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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: Electr ic 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 emi ssion 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 comme nts, 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”) Ap ache Generating Station and potentially other small cooperative power plants, imposing extrav agant 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 EP A 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.Comments and Request for Sma ll Cooperative Categorization [Non-CBI Version] 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 genera tion and transmission electric cooperative formed in 1961 to provide electric generation serv ice to local rural, c onsumer-owned electric distribution cooperatives in Ariz ona. As a not-for-profit cooper ative, AEPCO is fully owned by

its members. AEPCO has six “Class A” memb ers, who participate in and rely on AEPCO’s electric generation services, a nd one “Class D” member that only participates in AEPCO’s electric scheduling and trading services. Together, AEPCO’s Cl ass A members serve just under 150,000 meters. The electric service base is heavil y skewed toward rural residential use, with relatively little commercial or industrial load. The service ar ea 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 (“GT 1”), a 10 net MW simple cycle gas turbine in 1964. GT1 exhausts through either the ST1 wi ndbox and stack or its own stack. In 1978-1979, AEPCO added Steam Units 2 and 3 (“ST2” a nd “ST3”), almost id entical 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 EP A 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 “h eat rate.” A high heat rate means that their relative energy cost is high compared to the mark et. 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, coalComments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 3

The approximate average heat rate of a newe r combined cycle unit would, for comparison purposes, be in the range of 7,000 to 7,800 Btu/kW h 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 fr om $158 million in 2012 to $170 million in 2013. Under the terms of the cooperative’s bylaws, al l amounts in excess of operating costs, expenses and prior losses are received with the understand ing that they are furnished by the members as patronage capital and eventually returned b ack 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 Cooperativ e Finance Corporation (“CFC”). The RUS mortgage limits AEPCO’s total debt to $600 million, assuming AEPC O can get necessary approval or lien accommodation under RUS regul atory and loan processes to fund capital

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

fashion.

Unlike many other electric cooperatives, AEPC O is also subject to regulation by its state public utility commission, the Arizona Corpor ation Commission (“ACC”). The ACC must approve AEPCO’s rates to its Arizona member s 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 th e three All Requirements Members (ARMs) and the three Partial Requirements Members (PRMs). This relationship is fundament ally unlike that of a traditional IOU’s relationship to its customers.

a) AEPCO’s Members Are Independen t Entities that Make Power and Energy Purchase Decisions Ba sed on the Best Interest of

Their Members

Each AEPCO member is a cooperative charge d with procuring econom ical power for its members. Because the members are independent le gal 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, w ho 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 Sma ll 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 pow er elsewhere despite existing contractual requirements. This differs from many situations where the rate payers may have the theoretical right to contract elsewh ere, but do not have the effective ability to do so. In this case, AEPCO’s ultimate rate payers are already organi zed into cooperatives that can contract at

wholesale to take their busi ness 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 ha ve “capital” in the trad itional sense of an investor owned utility. Instead, AEPCO has “patronage capital,” wh ich is retained earnings not yet returned to its members. Only the patronage capital necessary to maintain financial stability is retained at the generation coope rative. Any excess is required to be returned to the members.

Second, AEPCO does not have any ability to is sue equity instruments and generally does not have the ability to seek capit al contributions from its member s for capital expenditures. All expenditures for plant improvements or retrofits are financed by debt in struments secured by the RUS mortgage. In short, AEPC O does not have the ability in ternally to raise capital.

Third, AEPCO’s operating margins generally are fa irly thin and net cash flows have been historically flat and frequently negative. Routinely, principal payments and non-operating expenditures result in little remaining cash margi n. Operating margins have been less than or a

little more than the amount needed to finance th e increase in existing debt service. Because capital construction costs are front loaded, AEPCO does not have th e internal ability to finance the construction or purcha se of new generation and pay down its ex isting debt load. It must have a loan, which must be secure d by the RUS mortgage and AEPC O must meet RUS’s TIER and DSC covenant requirements. These mortgage co venants cannot be achieved with the margins provided by AEPCO’s present (or pe nding) rate structure if the Cl ean Power Plan were to be implemented. Significant rate increases would be required.

For the reasons discussed in these comments and request fo r 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 reti rement of AEPCO’s affected E GUs 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 financia l resources to construc t new units, buy existing units, or purchase power to replace at leas t 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 PlanComments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 5

AEPCO has carefully reviewed EPA’s propos ed Clean Power Plan and the proposed Carbon Pollution Emissions Guidelines, which es tablish 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 EP A has looked at four “building blocks” in setting the Interim Goal and Final Goal: (1) impr oved 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 substant ial “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 SubpartUUUU of Part 60—State RateBased CO 2 Emission Performance Goals (pounds of CO 2 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 follo wing 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	E R ൯ ൅ ൫OG	Gen ൈ OG E R ൯ ൅ ሺNGCC Gen ൈ NGCC ERሻ	൅	Other	Emissions

Coal	Gen ൅ OG Gen ൅ NGCC Gen ൅ Other Gen

ሺ 24,335,930 ൈ 2,268 ሻ ൅ ሺ 1,033,871 ൈ 1,563 ሻ ൅ 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 ܩ݁݊ ௨௖ା௔௥ ൅ ܴܧ	ܩ݁݊ ൅ ܧܧ ܩ݁݊

ሺ 0 ൈ 2,132 ሻ ൅ ሺ 0 ൈ 1,563 ሻ ൅ 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+)Comments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 6

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 re dispatched to NGCC. As noted above, AEPCO has no NGCC generating capacity and redispat ch of ST2, ST3 and ST1 reduces Apache Generating Station’s capacity from net instal led 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 considerab le flexibility in applying the Clean Power Plan flexibly to address circumstances and to prev ent 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 occu r 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 Bloc k #2 because there is no “OG Gen” capacity left that has not already been redispatched to NGCC. Accordi ngly, it appears that under the Clean Power Plan as proposed, effective Ja nuary 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 EP A’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 re newable energy exceed EPA’s calculations,

which EPA believes will be the case because of Ar izona’s renewal portfolio standard (“RPS”) is relatively high. In addition, AEPCO and ADEQ ha ve determined that EPA treats “import” power as having a “0” carbon intensity when impor ted 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 assump tions 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 th e 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 calcu lations is not counted and it is not clear to AEPCO how Arizona will experience meaningful be nefit from it. Third, EPA’s modeling runs assume significant changes in Arizona’s energy pos ition 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 thei r own systems. AEPCO’s marketing and resourceComments and Request for Sma ll Cooperative Categorization [Non-CBI Version] 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 comp ly 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 a ccept, and the fact that it is a generation cooperative without direct custom ers, which eliminates most energy efficiency programs from consideration. In this part of its comments, AEPCO has (1) eval uated available options; and (2) prepared high level analyses of the two principa l 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 inte nsity 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 CO 2 /MWh of AEPCO’s fleet;

 Build a new EGU not subject to the Clean Po wer 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 co al-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 followi ng heat rate or carbon efficiency improvements are possible:

 ST1 (XXXX lb/MWh estimated in 2012)

o xxxxxxxxxxxxxxxxxxxxxxComments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 8

 ST2 (XXXX lb/MWh in 2012)

o XXXXXXXXXXXXXX XXXXXXXXXXXX XXXXXXXXX

o XXXXXXXXXXXXXX XXXXXXXXXXXXXX XXXXXXXXXX

o XXXXXXXXXXXX XXXXXXXXXXXX XXXXXXXXX

 ST3 (XXXX lb/MWh in 2012)

o XXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXX XXXXXXXXXXX

o XXXXXXXXXXXXXX XXXXXXXXXXXX XXXXXXXXX

o VVVVVVVVVVVVVVVVV VVVVVVVVVVVVV

As part of the Regional Haze Rule (“RHR”), AE PCO 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 inte nsity sources, but it must also meet its members’ load requirements. Reduced utilization thus must be undertaken in conjunction with another alternat ive, purchase or construction of another generation asset, or market power purchases. In addition, reduced uti lization also adversely a ffects 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. A ssuming that siting and transmission issues could be overcome in time, the cost of buildi ng 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 bu ild a new unit is addressed below.Comments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 9

e) Build or purchase renewable energy resources

There are several options avai lable to AEPCO, including inst alling photovoltaic or solar thermal facilities or wind energy. Solar is probabl y 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 lo ad,” 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, AE PCO has selected two options for further analysis. The first option is the “compliance” option, wher e AEPCO seeks to meet the requirements of the proposal w ith its own units. The second op tion 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 Powe r Plan proposal from normal business changes required to operate AEPCO). All cases assu me 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 un it 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 appr oximately 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; reti re ST3 in 2017; purchase XXXXXXX new, NSPS NGCC starting 2020; and purchase solar PV a nd install Wartsilas as needed to both

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

CCCCCC installed solar PV a nd XXXXXX installed Wartsila capacity. This option will result in approximately XXXXX million in a dditional 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 Wart silas 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 optio n will result in XXXXX million in additional capital and shows a redu ction in carbon intensity to 941 lb/MWh in 2030.Comments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 10

Model output files for each case are included in Attachments “B”, “C” and “D.” All non-base cases result in capital expenditures of at le ast XXX million more than “business as usual.”

3. Financial Impact of the Co mpliance Options on AEPCO

Monthly charges to the Class A Members are ca lculated and billed in accordance with the Wholesale Power Contract or Partial Requireme nts Capacity and Energy Agreement and consist primarily of a Monthly Fixed Charge, Monthl y 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 a nd non-tariff revenues are cl assified by functional categories of Fixed Expenses, O&M Expenses a nd 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 X XXXXX 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 char ges 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 conve rted the increase in annua l fixed charges to its corresponding cost in $/KW-Month, which is the un it of measurement typically used to purchase or sell long term or “firm” electrical capacit y. Converting fixed charges to $/KW-Month allows a better understanding of the impact of the incr ease in fixed costs on AEPCO’s cost structure and competitive position.Comments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 11

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 ab ove, 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 c onverted 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 capaci ty. 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 E ffective $/KW-Month Capacity

Cost Is Material

Adding the previously discussed charges a nd 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)Comments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 12

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 subs tantial increases, particularly when borne by the relatively small number of members and their customers.

Using the fixed and O&M costs discussed a bove 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 char ges whether they purch ase any electricity

from AEPCO or not. It is also important to realize that AE PCO’s members must act on this information quickly given the time lag associat ed with AEPCO’s options including, but limited to purchasing new or existing assets, purchasing power, or building new a ssets 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 change s in wholesale and retail electr ic 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 ofComments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 13

competitive markets means that AEPCO’s Apache Stat ion or alternatives must be situated to compete in those markets with reliable, reasona bly-priced energy to retain AEPCO’s members.

Determining the “market rate” for capac ity 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 competitor s. Instead, AEPCO and its members must proceed by analysis and informed judgment.

In this case, AEPCO can draw some c onclusions from recent developments: the Southwest Public Power Resources (“SPPR”) Gr oup Purchase Power Agreement (“PPA”) with Sempra Generation, Salt River Proj ect’s (“SRP’s”) recent purchase of one block of the Mesquite Generating Station from Semp ra Generation, and AEPCO’s ow n 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 he at rate of XXX MMBtu/MWh, increased by a sales tax of X%, plus a variable O&M charge st arting 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 na tural gas combined-cycle plant.

o Using standard assumptions for financi ng 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 w ould be essentially the same formulation as in the SPPR PPA, but based on the actua l heat rate (estimated XMMBtu/MWh)

and the actual cost to SR P of the natural gas.

 AEPCO approached a number of merchant plant operators about possible purchase of either blocks of power or assets at vari ous facilities. While these discussions are obviously confidential, in general AEPCO obt ained 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 XXXXX XXXXXX/MWh in 2020, approaching XXXXXXXXX/MWh in 2030.Comments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 14

o Energy charges are difficult to forecast gi ven 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 obtaine d a forward power estimate from ACES Power Marketing to assist in the long-term va luation of the Sempra PPA discussed above. Critically, the ACES analysis discussed two i ssues: 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 pe riod to perhaps as high as XXXX/MWh in 2028. However, it also shows that the market im plied 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 Regulator y Impact Analysis.

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

AEPCO believes that Apache Station is non-viab le 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 Op tion is selected are grav e, 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, $/KWMonthO&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 Sma ll 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 XXXXXX XXXXXXXXXXXX) 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 compet itive. 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 stay ing in AEPCO versus leaving AEPCO and buying power on the open market becomes quite large. Here is the breakdown:

Table 7. AEPCO Premium Ov er 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 im pediments 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 e ither 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 review ing all available optio ns to reduce exposure to AEPCO costs—including potentia lly 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 happ en is that AEPCO woul d dissolve, leaving all of the Apache Station as a potentially stranded a sset. Given the heat rate and other penalties discussed above, it is not cl ear that a purchaser coul d be found for the assets.Comments and Request for Sma ll 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 utili ties, 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 prov iding basic services, while also providing for

reasonable reductions in carbon emission rate and mass.

1. Utilities and EGUs Qualifyi ng for Alternative Category

AEPCO believes that the category should be lim ited to public or coope rative 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 a nd 75 small public utilitie s 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-achiev ing 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) woul d occur prior to the end of the unit’s remaining useful life; AND

 The cost of building a replacement, NSPS-complia nt unit together with the cost of paying down debt on the existing non-achie ving 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 Pl an—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 cooperat ive utility meets the qualifying te st, then it would qualify for an alternative, utility specific goa l 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 duri ng the Interim Goal period:

 Achieve all reasonably cost effective h eat 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 a pproval or 2025, whichever is earlier;

 Meet one-half of the general state plan ener gy efficiency goal, if the small public or cooperative utility has lo cal distribution; andComments and Request for Sma ll 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 with in three years of plan approval, whichever

is earlier.

In the Final Goal period (e.g., 2030 and therea fter 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 re main 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 obtai n renewable energy credits (in a state plan recognizing such credits ) equal to at l east 10% of the non- achieving unit(s)’ capacity prior to the start of the final goa l 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 pr ovision. These provisions provid e assurance to EPA that nonachieving units cannot run indefinitely, provide an incentive (in the form of additional renewables that must be purchased) to the quali fying 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 bei ng forced to acquire new units. This avoids the substantial problem of forcing pub lic 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, sma ll 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 C ooperative Utility Alternative on AEPCO and Similarly Situated Small Entities

The proposed small public and cooperative ut ility approach substa ntially 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-MonthComments and Request for Sma ll 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 Sma ll Public and Cooperativ e Utility case are set

forth in Attachment “G.” As seen in the ta ble 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 ProposalFixed Charge, $/KWMonthO&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 BaseComments and Request for Sma ll Cooperative Categorization [Non-CBI Version] Arizona Electric Power Cooperative, Inc. September 29, 2014 Page 19

While the proposed small public and cooperative u tility alternative does not make AEPCO fully competitive in the market, it does not leav e 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 ec onomics, AEPCO believes that so me 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 ther e are approximately 98 entities that may qualify for the small public and c ooperative utility alternative cat egory. 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 fo r the alternative category. As noted above, the alternative potentially encompasses 23 cooperative and 75 pub lic 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 mega watt hours would be reduced under the Clean Power Plan. Finally, AEPCO converted th e 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 a nd 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% reducti on, or 9,092,838 metric tons. Co mparing this sum to EPA’s calculated 730,000,000 metric ton re duction, the proposal would resu lt in leakage of at most 1.2% of the total tonnage.

AEPCO believes that this calculation substa ntially overstates the impact on the proposed

Clean Power Plan. AEPCO ran its own resour ce planning scenarios. Based upon a “reasonably likely” forecast using the proposed small public and cooperative utility provision, AEPCO

forecasts that its final flee t 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 pe riod, all measured against an average portfolio rate of XXXX lbs/MWh in the baseline period.

If AEPCO’s evaluation is similar to other u tilities 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. Give n the substantial benefits that the proposed alternative categorization provide s to the small public and coopera tive utility sector and its members, ratepayers and taxpayers, these bene fits should outweigh the small cost in carbonComments and Request for Sma ll 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 expandi ng the requested category to incl ude 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 subcat egories 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, t ypes, and classes of designate d 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 li mitations of the entities involved (small public or cooperati ve utilities, which are non-pr ofit) provide a strong basis for subcategorization and providing both a more re laxed limit (meeting the building blocks on the system only, with a target of reaching the Stat e 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 c onsider 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 claime d as Confidential Business Information. The

Confidential Business Information version was file d 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. AE PCO looks forward to submitting

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

situated entities.Comments and Request for Sma ll 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 Co mpliance 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 Sma ll Cooperative Categorization Arizona Electric Power Cooperative, Inc. September 29, 2014

ATTACHMENT “A”

Steve Burr, ADEQ, email dated August 22, 20141 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.s authoff@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@te p.com'; 'msheehan@tep.com'; 'bill.lawson@pacificorp.com'; 'chad.teply@pacificorp.com'; 'steven.jensen@pacificorp.com'; 'mary.wiencke@pacificorp.com'; 'CSWoollums@berkshirehathawayenergyco.c om'; 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 (McK aughan.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 7022 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

‐ 4251Comments and Request for Sma ll Cooperative Categorization Arizona Electric Power Cooperative, Inc. September 29, 2014

ATTACHMENT “B”

Resource Planning Model Outputs for Base Case

Not Included – Confidential Business InformationComments and Request for Sma ll Cooperative Categorization Arizona Electric Power Cooperative, Inc. September 29, 2014

ATTACHMENT “C”

Resource Planning Model Outputs for Compliance Case

Not Included -- Confidential Business InformationComments and Request for Sma ll Cooperative Categorization Arizona Electric Power Cooperative, Inc. September 29, 2014

ATTACHMENT “D”

Resource Planning Model Outputs for Exit Case

Not Included -- Confidential Business InformationComments and Request for Sma ll Cooperative Categorization Arizona Electric Power Cooperative, Inc. September 29, 2014

ATTACHMENT “E”

Annualization AssumptionsATTACHMENT “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 Sma ll Cooperative Categorization Arizona Electric Power Cooperative, Inc. September 29, 2014

ATTACHMENT “F”

Proposed Small Public and Cooperative Utility Category Regulatory LanguageComments and Request for Sma ll 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 coop erative utility on January 8, 2014 in accordance

with this subsection. (1) For purposes of this subsection, a “small public or cooperative util ity” is a governmentallyor cooperatively owned non-profit entity primar ily engaged in the generation, transmission,

and/or distribution of electric en ergy 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 cooperati ve utility qualifies for the alternat ive limit in this subsection if, after implementing all reasonably cost effec tive affected unit heat rate improvements, dispatching all existing natural gas combined cycle affected un its owned by the entity at 70% annual net capacity, and accounting for any rene wable 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 ne t generation in th e baseline period; (iii) shutting the non-achieving unit(s) down will occur prior to th e 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-com pliant, unit or units to replace the non-achieving unit(s) plus servicing existi ng debt for the non-achievi ng units would, in the judgment of the state, be excessive. (3) For each small public or cooperative ut ility that owned an affected EGU on June 18, 2014 and continues to own that non-achieving unit satisf ying the criteria in pa ragraph (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 al ternative goal under its state plan as follows: (i) During the interim goal period: (A) Each non-achieving unit owned by the quali fying small public or cooperative utility must implement all reasonably cost effective meas ures to improve heat ra te, 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 l ong 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 Sma ll 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 recogni zing such credits) equal to at least 10% of non-achieving unit(s) capacity wi thin 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 followi ng (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 establishe d in Table 1 of Subpart UUUU by 2030; or (II) an amount that achieves a 15 percent reduc tion 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 subsecti on (b)(3)(i)(E) by 2020 or three years after plan approval,

whichever is later. (ii) During the final goal period, the state pl an 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 rema in in operation, then the qualifying small public or cooperative utility shall continue a ny 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 su ch credits) beyond the quantity required in subparagraph (b)(3)(i)(C), equal to at least 10% of the non-ac hieving unit(s)’ cap acity prior tothe 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 ope ration 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 opera te pursuant to this s ubsection (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 th e 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 Sma ll Cooperative Categorization Arizona Electric Power Cooperative, Inc. September 29, 2014

ATTACHMENT “G”

Resource Planning Model Outputs for Smal l Public and Cooperative Utility Case

Not Included -- Confidential Business InformationComments and Request for Sma ll Cooperative Categorization Arizona Electric Power Cooperative, Inc. September 29, 2014

ATTACHME NT “H”

Powerpoint Presentation to EPA o n September 25

, 2 0 14

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## Clean Power Plan Cooperative Impacts

and a
Possible Alternative Resolution

September 25, 2014

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# 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

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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).

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# Apache Generating Station

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# Transmission System

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# Current Membership

6 • All-requirements members ("ARMs") purch ase all the requirements necessary for serving their distribution cooperative members from AEPCO

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

other market sources

• Class D Member Valley takes scheduli ng 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

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## ADEQ on CPP Goal Calculation

• Formula:

– “Gen” = Generation in MWh

– “ER” = Emission rate in lbs CO 2 /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	 ൈ N GCC	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 8 Public Release Version

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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

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# ADEQ: No Flexibility in CPP

as Proposed for Arizona

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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 CO 2 

### /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.

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# 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.

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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%)

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# 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

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# AEPCO Out of Market

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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]

.

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# 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

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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

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# 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.

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# 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.

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# 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

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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

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# Impact on CO 2 

# 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.

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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

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