1 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096 , W A 3

- 04 November 9
, 2012 

## Apache Plant: Report on SCR Incremental Cost Assessment

Energy Strategies, LLC conducted an assessment of potential revenue requirement s and electric rate impacts associated with possible installation of Selective Catalytic Reduction (SCR) on units ST2 and ST3 at the Apache Plant, owned and operated by Arizona Electric Power Cooperative (AEPCO). The purpose of the analysis was as follows:

1. Produce an independent assessment of the incrementa l cost impacts of SCR using available information . Th e analysis aimed to identify the largest identifiable annual cost increase over the specified time horizon

. 2. Utilize the cost analysis to compare affordability impacts as defined by retail rate impacts t o similar estimates previously provided by AEPCO and Earthjustice as part of their comments on
the EPA ’s proposed rulemaking affecting Apache

. 1

The information and data utilized in the assessment was derived primarily from sources within the existing docke t (EPA Docket No. EPA

- R09

- OAR

- 2012

- 0021) , and included :

**•** AEPCO ’s letter to EPA dated September 18, 2012 (including appendices labeled as At tachments “1”, “2”, and “3” )

.

**•** “ AEPCO’s Response to the EPA’s Request for Additional Information” dated August 23, 2012
, including a table within that document labeled as “Exhibit 1” which illustrates AEPCO’s estimated incremental revenue requirement due to SCR

.

**•** “Affordability of Pollution Control on the Apache Coal Units, Review of Arizona Electric Power Cooperative’s Comments on Behalf of the Sierra Club”, Resource Insight, Inc., September 2012 2

**•** AEPCO ’s August 22, 2012 Integrated Resource Plan presentation to the Arizona Corporation
Commission (ACC)

. .

**•** EIA Form

- 861 data for member cooperatives sales, revenues & custome r counts for 2011

. The following discussion is categorized in two main section s : discussion of the incremental cost model and the results of the analysis, and discussion of the differences between the assessment results and those provided by AEPCO and Ear thjustice.

Incremental Cost Model

The Incremental Cost Model (“Model”), constructed by Energy Strategies in Microsoft Excel
, utilizes the input s described below to convert capital and operating expenses into an incremental unit cost

1 “Approval, Disapproval and Promulgation of Air Quality Implementation Plans; Regional Haze State and Federal Implementation Plans; Proposed Rule,” 77 FR 42834, July 20, 2012.
2 This document was submitted as Attachment 3 to comments submitted by Earthjust ice on behalf several conservation organizations, including the Sierra Club. When we refer to Earthjustice in this report, we are referring to the analysis and findings in this document.2 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096, WA 3

- 04 ($/MWh) for power gener ated at the Apache Station. The Model assigns costs in a time series for years beginning in 2019 and ending in 2031. The reason for select ing the specific first and last year is based

upon the following. First, 2019 appears to represent the highest incremental cost year in the AEPCO revenue requirements analysis (“Exhibit 1” ) and 2031 represents the final year in the series in Exhibit 1. Secondly, e ven though AEPCO Exhibit 1 indicates that 2017 is the first year of increasing revenue requirement du e to SCR
, Exhibit 1 also indicates that the revenue requirement due to SCR peaks in 2019. Even though AEPCO’s Attachment 3 states an “In Service Date” of 2017 for the entire SCR investment,

we opted to begin the assessment in 2019
, the first full year of incremental CAPEX under the assumption that
, due to regulatory lag, cost recovery (i.e. retail rate s) for the SCR investment would trail
the installation by perhaps one or more years . The assumption , therefore, that the largest incremental cost impact wo uld occur in 2019 is consistent with AEPCO ’s Exhibit 1 . In addition, from the standpoint of characterizing the impact of SCR on retail electric rates, initiating the Model’s cash flow in 2019 and allocating all new capital cost recovery to start in that y ear will insure that the impact to rates is not understated; rather it may be conservatively overstated.

The Model utilizes the following cost, volume , financial data and metrics.

Item Value Units Source Capital Cost $164,962,868 $ EPA Interest Rate 3.00% percent AEPCO Attachment 3 Depreciation Period 19.00 years Calculated Depreciation $10,127,283 $ per year Calculated Straight Line Margin 1.50% percent AEPCO Attachment 3 Taxes & Insurance $3,848,368 percent AEPCO Attachment 3 Escalation Rate 3% percent Assumed rate of inflation for O&M Variable O&M $2,788,380 per year AEPCO Attachment 3 Fixed O&M $1,072,576 per year AEPCO Attachment 3 Plant Output 3,037,968 MWh per year AEPCO Attachment 2

The Model results (see Appendix 1) indicate that the incremental system revenue requirement for AEPCO as a result of SCR would be approximately $23.8 million in 2019, or $ 9.48 per MWh , assuming that all the cost of SCR were allocated only to AEPCO Member co

- ops for retail sales (Scenario “A”).
Under Scenario “B” , where only a portion of the Apache generation output is used to cover M ember energy requirements
, the remaining portion of Apache generation (and incremental cost) is allocated to off

- system or non

- Member sales. Under this scenario, the incremental system revenue requirement for
AEPCO that would be applicable to members would be approximately $19.7 million, or $7.84 per MWh.



### R **ETAIL** 

### R **ATES**

The system impact estimates discussed above
, and reported in Appendix 1
, repr esent AEPCO system costs and cannot be directly applied to retail rate impacts on a dollars per MWh basis . For example, the3 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096, WA 3

- 04 $23.8 million incremental revenue requirement that drives a 15.4% increase in AEPCO revenue requirement under Scenario A would not represent the same increase in retail electric rates, since retail rates are a combination of AEPCO ‘wholesale’ generation services plus the distribution service costs of
the respective cooperative.

In order to derive estimated retail rate impacts, the incremental system revenue requirements defined
in both Scenario s A and B were applied to each Member co

- op in order to analyze specific rate and customer cost impacts for each M ember. Utilizing EIA Form

- 861 data
, the assessment calculated the 2011 residential, commercial and industrial rates and customer costs for each M ember cooperative.
U sing the Allocated Capacity Percentages, or “ACP” as identified by AEPCO ( Comments to EPA on BART, June 29, 2012, pg. 2), the annual incremen tal SCR revenue requirement was allocated to each M ember on a percentage basis

. Each rate for each M ember utility was then allocated a share of the SCR costs on a dollars per MWh basis as determined by each rate class’ share of the total annual sales. The resulting impacts to retail rates and customer costs are shown in Appendix 2. A selected portion of the information in Appendix 2 is presented in the following table.

Incremental Retail Rate Impacts on Member Co

- ops Due to SCR ( As 2019 C osts W ould I mpact 2011 R etail R ates ) 3

Scenario Range of Outcomes

Among Member Co

- ops Residential Class Only Combined Residential, Commercial & Industrial

% Increase Average $ per
Yr Per Customer % Increase Average $ per
Yr Per Customer A: Members Pay all SCR Costs Low 5.4% $83 5.8% $125 High 10.6% $129 12.0% $220 B: Member s Pay Portion of SCR Costs Low 4.5% $69 4.8% $103 High 8.8% $107 9.9% $182

The table above indicates that, depending on the specific cooperative, residential electric costs might increase as a result of SCR by as little as $69 per year to as much as $129 per year; a range of increase
between 4.5% and 10.6%. Commercial and industrial rates would see slightly higher percent increases than residential electric rates because they are lower to begin with

. The limitations of the retail rate analysis require explanation. First, the comparison in the table above
utilizes the repo rted 2011 retail revenues and sales
, and calculates the average retail rate from those values. Individual rate schedules and variations in customer usage within a rate type (i.e. residential service) has not been considered, thus the results are the “aver age” rate impact for a given customer class. Secondly, the average rate impact involves the assessment of an estimated 2019 incremental cost to rates (averaged) that exist in 2011. In other words, the model did not escalate Member co

- op rates

3 The use of 2011 retail rates for this comparison table makes no ass umptions regarding the actual 2019 retail rate; rather, compares the most currently report ed retail rates to those same rates with the incremental cost of SCR in 2019.4 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096, WA 3

- 04 from 2011 t o 2019. However, it is recognized that rates are indeed likely to escalate over that time period. Therefore, since higher rates in 2019 would ‘dampen’ the incremental impact in terms of the percent increase , the results of the assessment should be consid ered conservative by design.

Assessment Conclusions

One of the objectives of this assessment was to address differences in the outcomes between the Model
results and those previously provided by AEPCO and Earthjustice. The following comments discuss th e evaluation and identify areas of differences, as well as suggest items that may warrant further attention.

**•** In part
, the Model was able to reproduce and explain many of the estimations and comments by
AEPCO. When the Model was run u sing what are believed to be the same input values for key
financial and volumetric data employed by AEPCO , including AEPCO’s estimated capital cost of $ 192 million
, the Model returned estimated incremental costs of $26,495,434 , which differ s from the AEPCO estimate of $26,367,378 ( Attachment 3) by less than 0.5%

. I n its Exhibit 1, AEPCO reported a slightly higher estimate of the 2019 incremental revenue requirement
, $ 27,632 ,000 ; the Model’s result is 4.1% lower than this value

. Based on AEPCO’s ACC filing of
the estimated 2019 revenue requirement without SCR
, the Model estimated an increase of
17.1% due to SCR compared to AEPCO’s estimate of 17.8%. Thus, a lthough the result s are not identical , the Model’s outcome when AEPCO’s capital cost is used yields a very similar result to the result reported by AEPCO

. For clarification , the incremental revenue requirement outcome of the Model is nearly the same as AEPCO’s when AEPCO’s capital cost estimate is applied in the
Model ; howe ver, the outcome is materially different (1 6 % lower; $23.8 million versus $ 27.6 million) when capital cost assumptions from EPA ($164 million) are run in the Model rather than the capital cost assumed by AEPCO ($ 19 2 million).

**•** To a lesser degree, the Model was able to approximate the revenue requirement and rate impacts estimated by Earthjustice when the Model used the same capital cost estimate employed by Earthjustice ($80 million)

. With the Earthjustice capital cost assumption incorporated in the M odel
, the resulting revenue requirement was a n overall $6.18 per MWh (10.0 % increase) and $5.11 per MWh (8.3% increase) for Scenarios A and B respectively. Comparatively, the Earthjustice report estimated a $3.98 per MWh increase in total Class

- A member co

- op costs which , if correctly translated to mean the overall AEPCO incremental revenue requirement, would indicate a result that is 36% lower than the Model returned using the $80 million capital cost assumption

. Understandably, w hen the se higher indep endently

- derived increm ental AEPCO revenue requirements were processed through the Model, retail rate impacts were noticeably higher than those reported by Earthjustice

. To an even greater extent, when the modeled incremental costs under the EPA capital assumption were translated into retail rate impacts, those impacts were significantly higher than those estimated by Earthjustice. The following table compares the5 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096, WA 3

- 04 increase in residential electric rates in the Earthjustice report with the results of independently modeled output utilizing, a) the Earthjustice capital cost estimate
, and b) the EPA capital cost
esti mate. The modeled residential electric rate impacts in the foll owing table assume Scenario “B” as previously defined

.

The comparison above is between impacts to 2010 residential rates (as reported by Earthjustice and as output in the Model using the Earthjustice and EPA capital estimates) and 2011
residential rates (as output by the Model using the Earthjustice and EPA capital cost estimates). When applied to the Model, Earthjustice’s estimated capital cost yields a 4.0% increase in average Class

- A member residential rates for 2010 (the only year used in thei r analysis) compared to their estimated 3.3%. However, when the EPA capital cost estimate is applied
, the Model indicates that average Class

- A member residential rates for either 2010 or 2011 would be nearly double Earthjustice’s estimate , increasing by 6% due to SCR.

It should be noted that the work conducted by Earthjustice is primarily an analysis of the AEPCO comments and as such does not contain an explanation of the methodology employed by the Earthjustice consultants. As a result, the comparability of the independent assessment and the Earthjustice comments should be taken as preliminary and subject to check if/as more data
becomes available.

**•** T here are several key assumptions and methods that are influencing the comparative analysis
between the independent assessment and those of AEPCO and Earthjustice. Th ese issues are as follows:

o AEPCO analysis appears to ignore impact of “ off system ” sales

In its Attachment 2
, AEPCO estimates annual production of ST3 at 1,518,984 MWh, the result of 204 MW operating capacity at 85% capacity factor. The documents submitted Earthjustice

Report

2010 2011 Impact on
2010 Rates Impact on
2010 Rates Impact on
2011 Rates Impact on
2010 Rates Impact on
2011 Rates Mohave Electric Cooperative 11.13 $ 11.53 $ 4.8% 5.9% 5.7% 9.1% 8.8% Sulphur Springs Valley E C 13.46 $ 13.69 $ 3.0% 3.7% 3.6% 5.6% 5.5% Trico Electric Cooperative 15.50 $ 14.31 $ 2.2% 2.8% 2.9% 4.1% 4.5% Graham County Electric Coop 13.62 $ 13.49 $ 3.7% 4.9% 4.5% 6.8% 6.9% Anza Electric Coop 19.43 $ 18.09 $ 2.7% 3.7% 3.8% 5.5% 5.9% Duncan Valley Elec Coop 13.45 $ 13.05 $ 3.7% 5.7% 5.6% 8.3% 8.5% Class-A Member Average 13.60 $ 13.37 $ 3.30% 4.0% 3.9% 6.2% 6.1% Comparison Between Study Results: Earthjustice Report and Independent Model Outcomes 2010 and 2011 Rate Impacts due to SCR with Varying Capital Estimates

AEPCO Member Cooperative Avg. Residential Rates as Reported in EIA 861 Independent Model Assuming Capital Cost Estimate of Earthjustice of $80M Assuming Capital Cost Estimate of EPA of ~$164M6 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096, WA 3

- 04 by AEPCO to EPA and to the ACC in the AEPCO July 2012 rate filing suggest identical costs and production capabilities for ST2. Therefore, the productio n from both of Apache’s steam generators combined would total 3,037,968 MWh. At the same time
, AEPCO ’s total MWh sales to the Member co

- ops in 2019 are estimated by the Model to be 2,513,087 MWh. Assuming that all energy generated from Apache in excess o f the sum of the Member co

- op s ’ energy needs is sold in the wholesale market
, AEPCO may be able to dispose of 524,881 MWh in 2019 by selling that production in to the bulk power market. AEPCO’s Attachment 3, conversely, appears to assign the entire
increme ntal cost of SCR to it system customers

. Thus, instead of applying the $ 2 7 million
in incremental cost to all MWh sales

– both on and off the system

– the AEPCO analysis appears to place the entire burden of the incremental capital and O&M cost on M ember

c o

- ops and their retail customers

. Most certainly one would expect the margin on those megawatt

- hours sold at wholesale to be reduced due to the additional cost of SCR, but the analysis should account for a share of the SCR cost going to off

- system sale vo lumes and not only allocated to member rates.

o AEPCO’s use of 201 9 costs applied to the 2012 revenue requirement

Attachment 3 fr om AEPCO compares a revenue requirement of SCR of $26,367,378 (a s discussed previously, a slightly lower value than the $27,633, 000 incremental revenue requirement found in Exhibit 1 ) to the 2012 non

- SCR revenue requirement . That comparison yields, and is reported in Attachment 3
, as a 17.5% increase in overall revenue requirement. That comparison arguably applies a 2019 cost to a 2012 revenue requirement without SCR. If the non

- SCR revenue requirement in 2019 were to be larger than that in 2012 , as one could reasonably expect on the basis of cost inflation at
a minimum
, the higher non

- SCR revenue requirement in 2019 would act to dampen the impact of the incremental cost

. It bears mention that AEPCO’s Exhibit 1 does in fact use
a 2019 non

- SCR revenue requirement in comparison to the 2019 incremental cost, which yields a very similar result

- 17.8% on Exhibit 1 versus 17.5% in Att achment 3.

o Large variations in Base Fixed revenue requirement

AEPCO’s current rate case filed at the ACC is seeking a 2.92% reduction in rates supported by a decline in its total system revenue requirement of approximately $150M. Many of the documents a nd data provided by AEPCO in th e EPA proceeding
, such as the 2012 revenue requirement, are products of the company’s rate case filing. The company’s Base Fixed revenue requirement as shown in AEPCO’s Exhibit 1 indicate s significant variations (as high as 20% year over year) in the 2019 to 2031 time horizon. AEPCO envisions a large decline in Base Fixed revenue requirement between 2017 and 2021, which result s in reduced total revenue requirement s in these years and, therefore, higher estimated SCR rate impact s in terms of the percent increase than would otherwise be expected

.7 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096, WA 3

- 04 In fact, the 2021 Total System Revenue Requirement is projected to be approximately the same as the 2011 revenue requirement value. Said another way, it appears from
Exhibit 1 tha t total costs for the 10 year period of 2011 to 2021 would not increase, even though AEPCO would be serving a growing load. If AEPCO actually experiences higher revenue requirements in its Base Fixed or Base O&M than it currently projects, the incrementa l impact of SCR on total revenue requirements and retail rates would be dampened.

o Earthjustice ’s assumed capital cost is less than half that assumed by AEPCO

.

The consultant’s report submitted by Earthjustice bases its estimated impacts upon a capital number that is less than half the current AEPCO capital cost estimate . On page 3 of the Resource Insight, Inc. R eport it is state s that “The Coop assumes a capital cost of $80 million...”, and on page 8 of the same report it states that “Exhibit 1 reports t hat AEPCO’s debt load would increase by $184 million in 2018 (Total Change in Long

- Term Debt line). This is more than twice the $80 million capital cost of the SCR system estimated by EPA and accepted in AEPCO’s comments. AEPCO does not provide any

suppo rt for this inflated cost value. ”

AEPCO ’s most recent cost estimate is $192 million (including SCR and LNB/OFA) and not the $80 million used in the Earthjustice consultant’ s report. I t appears that the consultant’s report for Earthjustice continued to use the nu mbers provided by AEPCO
earlier and relied upon by EPA in its proposal , rather than later capital cost estimates provided by AEPCO

. As a result, this large difference between the AEPCO and Earthjustice assumptions on capital cost drive s a very d ifferent expectation of revenue requirement, where the Earthjustice estimate d incremental revenue requirement as modeled ($1 5,520 ,000 ) was approximately 44 % lower than the incremental revenue requirement reported by AEPCO in their Exhibit 1

.

It app ears clear by references made within the consultant’s report that the Earthjustice capital estimate of $80 million reflects the AEPCO estimate provided in June 2012, and does not consider the significantly different cost estimate s in AEPCO’s August 2012
Ex hibit 1 or September 2012 letter Attachment 2. For comparison purposes, the capital cost estimate supplied by EPA, as discussed in prior sections of this report, is approximately $164 million.8 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096, WA 3

- 04 A p p e n d i x 1

Assumptions: Units Sources: Capital Cost 164,962,878 $ $ EPA Supplied
Interest Rate 3.00% percent AEPCO Attachment 4 Depreciation Period 19.00 years Calculated Depreciation 8,682,257 $ $ per year Calculated Straight Line Margin 1.50% percent AEPCO Attachment 3 Taxes & Insurance 3,848,368 $ percent AEPCO Attachment 3 Escalation Rate 3.00% percent Assumed rate of inflation for O&M Variable O&M 2,788,380 $ per year AEPCO Attachment 3 Fixed O&M 1,072,576 $ per year AEPCO Attachment 3 Plant Output 3,037,968 MWh per year AEPCO Attachment 2 Volumes Units - - - - - - - 2019

a Estimated Apache Plant Production (AEPCO Attachment 2) MWh 3,037,968 b AEPCO System Sales Estimated Sales Escalation % 1.10% MWh 2,513,087

c ST2/ST3 Production Less System Sales a-b 524,881 d Percentage of Apache generation sold to Class-A Members % 83% 

### SCR Incremental Cost

1 Incremental Capital Expense (CAPEX)

2 Incremental Plant In Service
3 ST2 & ST3 SCR + LNB/OFA $000 164,963
4 Total Incremental Plant in Service $000 164,963
5 Depreciation Expense Combined Units ST2 & ST3
6 Starting Book Value $000 164,963
7 Annual Depreciation Expense $000 8,682 8 Ending Book Value $000 156,281 9 Accumulated Depreciation $000 8,682 10 Total Incremental Depreciation Expense 8,682
11 Interest Expense Applied on Starting Book Value $000 4,949
12 Return on Capital
13 Book Value $000 164,963
14 Capital Recovery $000 2,474
15 Total Incremental CAPEX $000 16,106 16 $/MWh 6.41
17 Incremental Operating Expense (OPEX)

18 ST2 & ST3 SCR + LNB/OFA $000 3,861 19 ST2 & ST3 SCR + LNB/OFA $000 3,848 20 Total Incremental OPEX $000 7,709
21 Total Incremental OPEX $/MWh 3.07
22 Total Incremental Expense
23 $000 23,815 $
24 $/MWh 9.48 $
25 $000 19,700 $
26 $/MWh 7.84 $ Scenario "A": Members pay 100% of incremental cost; none paid by off-system sales

Scenario "B": Members pays incremental cost based on Class-A energy use only 2017/2018 Install Years

O&M Taxes & Insurance 

### Apache Generation Station (AEPCO) - Incremental Cost Model9 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096, WA 3

- 04 A p p e n d i x 1 ( c o n t i n u e d )



### SCR Incremental Cost

2019 Comparison Metrics Source Calculation AEPCO Estimates AEPCO's reported revenue requirements ($192M CAPEX)

A System Revenue Requirement: "EPA Analysis (Exhibit 1 - without SCR 2019) AEPCO Exhibit 1 154,824 $
B Incremental Revenue Requirement (Calculated from Exhibit 1 - with SCR 2019) AEPCO Exhibit 1 27,632 $
C % Increase in System Revenue Requirement (Exhibit 1 - 2019) AEPCO Exhibit 1 17.8%

Independent Assessment Modeling Application of AEPCO's costs to the Assessment Model Incremental Revenue Requirement (AEPCO CAPEX: $192M)

D Incremental Revenue Requirement: Scenario A MODEL MODEL 4.1% 26,495 $
E Incremental Revenue Requirement: Scenario B MODEL MODEL 20.7% 21,918 $
F Incremental Revenue Requirement ($/MWh): Scenario A MODEL MODEL 10.54 G Incremental Revenue Requirement ($/MWh): Scenario B MODEL MODEL 8.72
H % Increase in Revenue Requirement Due to SCR: Scenario A MODEL D/A 17.1%
I % Increase in Revenue Requirement Due to SCR: Scenario B MODEL E/A 14.2% Application of Earthjustice's Capital Cost Estimate to the Assessment Model Modeled Incremental Revenue Requirement @ Earthjustice Estimated CAPEX of $80M
J Incremental Revenue Requirement: Scenario A MODEL MODEL 43.8% 15,520 $
K Incremental Revenue Requirement: Scenario B MODEL MODEL 53.5% 12,838 $
L Incremental Revenue Requirement ($/MWh): Scenario A MODEL MODEL 6.18 $
M Incremental Revenue Requirement ($/MWh): Scenario B MODEL MODEL 5.11 $
N % Increase in Revenue Requirement Due to SCR: Scenario A MODEL J/A 10.0% O % Increase in Revenue Requirement Due to SCR: Scenario B MODEL K/A 8.3% Application of EPA's Capital Cost Estimate to the Assessment Model Incremental Revenue Requirement (EPA CAPEX: $165M)

P Incremental Revenue Requirement: Scenario A MODEL MODEL 13.8% 23,815 $ Q Incremental Revenue Requirement: Scenario B MODEL MODEL 28.7% 19,700 $
R Incremental Revenue Requirement ($/MWh): Scenario A MODEL Line 24 9.48 $
S Incremental Revenue Requirement ($/MWh): Scenario B MODEL Line 26 7.84 $
T % Increase in Revenue Requirement Due to SCR: Scenario A MODEL P/A 15.4%
U % Increase in Revenue Requirement Due to SCR: Scenario B MODEL Q/A 12.7% % Lower Than AEPCO's $192M CAPEX
Case 

### Apache Generation Station (AEPCO) - Incremental Cost Model10 Prepared by Energy Strategies, LLC for ECR Incorporated EPA Contract EP

- D

- 10

- 096, WA 3

- 04 

## Appendix 2

SCENARIO A: Members Pay 100% SCR Cost, Regardless of Off-System Sales of Apache Production

Member Cooperative Avg. cents/kWh $/Customer /Year %
Increase Avg. cents/kWh $/Customer /Year %
Increase Avg. cents/kWh $/Customer /Year %
Increase Avg. cents/kWh $ / Year %
Increase Mohave Electric Cooperative, Inc 11.53 $ 10.07 $ 6.44 $ 10.23 $ 1.23 $ 129 $ 10.6% 1.23 $ 665 $ 12.2% 1.23 $ 54,530 $ 19.0% 1.23 $ 220 $ 12.0% Sulphur Springs Valley E C Inc 13.69 $ 10.91 $ 9.72 $ 12.04 $ 0.90 $ 79 $ 6.6% 0.90 $ 386 $ 8.3% 0.90 $ 135,763 $ 9.3% 0.90 $ 148 $ 7.5% Trico Electric Cooperative Inc 14.31 $ 12.17 $ 9.99 $ 13.44 $ 0.78 $ 83 $ 5.4% 0.78 $ 819 $ 6.4% 0.78 $ 6,614 $ 7.8% 0.78 $ 125 $ 5.8% Graham County Electric Coop Inc 13.49 $ 13.15 $ 11.23 $ 12.89 $ 1.12 $ 112 $ 8.3% 1.12 $ 472 $ 8.5% 1.12 $ 26,251 $ 9.9% 1.12 $ 204 $ 8.7% Anza Electric Coop Inc 18.09 $ 18.47 $ 18.11 $ 18.17 $ 1.29 $ 107 $ 7.1% 1.29 $ 437 $ 7.0% 1.29 $ 1,286 $ 7.1% 1.29 $ 133 $ 7.1% Duncan Valley Elec Coop, Inc 13.05 $ 11.85 $ 12.24 $ 12.68 $ 1.35 $ 124 $ 10.3% 1.35 $ 269 $ 11.4% 1.35 $ 477 $ 11.0% 1.35 $ 155 $ 10.6%

SCENARIO B: Members Pay a Portion of SCR Cost & The Portion Sold to Off-System Covers its Share of SCR Cost

Member Cooperative Avg. cents/kWh $/Customer /Year %
Increase Avg. cents/kWh $/Customer /Year %
Increase Avg. cents/kWh $/Customer /Year %
Increase Avg. cents/kWh $ / Year %
Increase Mohave Electric Cooperative, Inc 11.53 $ 10.07 $ 6.44 $ 10.23 $ 1.01 $ 107 $ 8.8% 1.01 $ 550 $ 10.1% 1.01 $ 45,108 $ 15.7% 1.01 $ 182 $ 9.9% Sulphur Springs Valley E C Inc 13.69 $ 10.91 $ 9.72 $ 12.04 $ 0.75 $ 66 $ 5.5% 0.75 $ 319 $ 6.8% 0.75 $ 112,307 $ 7.7% 0.75 $ 122 $ 6.2% Trico Electric Cooperative Inc 14.31 $ 12.17 $ 9.99 $ 13.44 $ 0.64 $ 69 $ 4.5% 0.64 $ 677 $ 5.3% 0.64 $ 5,471 $ 6.4% 0.64 $ 103 $ 4.8% Graham County Electric Coop Inc 13.49 $ 13.15 $ 11.23 $ 12.89 $ 0.92 $ 93 $ 6.9% 0.92 $ 391 $ 7.0% 0.92 $ 21,716 $ 8.2% 0.92 $ 169 $ 7.2% Anza Electric Coop Inc 18.09 $ 18.47 $ 18.11 $ 18.17 $ 1.07 $ 89 $ 5.9% 1.07 $ 362 $ 5.8% 1.07 $ 1,064 $ 5.9% 1.07 $ 110 $ 5.9% Duncan Valley Elec Coop, Inc 13.05 $ 11.85 $ 12.24 $ 12.68 $ 1.11 $ 102 $ 8.5% 1.11 $ 223 $ 9.4% 1.11 $ 394 $ 9.1% 1.11 $ 128 $ 8.8% * Member cost responsibility estimate is based on 2012 projected member sales escalated 1.1% per year to 2019, and AEPCO estimated Apache production. Assumes that Member coops receive all their consumed MWhs from Apache production and remaining balance is sold off-system.

Estimated 2019 Apache production (kWh): Estimated 2019 Member load (kWh):
Allocated % of SCR cost to Members in 2019: Commercial Industrial Combined

83% Residential

Commercial

2,513,086,574 2011 Average Retail Electric Rate (cents/kWh) 2019 Incremental Retail Electric Cost Due to SCR: SCR Cost Total Paid for by Member Coops (cents/kWh, incremental $ per year per customer, & % increase over 2011 Average Retail Rates)

2011 Average Retail Electric Rate (cents/kWh) 2019 Incremental Retail Electric Cost Due to SCR: SCR Cost Partially Paid by Members, Partially Paid by Market Sales* (cents/kWh, incremental $ per year per customer, & % increase over 2011 Average Retail Rates)

3,037,968,000 Residential Industrial Combined Residential Commercial Industrial Combined

Residential Commercial Industrial Combined