system and require additional capacity. This estimate is based on upgrading the existing ID fans, 

rather than installing booster fans. The extent and form of the upgrades cannot be determined 

without a fan study. ID fan upgrade costs for this study were estimated at 50 percent of new fan 

installed cost for similar size fans. Fan pricing was based on the average price of six vendor fan 

quotes for a similar size fan.

Auxiliary Power Modifications (Cell G24): The electrical operating loads associated with SCR 

are estimated to be 0.8 to 1.0 MW per unit. Most of this new electrical load is associated with 

overcoming the additional flue gas draft (pressure drop) through the SCR system, but there are 

also smaller loads such as reagent vaporization and supply loads.

The spare capacity of the current electrical auxiliary and start-up systems at Apache Station is 

effectively non-existent based on a load flow study from a couple of years ago. On the auxiliary 

side there are several 480V buses that are running below 90% of nominal voltage in the standard 

running scenario. During startup the voltage on the 480V buses drops below 75% of nominal 

voltage. Adding additional load will only worsen these conditions. Another example from the 

load study indicated that the existing 2A 4160 V bus is loaded beyond 90% of its 2000 amp

capacity. Adding the additional SCR load puts the current at 98 percent of the switchgear 

ampacity.

With these considerations in mind, and based on estimated SCR electrical loads, a new auxiliary 

transformer and start-up transformer will be required to support these loads. Electrical 

modification direct costs are estimated to be $6.25 million per unit. This covers work directly 

attributable to the SCR addition for new auxiliary transformer, start-up transformer, associated 

construction and switch yard updates for each unit. Electrical equipment costs were estimated 

from actual equipment costs from other projects.

Indirects and Engineering (Cells G28 and G29): A 5 percent factor was included to account for 

costs associated with construction and startup management. This factor also accounts for 

construction management indirects such as per diem, travel expenses, and temporary facilities. 

Performance bond have not been included. Engineering costs are accounted for with a 10 

percent factor which is typical.
Memorandum (continued)

September 13, 2012

Page 4

The IPM Model from EPA uses a 10% factor for engineering and construction management cost. 

Based on our experience, it is not uncommon for engineering, construction management and 

startup to be 15 to 18 percent of the direct project cost.

Escalation, Contingency, and EPC Fee (Cells G30, G31 and G32):

An escalation factor of 5.5 percent has been calculated and applied to the estimate. This factor 

was calculated by applying an annual escalation rate of 2 percent from the start of the project to 

the middle of the construction period.

A 20 percent factor has been included to account for project contingency and EPC contractor 

contingency. Contingency addresses uncertainty in the site installation and project, which is 

relatively undefined at this point. As scope is defined, money in contingency may need to be 

allocated to other portions of the estimate. The EPC Contractor and subcontractors also include 

contingency (typically 4 to 8 percent) in the EPC contract, which the Owner will incur, even if 

the money is not applied toward project costs.

The EPC fee fluctuates depending on construction market conditions, but it currently trends 

around 6 percent, which is the basis for this estimate.

General Owner Costs, Taxes and Owner Contingency (Cell G37)

A 12 percent factor was used to account for these three items. Typical factors for these items

vary from 2-5% (General Owner Cost), 3-5% (Taxes), 3-5% (Owner Contingency). General 

Owner costs include Owner personnel labor costs for project development, management, and 

operations associated with the construction of the project. It also includes legal counsel, 

permitting fees, license fees, start-up fuel, initial fills, insurance, and spare parts. Some of the 

various types of taxes that could be imposed include sales, use, gross receipts, and property tax. 

Owner contingency covers market uncertainty and additional scope identified during project 

execution.

Although not allowed by EPA in the IPM model, Owner costs are actual costs that the Owner 

will incur.

Allowance for Funds Used During Construction (AFUCD) (Cell G38)

A 3 percent factor was used to account for AFUDC, which is based on a couple years of interest 

at 1.5 percent. Although not allowed by EPA in the IPM model, AFUDC is expected to be 

actual costs that the Owner will incur and that will impact member rates.
Memorandum (continued)

September 13, 2012

Page 5

O&M Cost Comparison

The estimated SCR operating and maintenance costs from the EPA subcontractor and B&McD 

were similar at approximately $1.8 million per year for one unit. One of primary differences 

between these two estimates is that the EPA estimate is based on 71 percent capacity factor and 

the B&McD estimate is based on 85 percent capacity factor.
SCR Costs based on IPM Cost Model

AEPCO

Rev 4 August 29, 2012

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

56

57

A B C D E F G H

Inputs

Variable Designation Units Calculation Notes BMcD Estimate Basis

Estimate Source EPA Subcontractor EPA Subcontractor BMcD w/EPA Approach

Unit Apache ST2 Apache ST3 Apache ST2 or ST3

Unit Size A (MW) 204 204 204 Unit size consistent with EPA subcontractor

Retrofit Factor B

(an average retrofit has a factor

= 1.0) 1 1 1.65

IPM summary says retrofit factor can result

in cost increases of 30 to 50%, see notes for

explanation of 1.65 factor

Heat Rate C (Btu/kWh) 11351 10898 10898

NOx Rate D (lb/MMBtu) 0.26 0.31 0.31

assumed inlet SCR NOx rate with Low NOx

burners and over fire air (OFA), 0.31

lb/MMBtu is consistent with ADEQ BART

analysis

SO2 Rate E (lb/MMBtu) 1.7 1.7 1.7 Based on El Segundo/PRB fuel blend

Type of Coal F PRB PRB PRB

Coal Factor G Bit=1.0, PRB=1.05, Lig=1.07 1.05 1.05 1.05

Heat Rate Factor H C/10,000 1.1351 1.0898 1.0898

Heat Input I (Btu/hr) A*C*1000 2,315,604,000 2,223,192,000 2,223,192,000

Capacity Factor J (%) 62 71 85 assumed capacity factor

NOx Removal Efficiency K % 80.77 83.87 77.42

Based on NOx emission rate of 0.07

lb/MMBtu, which is consistent with the

Arizona Department of Environmental

Quality (ADEQ) BART analysis

NOx Removal Factor L I/J?? 0.875 0.875 0.875

NOx Removed M lb/h D*I/10^6*K/100 486.3 578.0 533.6

Urea Rate (100%) N (lb/hr) M*0.525*60/46*1.01/0.99 339.7 403.8 372.8

Steam Required O (lb/hr) N*1.13 383.9 456.3 421.2

Aux Power P (%)

0.56*(G*H^0.43; Aux. Power is

not used in the variable O&M

Costs. 0.60 0.59 0.59

Urea Cost 50% Wt Solution R ($/ton) 400 400 400 use same unit cost

Catalyst Cost S ($/m3) 8000 8000 8000 use same unit cost

Aux Power Cost T ($/kWh) 0.06 0.06 0.06 use same unit cost

Steam Cost U ($/klb) 4 4 4 use same unit cost

Operating Labor Rate V ($/hr) Labor including all benefits 60 60 60 use same unit cost

SCR Capital Costs

BMR ($) Base Module SCR Cost 27,457,000 26,448,000 43,639,000

Low Dust adjustment

Assumed cost deduct to go from

high dust SCR to low dust SCR 25% 25% 10%

Assume 10% deduct instead of 25%; see

notes

Adjusted BMR ($) Adjusted Base Module Cost 20,593,000 19,836,000 39,275,000

BMF ($) Base Reagent Preparation Costs 1,925,000 2,010,000 1,971,000

BMA ($) Base Module Air Preheater Cost

Air Heater Modification/SO3

Modification

BMB ($) Base Module BOP Costs

ID or Booster Fans & Auxiliary

Power Modifications 3,818,000 3,753,000 6,193,000

BM ($) Base Module Cost 26,336,000 25,599,000 47,439,000

BM ($/kW)) 129 125 233

Total Project Cost

A1=10% of BM

Engineering and Construction

Management Costs 2,634,000 2,560,000 4,744,000 use same cost factor as EPA

A2=10% of BM

Labor adjustment for 6 x 10 hour

shift premium, per diem 2,634,000 2,560,000 4,744,000 use same cost factor as EPA

A3=10% of BM Contractor Profit and Fees 2,634,000 2,560,000 4,744,000 use same cost factor as EPA

CECC ($) = BM+A1+A2+A3 Capital, Engineering, and Construction Cost 34,238,000 33,279,000 61,671,000

CECC ($/kW) 168 163 302

B1=5% of CECC

Owners costs including all 'home

office' costs (owner's

engineering, manangement, and

procurement)

no owner costs assumed consistent with EPA

protocol

B2=6% of CECC + B1 AFUDC

no AFUDC assumed consistent with EPA

protocol

TPC ($) = CECC + B1 +B2 Total Project Cost (2009 $) 34,238,000 33,279,000 61,671,000

TPC ($/kW) 168 163 302

EPC fee 9,250,650

IPM summary indicates TPC for turnkey EPC

contract can increase costs 10 to 15%, use

15% to be consistent with the general (i.e.

not detailed) nature of this estimate

TPC w/EPC fee ($) 70,921,650

TPC w/EPC fee ($/kW) 348
SCR Costs based on IPM Cost Model

AEPCO

Rev 4 August 29, 2012

58

59

60

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67

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77

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79

80

A B C D E F G H

SCR O&M Costs

Estimate Source EPA Subcontractor EPA Subcontractor BMcD w/EPA Approach BMcD Estimate Basis

Unit Apache ST2 Apache ST3 Apache ST2 or ST3

Fixed O&M Costs

FOMO ($/kW yr) Operations Staff 0.31 0.31 0.31

based on 0.5 operator/unit consistent with

EPA estimate

FOMM ($/kW yr) Maintenanance L&M 1.47 1.47 1.47

based on $300,000 maintenance M&L,

consistent with EPA estimate

FOM ($/kW yr) Fixed O&M 1.78 1.78 1.78

FOM ($/yr) one unit 362,400 362,400 362,400

Variable O&M Costs

VOMR ($/MWh) Reagent 0.67 0.79 0.73 IPM equation

VOMW ($/MWh) Catalyst 0.35 0.35 0.35 Equation not provided in IPM Model

VOMM ($/MWh) Steam 0.008 0.009 0.008 IPM equation

VOM ($/MWh) Variable O&M 1.02 1.15 1.09

VOM ($/yr) one unit 1,134,172 1,460,063 1,654,422

Total O&M 1,496,572 1,822,463 2,016,822

Notes and Conclusions:

Inclusion of retrofit factor, altitude effects and EPC contacting arrangement results in SCR capital costs that are 70 % higher than EPA estimates ($56.7 vs. $33.3M
SCR Cost Comparison

AEPCORev 4 August 29, 2012

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A B C D E F G H I

SCR Capital Cost Comparison

Cost Item Cost Item Estimate Basis Cost Item Estimate Basis

BMR ($) 26,448,000 SCR Island Cost 19,680,000 SCR and Reagent Preparation Vendor quote 19,680,000 SCR and Reagent Preparation Vendor quote

2,974,000 Concrete and Piling Scale other projects, see notes 2,974,000 Concrete and Piling Scale other projects, see notes3,119,000 Steel Scale other projects, see notes 3,119,000 Steel Scale other projects, see notes2,948,000 CS Ductwork Scale other projects, see notes 2,948,000 CS Ductwork Scale other projects, see notes1,067,000 Insulation Scale other projects, see notes 1,067,000 Insulation Scale other projects, see notes1,755,000 Civil, and Architecture Scale other projects, see notes 1,755,000 Civil, and Architecture Scale other projects, see notes1,987,000 Mechanical Scale other projects, see notes 1,987,000 Mechanical Scale other projects, see notes4,902,000 Electrical Scale other projects, see notes 4,902,000 Electrical Scale other projects, see notes

662,000 I&C Scale other projects, see notes 662,000 I&C Scale other projects, see notes

Low Dust adjustment 25%

Assumed cost deduct to go from high dustSCR to low dust SCR, no basis was given forthe 25% factor included High dust to low dust adjustment included in vendor quote included High dust to low dust adjustment included in vendor quote

Adjusted BMR ($) 19,836,000 SCR Island Cost 39,094,000 SCR Island Cost 39,094,000 SCR Island CostBMF ($) 2,010,000 Base Reagent Prep Costs included Base Reagent Prep Costs included in vendor quote included Base Reagent Prep Costs included in vendor quoteBMA ($) Air Heater Modification/SO3 Modification Air Heater Modification/SO3 Modification Air Heater Modification/SO3 ModificationBMB ($) 3,753,000

ID or Booster Fans & Auxiliary PowerModifications 3,400,000 ID Fan Upgrade Scale other projects, see notes 3,400,000 ID Fan Upgrade Scale other projects, see notes

5,625,000 Auxiliary and Startup Transformers see notes 5,625,000 Auxiliary and Startup Transformers see notes

BM ($) 25,599,000 Bare Module Cost 48,119,000 Bare Module Cost 48,119,000 Bare Module CostBM ($/gross kW) 125 236 236Total Project Cost 2,406,000 Indirects 5% of BM, see notes

A1=10% of BM 2,560,000

Engineering and Construction ManagementCosts 4,812,000 Engineering and Construction Management Costs 10% of BM 4,812,000 Engineering 10% of BM, see notes

A2=10% of BM 2,560,000

Labor adjustment for 6 x 10 hour shiftpremium, per diem 4,812,000

Labor adjustment for 6 x 10 hour shift premium, perdiem 10% of BM 3,044,000 Escalation 5.5% of BM, Indirects, Engr.

11,676,000 Contingency 20% of BM, Ind., Eng., Esc.

A3=10% of BM 2,560,000 Contractor Profit and Fees 4,812,000 Contractor Profit and Fees 10% of BM 4,203,000 EPC Fee 6% of BM, Ind., Eng., Esc., Cont.CECC ($) = BM+A1+A2+A3 33,279,000 Capital, Engr. And Const. Cost Subtotal 62,555,000 Capital, Engr. And Const. Cost Subtotal 74,260,000 Capital, Engr. And Const. Cost SubtotalCECC ($/gross kW) 163 307 364B1=5% of CECC

Owners costs including all 'home office' costs(owner's engineering, manangement, andprocurement)

Owners costs including all 'home office' costs(owner's engineering, manangement, andprocurement) not allowed 8,911,000

General Owner Costs, Taxes, OwnerContingency 12% of CECC; see notes

B2=6% of CECC + B1 AFUDC AFUDC not allowed 2,495,000 AFUDC 3% of CECC and B1, see notesTPC ($) = CECC + B1 +B2 33,279,000 Total Project Cost (2009 $) 2 62,555,000 Total Project Cost (2012 $) 85,666,000 Total Project Cost (2012$)TPC ($/gross kW) 163 307 420

Cost Relative to EPA Cost 100% Cost Relative to EPA Cost 188% Cost Relative to EPA Cost 257% Cost Relative to EPA Cost

9,383,250 EPC Fee 15% of TPC as suggested in IPM

71,938,250 Total Project Cost (2012 $) w/ EPC Fee

216% Cost Relative to EPA Cost

Gross MW 204 204 204

IPM Model (EPA Subcontractor) BMcD Estimate applied to IPM Model with EPA Assumptions BMcD Estimate and Assumptions compared with IPM Model
SCR Cost Comparison

AEPCORev 4 August 29, 2012

515253545556575859606162636465666768697071727374757677

A B C D E F G H I

SCR O&M Cost ComparisonCapacity Factor (%) 71 Capacity Factor (%) 85 Capacity Factor (%)Fixed O&M Costs

FOMO ($/kW yr) 0.31 Operations Staff 0.37 Operations Staff Assume 0.75 operator per unitFOMM ($/kW yr) 1.47 Maintenanance L&M 1.92 Maintenanance L&M Assumed at 1% of SCR direct costFOM ($/kW yr) 1.78 Fixed O&M 2.28 Fixed O&MFOM ($/yr) one unit 362,400 Fixed O&M ($/yr) one unit 466,000 Fixed O&M ($/yr) one unit

Variable O&M Costs

VOMR ($/MWh) 0.79 Reagent 0.49 Reagent 200 pph NH3 required per unitVOMW ($/MWh) 0.35 Catalyst 0.36 Catalyst 200 m3 replaced every 2 yearsVOMM ($/MWh) 0.01 Soot blowing SteamVOM ($/MWh) 1.15 0.852VOM ($/year) one unit 1,460,063 1,294,600Annual O&M ($/yr) 1,822,463 1,760,600

Electrical Energy (MW) 1.02

Energy Task 8 document says typically 0.5%of output: EPA technicalsupport documentdoes not factor in energy costs 0.77 Energy

Estimated from flow and assumedpressure drop, power shown forone unit

Notes1 Tables show the estimated SCR cost for either Apache ST2 or ST3. The cost of LOw Nox burners and overfire air are not included in this estimate.2 Capital Costs from the EPA subcontractor are shown in 2009$ since that is the basis of the IPM model.

IPM Model (EPA Subcontractor) BMcD Estimate and assumptions compared to IPM Model
SCR O Cost Basis

AEPCO

Rev 4 August 29, 2012

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

A B

SCR O&M Costs1

Labor Cost ($/FTE) 100,000

Capacity Factor (%) 85%

Capital Cost $ 39,100,000

Maintenance Factor (L&M) 1.0%

Annual Maintenance (L&M) $ 391,000

Operating Labor (FTE)) 0.75

Labor Cost (FTE) $ 75,000

Catalyst Volume (m3/layer) 200

Catalyst Replacement Interval (years) 2

Catalyst Unit Cost ($/m3) $ 5,500.00

Annual Catalyst Replacement Cost ($/yr) $ 550,000

Ammonia Rate (lb/hr) 200

Ammonia Cost ($/ton) $ 1,000

Ammonia Cost ($/year) $ 744,600

Total Annual O&M Cost ($/yr) one unit $ 1,760,600

Notes:

1) O&M Costs are shown for one unit (ST2 or ST3)
ATTACHMENT “2”
Comparison of EPA v AEPCO re Cost Effectiveness of SCR+LNB+OFA

9/14/2012, chw

From AEPCO Estimates

for SCR plus EPA

estimates for LNB+OFA Notes

Apache 2 Apache 3 Apache 3

Unit Output 204 204 204

Capacity Factor 0.62 0.71 0.85

Annual Output (MWh) 1,107,965 1,268,798 1,518,984

Capital Cost of SCR+LNB+OFA 44,779,657 43,812,028 96,209,189 1

Capital Recovery Factor 0.0944 0.0944 0.0944

Annualized Rate ($/yr) 4,226,883 4,135,546 9,081,467

Fixed O&M ($/yr) 432,688 432,688 536,288 2

Variable O&M ($/kWh) 0.92 3

Variable O&M ($/yr) 1,210,656 1,532,869 1,400,929

Annual O&M ($/Year) 1,643,344 1,965,557 1,937,217 4

Total Annual Cost ($/Year) 5,869,299 6,103,078 11,018,684

Baseline Emission Rate (lb/MMBtu) 0.371 0.438 0.438

SCR Emission Rate 0.050 0.050 0.070 5

SCR Control Efficiency 87% 89% 84%

Baseline Emissions (tpy) 2,333 3,028 3,625

Heat Rate (Btu/kWh) 11,351 10,898 10,898

Heat Rate (MMBtu/hr) 2,316 2,223 2,223

Annual C.F. 0.62 0.71 0.71

Emission Rate (lb/hr) 116 111 156

Emission Rate (tpy) 314 346 484

Emissions Removed (tpy) 2,019 2,683 3,141

Annual Cost 5,869,299 6,103,078 11,018,684

Cost effectiveness ($/ton) 2,908 2,275 3,508

$/dv from Technical Support Document, Table 20

Greatest Improvement (Chiricahua WA), (dv) 1.59

Cumulative Improvement, (dv) 6.51

Annual Cost per "EGU BART Costs_Apache_Cholla_Coronado_Final2.xls 13,034,430 6

$/max dv, millions 8.2

$/cumulative dv, millions 2.0

$/dv derived from AEPCO's cost estimates

Annual Cost per AEPCO's estimate for Apache 2 and Apache 3 22,037,368

$/max dv, millions per AEPCO's estimate 13.9

$/cumulative dv, millions, per AEPCO's estimate 3.4

notes

1 AEPCO's estimate is $85,666 for SCR plus EPA's estimate of $10,543,189 for LNB+OFA

2 AEPCO's estimate of $466,000 for SCR plus EPA's estimate of $70,288 for LNB+OFA

3 AEPCO's estimate of $1,294,600 @ .85cf for SCR plus EPA's estimate of $88,816 @ .71cf for LNB+OFA

4 EPA's totals should actually be 5,870,227 and 6,101,103 per calculation

5 AEPCO estimates are based on meeting .07 lb./MMBtu emission rate

6 Footnote #94 of the TSD refers to a spreadsheet found on the EPA docket and notes cost differences due to tax and insurance

From Arizona Regional Haze Technical Support Document Dated

July 2012, data from Tables 16, 17, 18, and 19 for SCR+LNB+OFA
ATTACHMENT “3”
Arizona Electric Power Cooperative, Inc.

Estimated Revenue Requirements Associated With

SCR Installation on Steam Turbine Unit Nos. 2 & 3

September 18, 2012

rev 2

Col. 1 Col. 2 Col. 3

SCR Overfire Air &

Install Low NOX Burners Total

Line Description $ $ $

1 Assumptions:

2 Estimated Capital & O&M Costs-SCR Retrofit:

3 Capital Cost $ 171,332,000 $ 21,086,378 $ 192,418,378 LNB+OFA per EPA estimate

4 Fixed O&M Cost $ 932,000 $ 140,576 $ 1,072,576 LNB+OFA per EPA estimate

5 Variable O&M - 85% Capacity Factor $ 2,589,200 $ 199,180 $ 2,788,380 LNB+OFA per EPA estimate *.85/.71 c.f.

6 In Service Date 2017 2017

 7

8 Fixed Charges:

9 TIER Requirement 1.50 1.50

 10 Depreciation Rate 5.26% 5.26%

 11 Interest Rate 3.00% 3.00%

 12 Taxes & Insurance 2.00% 2.00%

 13 Margins - Per Tier Requirement 1.50% 1.50%

 14 Total Fixed Charge Rate 11.76% 11.76%

 15

 16 Revenue Requirements:

 17 Fixed Costs:

 18 Depreciation $ 9,017,474 $ 1,109,809 $ 10,127,283

 19 Interest - First Year 5,063,945 623,236 5,687,181

 20 Taxes & Insurance 3,426,640 421,728 3,848,368

 21 Margin 2,531,973 311,618 2,843,590

 22 Subtotal 20,040,031 2,466,391 22,506,422

 23 O&M Costs

 24 Fixed O&M 932,000 140,576 1,072,576

 25 Variable O&M 2,589,200 199,180 2,788,380

 26 Subtotal 3,521,200 339,756 3,860,956

 27

 28 Total Revenue Requirement $ 23,561,231 $ 2,806,147 $ 26,367,378

 29

 30 AEPCO Revenues Generated by Proposed Rates -

 31 Test Year Ended 12/31/2012 $ 150,397,406 $ 150,397,406 $ 150,397,406

 32

 33 Percent Increase 15.666% 1.866% 17.532%

 34

 35

Attachment 3_AEPCO - 9/18/2012
Arizona Electric Power Cooperative, Inc.

Estimated Revenue Requirements Associated With

SNCR Installation on Steam Turbine Unit Nos. 2 & 3

September 18, 2012

rev 2

Col. 1 Col. 2 Col. 3

SNCR Overfire Air &

Install Low NOX Burners Total

Line Description $ $ $

1 Assumptions:

2 Estimated Capital & O&M Costs-SNCR Retrofit:

3 Capital Cost $ 8,159,994 $ 21,086,378 $ 29,246,372 SNCR, LNB+OFA per EPA estimate

4 Fixed O&M Cost $ 205,894 $ 140,576 $ 346,470 SNCR, LNB+OFA per EPA estimate

5 Variable O&M - 85% Capacity Factor $ 2,808,964 $ 199,180 $ 3,008,144 SNCR, LNB+OFA per EPA estimate *.85/.71 c.f.

6 In Service Date 2017 2017

 7

8 Fixed Charges:

9 TIER Requirement 1.50 1.50

10 Depreciation Rate 5.26% 5.26%

11 Interest Rate 3.00% 3.00%

12 Taxes & Insurance 2.00% 2.00%

13 Margins - Per Tier Requirement 1.50% 1.50%

14 Total Fixed Charge Rate 11.76% 11.76%

 15

16 Revenue Requirements:

17 Fixed Costs:

18 Depreciation $ 429,473 $ 1,109,809 $ 1,539,283

19 Interest - First Year 241,179 623,236 864,415

20 Taxes & Insurance 163,200 421,728 584,927

21 Margin 120,590 311,618 432,208

22 Subtotal 954,442 2,466,391 3,420,833

23 O&M Costs

24 Fixed O&M 205,894 140,576 346,470

25 Variable O&M 2,808,964 199,180 3,008,144

26 Subtotal 3,014,858 339,756 3,354,614

 27

28 Total Revenue Requirement $ 3,969,300 $ 2,806,147 $ 6,775,447

 29

30 AEPCO Revenues Generated by Proposed Rates -

31 Test Year Ended 12/31/2012 $ 150,397,406 $ 150,397,406 $ 150,397,406

 32

33 Percent Increase 2.639% 1.866% 4.505%

 34

 35

Attachment 3_AEPCO - 9/18/2012