7272 E. INDIAN SCHOOL ROAD, SUITE 360 

SCOTTSDALE, ARIZONA 85251 

TELEPHONE: 480-505-3900 

FACSIMILE: 480-505-3901 

ERIC L. HISER 

DIRECT LINE: 480-505-3927 

e-mail: ehiser@jordenbischoff.com

LAW OFFICES

JORDEN BISCHOFF

& HISER, P.L.C.

 September 29, 2014 

VIA FEDERAL EXPRESS AND www.regulations.gov 

PUBLIC RELEASE VERSION 

The Hon. Gina McCarthy 

Administrator 

U.S. Environmental Protection Agency 

USEPA Ariel Rios Building (AR) 

1200 Pennsylvania Avenue N.W. 

Washington, DC 20004 

Re: Comments and Request for Separate Categorization of Small Public and 

Cooperative Generation Units under the “Carbon Pollution Emission Guidelines 

for Existing Stationary Sources: Electric Utility Generating Units; Proposed 

Rule,” 79 Fed. Reg. 34830 (June 18, 2014) 

 Docket ID EPA-HQ-OAR-2013-0602 

 

Dear Ms. McCarthy: 

On June 18, 2014, the U.S. Environmental Protection Agency (“EPA”) published the 

proposed “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric 

Utility Generating Units” (the “Rule, Clean Power Plan or CPP”), at 79 Fed. Reg. 34830, 

proposing to establish “best system of emission reduction” or “BSER” goals for electric 

generating units, which will then be administered by the States through the Clean Air Act section 

111(d) program. As outlined in these comments, despite EPA’s promise that there is 

“flexibility” in the proposed program, the result of the proposal is to shut down the Arizona 

Electric Power Cooperative, Inc. (“AEPCO”) Apache Generating Station and potentially other 

small cooperative power plants, imposing extravagant costs and potentially jeopardizing the 

cooperatives’ vital role in delivering power to rural America. Because small public and 

cooperative power plants are in a fundamentally different position than investor owned utilities 

(“IOUs”), AEPCO respectfully requests that EPA consider creating a separate category for 

“small public and cooperative electric generating units (“EGUs”)” within the framework of the 

larger proposal. 

The reasons for AEPCO’s comments and request for categorization are set forth below. 

 
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Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 2 

A. Background Information on AEPCO and the Cooperative Model

AEPCO is a rural, consumer-owned generation and transmission electric cooperative 

formed in 1961 to provide electric generation service to local rural, consumer-owned electric 

distribution cooperatives in Arizona. As a not-for-profit cooperative, AEPCO is fully owned by 

its members. AEPCO has six “Class A” members, who participate in and rely on AEPCO’s 

electric generation services, and one “Class D” member that only participates in AEPCO’s 

electric scheduling and trading services. Together, AEPCO’s Class A members serve just under 

150,000 meters. The electric service base is heavily skewed toward rural residential use, with 

relatively little commercial or industrial load. The service area of AEPCO’s members includes 

seven Native American tribes. Roughly 33% of AEPCO’s members’ customers are below the 

federal poverty line. The cost of electricity is thus of great concern to AEPCO, its members and 

their members. 

1. AEPCO’s Apache Generating Station 

AEPCO operates only one power generation facility: the Apache Generating Station 

(“Apache”). Apache was first constructed with the installation of Steam Unit 1 (“ST1”), a 72-75 

net MW steam unit in 1963 and Gas Turbine 1 (“GT1”), a 10 net MW simple cycle gas turbine in 

1964. GT1 exhausts through either the ST1 windbox and stack or its own stack. In 1978-1979, 

AEPCO added Steam Units 2 and 3 (“ST2” and “ST3”), almost identical Riley Stoker 

turbocharged boiler units with a 175 net MW capacity each. ST2 and ST3 are AEPCO’s coalfired units. A number of other simple cycle combustion turbines (GT2 through GT4) were added 

later. Collectively, Apache has approximately 555 MW of net installed capacity, of which 425 

MW are affected by the proposed Rule. As EPA noted in the Rule, AEPCO and its members 

sold less than 2.5 million MWh of electricity in 2012, well below the 4 million MWh or 750 MW 

net used by the Federal Energy Regulatory Commission (“FERC”) to classify a utility as small. 

77 Fed. Reg at 72540; 13 C.F.R. § 121.201 n.1. Of these units, it appears that ST1, ST2, ST3 

and possibly GT3 may be “affected EGUs” subject to the proposed Section 111(d) requirements. 

AEPCO’s Apache Station ST1, ST2 and ST3 units are over 30 years old. As a result of 

their age, ST1, ST2 and ST3 have a relatively high “heat rate.” A high heat rate means that their 

relative energy cost is high compared to the market. The current net heat rates of AEPCO’s ST1, 

ST2 and ST3 are: 

Table 1. AEPCO Net Heat Rates, Btu/kWh 

Unit Full Load Net Heat Rate 

ST1, gas (w/GT1) 

ST2, coal 

ST2, gas 

ST3, coal 
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Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 3 

The approximate average heat rate of a newer combined cycle unit would, for comparison 

purposes, be in the range of 7,000 to 7,800 Btu/kWh at the approximate elevation of Phoenix, 

Arizona. 

2. AEPCO’s Financial Capabilities 

AEPCO’s small generating capability results in a correspondingly limited financial base 

and financial resources. AEPCO has patronage capital—essentially earnings contributed by its 

members and legally required to be returned to them in the future—of approximately $111 

million. AEPCO’s total revenues ranged from $158 million in 2012 to $170 million in 2013. 

Under the terms of the cooperative’s bylaws, all amounts in excess of operating costs, expenses 

and prior losses are received with the understanding that they are furnished by the members as 

patronage capital and eventually returned back to the members. In addition, AEPCO has 

approximately $182 million in debt, secured by a mortgage with the Rural Utilities Service 

(“RUS”) and National Rural Utilities Cooperative Finance Corporation (“CFC”). The RUS 

mortgage limits AEPCO’s total debt to $600 million, assuming AEPCO can get necessary 

approval or lien accommodation under RUS regulatory and loan processes to fund capital 

additions. Most rural electric generation and distribution cooperatives are funded in similar 

fashion. 

Unlike many other electric cooperatives, AEPCO is also subject to regulation by its state 

public utility commission, the Arizona Corporation Commission (“ACC”). The ACC must 

approve AEPCO’s rates to its Arizona members and also AEPCO’s debt arrangements. 

As noted above, AEPCO’s cooperative nature defines its financial abilities and its 

relationship to its customers, in this case the three All Requirements Members (ARMs) and the 

three Partial Requirements Members (PRMs). This relationship is fundamentally unlike that of a 

traditional IOU’s relationship to its customers. 

a) AEPCO’s Members Are Independent Entities that Make Power 

and Energy Purchase Decisions Based on the Best Interest of 

Their Members 

Each AEPCO member is a cooperative charged with procuring economical power for its 

members. Because the members are independent legal entities, they have the ability to deal on 

the market for that power. The three smallest members are “all requirements members,” or 

ARMs, who have contracted with AEPCO for all of their power needs. The three large members 

are “partial requirements members,” or PRMs, who have contracted with AEPCO for only some 

of their power needs. The PRMs are free to supplement their AEPCO power supply and/or, 

subject only to contractual minimum provisions, buy market power to substitute for scheduling 

energy from their AEPCO power supply. 
Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 4 

Because AEPCO’s members are independent, they retain the ability to determine whether 

AEPCO’s costs have gone out of line and, if so, to exert pressure through their representatives on 

AEPCO’s board or, in compelling situations, to contract for power elsewhere despite existing 

contractual requirements. This differs from many situations where the rate payers may have the 

theoretical right to contract elsewhere, but do not have the effective ability to do so. In this case, 

AEPCO’s ultimate rate payers are already organized into cooperatives that can contract at 

wholesale to take their business elsewhere should AEPCO’s costs become non-competitive. 

This dynamic is critical to understanding the impact on AEPCO of the proposed Clean Power 

Plan proposal. 

b) Understanding AEPCO’s Earnings Position and Internal 

Financing Capacity 

First, as noted elsewhere, AEPCO does not have “capital” in the traditional sense of an 

investor owned utility. Instead, AEPCO has “patronage capital,” which is retained earnings not 

yet returned to its members. Only the patronage capital necessary to maintain financial stability 

is retained at the generation cooperative. Any excess is required to be returned to the members. 

Second, AEPCO does not have any ability to issue equity instruments and generally does 

not have the ability to seek capital contributions from its members for capital expenditures. All 

expenditures for plant improvements or retrofits are financed by debt instruments secured by the 

RUS mortgage. In short, AEPCO does not have the ability internally to raise capital. 

Third, AEPCO’s operating margins generally are fairly thin and net cash flows have been 

historically flat and frequently negative. Routinely, principal payments and non-operating 

expenditures result in little remaining cash margin. Operating margins have been less than or a 

little more than the amount needed to finance the increase in existing debt service. Because 

capital construction costs are front loaded, AEPCO does not have the internal ability to finance 

the construction or purchase of new generation and pay down its existing debt load. It must have 

a loan, which must be secured by the RUS mortgage and AEPCO must meet RUS’s TIER and 

DSC covenant requirements. These mortgage covenants cannot be achieved with the margins 

provided by AEPCO’s present (or pending) rate structure if the Clean Power Plan were to be 

implemented. Significant rate increases would be required. 

For the reasons discussed in these comments and request for categorization, AEPCO does 

not believe that it can afford to expand debt to the extent necessary to accommodate the proposed 

Clean Power Plan’s expedited retirement of AEPCO’s affected EGUs and provide for alternative 

power generation for AEPCO’s members. AEPCO does not have other units that can meet its 

load obligations and does not have the financial resources to construct new units, buy existing 

units, or purchase power to replace at least 425 of its 555 MW net capacity by 2020 and the 

proposed Rule, or any apparent variation of the proposed Rule, does not provide sufficient 

flexibility to allow meaningful relief. 

B. AEPCO’s Understanding of the Clean Power Plan 
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Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 5 

AEPCO has carefully reviewed EPA’s proposed Clean Power Plan and the proposed 

Carbon Pollution Emissions Guidelines, which establish both a State Interim Goal and Final 

Goal for Arizona. AEPCO has also participated extensively with the Arizona Department of 

Environmental Quality (ADEQ) in attempting to understand the implications of the proposal for 

AEPCO and Arizona. AEPCO understands that EPA has looked at four “building blocks” in 

setting the Interim Goal and Final Goal: (1) improved heat rates at existing coal-fired EGUs; (2) 

redispatch to lower emitting natural gas combined cycle (NGCC) units; (3) redispatch to lower or 

zero emitting resources (e.g., renewables); and (4) energy efficiency. EPA states that its 

proposal provides states substantial “flexibility” to then apply these four building blocks (plus 

other measures) to achieve the Interim and Final Goal. 

1. The Arizona Interim and Final Goals 

EPA established the Arizona goals as 735 lb/MWh (Interim Goal) and 702 lb/MWh 

(Final Goal) in its proposal. See proposed Table 1 to Subpart UUUU of Part 60—State RateBased CO2 Emission Performance Goals (pounds of CO2 per net MWh). Based upon review of 

the Technical Support Documents and spreadsheets in the docket, it appears that the Interim and 

Final Goal calculations are based upon the following equation: 

It appears that EPA then calculated the following values for Arizona’s “existing” baseline 

(2012): 

The Final Goal appears to have been calculated as follows: 

Which, when applied to Arizona, gives the following result: 

൫Coal	Gen	 ൈ Coal	ER൯ ൅ ൫OG	Gen ൈ OG ER൯ ൅ ሺNGCC Gen ൈ NGCC ERሻ	൅	Other	Emissions

Coal	Gen ൅ OG Gen ൅ NGCC Gen ൅ Other Gen

ሺ24,335,930 ൈ 2,268ሻ ൅ ሺ1,033,871 ൈ 1,563ሻ ൅ ሺ26,782, 325 ൈ 900ሻ	൅	17,227,768

24,335,930 ൅ 1,033,871 ൅ 26,782,325 ൅ 19,361

ൌ 1,551 lbs/MWh

൫Coal	Gen௥ௗ ൈ Coal	ER௛௥௜൯ ൅ ൫OG	Gen௥ௗ ൈ OG ER൯ ൅ ሺNGCC ܩ݁݊௥ௗ ൈ NGCC	ERሻ	൅	Other Emissions

Coal	Gen௥ௗ ൅ OG	Gen௥ௗ ൅ NGCC Gen௥ௗ ൅ Other Gen ൅ ܰݑ݈ܿ݁ܽݎ ܩ݁݊௨௖ା௔௥ ൅ ܴܧ	ܩ݁݊ ൅ ܧܧ ܩ݁݊

ሺ0 ൈ 2,132ሻ ൅ ሺ0 ൈ 1,563ሻ ൅ ሺ52,152,126 ൈ 900ሻ ൅ 17,227,768

0 ൅ 0 ൅ 52,152,126 ൅ 19,361 ൅ 1,818,486 ൅ 3,663,325 ൅ 9,216,009

= 735 lbs/MWh Interim Goal (2020-2029) 

ൌ 702 lbs/MWh Final Goal (2030+) 
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Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

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This calculation is based on the premise that all existing coal-fired EGUs, including Apache 

Station’s ST2 and ST3, are redispatched to NGCC. It also assumes that Apache Station’s 

existing natural-gas fired steam unit, ST1, is redispatched to NGCC. As noted above, AEPCO 

has no NGCC generating capacity and redispatch of ST2, ST3 and ST1 reduces Apache 

Generating Station’s capacity from net installed 555 MW to 135 MW. For reasons set forth 

below, this is devastating. 

2. There Is No Flexibility to Meet EPA’s Requirements in Any Other

Way

EPA emphasizes that States have considerable flexibility in applying the Clean Power 

Plan flexibly to address circumstances and to prevent bad results. However, in Arizona’s case, it 

appears that this flexibility is illusory. As detailed in the attached email from ADEQ’s Steve 

Burr to EPA dated August 22, 2014 and included as Attachment “A,” Arizona has no ability to 

alter the Clean Power Plan allocation. The target assumes that all coal-fired EGUs are shut 

down; therefore, there is no gain that can occur from Building Block #1. If Arizona increases the 

allocation to Building Blocks #3 and #4, Arizona cannot comply with the interim goal. 

Similarly, Arizona cannot increase Building Block #2 because there is no “OG Gen” capacity 

left that has not already been redispatched to NGCC. Accordingly, it appears that under the 

Clean Power Plan as proposed, effective January 1, 2020, AEPCO must shut down all of its 

affected EGUs. 

AEPCO is aware that there are EPA IPM model runs that suggest that coal-fired 

generation can be preserved in Arizona. EPA has stated that these runs are “illustrative” only 

and do not represent future reality. Based on discussions with EPA’s modeling staff on 

September 18, 2014, these runs are based on the following assumptions: (1) renewable energy 

and energy efficiency are sufficient to reduce demand and reduce the necessity for switch to 

NGCC power; and (2) energy efficiency and renewable energy exceed EPA’s calculations, 

which EPA believes will be the case because of Arizona’s renewal portfolio standard (“RPS”) is 

relatively high. In addition, AEPCO and ADEQ have determined that EPA treats “import” 

power as having a “0” carbon intensity when imported to Arizona, and import power is used to 

reduce in-state generation to meet the Interim and Final Goals. 

There are several problems with the assumptions underlying EPA’s Goals and IPM runs. 

First, as outlined above by ADEQ, increases in renewable energy and energy efficiency are time 

delayed and do not help with compliance with the interim goal. Second, Arizona’s RPS assumes 

that hydropower is renewable energy and relies extensively upon it, yet EPA does not give 

“credit” for hydropower for purposes of goal calculation or monitoring. This means that much of 

the margin between Arizona’s RPS and EPA’s calculations is not counted and it is not clear to 

AEPCO how Arizona will experience meaningful benefit from it. Third, EPA’s modeling runs 

assume significant changes in Arizona’s energy position from a net exporter to a net importer of 

power, an assumption and forecast that is shared by none of the Arizona utilities due to the 

ownership structure of the Arizona power market, where much of the generation is tied to owners 

from other states who export that power to their own systems. AEPCO’s marketing and resource 
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Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 7 

planning staff is also gravely concerned about EPA’s assumption that market power will be 

freely available post-2020, as the Clean Power Plan will substantially disrupt existing generation 

and market patterns. 

C. AEPCO’s Options for Apache Station Under the Clean Power Plan 

AEPCO is obligated to ensure that it can comply with whatever final state plan is adopted 

to meet the final EPA Interim and Final Goals. AEPCO’s options are limited by what it can 

physically build within the proposal’s time lines, what it can financially achieve, what its 

members and their customers and the ACC will accept, and the fact that it is a generation 

cooperative without direct customers, which eliminates most energy efficiency programs from 

consideration. In this part of its comments, AEPCO has (1) evaluated available options; and (2) 

prepared high level analyses of the two principal compliance strategies available to it: comply 

with the program as written; or shut down existing units to exit the program. 

1. Compliance Strategies Available to AEPCO 

The following options for reducing carbon intensity from AEPCO’s Apache Station are 

available: 

 Improve the heat rate/carbon efficiency of “affected EGUs”; 

 Reduce utilization of “affected EGUs”; 

 Purchase an existing “affected EGU” to reduce the overall CO2/MWh of AEPCO’s fleet; 

 Build a new EGU not subject to the Clean Power Plan and shut down affected EGUs as 

appropriate; 

 Build/purchase renewable energy, such as solar photovoltaic, wind, or solar-thermal; 

 Purchase power on the market, if available; and 

 Any combination of the above. 

Each of these options, its feasibility, and pros and cons, is discussed below. 

a) Improve the heat rate/carbon efficiency of affected EGUs 

Apache Station contains three affected EGUs: ST1, a natural gas-fired steam unit with 

hybrid combined cycle options; ST2, a coal-fired steam unit; and ST3, a coal-fired steam unit. 

Apache Station has one peaking combustion turbine that theoretically could become an affected 

EGU, but is unlikely to ever exceed the 219,000 MW hours use threshold. AEPCO’s 

engineering staff has determined that the following heat rate or carbon efficiency improvements 

are possible: 

 ST1 (XXXX lb/MWh estimated in 2012) 

o xxxxxxxxxxxxxxxxxxxxxx 

 
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Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

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 ST2 (XXXX lb/MWh in 2012) 

o XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX 

o XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX 

o XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX 

 ST3 (XXXX lb/MWh in 2012) 

o XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX 

o XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX 

o VVVVVVVVVVVVVVVVVVVVVVVVVVVVVV 

As part of the Regional Haze Rule (“RHR”), AEPCO has proposed to convert ST2 to natural gas 

by December 2017. Natural gas conversion slightly increases available MWh from the unit, but 

results in a higher energy cost due to the higher cost of natural gas per MWh compared to coal. 

This economic dynamic is discussed below. 

None of the changes that AEPCO can make will approach either the 735 lb/MWh Interim 

Goal or the 702 lb/MWh Final Goal. Additional measures will be required. 

b) Reduce Utilization of Affected EGUs 

AEPCO can attempt to reduce utilization of its highest carbon intensity sources, but it 

must also meet its members’ load requirements. Reduced utilization thus must be undertaken in 

conjunction with another alternative, purchase or construction of another generation asset, or 

market power purchases. In addition, reduced utilization also adversely affects the heat rate of 

the EGU compared to full utilization. 

c) Purchase an “affected EGU” to reduce the AEPCO overall 

carbon intensity. 

AEPCO can purchase an affected EGU to reduce the AEPCO affected EGU fleet’s 

overall carbon intensity. AEPCO has evaluated current market opportunities for purchase of 

existing NGCC units and some are available in the range of $500 to $800 per kilowatt in sizes 

that AEPCO could use. The financial impact of attempting to purchase such a unit is addressed 

below. 

d) Build a new EGU. 

AEPCO could seek to build a new EGU. Assuming that siting and transmission issues 

could be overcome in time, the cost of building a new NGCC unit that will comply with the 

proposed EGU NSPS, 79 Fed. Reg. 1430 (Jan. 8, 20140), is likely in the range of $1100 to $1400 

per kilowatt. It is unlikely that a new resource could be brought online prior to 2020. The 

financial impact of attempting to build a new unit is addressed below. 
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September 29, 2014 

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e) Build or purchase renewable energy resources 

There are several options available to AEPCO, including installing photovoltaic or solar 

thermal facilities or wind energy. Solar is probably the lowest cost alternative for installation in 

Arizona and has an approximate cost of $2000/kW with a capacity factor of 0.25. AEPCO has 

space at its existing Apache Generation Station to install solar photovoltaic (PV) panels. One 

challenge with renewable resources generally is their uncertain reliability. AEPCO thus 

generally cannot count on renewables to “meet load,” but must maintain sufficient backup power 

generation capacity to meet load should the renewables be off-line due to lack of sun light, lack 

of wind, or other reasons. The financial impact of including renewables to meet the proposed 

Clean Power Plan is addressed below. 

2. Options Selected for Further Analysis 

Based on the information presented above, AEPCO has selected two options for further 

analysis. The first option is the “compliance” option, where AEPCO seeks to meet the 

requirements of the proposal with its own units. The second option is the “exit” option, where 

AEPCO builds new units subject to the proposed NSPS to replace all its existing affected EGUs 

and exit the 111(d) program entirely. Details of each option are set forth below, as is a “base 

case” option that presents “business as usual” if the Clean Power Plan proposal did not exist 

(necessary to distinguish costs of the Clean Power Plan proposal from normal business changes 

required to operate AEPCO). All cases assume that demand remains close to contract 

minimums, amounting to approximately 537 MW in 2020, increasing to 548 MW in 2030, and 

load is similarly restrained, rising from 3016 GWh in 2020 to 3511 GWh in 2030: 

 Base Case: Purchase XXXXXXX existing NGCC unit in 2015; convert ST2 and ST3 as 

required by RHR FIP/SIP in late 2017 and operate through 2035 pursuant to existing 

contracts. This option will result in approximately XXXX million in additional capital 

cost. The base case shows approximately a reduction in carbon intensity from 1717 

lb/MWh to 1683 lb/MWh by 2030. 

 Compliance Option: Purchase XXXXXXXXX existing affected NGCC unit in 2015; 

convert ST2 to natural gas in 2017; retire ST3 in 2017; purchase XXXXXXX new, NSPS 

NGCC starting 2020; and purchase solar PV and install Wartsilas as needed to both 

achieve Interim and Final Goals and minimize additional costs. This option results in 

CCCCCC installed solar PV and XXXXXX installed Wartsila capacity. This option will 

result in approximately XXXXX million in additional capital cost and shows a reduction 

in carbon intensity from 1717 lb/MWh to 892 lb/MWh in 2030 (affected EGUs would 

meet the state target of 702 lb/MWh). 

 Exit Option: Purchase XXXXXX unaffected NGCC in 2015; convert ST2 to natural gas 

in 2017; retire ST3 in 2017; retire ST1 and ST2 in 2019; purchase XXXXXX new, NSPS 

NGCC starting 2020; purchase solar PV and Wartsilas as needed to achieve Interim and 

Final Goals and minimize additional costs. This options results in no solar PV and XXX 

XXX installed Wartsila capacity. This option will result in XXXXX million in additional 

capital and shows a reduction in carbon intensity to 941 lb/MWh in 2030. 
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September 29, 2014 

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Model output files for each case are included in Attachments “B”, “C” and “D.” All non-base 

cases result in capital expenditures of at least XXX million more than “business as usual.” 

3. Financial Impact of the Compliance Options on AEPCO 

Monthly charges to the Class A Members are calculated and billed in accordance with the 

Wholesale Power Contract or Partial Requirements Capacity and Energy Agreement and consist 

primarily of a Monthly Fixed Charge, Monthly Operations & Maintenance (“O&M”) Charge, 

Base Energy Charge, Base Fuel Cost Adjustor Charge, Other Energy Charge, and Other Fuel 

Cost Adjustor Charge. AEPCO’s expenses and non-tariff revenues are classified by functional 

categories of Fixed Expenses, O&M Expenses and Energy Expenses. As a result, Fixed Costs 

and Monthly O&M Costs are billed separately to the members, not as part of the energy rate. 

a) The Annualized Fixed Cost to AEPCO of the Compliance and 

Exit Options Ranges from XXX to XXX Million per Year 

Applying annualized assumptions, as set forth in Attachment “E,” the additional fixed 

charges the various Compliance Options range from XXXXXXX to XXXXXX million per year, 

which must be spread over AEPCO and its members’ approximately 150,000 meters. These 

costs will be added to AEPCO’s existing fixed charges for these units. The following table 

summarizes the impact on AEPCO’s fixed charges in 2020 and 2030, giving both the Base Case 

and the cost for each option: 

Table 2. Fixed Cost Impacts Compliance Options in 2020/2030 

Category Base Compliance Exit 

Annualized Existing Fixed 

Charges (000s): 

 

Annualized Fixed Charges 

for Option (000s): 

 

Total Annualized Fixed 

Charges (000s): 

 

Net KW-Months, 2020/2030 

(000s) 

 

Fixed Charges, $/KW-Month 

In the last two lines of Table 2, AEPCO has converted the increase in annual fixed charges to its 

corresponding cost in $/KW-Month, which is the unit of measurement typically used to purchase 

or sell long term or “firm” electrical capacity. Converting fixed charges to $/KW-Month allows 

a better understanding of the impact of the increase in fixed costs on AEPCO’s cost structure and 

competitive position. 

 
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b) The O&M Cost to AEPCO of the Compliance Options Ranges 

from XXX to XXXX Million Per Year. 

In addition to the financing costs, purchase and/or installation of new assets will impose 

additional O&M costs on AEPCO. As noted above, O&M represents part of the Monthly O&M 

Charge that AEPCO charges its members. The following table summarizes the impact on 

AEPCO’s O&M expense. 

Table 3. O&M Impacts of Compliance Options in 2020/2030 

Category Base Compliance Exit 

Annualized Existing O&M 

(000s): 

 

Annualized O&M Increase 

for Option upgrades (000s): 

 

Total Annualized O&M 

(000s): 

 

Net KW-Months, 

2020/2030 (000s) 

 

Total Annualized O&M, 

KW-Months: 

 

In the last two lines of Table 3, AEPCO has converted the increase in monthly O&M charges to 

its corresponding cost in $/KW-Month, which is the unit of measurement typically used to 

purchase and sell long term capacity. Converting O&M charges to $/KW-Month allows a better 

understanding of the impact of the increase in O&M costs on AEPCO’s cost structure and 

competitive position. 

4. The Combined Effect of Fixed Costs and O&M Costs of the 

Compliance Options on AEPCO’s Effective $/KW-Month Capacity 

Cost Is Material 

Adding the previously discussed charges and expenses gives AEPCO’s “new” capacity 

cost in $/KW-Month for each option under study. That cost is estimated as follows: 

Table 4. Capacity Cost for Compliance Options in 2020/2030 

Category Base Compliance Exit 

Existing Fixed Charges 

$/KW-Month 

 

Existing O&M 

Total Existing Fixed and O&M 

Charges, $/KW-Month (Capacity 

Charge) 

 

 
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Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

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Category Base Compliance Exit 

Additional Fixed Charges for 

Option, $/KW-Month 

 

Fixed O&M Costs for Option 

Upgrades 

$/KW-Month 

 

Total Fixed & O&M Costs for 

Option Upgrades, $/KW-Month 

 

 

GRAND TOTAL Fixed Plus 

O&M, $/KW-Month 

Base 69.8% over Base 62.8% over Base 

If AEPCO adopts the “compliance option,” its capacity charges, expressed in a $/KWMonth basis, will increase by 69.9% in 2020 and 78.1% in 2030 compared to base. If AEPCO 

seeks to exit the program, its capacity charges, expressed in a $/KW-Month basis, will increase 

by 62.9% in 2020 and 59.1% in 2030. These are substantial increases, particularly when borne 

by the relatively small number of members and their customers. 

Using the fixed and O&M costs discussed above translates to additional charges to 

AEPCO’s Class A members as follows: 

Table 5. Impact on AEPCO Class A Members in 2020/2030 

AEPCO Member Group Capacity % Compliance 

Option 

Exit Option 

Collective All Requirements Members 

(Anza, Duncan, Graham Electric 

Cooperatives) (000s) 

 

Mohave Electric Cooperative 

Sulphur Springs Valley Electric Cooperative 

Trico Electric Cooperative 

AEPCO’s members must pay these fixed charges whether they purchase any electricity 

from AEPCO or not. It is also important to realize that AEPCO’s members must act on this 

information quickly given the time lag associated with AEPCO’s options including, but limited 

to purchasing new or existing assets, purchasing power, or building new assets should alternate 

courses of action be deemed necessary or prudent by AEPCO or its members. 

5. Apache Station Operates in a Competitive Market 

As a result of area-wide changes in wholesale and retail electric supply, there is currently 

a very competitive marketplace for the sale of capacity and energy. Not only can AEPCO 

participate in these markets, but also AEPCO’s Class A PRMs could as well. The existence of 
Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 13 

competitive markets means that AEPCO’s Apache Station or alternatives must be situated to 

compete in those markets with reliable, reasonably-priced energy to retain AEPCO’s members. 

Determining the “market rate” for capacity is a constantly changing and dynamic 

exercise. While AEPCO obviously knows its own $/KW-Month capacity rate, it does not know 

what that rate is or will be for its competitors. Instead, AEPCO and its members must proceed 

by analysis and informed judgment.

In this case, AEPCO can draw some conclusions from recent developments: the 

Southwest Public Power Resources (“SPPR”) Group Purchase Power Agreement (“PPA”) with 

Sempra Generation, Salt River Project’s (“SRP’s”) recent purchase of one block of the Mesquite 

Generating Station from Sempra Generation, and AEPCO’s own inquiries about purchasing 

assets to meet generation needs. 

 The SPPR PPA, involves XX public entities: 

o The PPA is based on a capacity fixed cost of XXX KW-Month plus a fixed O&M 

charge, presently estimated at XXXX KW-Month, for a total fixed cost of 

approximately XXXX KW-Month in 2015. The XXXX is fixed, but the XXXX 

escalated at X% annually would be XXXX in 2020 and the total fixed would then 

be XXXXX. 

o The PPA energy cost is based on natural gas at the So-Cal Border daily index as a 

fuel cost, applied to a heat rate of XXX MMBtu/MWh, increased by a sales tax of 

X%, plus a variable O&M charge starting at about XXX per MWh in 2015. 

Escalating the $XXX by XXX annually would be XXXX in 2020. 

 SRP recently purchased one block of the Mesquite merchant power plant for $371 

million. Mesquite is a dual 624 MW natural gas combined-cycle plant. 

o Using standard assumptions for financing costs, the capacity costs would be 

XXXXXXX/KW-Month, lower than the SPPR PPA. AEPCO assumes that the 

fixed and variable O&M costs are the same as stated in the SPPR PPA, as those 

are based on the same Sempra Generation plant. 

o Finally, we assume that the energy cost would be essentially the same formulation 

as in the SPPR PPA, but based on the actual heat rate (estimated XMMBtu/MWh) 

and the actual cost to SRP of the natural gas. 

 AEPCO approached a number of merchant plant operators about possible purchase of 

either blocks of power or assets at various facilities. While these discussions are 

obviously confidential, in general AEPCO obtained possible pricing (pre-Clean Power 

Plan announcement, which may impact the price) in the following amounts: 

o Fixed and O&M charges would likely be in the range of XXXXXXX/KW-Month 

in 2020, approaching XXXXXXXX/KW-Month in 2030. 

o Variable O&M would likely be in the range of XXXXXXXXXXX/MWh in 2020, 

approaching XXXXXXXXX/MWh in 2030. 
Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 14 

o Energy charges are difficult to forecast given the changes in the market from the 

Clean Power Plan proposal, but would likely be in the range of XXXXXX 

XXXX/MWh in 2020, rising to XXXXXXXXXX/MWh in 2030. 

In 2012, Valley Electric Association obtained a forward power estimate from ACES 

Power Marketing to assist in the long-term valuation of the Sempra PPA discussed above. 

Critically, the ACES analysis discussed two issues: Forward Power Demand, priced in $/MWh, 

and Market Implied Heat Rate (MBtu/kWh). This forecast shows on-peak power demand 

increases from XXXXX/MWh in the 2017-2018 period to perhaps as high as XXXX/MWh in 

2028. However, it also shows that the market implied heat rate will decline from a present XXX 

XX MBtu/kWh in 2018 to approximately XXXX MBtu/kWh in 2020. 

AEPCO has also attempted its own forecast, using EPA’s assumptions on market prices 

set forth in the Regulatory Impact Analysis. 

 

6. Apache Is Non-Viable with Any Compliance Option Costs Added 

AEPCO believes that Apache Station is non-viable with the added costs of Clean Power 

Plan upgrades. When fixed costs are added, the implications of the market trends discussed 

above for AEPCO if either the Compliance or Exit Option is selected are grave, as can be seen in 

the following analysis: 

Table 6. Annualized Market Impact on AEPCO of Compliance Options in 2020/2030 

Market Price Forecast Peak Rate Wrap Rate Comments 

ACES estimate, 

$/MWh (pre-CPP) 

 ACES, Sept. 2020 

estimate 

EPA estimate, $/MWh Est. from EPA IPM/RIA 

AEPCO/PPA Cost 

Comparison 

PPA AEPCO 

Compliance 

AEPCO Exit Comments 

Fixed Charge, $/KWMonth  

O&M Charge, $/KWMonth 

Capacity Charge, 

$/KW-Month 

 

Capacity Charge, 

$/MWh 

 

Variable O&M Charge, 

$/MWh 

 

Energy Charge, $/MWh 

Total Cost, $/MWh Base 38.5% over 

Base 

37.6% over 

Base 

The Table 6 analysis shows: 
Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 15 

 That AEPCO will operate with a premium over market of approximately XXXX/MWh 

versus a long term PPA’s equivalent total cost XXXXXXXXXXXXXXXXXX) in 2020 

if AEPCO seeks to comply with the proposed Clean Power Plan. 

 That AEPCO will operate with a premium over market of approximately XXXX/MWh 

versus a long term PPA’s equivalent total cost XXXXXXXXXXXXXX) in 2020 if 

AEPCO seeks to exit the proposed Clean Power Plan as a compliance strategy. 

 That AEPCO will operate with a cost structure in excess of its likely recovery in either 

Peak or Wrap rates in 2020 if it seeks to comply with the proposed Clean Power Plan. 

On a peak basis, AEPCO’s deficit ranges from XXXXXXXXX/MWh. On a wrap basis, 

AEPCO’s deficit ranges from XXXXXXXXX/MWh. 

 Energy charges are more variable and difficult to forecast, but if natural gas remains 

cheap, then AEPCO’s energy cost advantage (coal over natural gas) will decline, 

rendering AEPCO’s energy charges less competitive. As forecast, AEPCO is very 

concerned that its energy charges may not be competitive in any month. 

 As forecast, AEPCO is wholly non-competitive on a long-term capacity basis. Its ability 

to compete on the spot market is also impaired. 

This premium over the market and competitive PPAs is unsustainable. As it applies to 

AEPCO’s PRMs, the difference in cost of staying in AEPCO versus leaving AEPCO and buying 

power on the open market becomes quite large. Here is the breakdown: 

Table 7. AEPCO Premium Over Market in 2020/2030 (000s)

AEPCO Member Group Compliance Premium Exit Premium 

Collective All Requirements Members 

(Anza, Duncan, Graham Electric 

Cooperatives) 

 

Mohave Electric Cooperative 

Sulphur Springs Valley Electric Cooperative 

Trico Electric Cooperative 

While it is true that there are contractual impediments to a PRM (or ARM) leaving AEPCO, 

member cooperative boards have legal duties to their members. Unless changed, the capacity 

premium and energy charges resulting from either the proposed Compliance Option or Exit 

Option, if incurred as presently foreseen from the Clean Power Proposal, will result in each PRM 

minimizing purchases of AEPCO power and reviewing all available options to reduce exposure 

to AEPCO costs—including potentially withdrawing from AEPCO. If even one PRM leaves and 

shifts their costs to the remaining members, the premium upon the remaining members would 

increase by 45% to 79%. What would likely happen is that AEPCO would dissolve, leaving all 

of the Apache Station as a potentially stranded asset. Given the heat rate and other penalties 

discussed above, it is not clear that a purchaser could be found for the assets. 
Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 16 

D. Request for “Small Public and Cooperative Utility” Category 

Based on the challenges faced by AEPCO and similarly-situated small public and 

cooperative non-profit utilities, AEPCO respectfully requests that EPA consider creating a 

separate category for “small public and cooperative utilities” that provides relief to these small 

entities, ensuring their ability to continue providing basic services, while also providing for 

reasonable reductions in carbon emission rate and mass. 

1. Utilities and EGUs Qualifying for Alternative Category 

AEPCO believes that the category should be limited to public or cooperative entities that 

sell 4 million MWh or less of energy, consistent with the FERC definition. 16 U.S.C. § 824(f). 

AEPCO estimates that there are 23 cooperatives and 75 small public utilities that fit into this 

category based on 2012 data. In order to qualify for relief, the small public or cooperative utility 

would need to demonstrate, applying EPA’s building blocks only to its existing system 

resources, that: 

 One or more affected EGUs (a “non-achieving unit”) cannot meet the relevant state 

Interim Goal or Final Goal; AND 

 Such non-achieving unit(s) make up 20% or more of the small public or cooperative 

utility’s generating capacity; AND 

 Shutting down the unit in 2020 (or 2030) would occur prior to the end of the unit’s 

remaining useful life; AND 

 The cost of building a replacement, NSPS-compliant unit together with the cost of paying 

down debt on the existing non-achieving units, would be excessive. 

In essence, this test is meant to identify only those small public and cooperative utilities that are 

severely affected by the proposed Clean Power Plan—both in terms of costs of compliance and 

loss of generation capacity required to serve member load. 

2. Emissions Reductions Requirements 

 If a small public or cooperative utility meets the qualifying test, then it would qualify for 

an alternative, utility specific goal in the state plan, rather than participating in the general state 

plan. The alternative state plan would require the qualifying small public or cooperative utility 

to undertake the following during the Interim Goal period: 

 Achieve all reasonably cost effective heat rate improvements on any non-achieving 

unit(s) (not just coal-fired ones); 

 Redispatch any NGCC units it owns until 70% annual capacity is achieved; 

 Install renewable energy or obtain RECs equal to 10% of the non-achieving unit(s) 

capacity within 5 years of plan approval or 2025, whichever is earlier; 

 Meet one-half of the general state plan energy efficiency goal, if the small public or 

cooperative utility has local distribution; and 
Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 17 

 Achieve reductions equal to the lesser of the state Final Goal or 15% of total carbon 

emissions across the small public or cooperative utility’s portfolio by 2030, with at least 

33% of that reduction to occur by 2020 or within three years of plan approval, whichever 

is earlier. 

In the Final Goal period (e.g., 2030 and thereafter period), the qualifying small public or 

cooperative utility would need to achieve the following: 

 Shutdown the non-achieving unit(s) at the start of the final goal period; or 

 If any non-achieving unit(s) will remain in operation beyond 2029, then 

o continue any measures imposed on the non-achieving unit(s) and the utility by the 

state plan effective in 2029; and 

o install additional renewable energy or obtain renewable energy credits (in a state 

plan recognizing such credits) equal to at least 10% of the non-achieving unit(s)’ 

capacity prior to the start of the final goal period and every five years thereafter if 

the unit(s) continue to run. 

In addition, all units covered by the small public or cooperative utility plan must shut down at the 

earlier of the end of their remaining useful life or December 31, 2039. The shutdown date must 

appear in the state plan provision. These provisions provide assurance to EPA that nonachieving units cannot run indefinitely, provide an incentive (in the form of additional 

renewables that must be purchased) to the qualifying utility to shutdown the units as soon as 

possible, while still providing some additional flexibility for the small public or cooperative 

utility to pay down debt on such units before being forced to acquire new units. This avoids the 

substantial problem of forcing public or cooperative customers to pay for two sets of units: one 

set retired under the Clean Power Plan and not producing energy and a second set providing the 

energy. Unlike IOUs or larger utilities, small public and cooperative utilities do not have 

investors or a sufficient ratepayer or taxpayer base to bear the load such payments would impose. 

 The proposed regulatory text is found in Attachment “F”. 

3. Impact of the Small Public and Cooperative Utility Alternative on 

AEPCO and Similarly Situated Small Entities 

 The proposed small public and cooperative utility approach substantially reduces the 

impact of EPA’s proposed Clean Power Plan on this sector, while still achieving significant 

carbon emissions reductions. In AEPCO’s case, adoption of this proposal would result in the 

following impacts: 

Table 8. AEPCO Small Public and Cooperative Proposal 

Category Small Coop 

Proposal 

Compliance 

Option 

Exit Option 

Existing Fixed Charges 

$/KW-Month 

 
Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 18 

Category Small Coop 

Proposal 

Compliance 

Option 

Exit Option 

Existing O&M 

Total Existing Fixed and O&M 

Charges, $/KW-Month (Capacity 

Charge) 

 

 

Additional Fixed Charges for 

Option, $/KW-Month 

 

Fixed O&M Costs for Option 

Upgrades 

$/KW-Month 

 

Total Fixed & O&M Costs for 

Option Upgrades, $/KW-Month 

 

 

GRAND TOTAL FixedPlus 

O&M, $/KW-Month 

 

The detailed modeling assumptions for the Small Public and Cooperative Utility case are set 

forth in Attachment “G.” As seen in the table above and the following market analysis, these 

changes substantially help AEPCO’s competitive position: 

Table 9. Annualized Market Impact on AEPCO Small Coop Proposal in 2020/2030 

Market Price Forecast Peak Rate Wrap Rate Comments 

ACES estimate, 

$/MWh (pre-CPP) 

 

EPA estimate, $/MWh 

AEPCO/PPA Cost 

Comparison 

PPA AEPCO 

Compliance 

AEPCO Exit Small Coop 

Proposal 

Fixed Charge, $/KWMonth  

O&M Charge, $/KWMonth 

Capacity Charge, 

$/KW-Month 

Capacity Charge, 

$/MWh 

 

Variable O&M Charge, 

$/MWh 

 

Energy Charge, $/MWh 

Total Cost, $/MWh Base 38.5% over 

Base 

37.6% over 

Base 

8.3% over Base 
Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 19 

While the proposed small public and cooperative utility alternative does not make AEPCO fully 

competitive in the market, it does not leave AEPCO substantially worse off as do the 

Compliance Option and the Exit Option. Based upon its understanding of the small public and 

cooperative utility markets and economics, AEPCO believes that some of the other utilities in 

this sector would similarly benefit. 

4. Impact on Carbon Reductions Sought Under the Proposed Clean 

Power Plan 

As noted above, AEPCO believes that there are approximately 98 entities that may 

qualify for the small public and cooperative utility alternative category. AEPCO has attempted a 

very rough evaluation of the impact of the proposed alternative category on the carbon emissions 

reductions that EPA is seeking. 

AEPCO looked up net generation on the EIA, FERC and EPA databases to identify all 

utilities potentially qualifying for the alternative category. As noted above, the alternative 

potentially encompasses 23 cooperative and 75 public entities. AEPCO summed the total net 

megawatt hours from all 98 utilities and assumed that 15% of this total would be reduced under 

the alternative, while 30% of the coal megawatt hours would be reduced under the Clean Power 

Plan. Finally, AEPCO converted the values to metric tons for comparison with EPA’s estimated 

730 million metric ton reduction under the Clean Power Plan. 

The results show that if the small public and cooperative utility alternative guidelines 

were selected by all such entities (assuming that they qualify), it would cover 98 entities, 

generating approximately 60,618,920 metric tons. The proposed alternative category would 

achieve at least a 15% reduction, or 9,092,838 metric tons. Comparing this sum to EPA’s 

calculated 730,000,000 metric ton reduction, the proposal would result in leakage of at most 

1.2% of the total tonnage. 

 AEPCO believes that this calculation substantially overstates the impact on the proposed 

Clean Power Plan. AEPCO ran its own resource planning scenarios. Based upon a “reasonably 

likely” forecast using the proposed small public and cooperative utility provision, AEPCO 

forecasts that its final fleet wide generation rate would likely be XXXX lbs/MWh during the 

Interim Goal period, a 17.1% reduction, dropping to XXX lbs/MWh by 2030, resulting in a 

21.0% reduction in portfolio carbon emissions in the Final Goal period, all measured against an 

average portfolio rate of XXXX lbs/MWh in the baseline period. 

 If AEPCO’s evaluation is similar to other utilities in its position, then the total leakage 

from the proposed Clean Power Plan is likely to be less than 10% of the potentially affected 

carbon emissions, resulting in a loss of only 9 million metric tons or 1.2 percent of the 730 

million metric ton reduction EPA is seeking. Given the substantial benefits that the proposed 

alternative categorization provides to the small public and cooperative utility sector and its 

members, ratepayers and taxpayers, these benefits should outweigh the small cost in carbon 
Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 20 

emissions, particularly given that the category phases out no later than December 31, 2039 for all 

units and potentially earlier for many units. 

 AEPCO notes that many cooperatives, regardless of size, face the same issues that it does 

with financing the improvements required by the proposed Clean Power Plan. AEPCO will 

evaluate the impact of expanding the requested category to include all cooperatives and may 

supplement this request for categorization with additional information about such an expansion 

for EPA’s consideration. 

5. Legal Basis for Proposed Category 

EPA’s regulations governing the promulgation of the Guidelines for State Plans clearly 

give EPA the authority to promulgate subcategories and EPA has routinely exercised such 

authority under the general NSPS program. Section 60.22 provides in relevant part: 

The Administrator will specify different emission guidelines or compliance times 

or both for different sizes, types, and classes of designated facilities when costs of 

control, physical limitations, geographical location, or similar factors make 

subcategorization appropriate. 

40 C.F.R. § 60.22(b)(5). In this case, the costs of control and financial limitations of the entities 

involved (small public or cooperative utilities, which are non-profit) provide a strong basis for 

subcategorization and providing both a more relaxed limit (meeting the building blocks on the 

system only, with a target of reaching the State goals or 15% overall reduction, whichever is 

less) and a more relaxed time frame (providing a longer period to reach the overall reduction, up 

to but not to exceed the remaining useful life of the affected EGU). 

 AEPCO hopes that EPA will seriously consider these comments and requested 

subcategorization of the existing Clean Power Plan to create a subcategory for small public and 

cooperative utilities. 

Confidential Business Information

 This Public Release Version is not claimed as Confidential Business Information. The 

Confidential Business Information version was filed in accordance with EPA directions in the 

Federal Register. 

 In closing, AEPCO appreciates the opportunity to submit this first set of comments and 

request for categorization of the small public and cooperative utility sector apart from the general 

state targets set forth in the proposed Clean Power Plan. AEPCO looks forward to submitting 

additional comments in its efforts to help EPA understand the impact on AEPCO and similarly 

situated entities. 

Comments and Request for Small Cooperative Categorization [Non-CBI Version] 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

Page 22 

LIST OF ATTACHMENTS

A. Steve Burr, ADEQ, email dated August 22, 2014 

B. Resource Planning Model Outputs for Base Case [Not Included—Confidential Business 

Information] 

C. Resource Planning Model Outputs for Compliance Case [Not Included—Confidential 

Business Information] 

D. Resource Planning Model Outputs for Exit Case [Not Included—Confidential Business 

Information] 

E. Annualization Assumptions 

F. Proposed Small Public and Cooperative Utility regulatory language 

G. Resource Planning Model Outputs for Small Public and Cooperative Utility Case [Not 

Included—Confidential Business Information] 

H. Powerpoint presentation to EPA on September 25, 2018 [Public Release Version] 
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

ATTACHMENT “A” 

Steve Burr, ADEQ, email dated August 22, 2014 

 
1

Eric Hiser

From: Steve Burr <Burr.Steven@azdeq.gov>

Sent: Friday, August 22, 2014 1:09 PM

To: Eric C. Massey; 'barbara.sprungl@srpnet.com'; 'kara.montalvo@srpnet.com'; 

'grant.smedley@srpnet.com'; 'kelly.barr@srpnet.com'; 'harry.sauthoff@srpnet.com'; 

'jason.burke@srpnet.com'; 'charles.spell@aps.com'; 'ann.becker@pinnaclewest.com'; 

'michael.kafka@pinnaclewest.com'; 'paul.smith@aps.com'; 'nancy.nesky@aps.com'; 

'jyockey@tep.com'; 'ebakken@tep.com'; 'msheehan@tep.com'; 

'bill.lawson@pacificorp.com'; 'chad.teply@pacificorp.com'; 

'steven.jensen@pacificorp.com'; 'mary.wiencke@pacificorp.com'; 

'CSWoollums@berkshirehathawayenergyco.com'; Eric Hiser; 'mfreeark@ssw.coop'; 

'lgernet@ssw.coop'; 'Estoneburg@azcc.gov'; 'MLittle@azcc.gov'; Tai Wallace

Subject: FW: Emission Guidelines for Existing Stationary Sources: Electric Utility Generating 

Units; Proposed Rule; 79 Fed. Reg. 34830 (June 18, 2014); Docket ID No. EPA-HQOAR-2013-0602

Attachments: Arizona Interim Goal Analysis.xlsx

FYI

From: Steve Burr 

Sent: Friday, August 22, 2014 1:08 PM 

To: 'Jordan.deborah@Epa.gov'; McKaughan, Colleen (McKaughan.Colleen@epa.gov); 'A-and-R-Docket@epa.gov' 

Cc: Eric C. Massey 

Subject: Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units; Proposed Rule; 79 Fed. 

Reg. 34830 (June 18, 2014); Docket ID No. EPA–HQ–OAR–2013–0602 

Debbie and Colleen: Would you mind forwarding this to the appropriate staff at EPA?

Attached is the spreadsheet that the Arizona Department of Environmental Quality mentioned on the August 14, 2014

conference call between Region 9 states and EPA. The spreadsheet illustrates the fundamental inconsistency between

the proposed interim goal and EPA’s stated objective of allowing states flexibility in choosing how to comply with the

guidelines. The following table provides a summary of the results of our calculations:  

Step 3a & 3b (Redispatch) Step 6&7 (State Goal Phase I &

II (lbs/MWh))

Scenario Redispatched

Coal Gen.

(MWh)

Redispatch

O/G steam

Gen. (MWh)

Redispatched

NGCC Gen.

(MWh)

Interim Goal

or Rate (2020

‐ 2029

average)

Final Goal or

Rate (2030 and

thereafter)

1. EPA Goal Calculation 0 0 52,152,127 735 702

2. 15 % RE and 1.61 % Incremental

EE Savings

6,532,309 277,514 45,342,304 774 702

3. 21 % RE and 1.61 % Incremental

EE Savings

9,707,768 412,418 42,031,940 803 702

4. 33 % RE and 2.00 % Incremental

EE Savings

17,289,395 734,511 34,128,220 858 702
2

5. 33 % RE and 2.00 % Incremental

EE Savings

9,476,915 402,611 42,272,601 735 601

As the table shows, the more Arizona relies on Building Blocks 3 and 4 to achieve compliance with the final goal of 702

lbs CO2/MWh, the farther it gets from compliance with the interim goal (scenarios 2‐4). Conversely, if Arizona designs its

program to comply with the interim goal, it ends up with a final rate that is far lower than necessary to comply with the

final standard and ends up preserving a much smaller portion of its existing coal‐fired generation resources (scenario 5).

In fact, Arizona has no flexibility to shift from one Building Block to another to meet its rate‐based goal under the

program as proposed. The state cannot increase reliance on Building Block 1, because the rate‐based goal assumes zero

coal generation, and the interim goal, as explained above, prevents Arizona from increasing reliance on Building Block 3

or 4 to preserve coal generation.  If no coal generation remains in 2020, increasing the efficiency of coal units will

obviously have no effect on Arizona’s rate. Arizona cannot increase reliance on Building Block 2, because the interim

goal effectively requires the maximum redispatch possible.

Arizona is not the only state in this predicament. EPA’s goal calculation spreadsheet makes it clear that a number of

other states have goals that presume redispatch of all or a substantial portion of coal and OG generation to NGCC by

2020. Moreover, for some states, the presumption of 2020 implementation of Building Block 1 may present a similar

impediment to flexibility.

EPA therefore should eliminate, or adopt a different approach to, the interim goal. If an interim goal is included in the

final rule, it should provide a reasonable phase‐in period for all Building Blocks.  Otherwise EPA will deny Arizona and

many other states the flexibility it intended to include in the program.

Please note that the scenarios presented in the spreadsheet are offered solely to illustrate the problems with EPA’s

proposed interim goal. ADEQ has not evaluated the technical or economic feasibility of any of the RE or EE alternatives

included.

EPA should also note that the issue addressed in the spreadsheet and this email is not the only problem with the interim

goal or Building Block 2 that ADEQ has identified. ADEQ intends to submit additional comments on these issues as well

as other aspects of the proposal.

Steve Burr

Legal Support Section

Air Quality Division

Arizona Department of Environmental Quality

602‐771‐4251
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

ATTACHMENT “B” 

Resource Planning Model Outputs for Base Case 

Not Included – Confidential Business Information 
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

ATTACHMENT “C” 

Resource Planning Model Outputs for Compliance Case 

Not Included -- Confidential Business Information 

 
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

ATTACHMENT “D” 

Resource Planning Model Outputs for Exit Case 

Not Included -- Confidential Business Information 

 
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

ATTACHMENT “E” 

Annualization Assumptions 

 
ATTACHMENT “E”

Annualization Assumptions

AEPCO used the following assumptions to develop the annualized financial results provided in

the preceding analysis.

Existing Cooperative‐owned assets were depreciated using current RUS & ACC approved

deprecation rates.    These rates were developed to correspond with our 2035 contract dates.    The

purchase price of any newly acquired existing Combined Cycle Natural Gas asset was depreciated using a

straight‐line method assuming a useful life of 20 years.    Newly‐built natural gas resources were

depreciated using a thirty year useful life.  Photovoltaic solar projects were depreciated assuming a 25

year life.

The Cooperative assumed the continued availability of the RUS program in developing its

financing assumptions.  Amortizing RUS debt with level payments was modelled and maturity dates were

selected that matched the useful lives of the assets.  Current RUS interest rates were modified based on

expected fluctuations in treasury rates.  The following interest rates were used in our model:

2015 2016 2017 2018 2019 2020 2021 2022

3.5% 3.8% 4.0% 4.5% 4.8% 5.0% 5.3% 5.5%

 

2023 2024 2025 2026 2027 2028 2029 2030

5.0% 5.0% 4.5% 4.5% 4.3% 4.0% 4.0% 4.0%

A 2% burden rate consisting of property tax and insurance was assessed on newly acquired or

built property.  In addition, a 1.5X Times Interest Earned (TIER) adder was included to ensure compliance

with the financial covenants of our RUS mortgage and to be consistent with historical ACC approved

revenue requirements.
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

ATTACHMENT “F” 

Proposed Small Public and Cooperative Utility Category Regulatory Language 

 
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

ATTACHMENT “F” 

Proposed 40 C.F.R. § 60.5765(b) 

 (b) In lieu of meeting the state-wide goal established in 40 C.F.R. § 60.5765(a) and Table 1, a 

State may establish an alternative rate-based or mass-based emission performance goal for 

affected EGUs owned by a small public or cooperative utility on January 8, 2014 in accordance 

with this subsection. 

 (1) For purposes of this subsection, a “small public or cooperative utility” is a governmentallyor cooperatively owned non-profit entity primarily engaged in the generation, transmission, 

and/or distribution of electric energy for sale with total electric output (including affiliates) of 4 

million megawatt hours (MWh) or less during the baseline period. 

 (2) An small public or cooperative utility qualifies for the alternative limit in this subsection if, 

after implementing all reasonably cost effective affected unit heat rate improvements, 

dispatching all existing natural gas combined cycle affected units owned by the entity at 70% 

annual net capacity, and accounting for any renewable resources (other than hydropower or 

existing nuclear generation) owned by the entity, the following are true: 

 (i) one or more affected EGUs (the “non-achieving unit(s)”) owned by the small public or 

cooperative utility cannot achieve the interim goal on a rate basis using only the small public or 

cooperative utility’s affected units and renewable resources and any existing state-mandated 

energy efficiency requirements; 

 (ii) the non-achieving unit(s), individually or collectively, make up 20 percent or more of the 

small public or cooperative utility’s net generation in the baseline period; 

 (iii) shutting the non-achieving unit(s) down will occur prior to the end of the remaining useful 

life as determined by the utility regulatory commission having jurisdiction, if any, or the 

permitting authority, if none; and 

 (iv) the cost of building an equivalent sized NGCC, NSPS-compliant, unit or units to replace 

the non-achieving unit(s) plus servicing existing debt for the non-achieving units would, in the 

judgment of the state, be excessive. 

 (3) For each small public or cooperative utility that owned an affected EGU on June 18, 2014 

and continues to own that non-achieving unit satisfying the criteria in paragraph (b)(2) of this 

section, the State may exclude such non-achieving unit(s) from calculating its state-wide goal in 

Table 1 of this subpart and establish an alternative goal under its state plan as follows: 

 (i) During the interim goal period: 

(A) Each non-achieving unit owned by the qualifying small public or cooperative utility 

must implement all reasonably cost effective measures to improve heat rate, which must include 

enforceable increments of progress, not to exceed five years from plan approval; 

(B) The qualifying small public or cooperative utility shall increase dispatch of all 

existing NGCC units it owns to the maximum extent feasible, up to a 70% utilization rate; 

provided, however, that if the increased dispatch of NGCC units results in the non-achieving unit 

being reduced below its reliability limit, the state plan may provide for either periodic 

curtailment or earlier retirement of the non-achieving unit so long as total carbon mass is not 

increased over what would be achieved by 70% utilization of NGCC units owned by the small 

public or cooperative utility during the interim goal period. 
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 25, 2014 

Page 2 

(C) The qualifying small public or cooperative utility shall install renewable energy 

capacity or obtain renewable energy credits (in a state plan recognizing such credits) equal to at 

least 10% of non-achieving unit(s) capacity within five years of plan approval or 2025, 

whichever is later. 

(D) The qualifying small public or cooperative utility, if it has local distribution, shall 

achieve at least one-half of any applicable state energy efficiency requirements set forth in the 

state plan. 

(E) The qualifying small public or cooperative utility shall achieve a net reduction of its 

carbon intensity through the measures specified in paragraph (b)(3)(i)(A) through (D), plus 

additional increments of process specified in the state plan for such small public or cooperative 

utility, equal to the lesser of the following (excluding nuclear and hydropower): 

(I) an amount that achieves for the small public or cooperative utility an emission rate 

equal to the state Final Goal established in Table 1 of Subpart UUUU by 2030; or 

(II) an amount that achieves a 15 percent reduction from the baseline carbon intensity of 

the small public or cooperative utility. 

(F) The qualifying small public or cooperative utility must achieve at least 33% of the 

reduction required in subsection (b)(3)(i)(E) by 2020 or three years after plan approval, 

whichever is later. 

 (ii) During the final goal period, the state plan shall provide that the qualifying small public or 

cooperative utility must take one of the following actions: 

(A) Shutdown the non-achieving unit(s) at the start of the final goal period; or 

(B) If any non-achieving unit(s) will remain in operation, then the qualifying small 

public or cooperative utility shall continue any measures imposed on the non-achieving unit(s) 

and the utility by the state plan and shall install additional renewable energy or obtain renewable 

energy credits (in a state plan recognizing such credits) beyond the quantity required in 

subparagraph (b)(3)(i)(C), equal to at least 10% of the non-achieving unit(s)’ capacity prior to 

the start of the final goal period. Additional renewable energy offsets equal to 10% of the nonachieving unit(s)’ capacity must be obtained prior to each fifth anniversary of the final goal plan 

effective date if the unit is to be kept in operation beyond the anniversary date. These offsets are 

in addition to any other renewable energy requirements in the state plan that are applicable to all 

utilities. 

 (iii) In no event may a non-achieving unit operate pursuant to this subsection (b) beyond the 

end of its remaining useful life established by the utility regulatory commission having 

jurisdiction, if any, or the permitting authority, if none. The remaining useful life of any unit for 

which this subsection (b) shall not be greater than 20 years from the date of plan approval and a 

shutdown date for each non-achieving unit shall be included in the state plan. 

 (4) A state may establish more stringent requirements for a qualifying small public or 

cooperative utility. 
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

ATTACHMENT “G” 

Resource Planning Model Outputs for Small Public and Cooperative Utility Case 

Not Included -- Confidential Business Information 

 
Comments and Request for Small Cooperative Categorization 

Arizona Electric Power Cooperative, Inc. 

September 29, 2014 

ATTACHMENT “H” 

Powerpoint Presentation to EPA on September 25, 2014

Public Release Version
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Clean Power Plan Cooperative Impacts

and a

Possible Alternative Resolution

September 25, 2014

Public Release Version 1

Introductions

• Patrick Ledger, CEO

• Peter Scott, CFO

• Michelle Freeark, Director of Safety & Environmental

• Logan Gernet, Resource Planning

• Eric Hiser, counsel for AEPCO

– Jorden, Bischoff & Hiser, P.L.C.

• Vin Nitido, AEPCO Board Member

– CEO, Trico Electric Cooperative

Public Release Version 2
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Organization and

Membership

• Arizona Electric Power

Cooperative (AEPCO) owns

and operates Apache

Generating Station.

• Southwest Transmission

Cooperative (SWTC) owns and

operates the transmission

system.

• Serve six rural electric

distribution cooperatives over

a large geographical area—12

counties, numerous cities, and

8 tribes (about 150,000

meters).

Public Release Version 3

Apache Generating Station

Public Release Version 4
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Transmission System

Public Release Version 5

Current Membership

6

•All-requirements members ("ARMs") purchase all the requirements necessary 

for serving their distribution cooperative members from AEPCO

•Partial-requirements members ("PRMs") purchase both from AEPCO and from 

other market sources

•Class D Member Valley takes scheduling and trading services from AEPCO Public Release Version
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AEPCO’s Concerns

• AEPCO previously met with EPA over regional

haze.

– Severely affected by $192 million proposal

– Worked with EPA to develop alternative, $30 million

but 25% increase in fuel costs

– Thought we had made AEPCO viable for medium term

• Clean Power Proposal jeopardizes gains

– Want to work with EPA once again to reach a similarly

successful resolution that achieves EPA’s goals while

providing reliable and affordable power to members

Public Release Version 7

ADEQ on CPP Goal Calculation

• Formula:

– “Gen” = Generation in MWh

– “ER” = Emission rate in lbs CO2/MWh

– “OG” = Oil and Gas

– “Other” generation consists of IGCC and high utilization (> 33%

capacity factor [CF]) combustion turbines. Other generation is

excluded from the redispatch calculations in Step 3.

• Arizona:

Coal	Gen	 ൈ Coal	ER ൅ OG	Gen	 ൈ OG	ER ൅ ሺNGCC	Gen	 ൈ NGCC	ERሻ	൅	Other	Emissions

Coal	Gen ൅ OG	Gen ൅ NGCC	Gen ൅ Other	Gen

24,335,930 ൈ 2,268 ൅ 1,033,871 ൈ 1,563 ൅ ሺ26,782, 325 ൈ 900ሻ	൅	17,227,768

24,335,930 ൅ 1,033,871 ൅ 26,782,325 ൅ 19,361

ൌ 1,551 lbs/MWh

Public Release Version 8
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ADEQ on CPP Goal Calculation

• Arizona in 2029:

0 ൈ 2,132 ൅ 0 ൈ 1,563 ൅ ሺ52,152,126 ൈ 900ሻ	൅	17,227,768

0 ൅ 0 ൅ 52,152,126 ൅ 19,361 ൅ 1,818,486 ൅ 3,663,325 ൅ 9,216,009

ൌ 702	lbs/MWh

Public Release Version 9

ADEQ:  No Flexibility in CPP

as Proposed for Arizona

Public Release Version 10
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AEPCO Compliance Options

• Improve the heat rate/carbon efficiency of “affected

EGUs”;

• Reduce utilization of “affected EGUs”;

• Purchase an existing “affected EGU” to reduce the

overall CO2/MWh of AEPCO’s fleet;

• Build a new EGU not subject to the Clean Power Plan

and shut down affected EGUs as appropriate;

• Build/purchase renewable energy, such as solar

photovoltaic, wind, or solar‐thermal;

• Purchase power on the market, if available; and

• Any combination of the above.

Public Release Version 11

Options Studied

• AEPCO evaluated three options:

– Base Case:  Purchase XXX MW of existing NGCC unit in 2015; convert

ST2 and ST3 as required by RHR FIP/SIP in late 2017 and operate

through 2035 pursuant to existing contracts.  

– Compliance Option:  Purchase XXX MW of an existing affected NGCC

unit in 2015; convert ST2 to natural gas in 2017; retire ST3 in 2017;;

and purchase solar PV and Wartsilas as needed to both achieve

Interim and Final Goals and minimize additional costs.

– Exit Option:  Purchase XXX MW of unaffected NGCC in 2015; convert

ST2 to natural gas in 2017; retire ST3 in 2017; retire ST1 and ST2 in

2019; purchase XXX MW new, NSPS NGCC starting 2020; purchase

solar PV and Wartsilas as needed to achieve Interim and Final Goals

and minimize additional costs.

Public Release Version 12
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Case Study Results

• Base Case:

– $XX.X million reduces CPP units to XXXX lb/MWh

(22.4%) and portfolio to XXXX lb/MWh (16.7%)

• Compliance Case:

– $XXX.X million reduces CPP units to XXX lb/MWh

(68.2 %) and portfolio to XXX lb/MWh (56.0%)

• Exit Case:

– $XXX.X million eliminates CPP units (100%) and

reduces portfolio to XXX lb/MWh (53.6%)

Public Release Version 13

Case Study Results

Category Base Compliance Exit

Existing Fixed Charges

$/KW‐Month

Existing O&M

Total Existing Fixed and O&M Charges,

$/KW‐Month (Capacity Charge)

Additional Fixed Charges for Option,

$/KW‐Month

Fixed O&M Costs for Option Upgrades

$/KW‐Month

Total Fixed & O&M Costs for Option

Upgrades, $/KW‐Month

GRAND TOTAL FIXED Plus O&M, $/KW‐

Month

Base 69.8% over Base 62.8% over Base

Public Release Version 14
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AEPCO Out of Market

15

Market Price Forecast

(ACES)

Peak Rate Wrap Rate Comments

High Price, $/MWh

Low Price, $/MWh

AEPCO/PPA Cost

Comparison

PPA AEPCO

Compliance

AEPCO Exit Comments

Fixed Charge, $/KW‐

Month

O&M Charge, $/KW‐

Month

Capacity Charge, $/KW‐

Month

Capacity Charge, $/MWh

Variable O&M Charge,

$/MWh

Energy Charge, $/MWh

Total Cost, $/MWh Base 38.5% over Base 37.6% over Base

0

[1].

Public Release Version

Impact on Members

AEPCO Member Group Compliance Premium Exit Premium

Collective All Requirements Members

(Anza, Duncan, Graham Electric Cooperatives)

Mohave Electric Cooperative

Sulphur Springs Valley Electric Cooperative

Trico Electric Cooperative

Public Release Version 16
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Impact on AEPCO

• Unless changes, it appears that Interim Goal

and Final goal will require shut down of

Apache Station in 2020.

• Even with changes in Interim Goal, AEPCO has

no realistic way of reaching the Final Goal by

2030.

• This jeopardizes 425 MW of 555 MW capacity.  

– Creates reliability issues on transmission system

Public Release Version 17

Solutions

• EPA should subcategorize the affected EGU

category to provide a pathway for small public

and cooperative utilities to achieve substantial

reductions, but over a longer time frame

consistent with their financial abilities.

• Who:

– Public and cooperative utilities with base year sales of

4 million megawatt hours or less

– Disproportionately affected by proposed Clean Power

Plan

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Who Qualifies

• In order to qualify for relief, the small public or cooperative

utility would need to demonstrate, applying EPA’s building

blocks only to its existing system resources, that:

– One or more affected EGUs (a “non‐achieving unit”) cannot

meet the relevant state Interim Goal or Final Goal; AND

– Such non‐achieving unit(s) make up 20% or more of the small

public or cooperative utility’s generating capacity; AND

– Shutting down the unit in 2020 (or 2030) would occur prior to

the end of the unit’s remaining useful life; AND

– The cost of building a replacement, NSPS‐compliant unit

together with the cost of paying down debt on the existing non‐ achieving units, would be excessive.

Public Release Version 19

Alternative Guideline

• Interim Goal Period:

– Achieve all reasonably cost effective heat rate improvements on any

non‐achieving unit(s) (not just coal‐fired ones);

– Redispatch any NGCC units it owns until 70% annual capacity is

achieved;

– Install renewable energy or obtain RECs equal to 10% of the non‐ achieving unit(s) capacity within 5 years or plan approval or 2025,

whichever is earlier;

– Meet one‐half of the general state plan energy efficiency goal, if the

small public or cooperative utility has local distribution; and

– Achieve reductions equal to the lesser of the state Final Goal or 15% of

total carbon emissions across the small public or cooperative utility’s

portfolio by 2030, with at least 33% of that reduction to occur by 2020

or within three years of plan approval, whichever is earlier.

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Alternative Guideline

• Final Goal Period:

– Shutdown the non‐achieving unit(s) at the start of the final goal

period; OR

– If any non‐achieving unit(s) will remain in operation beyond

2029, then

• continue any measures imposed on the non‐achieving unit(s) and the

utility by the state plan effective in 2029; AND

• install additional renewable energy or obtain renewable energy

credits (in a state plan recognizing such credits) equal to at least 10%

of the non‐achieving unit(s)’ capacity prior to the start of the final goal

period and every five years thereafter if the unit(s) continue to run.

• In addition, all units covered by alternative must shut down

at the earlier of the end of their remaining useful life or

December 31, 2039, as specified in state plan.

Public Release Version 21

Impact of Alternative Market Price Forecast

(ACES)

Peak Rate Wrap Rate Comments

High Price, $/MWh

Low Price, $/MWh

AEPCO/PPA Cost

Comparison

PPA AEPCO

Compliance

AEPCO Exit Small Coop Proposal

Fixed Charge, $/KW‐Month

O&M Charge, $/KW‐Month

Capacity Charge, $/KW‐

Month

Capacity Charge, $/MWh

Variable O&M Charge,

$/MWh

Energy Charge, $/MWh

Total Cost, $/MWh Base 38.5% over base 37.6% over base 8.3% over base

Public Release Version 22
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Impact of Alternative

• AEPCO has evaluated the potential impact of

its proposed subcategory on EPA’s Clean

Power Plan proposal.

– EPA is guaranteed at least 15% reduction or State

Goal achievement by all small public and

cooperative utilities.

– It will likely be more: In AEPCO’s case, it results in

a 21% overall portfolio decrease

Public Release Version 23

Impact on CO2 Reductions

• AEPCO assessed the preliminary impact on

carbon reductions.

– Unclear if all small entities qualify

– Maximum leakage is 9 million metric tons (1.2%)

– Likely leakage is 6 million metric tons (0.8%)

• However, alternative requires improvements

on total portfolio, further reducing leakage

from proposed Clean Power Plan.

Public Release Version 24
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Summary

• CPP as proposed imposes substantial burdens on

AEPCO, likely resulting in shut down of Apache

Station or excessive costs on relatively poor, few

and rural rate payers of members

• Subcategorization can significantly reduce the

burden by allowing time to achieve EPA’s goals at

substantially less cost

• AEPCO is pleased to work with EPA to develop a

viable subcategory proposal

Public Release Version 25