1

Summary of Additional Analysis 

Performed for Small Entity AEPCO

Table of Contents

 

I. Background ........................................................................................................................... 2

A. BART Regulations........................................................................................................... 2

B. Appendix Y on Affordability ........................................................................................... 3

II. AEPCO Background ............................................................................................................. 4

A. Equipment at Apache and Proposed Application of BART............................................. 4

B. AEPCO Membership and Management........................................................................... 5

C. Financial Interrelationships With Cooperatives............................................................... 7

D. Other Agreements and Power Sales................................................................................. 9

E. Government Regulation & Competition ........................................................................ 10

F. Financing ........................................................................................................................ 10

G. AEPCO’s Affordability Claim....................................................................................... 12

H. Financial and Economic Information Requested from AEPCO .................................... 14

III. NPRM Five-Factor BART Analysis.................................................................................. 16

IV. Small Entity Screening ...................................................................................................... 18

V. Supplemental Analysis of Costs of Compliance ................................................................ 18

VI. Small Entity Status and Affordability................................................................................ 22

VII. Rural Cooperative Financing and Affordability ................................................................ 24

VIII. Ratepayer Impacts and Customer Base .............................................................................. 26

IX. Market Share, Plant Operations......................................................................................... 29

X. Conclusion.......................................................................................................................... 31
2

I. Background

Our notice of proposed rulemaking (NPRM) was signed on July 2, 2012, and was 

published in the Federal Register on July 20, 2012.

1

In the NPRM, EPA proposed to disapprove 

portions of the Arizona Regional Haze State Implementation Plan (SIP) submitted by the

Arizona Department of Environmental Quality (ADEQ) on February 28, 2011, including 

disapproval of ADEQ’s BART determination for NOx controls at Units 2 and 3 of Arizona 

Electric Power Cooperative, Inc. (AEPCO)’s Apache Generating Station (Apache). The NPRM 

proposed to implement a Federal Implementation Plan (FIP) that contained BART emissions 

limits for NOX at Apache Units 2 and 3. 

In June 2012, AEPCO sent a letter to EPA which claimed that the emission limits 

consistent with Selective Catalytic Reduction (SCR) on Apache Units 2 and 3, which EPA was 

considering and subsequently proposed, were not affordable for a small cooperative utility. In the 

NPRM, we identified AEPCO as a small entity and discussed an initial economic impact 

assessment. We also requested information from AEPCO on the economics of operating Apache 

Generating Station and what impact the installation of SCR may have on the economics of 

operating Apache Generating Station. We received a description of plant conditions and potential 

economic effects before the NPRM was published,2and received additional information during 

the comment period. We noted in the NPRM that if our analysis of this information indicated 

that installation of SCR would have a severe impact on the economics of operating Apache 

Generating Station, we would incorporate such considerations in our selection of BART. 

On June 29, 2012, AEPCO provided supplemental information to EPA related to EPA’s 

proposed determination of the affordability of NOx controls at Apache Generating Station. 

AEPCO indicated that affordability of the controls is affected by its small size, the low income 

profiles of AEPCO’s service area, and AEPCO’s ability to access financing. In addition to the 

materials provided on June 29, 2012 and at EPA’s request, in early September, 2012, AEPCO 

provided supplemental information including rate case testimonies, power purchase contracts, 

and annual financial reports. This report summarizes our analysis of these information 

submittals, as well as our own analysis, in consideration of affordability issues for BART at 

Apache Generating Station.

A. BART Regulations 

As part of the 1990 Amendments to the CAA, Congress added section 169B to focus 

attention on regional haze issues. EPA promulgated a rule to address regional haze on July 1, 

1999. 64 FR 35714 (July 1, 1999) codified at 40 CFR part 51, subpart P (Regional Haze Rule).

The Regional Haze Rule, among other things, imposes BART emission limitations on BART 

eligible sources to improve visibility in Mandatory Federal Class I areas (National Parks and 

Wilderness areas).

 

1

77 FR 42834.

2 Docket Item C-16, Letter from Michelle Freeark (AEPCO) to Deborah Jordan (EPA), AEPCO’s Comments on 

BART for Apache Generating Station, June 29, 2012.
3

As discussed in more detail in the NPRM, EPA published the Guidelines for BART 

Determinations under the Regional Haze Rule at Appendix Y to 40 CFR part 51 (hereinafter 

referred to as the “BART Guidelines”) on July 6, 2005. The Guidelines are to assist states in 

determining which of their sources should be subject to the BART requirements and in 

determining appropriate emission limits for each such “subject-to-BART” source. In making 

BART determinations for fossil fuel-fired electric generating plants with a total generating 

capacity in excess of 750 megawatts, states must use the approach set forth in the BART 

Guidelines. States are encouraged, but not required, to follow the BART Guidelines in making 

BART determinations for other types of sources. States must address all visibility-impairing 

pollutants emitted by a source in the BART determination process. The most significant visibility 

impairing pollutants are SO2, NOX and PM.

Under CAA section 110(c), EPA is required to promulgate a Federal Implementation 

Plan within two years of the effective date of a finding that a state has failed to make a required 

SIP submission. Because we determined that Arizona failed to timely submit a Regional Haze 

SIP, we are required to promulgate a Regional Haze FIP for Arizona, unless we first approve a 

SIP that corrects the non-submittal deficiencies identified in our finding of January 15, 2009. 

Therefore, we proposed a FIP to address those portions of the SIP that we proposed to 

disapprove. 

In making BART determinations, section 169A(g)(2) of the CAA requires consideration 

of the following factors: 

(1) The costs of compliance; 

(2) the energy and non-air quality environmental impacts of compliance; 

(3) any existing pollution control technology in use at the source; 

(4) the remaining useful life of the source; and 

(5) the degree of improvement in visibility which may reasonably be anticipated to result 

from the use of such technology. 

B. Appendix Y on Affordability

The BART Guidelines allow for (but do not require) the consideration of “affordability” 

as part of the “costs of compliance” under certain circumstances, noting that:

1. Even if the control technology is cost effective, there may be cases where the 

installation of controls would affect the viability of continued plant operations.

2. 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 
4

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

reasoning... 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.3

Our NPRM stated “If we receive comments sufficiently documenting that installation of 

SCR may have a severe impact on the economics of operating Apache Generating Station, we 

may incorporate such considerations in our selection of BART.”

II. AEPCO Background 

A. Equipment at Apache and Proposed Application of BART

Apache consists of seven EGUs with a total plant-wide generating capacity of 560 

megawatts. In our NPRM, EPA proposed to approve ADEQ’s determination that Apache Units 

1, 2 and 3 are subject to BART. 

Apache Unit 1 is a wall-fired boiler with a net unit output of 85 MW that burns pipelinequality natural gas as its primary fuel, but also has the capability to use No. 2 through No. 6 fuel 

oils. ADEQ accepted AEPCO’s proposed BART recommendation of low-NOx burners (LNB) 

with flue gas recirculation (FGR) for Unit 1, but added a fuel restriction to allow only the use of 

natural gas. In our NPRM, we proposed to approve ADEQ’s NOx BART determination of LNB 

with FGR (natural gas usage only) with an emission limit of 0.056 lb/MMBtu for Apache Unit 1.

We also proposed to approve ADEQ’s emissions limits for SO2 and PM10 at Apache Unit 1.

Apache Units 2 and 3 are both dry-bottom, Riley Stoker turbo-fired boilers, each with a 

gross unit output of 204 MW. Apache Units 2 and 3 are coal-fired boilers operating on subbituminous coal.4 ADEQ’s BART determination for PM10 emission from Apache Units 2 and 3 

is upgrades to the existing ESP and a PM10 emissions limit of 0.03 lb/MMBtu for Units 2 and 3. 

(ADEQ referred to installation of a flue gas conditioning system, improvements to the scrubber 

bypass damper system, and implementation of programming optimization measures for ESP 

automatic voltage controls as potential upgrades. ADEQ did not provide a cost estimate for 

these upgrades). ADEQ’s BART determination for SO2 emissions from Apache Units 2 and 3 

was no new controls and an emission limit of 0.15 lb/MMBtu on a 30-day rolling average basis.

We proposed to approve ADEQ’s PM10 and SO2 BART determinations for Apache Units 2 and 

3. 

For NOx, ADEQ proposed LNB and over-fire air (OFA) for BART. In our NPRM, we 

proposed to disapprove ADEQ’s BART emissions limits for NOx at Apache Units 2 and 3. In our 

 

3 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.E.3

4

Between 1991 and 1993 Steam Units 2 and 3 were converted to dual fuel capability and can burn either coal or 

natural gas. In the documents submitted by AEPCO in support of its affordability determination, Units 2 and 3 are 

described as Coal/Natural Gas fueled units which can achieve full load on coal or gas. See Arizona Electric Power 

Cooperative Affirmation of Unit Life & Net Salvage Value Study, Final Report May 2011 by Black & Veatch at 

pages 2-1, 4-1.
5

NPRM, we proposed a BART emissions limit of 0.050, based upon selective catalytic reduction 

(SCR) with LNB and over fire air (OFA), the most stringent NOx control alternative considered 

by EPA for Apache Units 2 and 3.

TABLE 1–SUMMARY OF BART EMISSION LIMITS IN NPRM (TABLE 24 OF NPRM)

Unit Emission limitation (lb/MMBtu)

(rolling 30-boiler-operating-day average)

NOx PM10 SO2

Apache Generating Station Unit 1 0.056 0.0075 0.00064

Apache Generating Station Unit 2 0.050 0.03 0.15

Apache Generating Station Unit 3 0.050 0.03 0.15

TABLE 2–SUMMARY OF BART COMPLIANCE DATES IN NPRM (TABLE 25 OF NPRM)

Unit

Compliance Date

NOx PM10 SO2

Apache Generating Station Unit 1 Five years 180 days 180 days

Apache Generating Station Unit 2 Five years 180 days 180 days

Apache Generating Station Unit 3 Five years 180 days 180 days

B. AEPCO Membership and Management

AEPCO is a generation and transmission cooperative which owns and operates Apache. 

AEPCO is a, nonprofit Arizona rural electric generation cooperative, which is owned by several 

member distribution cooperatives. AEPCO provides power to these member cooperatives, as 

well as to municipalities and other customers. AEPCO and its members serve customers in nine 

Arizona counties (Cochise, Coconino, Graham, Greenlee, Mohave, Pima, Pinal, Santa Cruz and 

Yavapai), one county in California (Riverside) and two counties in New Mexico (Hidalgo and 

Grant).5 

 

5 webpage http://www.azgt.coop/about-us/arizona-electric-power-cooperative, accessed 11/9/12.
6

AEPCO has four classes of members: Class A members consist of three distribution 

cooperatives with all requirements contracts6, and three distribution cooperatives with partial 

requirements contracts. There are currently no Class B or C members. There is one Class D 

member, representing electric utilities other than Class A, B, or C with a written agreement for 

power and/or energy and/or substantial services, represented jointly by one director.7 

The Class A Member distribution cooperatives, which are also not-for-profit 

cooperatives, consist of: Anza Electric Cooperative, Inc. in south central California (Anza), 

Duncan Valley Electric Cooperative, Inc. (DVEC) in Greenlee County, AZ, Graham County 

Electric Cooperative, Inc. (GCEC) in Graham County, AZ, Mohave Electric Cooperative, Inc. 

(MEC) of Mohave County, AZ, Sulphur Springs Valley Electric Cooperative, Inc. (SSVEC) 

serving the major portions of Cochise County, AZ, and Trico Electric Cooperative, Inc. (Trico), 

serving the major portions of Pima County, AZ outside of Tucson.8

In addition to the Class A Member distribution cooperatives, Valley Electric Association 

(VEA), a Nevada cooperative, is a Class D Member of AEPCO that takes certain scheduling and 

trading services from AEPCO but does not have a wholesale power purchase contract with 

AEPCO.9

AEPCO is governed by a Board of Directors consisting of 13 Directors that oversee all 

aspects of its operation. One AEPCO Director represents AEPCO Class D Member, Valley EA. 

The other twelve Directors (two per Class A Member) are distribution cooperatives’ 

representatives who are selected by their respective distribution cooperative Boards. The Boards 

of each distribution cooperative are elected by their retail customers, which comprise their 

membership.

 

6

All requirements contracts are an agreement between an energy producer and a utility in which the utility requires 

all of its energy from a single source. In return for the right to exclusively supply the utility, the producer typically 

agrees to tie any changes to the price charged for the energy to the cost of producing it. 

7 Report of Independent Auditors and Financial Statements For Arizona Electric Power Cooperative, Inc. December 

31, 2011 and 2010 by Moss-Adams LLP signed April 23, 2012 (“Auditor’s Report”) at page 7.

8 AEPCO Apache Generating Station Comments to EPA on BART June 29, 2012 at page 1.

9

Id. at 2.
7

TABLE 3 – AEPCO MEMBERS (MODIFIED FROM AEPCO 2011 ANNUAL REPORT)

AEPCO Class A Members Headquarters 

City, State

Miles of 

Line

Meters 

Served

Members 

Per Mile

Anza EC

Gloria Britton, General Manager

Anza, CA 736 5,000 5

Duncan Valley EC

Michael Pearce, CEO

Duncan, AZ 453 2,315 3

Graham County EC

Steve Lines, General Manager

Pima, AZ 1,217 8,700 5

Mohave EC

J. Tyler Carlson, CEO

Bullhead City, 

AZ 1,512 38,728 21

Sulphur Springs Valley EC*

Creden Huber, CEO

Willcox, AZ 4,059 52,999 13

Trico EC*

Vin Nitido, CEO/General Manager

Marana, AZ 3,596 39,901 10

AEPCO Class B Member**

AEPCO Class D Member

Valley EA

Tom Husted, General Manager

Pahrump, NV

* Partial Requirements Member

** None currently. Salt River Project was a Class B member but that ended with the expiration 

of its contract on December 31, 2011.

C. Financial Interrelationships With Cooperatives

AEPCO supplies all or the major portion of the power needs of its six Class A Member 

distribution cooperatives under wholesale power contracts that are approved by the Rural 

Utilities Service (RUS).10 The Report of Independent Auditors and Financial Statements For 

Arizona Electric Power Cooperative, Inc. December 31, 2011 and 2010 by Moss-Adams LLP 

signed April 23, 2012 (“Auditor’s Report”) states:

- AEPCO holds all requirements wholesale power sales contracts with three of its six Class 

A member cooperatives pursuant to which each Class A member agrees to purchase from 

the Cooperative all of its electric power requirements. These all requirements power 

contracts expire December 31, 2035, and will remain in effect thereafter until terminated 

by either party upon six months notice. Management believes the Cooperative will be 

able to fulfill its requirements on these long-term contracts. One Class A all requirements 

member became a partial requirements member effective January 1, 2011.11

 

10 AEPCO Apache Generating Station Comments to EPA on BART June 29, 2012 at page 2.

11 Auditor’s Report at page 17.
8

- AEPCO holds partial requirements wholesale power sales contracts, expiring December 

31, 2035, with three of its Class A member cooperatives pursuant to which the Class A 

members have agreed to purchase from the Cooperative electric energy and capacity up 

to the member’s allocated capacity percentage in the Cooperative’s total resources 

existing at the time of execution of the contract. One Class A member cooperative that 

was an all requirements member for 2010 became a partial requirements member 

effective January 1, 2011.”12

- Class D membership requires the member to enter into a service contract for scheduling 

and trading services for a minimum term of 2 years. The service contract with 

[AEPCO’s] Class D member is renewed annually until terminated by either party upon a 

six months written notice.13

AEPCO’s all requirements members (ARMs) are Anza Electric Cooperative, Inc. (Anza), 

Duncan Valley Electric Cooperative, Inc. (DVEC), and Graham County Electric Cooperative, 

Inc. (GCEC).14 AEPCO’s ARMs each have a wholesale power contract with AEPCO that 

requires them to purchase power and energy solely from AEPCO. AEPCO is obligated to 

provide all elements of power supply required to meet the peak demands and energy 

requirements of the totality of their loads. AEPCO is the ARM’s agent for determining the 

economic dispatch of the collective “Allocated Capacity Percentage” (ACP) shares of the ARMs, 

including determining when it is reasonable to use market energy rather than energy from the 

Apache units, taking into account their share of the contractual minimum take from the coal-fired 

steam Units 2 and 3. The ARMs have no ability to purchase power outside of AEPCO but like 

the partial requirements members (PRMs), the ARMs must pay AEPCO fully for their respective 

ACP shares of the capacity-related costs of AEPCO’s Resources consisting of: (i) the fixed costs 

(depreciation, interest, property taxes, insurance and margin) and (ii) the fixed operation and 

maintenance costs (manpower, overhauls, capital replacements, demand charges on purchased 

power, fixed gas transportation charges, Southwest Transmission Cooperative, Inc. reserved 

transmission costs, etc).15

AEPCO’s PRMs are Mohave Electric Cooperative, Inc. (MEC), Sulphur Springs Valley 

Electric Cooperative, Inc. (SSVEC) and Trico Electric Cooperative, Inc. (Trico).16 Each PRM 

has an AEPCO wholesale power contract that specifies as a percentage (the ACP) its undivided 

interest in AEPCO Resources (including the units at AEPCO’s Apache Generating Station, 

which is AEPCO’s only generation station). Each PRM must pay AEPCO fully for its ACP 

share of the capacity-related costs of AEPCO’s Resources, (i) the fixed costs (depreciation, 

interest, property taxes, insurance and margin ) and (ii) the fixed operation and maintenance 

costs (manpower, overhauls, capital replacements, demand charges on purchased power, fixed 

gas transportation charges, SWTC reserved transmission costs, etc). These costs are billed by 

 

12 Id.

13 Id.

14 AEPCO information submission, August 23, 2012, in response to EPA Question 13.

15 Id.

16 Id.
9

AEPCO to the PRMs whether or not the PRMs schedule energy from their ACP share of AEPCO 

Resources. Only the energy charge components (fuel and fuel handling, energy costs from 

purchase power agreements) are charged based on use by a PRM. To the extent the PRM load 

exceeds contract minimums they are free to purchase energy from any external resource.17

Under the wholesale power contracts, the fixed and the majority of the operations and 

maintenance costs of AEPCO’s generation units are allocated among the Class A members based 

on an Allocated Capacity Percentage (ACP) that is proportional to the size of the respective 

cooperative to the total in year 2000. The ACP of each Class A member for costs related to 

AEPCO’s Apache generation units is as follows: ANZA – 2.5%, DVEC – 1.3%, GCEC – 7.6%, 

MEC - 35.8%, SSVEC – 31.7%, and TRICO – 21.1%. Under the wholesale power contract, the 

fuel and fuel handling costs are energy-related charges allocated among the Class A members 

based on the metered energy used by each cooperative in serving the respective loads of its retail 

electric membership. The installation of new emission controls at Apache will increase all of the 

components of AEPCO’s costs, fixed, operations and maintenance, and energy.18

In turn, AEPCO is a member of a transmission cooperative. In 1999, AEPCO restructured 

into three legally separate cooperatives: AEPCO, Sierra Southwest Cooperative Services, Inc., 

(Sierra), and Southwest Transmission Cooperative, Inc. (SWTC). Under this restructuring, 

AEPCO retained the power generation function, SWTC became the transmission and power 

delivery cooperative of which AEPCO is a Class B member,19 and Sierra became the staffing and 

service provider, and collectively they are known as Arizona’s G&T Cooperatives.20 AEPCO 

and SWTC have long term arrangements for SWTC to provide transmission services.21 

D. Other Agreements and Power Sales

AEPCO holds three nonmember scheduling and trading service agreements that have a 

six month termination notice, two scheduling and trading service agreements with 90-day 

termination notices, a nonmember power sales agreement of 8 MW which expires on September 

30, 2012, and a nonmember scheduling and energy trading agreement with an initial term 

through September 30, 2016, which continues thereafter until terminated by either party upon a 

two (2) year written notice.22 AEPCO’s annual report discusses scheduling and trade service 

agreements with Central Arizona Water Conservation District, Valley Electric Association in 

Pahrump, Nevada, the City of Safford and the Town of Thatcher, the San Carlos Irrigation 

Project, and Electrical Districts 4 and 5.23

 

17 Id.

18 AEPCO Apache Generating Station Comments to EPA on BART June 29, 2012, at 2 - 3.

19 Auditor’s Report at 25. 

20 http://www.azgt.coop/about-us/arizona-electric-power-cooperative, accessed 11/9/12.

21 Auditor’s Report at 18 and 25.

22 Id. at 17.

23 Id. at 25.
10

E. Government Regulation & Competition

AEPCO and the five Arizona Class A member distribution cooperatives are regulated by 

the Arizona Corporation Commission (ACC). 24 The ACC’s electric competition rules are in 

place, but the service areas of AEPCO’s Class A member distribution cooperatives have not been 

opened to competition by the ACC and will not be until the ACC hears and decides those 

cooperatives’ stranded cost cases.25 Stranded costs result when consumers select another power 

supplier and no longer contribute revenue to the incumbent utility for cost obligations which 

were incurred for their benefit before customer choice under an obligation to serve requirement 

Currently, AEPCO provides electric power to its all and partial requirements members pursuant 

to long term contracts, now extended to December 31, 2035, for resale to their “standard offer” 

customers at regulated rates. AEPCO states in its Consolidated Financial Statements that it is 

currently recovering its costs of providing electric service from regulated rates charged to its 

members for power sold to “standard offer” customers.26

For financing authority, AEPCO files an application with the ACC listing the projects to 

be financed along with justification and the proposed sources of financing, including interim 

financing. AEPCO states that an application for financing authority usually takes six to eight 

months to adjudicate and costs approximately $50,000 in legal fees and expenses in addition to 

AEPCO’s internal labor and expenses.27 To obtain regulatory approval of rate relief, AEPCO is 

required to file an application which is reviewed by the ACC for sufficiency and then scheduled 

for rate hearings. The adjudication process for an application for rate relief takes approximately 

thirteen months for a standard rate case and costs approximately $500,000 to $700,000 in legal 

and consulting fees and expenses as well as AEPCO staff labor and expense.28

As discussed in the section on Financing, directly below, AEPCO must also comply with 

the regulations of the RUS, as the holder of AEPCO’s debt related to Apache Generating 

Station.29 

F. Financing 

AEPCO states that all of AEPCO’s capital expenditures are funded through loans 

guaranteed by RUS, and that AEPCO’s wholesale power contracts with the Class A Members 

represent RUS’ security behind AEPCO’s debt. To fund construction projects, AEPCO must 

 

24 AEPCO Apache Generating Station Comments to EPA on BART June 29, 2012, at 2.

25 AEPCO information submission, August 23, 2012; Consolidated Financial Statements, December 31, 2003 and 

2002, “Retail Electric Competition” section, Exhibit GEP-1. 

26 Id.

27 AEPCO Apache Generating Station Comments to EPA on BART June 29, 2012 at 3.

28 Id.

29 Id. at 2.
11

prepare and provide to RUS construction work plans and projects, and seek loan authorizations 

for those plans and projects under 7 CFR 1710 of the Federal regulations.30

As of December 31, 2011, AEPCO had assets of approximately $350 million, liabilities 

of roughly $254 million and patronage capital (equity from Class A members) of about $96 

million. As a not-for profit cooperative, any revenues in excess of expenses are considered as 

contributed capital or patronage capital to be refunded to the Class A Members subject to RUS 

mortgage restrictions.31

As of December 31, 2011, AEPCO long term financing consisted of approximately $142 

million of Rural Utilities Services (RUS) guaranteed Federal Financing Bank (FFB) notes, $23 

million of National Rural Utilities Cooperative Finance Corporation (CFC), $14 million of CFC 

Guaranteed Solid Waste Disposal Revenue Bonds and $16 million of other debt.32 AEPCO assets 

are secured by a Consolidated Mortgage, Security Agreement and Financing Statement, dated 

August 3, 2009, made by and among AEPCO, RUS and CFC. 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 best two out of three most recent 

years. The ACC requires AEPCO to have a TIER and DSC greater than the RUS minimum.33

In addition to this rate design covenant, the mortgage has an additional 25 covenants 

which pledge to RUS all of AEPCO’s rights under its contracts and agreements, subjecting 

substantially all of AEPCO’s properties to its mortgage liens to secure present and future 

indebtedness to RUS. The mortgage also contains provisions for RUS control and supervision in 

such areas as:

1. Financial books and financial records;

2. Risk management;

3. Limitations of system extensions and additions; contracts for operation and 

maintenance; power purchases; power sales; service contracts; deposits of funds;

4. Limitations of patronage refunds and other cash distributions;

5. Compliance with loan agreements; and

6. Limitations on loans, investments and other obligations.

 

30 Id.

31 Id. at 3-4.

32 Id. at 4.

33 Id.
12

In addition to long term debt, AEPCO has a $25 million unsecured operating line of 

credit with CFC as well as a member investment program to provide working capital support.34

AEPCO states that its principal source of future financing is FFB Loans which are 

guaranteed by RUS. In order to secure additional FFB financing, AEPCO must file a loan 

application to RUS with sufficient documentation which demonstrates the need for the projects 

to be financed as well as a financial forecast which supports the application. A typical RUS loan 

application takes 8 to 12 months to be approved. After approval of the loan application, the 

Office of General Counsel 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 term treasury rate plus 1/8 of a percent. In addition to FFB 

financing, AEPCO may also borrow from CFC to either supplement financing requirements or to 

provide interim financing needs until FFB loan funds can be drawn. CFC financing requires a 

lien accommodation from RUS in order to be secured by the mortgage. CFC loan applications 

requiring lien accommodations from RUS generally take about the same time as RUS loan 

applications. Typically, CFC loan interest rates are 1.00% to 1.50% 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 also work with CFC to obtain pollution control financing 

through revenue bonds issued through the Pollution Control Corporation of Cochise County, 

Arizona.35

G. AEPCO’s Affordability Claim

AEPCO’s affordability claim has three aspects: First, AEPCO disputes the capital costs 

utilized by EPA. AEPCO states that EPA erred in disregarding ADEQ’s analysis & AEPCO’s 

initial cost estimates and that we under-estimated the costs of SCR.

Second, AEPCO states that as a small rural electric cooperative, it faces particular 

challenges in affording the installation of SCR controls on Apache Units 2 and 3. AEPCO states 

that there are implications from AEPCO’s cooperative status, including limitations imposed by 

the U.S. Department of Agriculture’s Rural Utilities Service (RUS). AEPCO states that SCR on 

Apache Units 2 and 3 is unaffordable to AEPCO because:

- AEPCO’s rural electric cooperative status affects its financing. AEPCO has no access 

to capital markets, but must seek financing from RUS. RUS has limited budget and 

AEPCO must compete against other coops and rural utilities.

- AEPCO operates only a single station.

- Only approximately 147,000 meters in the service population of its Class A members.

 

34 Id. at 4-5.

35 Id. at 7.
13

- Almost all of the effective power at the Apache Station is subject to BART 

requirements (little or no ability to “spread costs” over unaffected units, other facilities, 

or a large system of units and ratepayers).

- AEPCO’s “members will disapprove the project” if rates substantially above what its 

members would otherwise pay.

- AEPCO has limited internal resources, relatively small capital reserves. Limited 

working capital

- AEPCO needs prior government approval to raise money under current RUS and 

CFC agreements

Finally, AEPCO states that it serves a predominantly rural and poor customer base, which 

would be unable to absorb this size of rate increase without hardship. AEPCO argues that the 

cost of SCR on Apache Units 2 and 3 is unaffordable because operating costs are unreasonable 

based on AEPCO’s net revenues over expenses; financing costs are unreasonable based on

AEPCO’s resources; and AEPCO membership base cannot bear the estimated financing costs.

Regarding potential effects on product price, AEPCO estimates that its rates would need 

to rise by at least 17.5% to cover the cost of SCR on Apache Units 2 and 3, and states that this 

estimated rate increase will be:

- Harmful to AEPCO rural consumers and not-for-profit members

- Large enough to create uncertainty on ACC 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.”36 

Regarding potential effects on market share and profitability, AEPCO argues that our 

proposed BART determination will:

- Probably require a substantial rate increase

- Probably require renegotiation of existing 2009 consolidated mortgage as AEPCO 

would no longer meet the TIER and DSC requirements of its covenants

- Create downward pressure on AEPCO’s market share. AEPCO states that it must 

compete with general power pooling and also with its partial requirements members, who 

may elect to purchase power “against” the Apache Station units or, along with the all-

 

36 AEPCO September 18, 2012 letter at page 10.
14

requirements members, to shutdown those units in favor of a purchase power agreement 

(PPA) should the Apache’s Station’s costs go unduly out of line with the cost of power 

on the open market.37 

Regarding potential impact on plant operations, AEPCO argues that our proposed 

BART determination will:

- Increase AEPCO’s long term debt by 98%

- Severely reduce AEPCO’s working capital

- Require bridge financing at additional expense

- Impose substantial additional burdens on AEPCO at a time when contracts on 

Apache Unit 1 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.38 

H. Financial and Economic Information Requested from AEPCO

EPA requested the following information from AEPCO39: Current and projected net 

income/earnings for the company and contributed capital/patronage capital; information on the 

customer base of member cooperatives and ratepayers; and information on financing available to 

AEPCO for any new capital investment (such as pollution control equipment). Our request for 

documents from AEPCO included documents from AEPCO members if such documents are 

relevant to the analysis. 

We requested documentation for the information mentioned in the preceding paragraph, 

including:

- Annual reports: At a minimum, the most recent annual report for AEPCO, if this 

includes financial data for the last fiscal year and operating data.

- Documents on AEPCO’s member investment program to provide working capital 

support referenced in AEPCO’s June 29, 2012 letter.

- An estimate of the remaining useful life of each of the units at Apache Generating 

Station.

 

37 Id. at 10.

38 Id. at 11.

39 EPA’s August 6, 2012 letter to AEPCO.
15

- Clarification of the schedule and amortization period used for analysis of capital 

investments (including pollution controls), and the ability of AEPCO to recoup capital 

costs from their rate base over time. 

- Documentation on current rate structures, including information on seasonal and peak 

rates as available. Detailed analysis regarding anticipated rate increases necessary to 

support an SCR-based BART determination.

- Consolidated Mortgage, Security Agreement and Financing Statement, dated August 3, 

2009, referenced in AEPCO’s June 29, 2012 letter.

- Documents on the $25 million unsecured operating line of credit with National Rural 

Utilities Cooperative Finance Corporation, referenced in AEPCO’s June 29, 2012 letter.

- Wholesale power contracts that are approved by the United States Department of 

Agriculture’s Rural Utilities Service, and related documents including any information 

AEPCO would like EPA to consider regarding Times Interest Earned Ratio (TIER) 

ratios.

- Internal projections as to future performance: financial projections for AEPCO, 

prepared by or for the company. These projections can include those that have been filed 

with the Arizona Corporation Commission (ACC).

- Documentation of grid capacity limitations on AEPCO’s ability to import power.

- Information on the customers served by member cooperatives (socio-economic 

characteristics of the rate-payers, zip codes served), to support the claim in your June 29, 

2012 letter (p. 8) regarding the disproportionate burden of pollution control requirements 

on AEPCO customers.

- Documents regarding demand elasticity of the customer base. In the event of AEPCO 

rate increases, what are the options for (and limitations on) individual Class A members 

for purchasing power outside of AEPCO?

- Documents regarding AEPCO’s ability to access financing from the National Rural 

Electric Cooperative Finance Corporation.

- Documents to evaluate AEPCO’s claims regarding rate case applications (such as past 

rate cases evaluating AEPCO’s applications).

- Other internal records that document available equity and debt for AEPCO’s operations: 

For our analysis, EPA is seeking the most recent financial statement that has current and 

projected estimates of available equity and debt to the firm for capital investment. This 

financial statement may be part of a filing with the ACC.
16

We also asked for recommended points of contact, with contact information, for entities 

mentioned in AEPCO’s prior submissions to EPA, although we noted that EPA is not required to 

contact any of these entities, but we sought this information in case EPA determines that it is 

appropriate to reach out for further information in order to perform our analysis.

III. NPRM Five-Factor BART Analysis 

EPA conducted a five-factor BART analysis of Apache Units 2 and 3, documented in our 

NPRM. 40 We focused our technical analysis on evaluation of control effectiveness the feasible 

control technologies, evaluation impacts, and evaluation of visibility results. The NPRM 

discussed analysis of energy and non-air environmental impacts (including energy impacts, 

ammonia adsorption, and safety), pollution control equipment in use at Apache, remaining useful 

life, and degree of improvement in visibility. Cost of compliance is discussed in more detail 

below, so this section will focus on the visibility benefits that were estimated in the NPRM based 

on the proposed controls. 

In considering the results of the five-factor analysis, we noted in the NPRM that the 

remaining useful life of the source, as indicated previously by the plant economic life of Apache 

Units 2 and 3, is incorporated into control cost calculations as a 20-year amortization period. In 

addition, the presence of existing pollution control technology is reflected in the cost and 

visibility factors as a result of selection of the baseline period for cost calculations and visibility 

modeling. For Apache Units 2 and 3, a baseline period (2008 to 2010) was selected that reflects 

the currently existing pollution control technology (OFA). In examining energy and non-air 

quality impacts, we noted certain potential impacts resulting from the use of ammonia injection 

associated with the SNCR and SCR control options, but did not consider these impacts sufficient 

enough to warrant eliminating any of the available control technologies.

Table 4 shows the visibility benefits from our proposal estimated in the NPRM. As we 

noted in the NPRM, we used annual capacity factors of 62 percent (Apache 2), and 71 percent 

(Apache 3). In contrast, the annual capacity factors AEPCO used for each unit were 92 percent 

(Apache 2), and 87 percent (Apache 3). By using these lower capacity factors, our estimates of 

total annual emissions (and correspondingly, the annual emission reductions) for each control

scenario was lower than AEPCO’s estimates. Since cost-effectiveness ($/ton) is calculated by 

dividing annual control costs ($/year) by annual emission reductions (tons/year), the use of 

emission reductions based on lower capacity factors will increase the cost per ton of pollutant 

reduced.

 

40 77 FR 42834.
17

TABLE 4 – APACHE UNITS 2 AND 3: EPA’S VISIBILITY IMPROVEMENT FROM NOX CONTROLS 

(TABLE 17 IN THE NPRM)

Class I Area Baseline 

Impact

(dv)

Improvement 

from LNB

(dv)

Improvement 

from SNCR

(dv)

Improvement 

from SCR

(dv)

Chiricahua NM 3.41 0.44 0.82 1.51

Chiricahua WA 3.46 0.53 1.00 1.59

Galiuro WA 2.22 0.39 0.65 1.10

Gila WA 0.63 0.14 0.22 0.37

Mazatzal WA 0.28 0.05 0.09 0.14

Mount Baldy WA 0.28 0.07 0.11 0.18

Saguaro NP 2.49 0.38 0.66 1.16

Sierra Ancha WA 0.29 0.06 0.10 0.14

Superstition WA 0.61 0.10 0.19 0.31

Cumulative dv 13.67 2.14 3.83 6.51

# areas >= 0.5 6 1 4 4

$/max dv, millions $4.8 $6.0 $8.7

$/cumulative dv, 

millions $1.2 $1.6 $2.1

In analyzing visibility improvement, EPA evaluated LNB, SNCR (including LNB), and 

SCR (including LNB) applied to both Units 2 and 3. SCR was assumed to give a control 

effectiveness of 87 percent and 89 percent for Units 2 and 3, respectively (less than 90 percent

due to the 0.05 lb/MMBtu NOx lower limit assumed for SCR). The nine Class I areas within 300 

km of Apache were modeled; they are in the states of Arizona and New Mexico. The NPRM 

noted that improvements from SCR are substantially greater than for the other candidate controls

and that the modeled degree of visibility improvement supports SCR as BART for Apache.

Our consideration of degree of visibility improvement in the NPRM focused primarily on 

the improvement from base case impacts associated with each control option. While each of the 

available NOx control options achieves some degree of visibility improvement, we considered

the improvement associated with the most stringent option, SCR with LNB and OFA, to be 

substantial. Our consideration of cost of compliance focused primarily on the cost-effectiveness 

of each control option, as measured in cost per ton and incremental cost per ton of each control 

option. Despite the fact that the most stringent option, SCR with LNB and OFA, is the most 

expensive of the available control options, we considered it cost-effective on an average basis as 

well as on an incremental basis when compared to the next most stringent option, SNCR with 

LNB and OFA.

As a result, the NPRM stated that we consider the most stringent available control option, 

SCR with LNB and OFA, to be both cost-effective and to result in substantial visibility 

improvement, and that the energy and non-air quality impacts are not sufficient to warrant 
18

eliminating it from consideration. Therefore, the results of our five-factor analysis indicated that 

NOx BART for Apache Units 2 and 3 is SCR with LNB and OFA.

IV. Small Entity Screening

A small business, as defined by the Small Business Administration’s (SBA) regulations 

at 13 CFR 121.201, includes firms primarily engaged in the generation, transmission, and/or 

distribution of electric energy for sale if, including affiliates, the total electric output for the 

preceding fiscal year did not exceed 4 million megawatt hours (MWh). In 2011, AEPCO 

member cooperatives sold 2,453,272 MWh of electricity.41 Because AEPCO sold under 3 

million megawatt hours in 2011, we determined that AEPCO is a small entity. 

Because AEPCO meets this definition of a small entity, we conducted an initial 

assessment of the potential adverse impacts on AEPCO of requiring SCR with LNB and OFA. 

Using publicly available information, we estimated in the NPRM that the annualized cost of 

requiring SCR in Apache Units 1 and 2 would likely be in the range of 3 percent of AEPCO’s 

assets and between 6 and 7 percent of AEPCO’s annual sales. 

V. Supplemental Analysis of Costs of Compliance 

AEPCO disputes the capital costs utilized by EPA in our NPRM. AEPCO states that EPA 

erred in disregarding ADEQ’s analysis & AEPCO’s initial cost estimates, by failing to review 

the affordability of the final cost on AEPCO as a single facility cooperative, and that we underestimated the site-specific costs incurred by AEPCO in installing SCR. Discussing combined 

costs, AEPCO states:

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...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.42

In developing our proposed action for Apache Units 2 and 3, we examined the cost 

estimates for the SCR with LNB and OFA control option contained in AEPCO’s original BART 

analysis.43 By comparison, the SCR with LNB and OFA cost estimates we developed for our 

 

41 Annual Report for year ending Dec. 31, 2011 from AEPCO to Arizona Corporation Commission. Received May 

14, 2012. Available at 

http://www.azcc.gov/Divisions/Utilities/Annual%20Reports/2011/Electric/Arizona_Electric_Power_Cooperative_In

c.pdf.

42 APECO September 18, 2012 letter, at 7.

43 Docket Item No. B-01, Arizona Regional Haze SIP, Appendix D, at 49. 
19

proposed action44 do not differ significantly. A comparison of capital cost, total annual cost, and 

cost-effectiveness for these two estimates are summarized in the tables below:

TABLE 5 –APACHE UNIT 2: COST COMPARISON OF SCR WITH LNB AND OFA

Capital Cost

($)

Total Annual 

Cost

($/yr)

Emissions 

Removed

(tpy)

Average 

CostEffectiveness

($/ton)

EPA estimate $44,779,657 $5,869,299 2,019 $2,908

AEPCO original estimate $48,740,300 $6,102,740 3,250 $1,878

TABLE 6 –APACHE UNIT 3: COST COMPARISON OF SCR WITH LNB AND OFA

Capital Cost

($)

Total Annual 

Cost

($/yr)

Emissions 

Removed

(tpy)

Average 

CostEffectiveness

($/ton)

EPA estimate $43,812,028 $6,103,078 2,683 $2,275

AEPCO original estimate $48,740,300 $6,062,302 2,778 $2,182

While we used a different cost estimation methodology than AEPCO, our estimates of 

capital cost and total annual cost are very similar to the company’s original estimates and differ, 

for example, by only 8 percent and 4 percent (respectively) at Apache Unit 2. More importantly, 

we note that AEPCO’s original estimates for Apache Units 2 and 3 actually show lower $/ton 

values than our own, meaning that AEPCO’s original estimate indicates that SCR with LNB and 

OFA is cost-effective.

In submitted comments, AEPCO provided multiple analyses comparing our SCR (stand 

alone) cost estimate with revised estimates prepared by engineering firm Burns and 

McDonnell.45 AEPCO provided two sets of revisions: one in which it retained our assumptions 

regarding costs not included in the CCM, such as AFUDC and owner’s costs, and another set in 

which it included those costs. In both cases, these analyses also contained revisions in order to 

reflect capital costs and O&M costs that AEPCO considered more representative and appropriate 

for the Apache units. These revisions included the following:

 Higher bare module SCR costs

 Use of higher capacity factor (0.85 for both units, compared to 0.62 and 0.71)

 

44 77 FR 42856, Table 16. 

45 The analysis was included in Attachment 1 to AEPCO’s Comments on the page titled “SCR Capital Cost 

Comparison.”
20

 Lower SCR NOX removal efficiency (based on an SCR emission rate of 0.07 lb/MMBtu, 

compared to 0.05 lb/MMBtu)

 Inclusion of an additional 15 percent engineering, procurement, contracting fee (not 

included in our cost estimate)

 And certain other different assumptions regarding O&M costs that result in similar total 

O&M costs 

AEPCO then included our estimate of LNB and OFA costs with its SCR (standalone) costs to 

arrive at its overall cost estimate for the SCR with LNB and OFA control option. As discussed 

below, we used a 30-day rolling average BART emission limit of 0.070 lb/MMBtu for Apache 

Units 2 and 3, and a “bubble” across these two units to provide AEPCO an adequate margin for 

compliance. Although this 30-day limit accommodates the possibility of multiple startups in a 

given 30-day period, we expect such spikes to be smoothed out over the course of a year, so that 

the annual average remains closer to 0.05 lb/MMBtu.

For the other items noted above, we are willing to defer to AEPCO’s judgment on these 

issues in order to address AEPCO’s concerns that our cost estimate was insufficiently sitespecific. As a supplemental cost estimate, we have used the version of AEPCO’s cost estimate 

that adheres to our assumptions regarding costs that are allowed by the CCM. As shown in Table 

7, this results in revised SCR with LNB and OFA cost-effectiveness values of $3,450/ton and 

$2,973/ton for Apache 2 and 3, respectively, that are still within a range that we consider costeffective when considered in conjunction with the visibility improvement associated with SCR.
21

TABLE 7 –APACHE 2 AND 3: COST ESTIMATE OF SUPPLEMENTAL SCR WITH LNB AND OFA

Parameter Apache 2 Apache 3 Notes

SCR Capital Cost ($) $71,938,250 $71,938,250 1

LNB+OFA Capital Cost ($) $10,543,189 $10,543,189 2

SCR+LNB+OFA Capital Cost ($) $82,481,439 $82,481,439

Interest Rate (percent) 7.0 per cent 7.0 per cent

Equipment Lifetime (years) 20 20

Capital Recovery Factor 0.094 0.094 2

Annualized Capital Cost ($/yr) $7,785,664 $7,785,664

Fixed O&M ($/yr) $466,000 $466,000 1

Variable O&M ($/yr) $1,294,600 $1,294,600 1

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

Total Annual Cost ($/yr) $9,546,264 $9,546,264

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

Baseline Emission Rate 

(annual average lb/MMBtu)

0.371 0.438

SCR Emission Rate 

(annual average lb/MMBtu)

0.050 0.050 2

SCR Control Efficiency (percent) 87 percent 89 percent

Annual Capacity Factor 0.85 0.85 1

Baseline Emissions (tpy) 3,198 3,625

SCR Emissions (tpy) 431 414

Emissions Removed (tpy) 2,767 3,211

Annual Cost ($/yr) $9,546,264 $9,546,264

Emissions Removed (tpy) 2,767 3,211

Average Cost-Effectiveness ($/ton) $3,450 $2,973

Our supplemental analysis estimated that SCR with LNB and OFA at Apache Units 2 

and 3 would have total annual costs of $19.1 million. On a maximum deciview (dv) 

improvement basis, our supplemental analysis estimates a cost of $12.7 million per dv for 

improvements at the Class I area with the largest single improvement, and $3.1 M per dv for 

cumulative improvements at the multiple Class I areas affected by emissions from Apache Units 

2 and 3. These BART cost figures do not include other expenditures that will be required for

Apache Units 1, 2 and 3 to meet the BART emission limits included in Arizona’s Regional Haze 

SIP. Under the CAA, EPA is not permitted to consider economic feasibility when taking action 
22

on a SIP.46 To the extent these costs are relevant to our FIP action, we note that AEPCO did not

provide any cost estimates for the required upgrades to the existing ESPs and scrubbers at 

Apache Units 2 and 3 and estimated that the total first year annualized cost of the required 

controls at Apache Unit 1 (LNB and FGR) would be $0.552 million.47 These costs are two orders 

of magnitude lower than the SCR costs. Therefore, even if we were to take them into account, 

they would not substantially affect our analyses. Before proceeding to a more in-depth 

examination of the affordability issue, we note that this supplemental analysis, using revised cost 

figures, does not change our initial five-factor BART analysis that supports SCR. 

VI. Small Entity Status and Affordability

In support of its position that SCR with LNB and OFA at Apache Units 2 and 3 is 

unaffordable, AEPCO states that as a small rural electric cooperative, it faces particular 

challenges in affording the installation of such controls on Apache Units 2 and 3. 

AEPCO states that there are implications from AEPCO’s small size because:

- AEPCO operates only a single station.

- Only approximately 147,000 meters in the service population of its Class A 

members.

- Almost all of the effective power at the Apache Station is subject to BART 

requirements (little or no ability to “spread costs” over unaffected units, 

other facilities, or a large system of units and ratepayers).

EPA agrees that these factors are part of AEPCO’s status as a small entity, but size alone 

does not determine whether installation of SCR on Apache Units 1 and 2 would be affordable.

Our initial Screening Analysis, discussed in the NPRM, and a follow-up Supplemental 

Economic Analysis48 both analyzed the potential economic impact of our proposed rule on 

AEPCO through the analytical framework typically applied to small entities in a regulatory 

flexibility analysis. Under this small entity screening framework, we concluded that installation 

of SCR on Apache Units 2 and 3 could have a significant impact on AEPCO.49 However, this 

small entity analysis did not did not directly address the question of affordability (i.e. whether 

our proposed BART determination would affect the viability of continued plant operations).

 

46 Union Electric Co., v. EPA, 427 U.S. 246, 255-66 (1976); 42 U.S.C. 7410(a) (2).

47 Arizona Regional Haze SIP, Appendix D, Table 10.3; see also Comments of Arizona Electric Power Cooperative, 

Inc., Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP (September 18, 2012) page 9. In our

proposal, we noted that these control cost calculations include costs that are disallowed by EPA’s Control Cost 

Manual, such as owner’s costs and AFUDC. Both of these elements have the effect of inflating cost calculations and 

thus the cost-effectiveness of the various control options considered. See 77 FR 4284.

48 Arizona Regional Haze SIP, BART Determination for Apache Generating Station, Supplemental Economic 

Analysis. Memorandum from Larry Sorrels and Robin Langdon, EPA Office of Air Quality Planning and Standards 

(November 5, 2012).

49 Id.
23

As noted above, AEPCO’s affordability claim centered largely on ratepayer impacts. For 

electric utilities, EPA has not customarily analyzed or considered ratepayer impacts in BART 

determinations.50 Nonetheless, because our Screening Analysis and Supplemental Economic 

Analysis had established that AEPCO was a small entity and that our proposed rule might have a 

significant impact on AEPCO, we undertook three additional steps in furtherance of EPA policy 

that program offices should assess the direct adverse impact of every rule on small entities.

51

First, we conducted a supplemental analysis of the costs of compliance (i.e. the cost of various 

control options), based on cost estimates provided by AEPCO.

Second, we requested an electricity rate analysis through our contractor, EC/R Inc., to 

evaluate the possible electricity rate increases and the implications of AEPCO’s size. That Rate 

Impact Analysis is described below. 

Third, we considered ways to minimize adverse impact to AEPCO, as a small entity, 

even if our analysis failed to conclude that AEPCO had met the affordability threshold. In its 

comments on our proposal, AEPCO requested that “EPA set the final BART limits in terms of 

lb/MMBtu only and not as a specified technology” to provide AEPCO with “maximum 

flexibility.”52 AEPCO also requested that if EPA decided to finalize emission limits consistent 

with SCR that the limits be set at 0.07 lb/MMBtu.53 Given the unusual status of AEPCO as a

small entity and a rural electric cooperative, we believe that it is consistent with EPA policy to 

minimize adverse impact to this small entity to the extent that such action is feasible and 

consistent with our BART analysis.

In order to consider the extent to which it is feasible to minimize adverse impact to 

AEPCO, we considered in our analysis whether to finalize a 30-day rolling average BART 

emission limit of 0.070 lb/MMBtu for Apache Units 2 and 3, and a “bubble” across these two 

units to provide AEPCO an adequate margin for compliance, in the case where we concluded 

 

50 Exceptions include EPA’s Regional Haze FIP for Hawaii, where we analyzed potential rate impacts due to the 

unique energy situation in Hawaii, 77 FR 61478, 61488, and EPA’s BART FIP for Four Corners Power Plant, 

where we examined potential rate impacts as part of tribal consultation, 77 FR 51620, 51625-51626.

51 EPA's Action Development Process, Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as amended 

by the Small Business Regulatory Enforcement Fairness Act, November 2006, at 3. This EPA guidance document 

states that prior to the enactment of the Small Business Regulatory Enforcement Fairness Act, EPA exceeded the 

requirements of the Regulatory Flexibility Act (RFA) by preparing a regulatory flexibility analysis for every rule 

that would have any impact on any number of small entities. In view of the changes made by SBREFA, however, 

EPA decided to implement the RFA as written - a regulatory flexibility analysis as specified by the RFA is not 

required simply because the rule has some impact on some number of small entities: "Instead, such analysis will be 

required only in cases where we will not certify that the rule will not have significant economic impact on a 

substantial number of small entities" but "It remains EPA policy that program offices should assess the direct 

adverse impact of every rule on small entities and minimize any adverse impact to the extent feasible, regardless of 

the magnitude of the impact or the number of small entities affected."

52 AEPCO Comments, at 18. 

53 Id.
24

that a requirement to install SCR with LNB and OFA would not affect the viability of Apache 

Generating Station.

VII. Rural Cooperative Financing and Affordability

AEPCO states that there are limitations imposed by the U.S. Department of 

Agriculture’s Rural Utilities Service (RUS). AEPCO states that SCR on Apache Units 2 

and 3 is unaffordable to AEPCO because:

- AEPCO’s rural electric cooperative status affects its financing. AEPCO has no 

access to capital markets, but must seek financing from RUS. 

- RUS has limited budget and AEPCO must compete against other coops and rural 

utilities.

- AEPCO has limited internal resources, limited working capital, relatively small 

capital reserves. AEPCO does not have financial reserves available for major capital 

investments.

- AEPCO needs prior government approval to raise money under current RUS and 

CFC agreements

- Accessing financing mechanisms available through RUS requires rate increases 

that must be approved by the Arizona Corporation Commission

For the purpose of our analysis, we assumed that AEPCO would need to seek financing. 

Earthjustice commented that the cost of SCR with LNB and OFA at Apache could be covered 

with funds from AEPCO’s operating margins or legal settlements. Although AEPCO received a 

favorable ruling when the Surface Transportation Board (STB) rendered its decision on 

November 22, 2011, the amount of reparations due to AEPCO has been appealed by the 

defendants and, as such AEPCO has not recorded the settlement as of December 31, 2011.54

While Apache Generating Station does have annual operating margins that vary according to 

various conditions, we have not assumed that AEPCO can cover the costs of pollution control 

equipment exclusively from these funds, or from the STB settlement agreement. Because 

AEPCO is a member-owned utility, operating margins and other surplus funds may be 

earmarked to be returned to its member cooperatives on a rotating basis. While some of these 

funds may be available for capital expenditures such as pollution controls, we have assumed for 

the purpose of our analysis that financing will be necessary to achieve the pollution reductions 

required by our action.

We note that Earthjustice stated that RUS loan funds are not raised or subsidized by 

taxpayers, and the RUS does not anticipate any shortage in funding. In addition, EarthJustice 

claimed that the National Rural Utility Cooperative Finance Corporation (NRUCFC) is financed 

 

54 Auditor’s Report at 20.
25

by private investors, and AEPCO should not have any difficulty borrowing from the NRUCFC, 

if necessary. 

We conducted our own analysis of potential access to financing. Appendix A of the 

Consolidated Mortgage, Security Agreement and Financing Statement55 indicates that AEPCO’s 

maximum debt limit is $600 million. In addition, the long-term debt as of December 31, 2011 

was $178.8 million.56 In their June 29, 2012 comments AEPCO indicated that securing 

additional financing is both time consuming and expensive. To better understand the difference 

between the $600 million debt limit and the current long-term debt level of $178.8 million as 

well as to potentially understand the time and expense associated with securing additional 

financing, we contacted the U.S. Department of Agriculture’s Rural Utilities Service (RUS).

Based on information we received during a conversation with RUS representatives, we 

understand that AEPCO's ability to access financing for NOx controls is a separate question from 

affordability of the controls. The RUS representatives indicated:

In terms of financing, AEPCO is eligible under the terms of their mortgage to finance 

additional debt related to air pollution controls. Because under the terms of the mortgage 

AEPCO needs sufficient revenue to meet the financial metrics of Times Interest Earned 

Ratio and Debt Service Coverage ratio, financing controls would likely require a rate 

increase. Both incurring additional debt and increasing rates require approval from the 

Arizona Corporation Commission (ACC). Securing approval from the ACC for 

increasing rates can likely be time consuming—the time needed to secure ACC's 

approval has, on at least one occasion, resulted in AEPCO being close to not meeting the 

financial metrics under their mortgage.

57

We agree that the terms of AEPCO’s mortgage require AEPCO to have sufficient 

revenue to meet the financial metrics of Times Interest Earned Ratio and Debt Service Coverage 

ratio. But AEPCO is eligible to finance additional debt related to air pollution controls, and it has 

failed to show that such financing is unavailable to it.

Securing a rate increase from ACC may be time consuming. This supports giving

AEPCO five years for installation of such controls. 

AEPCO states that it is a rural electric cooperative that seeks financing from RUS, 

such financing may be necessary for installation of SCR, and prior government approval 

is needed to raise money under current RUS and CFC agreements. Taking all of that as 

true, the information provided to us regarding AEPCO financing of capital projects does 

 

55 The Consolidated Mortgage, Security Agreement and Financing Statement begins on page 115 of the supplement 

information provided by AEPCO; Appendix A is located on page 159.

56 Balance sheet information can be found in a Report of Independent Auditors for the December 31, 2011 and 2010 

balance sheets. The Report begins on page 1380 of the supplemental information provided by AEPCO. 

57 Arizona Regional Haze SIP, BART Determination for Apache Generating Station, Supplemental Economic 

Analysis. Memorandum from Larry Sorrels and Robin Langdon, EPA Office of Air Quality Planning and Standards 

(November 5, 2012).
26

not show that installation of SCR at Apache Units 2 and 3 would affect the viability of 

continued plant operations. 

VIII. Ratepayer Impacts and Customer Base

AEPCO states that it serves a predominantly rural and poor customer base, which 

would be unable to absorb this size of rate increase without hardship. 

EPA reviewed the supplemental information on per capita and median household 

incomes. Because electric utility bills are likely paid at the household and not individual, or per 

capita, level, we believe that median household income is an appropriate metric for assessment. 

We used census data to compare household income levels in the areas served by AEPCO’s Class 

A member cooperatives to average household incomes in the United States. In 2011 the median 

income for U.S. households was $50,502. Using the supplemental information provided by 

AEPCO, we calculated that the median income for AEPCO’s Member Co-ops’ ratepayers was 

$49,303. In addition, we aggregated the data on median household income by zip code into four 

incomes ranges. Seventy-one percent of the median household incomes by zip code were in the 

$40,000 and above income ranges and twenty-nine percent were in the median household income 

range of $20,000 to $39,999. We found that the household incomes in AEPCO’s Member Coops’ service area are in the same range as average U.S. household income, so an increase in 

AEPCO’s electricity rates should not cause greater hardship than a similar increase elsewhere in 

the country.58

Regarding potential effects on product price, AEPCO estimates that its rates would 

need to rise by at least 17.5% to cover the cost of SCR on Apache Units 2 and 3, and states 

that this estimated rate increase will be:

- Harmful to AEPCO rural consumers and not-for-profit members

- Large enough to create uncertainty on ACC 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.”59 

- AEPCO’s “members will disapprove the project” if rates substantially above what 

its members would otherwise pay.60

EPA requested an electricity rate analysis through our contractor, EC/R Inc., to assist us 

in evaluating the possible electricity rate increases. Our contractor noted that AEPCO’s analysis 

appears to place the entire burden of the incremental capital and O&M costs on its Member Co-

 

58 Arizona Regional Haze SIP, BART Determination for Apache Generating Station, Supplemental Economic 

Analysis. Memorandum from Larry Sorrels and Robin Langdon, EPA Office of Air Quality Planning and Standards 

(November 5, 2012).

59 AEPCO September 18, 2012 letter, at 10.

60 Id. at 8.
27

ops and their retail customers. However, the analysis should account for a share of the SCR cost 

going to off-system sales volumes and not only allocated to member rates. The contractor’s 

Incremental Cost Model calculated an increment in revenue requirements for AEPCO’s member 

cooperatives of 12.7 percent under the scenario that spreads the incremental SCR cost across all 

kWh produced at Apache, both Member Co-ops and off-system or non-Member sales. Under the 

alternative scenario that the incremental cost for SCR is covered exclusively by member 

cooperatives, the incremental revenue requirement was 15.4 percent.61 This analysis is based on 

a capital cost for the installation of SCR with LNB and OFA of $164.9 million, which matches 

the costs claimed by AEPCO in their comment letter minus certain charges excluded by EPA

CCM. This difference in the estimated capital cost for SCR also accounts for much of the 

discrepancy between AEPCO’s and Earthjustice’s estimates of electricity rate increases, since 

Earthjustice’s estimate was based on the capital cost estimates originally published in our 

NPRM.

AEPCO sells electricity through its member cooperatives, and not directly to residential 

and business customers, but EC/R also analyzed the impact of an increase in the cost of 

electricity generation on the monthly bills of electricity users serviced by AEPCO’s Member Coops. Table 8 indicates the incremental retail costs of electricity to end users under the two 

scenarios mentioned above. The potential rate increases for residential users in 2019, the first full 

year of incremental capital expenditures for pollution controls installed in 2017 (and the year 

with the largest incremental cost impact), range from 4.5 percent, or $5.75 per month over 2011 

rates, to 10.6 percent, or $10.75 per month over 2011 rates.62 EC/R used conservative 

assumptions in an effort to guard against understating the potential rate impacts.

TABLE 8 – INCREMENTAL RETAIL COSTS DUE TO SCR

(AS 2019 COSTS WOULD IMPACT 2011 RETAIL RATES)

Scenario

Range

of Outcomes

Among 

Member Coops

Residential Class Only Combined Residential, Commercial & 

Industrial

Percent

Increase

Average $ 

per Year 

per 

Customer

Average $ 

per Month

per 

Customer

Percent

Increase

Average $ 

per Year 

per 

Customer

Average $ 

per Month

per 

Customer

A: Members 

Pay all SCR 

Costs

Low 5.4% $83 $6.92 5.8% $125 $10.42

High 10.6% $129 $10.75 12.0% $220 $18.33

B: Members 

Pay Portion 

of SCR Costs

Low 4.5% $69 $5.75 4.8% $103 $8.58

High 8.8% $107 $8.92 9.9% $182 $15.17

 

61 Apache Plant: Report on SCR Incremental Cost Assessment. Prepared by Energy Strategies, LLC for EC/R, Inc. 

(November 2012).

62 Id.
28

While these projected rate increases are not trivial, they are comparable to 

average historical rate increases for AEPCO, Arizona, and U.S. ratepayers.63 They are 

also projected to occur seven years in the future. Again, in discussing the limitations of 

this retail rate analysis, it should be noted that EC/R used conservative assumptions in an 

effort to guard against understating the potential rate impacts. 

Baseline Electricity Rates: Table 9 is a rough analysis of 2010 residential retail electricity 

rates at AEPCO’s member cooperatives, compared to state and national rates. Residential rates 

charged by Class A member cooperatives in Arizona ranged from 1 to 1.4 times the state average 

rate, and 1 to 1.3 times the national average rate. Normalizing by cost of living using data from 

the Council for Community and Economic Research, Arizona Class A cooperative residential 

rates ranged from 0.8 to 1.3 times the national average rate.64

 

63 Energy Information Administration (EIA) State Historical Tables for 2011, Released: October 1, 2012. Average 

Price by State by Provider, 1990-2011. http://www.eia.gov/electricity/data/state/avgprice_annual.xls, last accessed 

November 5, 2012.

64 Both nominal and normalized rates were higher for the Anza Electric Cooperative, which serves some portions of 

Riverside County, California. 
29

TABLE 9. CLASS OF OWNERSHIP, NUMBER OF CONSUMERS, SALES, REVENUE, AND 

AVERAGE RETAIL PRICE BY STATE AND UTILITY: RESIDENTIAL SECTOR, 2010.

(HIGHLIGHTED COLUMNS ADDED BY F. DÓÑEZ, EPA R9) Number of Consumers Sales (MWh) Average (cents/kWh) Retail Price Percentage of StateAverage (1) Percentage of National Average (2)

Avg Price

Normalized by Cost

of Living (3)

%age of State

Normalized

Average (1, 3)

Normalized

%age of National

Average (2, 3)

Revenue

(1,000 dollars)

Entity 

State

Duncan 

Valley Elec 

Coop, Inc

A

Z 1,641 14,673 1,974 13.45 123% 117% 11.43 104% 99%

Graham 

County 

Electric 

Coop Inc

A

Z 7,603 74,173 10,101 13.62 124% 118% 11.58 106% 100%

Mohave 

Electric 

Cooperative

, Inc

A

Z 34,672 365,162 40,649 11.13 101% 96% 9.46 86% 82%

Sulphur 

Springs 

Valley E C 

Inc

A

Z 41,454 367,327 49,436 13.46 123% 117% 11.44 104% 99%

Trico 

Electric 

Cooperative 

Inc

A

Z 37,806 400,596 62,093 15.50 141% 134% 13.18 120% 114%

(1) The Arizona state average residential utility rate for 2010 was 10.97 cents/kwh. The 

California state average residential utility rate for 2010 was 14.75 cents/kwh. 

(2) The U.S. national average residential utility rate for 2010 was 11.54 cents/kwh. 

(3) For Arizona utilities, multiplied price by a 2012 cost of living index of 85%. For Anza 

Electric Coop, used a 2012 cost of living index of 1.195 (zip code 92536, Aguanga, CA).

IX. Market Share, Plant Operations

Regarding potential effects on market share and profitability, AEPCO argues that 

our proposed BART determination will:

- Probably require a substantial rate increase

- Probably require renegotiation of existing 2009 consolidated mortgage as 

AEPCO would no longer meet the TIER and DSC requirements of its covenants

- Create downward pressure on AEPCO’s market share. AEPCO states that it 

must compete with general power pooling and also with its partial requirements 
30

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’s Station’s costs go unduly out 

of line with the cost of power on the open market.65 

As discussed above, our consultant analyzed the potential rate increase. We understand 

that renegotiation of the 2009 consolidated mortgage will take time, and that is another reason to 

give AEPCO five years for compliance with the emissions limit. However, the fact that 

renegotiation is possible indicates that the effect on AEPCO of not meeting these financial 

requirements may not affect plant operations. 

Regarding market share – Many other electric utilities, including other rural electric 

cooperatives, are also being required to install BART controls. AEPCO’s customers are also 

largely its owners, and AEPCO has long term contracts with the majority. In the information 

submitted by AEPCO, AEPCO did not submit information to show that costs of electricity from 

AEPCO after installation of SCR on Apache Units 2 and 3 would be unduly out of line with cost 

of power on the open market.

Regarding potential impact on plant operations, AEPCO argues that our proposed 

BART determination will:

- Increase AEPCO’s long term debt by 98%

- Severely reduce AEPCO’s working capital

- Require bridge financing at additional expense

- Impose substantial additional burdens on AEPCO at a time when contracts 

on Apache Unit 1 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. 66 

See discussion above regarding financing and our supplemental analysis of cost of 

compliance. 

AEPCO failed to identify which contracts are expiring, whether the expiring contracts are 

in fact with Class A Members, and in how short a period the contracts will expire, although 

AEPCO did identify the expiring contracts as relating to Apache Unit 1. Our FIP action, in 

contrast, addresses Apache Units 2 and 3. However, we looked to the supporting document to 

determine the situation with AEPCO’s Class A Members. We note that one of AEPCO’s 

consultants identifies Apache Unit 1 as currently contracted through 2020, and Apache Units 2 

 

65 APECO September 18, 2012 letter at page 10.

66 Id. at 11.
31

and 3 as currently contracted through 2035.67 We also examined the independent Auditor’s 

Report to determine the scope of this issue. The Auditor’s Report states that AEPCO holds all 

requirements wholesale power sales contracts with three of its six Class A member cooperatives 

pursuant to which each Class A member agrees to purchase from the Cooperative all of its 

electric power requirements, and these all requirements power contracts expire December 31, 

2035, and will remain in effect thereafter until terminated by either party upon six months 

notice.68 The Auditor’s Report also notes that AEPCO holds partial requirements wholesale 

power sales contracts, expiring December 31, 2035, with three of its Class A member 

cooperatives pursuant to which the Class A members have agreed to purchase from the 

Cooperative electric energy and capacity up to the member’s allocated capacity percentage in the 

Cooperative’s total resources existing at the time of execution of the contract.69 

X. Conclusion

Neither the projected rate increases nor any submitted information or analysis 

indicate that a requirement to install SCR with LNB and OFA will affect the viability of 

Apache Generating Station. 

However, we are taking into account AEPCO’s status as a small entity as part of 

our determination. In particular, in its comments on our proposal, AEPCO requested that 

“EPA set the final BART limits in terms of lb/mmBtu only and not as a specified 

technology” to provide AEPCO with “maximum flexibility.”70 AEPCO also requested 

that, if EPA decided to finalize emission limits consistent with SCR, that the limits be set 

at 0.07 lb/MMBtu.71 We believe that it is consistent with EPA policy to minimize adverse 

impact to this small entity to the extent that such action is feasible and consistent with our 

BART analysis. 

To allow this small entity the maximum flexibility that is consistent with our 

analysis of the five factors, we have determined that it is appropriate to set the BART 

limit as a 30-day rolling average 0.070 lb/MMBtu limit, with a five year compliance 

deadline. As AEPCO noted, this approach may allow minor changes in configuration of 

the optimal system to allow AEPCO’s compliance at somewhat lower cost. This 30-day 

rolling average 0.070 lb/MMBtu limit is also applied as a “bubble” across Units 2 and 3. 

This approach allows for short term emission spikes from startups and provides this small 

entity with additional operational flexibility within the constraints of the BART 

emissions limit.

 

67 Arizona Electric Power Cooperative Affirmation of Unit Life & Net Salvage Value Study, Final Report May 2011 

by Black & Veatch at page 7-5.

68 Auditor’s Report at page 17. 

69 Id.

70 AEPCO Comments page 18. 

71 Id.