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

................................ ................................ ................................ .......................... 312



### 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 disapprov al 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 NPR M proposed to implement a Federal Implementation Plan (FIP) that contained BART emissions
limits for NO X 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 Reductio n ( 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 reque sted 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

econom ic effects before the NPRM was published, 2 and 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 operat ing 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 E PA’s request, in early September

, 2012

, AEPCO provided supplemental information inclu ding 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 addr ess 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 Mandat ory 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 “B ART Guidelines”) o n July 6, 2005 . The Guidelines are t o 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 det erminations 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 SO 2 , NO X and PM

.

Under CAA se ction 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

. B ecause 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 propos ed a FIP to address those portions of the SIP that we propos ed to disapprove

.

In making BART determinations, section 169A(g)(2) of the CAA requires consider ation
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 w here 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

co ntrol 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 condition s 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 analysi s that demonstrates, in sufficient4

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 in formation
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 a nd 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 approv e 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 pipeline

quality natural gas as its primary fuel, but also has the capability to use No

. 2 through No

. 6 fuel
oils

. ADEQ accepted AEPCO’s propos ed BART recommendation of low

- NOx burners ( LNB )
wit h flue gas recirculation ( FGR ) for Unit 1, but added a fuel restriction to allow only the use of natural gas . In our NPRM, we propos ed to approve ADEQ’s NOx BART determination of LNB with FGR (natural gas usage only) with an emission limit of 0.056 lb/MMBt u for Apache Unit 1. We also proposed to approve ADEQ’s emissions limit s for SO 2 and PM 10 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 Unit s 2 and 3 are coal

- fired boilers operating on sub

bituminous coal. 4 A DEQ ’s BART determination for PM 10 emission from Apache Units 2 and 3
is upgrades to the existing ESP and a PM 10 emissions limit of 0.03 lb/MMBtu for Units 2 and 3

. ( ADEQ referred to installation of a f lue 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). ADE Q ’s BART determin ation for SO 2 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 propos ed to approve ADEQ’s PM 10 and S O 2 BART determination s for Apache Units 2 and
3

.

For NO
x , ADEQ proposed LNB and over

- fire air (OFA) for BART. In our NPRM, w e
propose d to disapprove ADEQ ’s BART emissions limits for NO

x 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 ach ieve 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, w e 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 consider ed by EPA for Apache Units 2 and 3.

T ABLE 1

– S UMMARY OF BART E MISSION L IMITS IN NPRM (T ABLE 24 OF NPRM)

Unit Emission limitation (lb/MM Btu) (rolling 30

- boiler

- operating

- day average)

NO
x PM 10 SO 2 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

T ABLE 2

– S UMMARY OF BART C OMPLIANCE D ATES IN NPRM (T ABLE 25 OF NPRM)

Unit Compliance Date

NO
x PM 10 SO 2

Apache Generating Station Unit 1 Five years 180 days 180 days

Apache Generating Station Unit 2 F ive years 180 days 180 days

Apache Generating Station Unit 3 F ive 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. A EPCO 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 count y 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 contracts 6 , and three distribution cooperatives with par tial 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 jo intly 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 schedu ling 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 Cl ass 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 the ir retail customers, which comprise their membership.

6 A ll requirements contracts are a n agreement between an energy producer and a utility in which the ut ility requires all of its energy from a single source. In return for the right to exclusively supply the u tility, 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 Aud itors 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

T ABLE 3

– A EPCO M EMBERS (M ODIFIED FROM AEPCO 2011 A NNUAL R EPORT )

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 b y 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 Cooperativ e 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 fu lfill 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 th ree 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 tim e 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 sche duling 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 Electri c 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 AEPC O. 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 Per centage” ( 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 abilit y 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, intere st, 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 char ges, 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

m aintenance 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 fo r 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 allocate d 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, fi xed, 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 Tran smission 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 Cl ass 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 competi tion 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 whic h 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 r esale 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 “stand ard 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 f inancing 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 ap plication 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 $700,0 00 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 Gen erating

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 const ruction 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, “Reta il 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 approximate ly $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

mil lion 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 S tatement, 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 are as 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 applica tion, 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/ref inancing 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 F FB 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, CF C 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

th rough 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 e rred 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 contr ols 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 una ffordable 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 utilitie s.

- 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 c osts” 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, an d 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 f inance 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 A EP CO September 18, 2012 letter at page 10.14

requirements members, to shutdown those units in favor of a purchase power agr eement (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 expir ation, 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 AEPCO 39 : C urrent 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 include d documents from AEPCO members if such documents are
relevant to the analysis.

We requested documentation for the informa tion 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 t o 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 inve stment. 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 fiv e

- 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 ev aluation of visibility results. The NPRM
discuss e d 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. C ost of compliance is discusse d 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 note d 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 20 10) was selected that reflects the currently existing pollution control techno logy (OFA). In examining energy and non

- air quality impacts, we note d certain potential impacts resulting from the use of ammonia injection associated with the SNCR and SCR control options, but d id not consider these impacts sufficient enough to warrant el iminating 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, t he annual capacity factors AEPCO used for each unit were 92 percent (Apache 2), and 87 percent (Apache 3). B y 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 t on of pollutant
reduced.

40 77 FR 42834.1 7

T ABLE 4

– A PACHE U NITS 2 A ND 3: EPA’ S V ISIBILITY I MPROVEMENT F ROM N O X C ONTROL S ( T ABLE 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 U nits 2 and 3

. SCR was assumed to give a control
effectiveness of 87 percent and 89 percent for U nits 2 and 3, respectively (less than 90 percent due to the 0.05 lb/MMBtu NO
x 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 t he modeled degree of visibility improvement supports SCR as BART for Apache.

Our consideration of degree of visibility improvement in the NPRM focuse d primarily on the improvement from base case impacts associated with each control option. While each of the
available NO
x control options achieves some degree of visibility improvement, we consider ed the improvement associated with the most stringent option, SCR with LNB and OFA, to be
substantial. Our consideration of cost of compliance focuse d primarily o n the cost

- effective ness 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 consider ed 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 warrant18

eliminating it from consideration. Therefore, the results of our five

- factor an alysis indicate d that
NO
x 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 e lectric output for the preceding fiscal year did not exceed 4 million megawatt hours (M Wh). 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 smal l 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 annua lized 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 under

e stimated 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, Appendi x D, at 49.19

proposed action 44 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:

T ABLE 5

– A PACHE U NIT 2: C OST C O MPARISON OF SCR WITH LNB AND OFA

Capital Cost ($) Total Annual

Cost ($/yr) Emissions

Removed (tpy) Average

Cost

Effectiveness ($/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

T ABLE 6

– A PACHE U NIT 3 : C OST C OMPARISON OF SCR WITH LNB AND OFA

Capital Cost ($) Total Annual

Cost ($/yr) Emissions

Removed (tpy) Average

Cost

Effectiveness ($/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 AEP CO’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 C CM , such as AFUDC and owner’s costs, and another set in which it included those costs. In both cases, these analyses also contained revisio ns in order to reflect capital costs and O&M costs that AEPCO considered more representative and appropriate for the Apache units. These revisions include d the following:

 Higher bare module SCR costs

 Use of higher capacity factor (0.85 for both units, comp ared 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 NO X 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 cert ain 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/M MBtu for Apache Units 2 and 3, and a “bubble” across these two units to provide AEPCO an adequate margin for compliance. Al though this 30

- day limit accommodates the possibility of multiple startups in a given 30

- day period, we expect such spikes to be smoo thed 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 i nsufficiently site

specific. 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 C CM

. As shown in Table

7 , t his results in revised SCR with LNB and OFA c ost

- 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 cost

effective when considered in conjunction with the visibility improvement associated with SCR.21

T ABLE 7

– A PACHE 2 A ND 3: C OST E STIMATE OF S UPPLEMENTAL 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 av erage lb/MMBtu) 0.371 0.438

SCR Emission Rate (annual ave rage 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 t hat 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 $1 2

. 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 C AA, EPA is not permitted to consider economic feasibility when taking action22

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 scrub bers 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 w ere 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 f ive

- 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

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

AEPCO states that there are implications from AEPCO’s s mall 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 rat epayers).

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 Analysis 48 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 determin ation 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 als o 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 Determi nation 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

determinat ions. 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 E PA 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/ MM Btu 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, w e 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 ext ent to which it is feasible to minimize adverse impact to

AEPCO

, we consider ed 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 AEP CO 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 61 4 78, 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 gu idance 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 hav e 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 off ices 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 viabili ty 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

ac cess 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 ope rating 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 Earth

j ustice 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 Statement 55 indicates that AEPCO’s

max imum 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 t he 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 Agricultur e’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 :

I n terms of financing, AEPCO is eligible under the terms of their mortgage to finance
additional debt rela ted to air pollution controls. B ecause under the terms of the mortgage
AEPCO need s sufficient revenue to meet the financial metrics of Times Interest Earned Ratio and Debt Service Coverage ratio

, financ ing controls would likely require a rate increase. Both incurring additional debt and increasing rates require approval from the Arizona Corporatio n 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 mort gage

. 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 pollu tion controls, and it has failed to show that such financing is unavailable to it.

Securing a rate increase from ACC may be time consuming . T h i s 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 T he 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 I ndependent 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 B ase

AEPCO state s 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 bil ls 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 mem ber 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 th e median household income range of $20,000 to $39,999. We found that the household incomes in AEPCO’s Member Co

ops’ 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 h ardship 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 r ate 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. De lays 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 cost s on its Member Co

-

58 Arizona Regional Haze SIP, BART Determination for Apache Generating Station, Supplemental Economic Analysis. Memorandum from L arry Sorrels and Robin Langdon, EPA Office of Air Quality Planning and Standards ( November 5, 2012 )

. 59 AEPCO S eptember 18, 2012 letter, at 10.

60 Id

. at 8

.27

ops and their retail custome rs . 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

cooper atives 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 exclusivel y by member cooperatives, the incremental revenue requirement was 15.4 percent. 61 Th is 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
C CM . 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 generati on on the monthly bills of electricity users serviced by AEPCO’s Member Co

ops. 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

.

T ABLE 8

– I NCREMENTAL R ETAIL C OSTS D UE TO SCR
(A S 2019 C OSTS W OULD I MPACT 2011 R ETAIL R ATES )

Scenario Range

of Outcomes
Among
Member Co

ops Residential Class Only Combined Residential, Commercial &

Industrial

Percent

Increase Average $

per Y ea r

p er
Customer Average $

per Month

p er
Customer Percent

Increase Average $

per Y ea r

p er
Customer Average $

per Month

p er
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 201 2)

. 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 note d 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 accesse d 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

T ABLE 9

. C LASS OF O WNERSHIP

, N UMBER OF C ONSUMERS

, S ALES

, R EVENUE

, AND

A VERAGE R ETAIL P RICE BY S TATE AND U TILITY : R ESIDENTIAL S ECTOR

, 2010.
(H IGHLIGHTED COLUMNS A DDED BY F. D ÓÑEZ

, EPA R9) Number

of Consumer

s Sales

(MWh) Average Retail Price (cents/kWh) Percentage

of StateAverage (1) Percentage

of National Average (2) Avg Price

Normalized by Cost of Living (3) Normalized

%age of State 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
Ele ctric 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
Elec tric 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 fo r 2010 was 10.97 cents/kwh. The California state average residential utility rate fo r 2010 was 14.75 cents/kwh. (2) The U.S. na tional average residential utility rate f or 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 consolid ated 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 requirements30

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 powe r on the open market. 65

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

that r enegotiation 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 financi al requirements may not affect plant operations.

Regarding market share

– M any other electric utilities, including other rural electric cooperatives, are also b eing required to install BART controls. AEPCO’s customers are also largely its owners , and AE PCO has l ong 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 p ower 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 ex pense

- 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 c ertainty 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. Ou r FIP action, in

con tras t, addresses Apache Units 2 and 3. However, we looked to the supporting document to
d etermine the situation with AEPCO’ s Class A Members. We note that one of AEPCO’s consultants identifies Apache Unit 1 as currently contracted throu gh 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 det ermine the scope of this issue. The Auditor’s Report states that AEPCO holds all requirements wholesale power sales contracts w ith 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 e ffect 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. Conc lusion

N either 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 A EPCO also requested that, if EPA decided to finalize emission limits consistent with SCR, that the limits be set
at 0.07 lb/MMBtu. 71 W e believe that it is consistent with EPA policy to minimize adverse impact to this small entity to the extent that such act ion 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 averag e 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

.