1

Prepared by Energy Strategies, LLC for

ECR Incorporated

EPA Contract EP-D-10-096, WA 3-04 November 9, 2012

Apache Plant: Report on SCR Incremental Cost Assessment 

Energy Strategies, LLC conducted an assessment of potential revenue requirements 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 incremental cost impacts of SCR using available 

information. The 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 to 

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 docket (EPA Docket No. EPA-R09-OAR-2012-0021), and included:

• AEPCO’s letter to EPA dated September 18, 2012 (including appendices labeled as Attachments 

“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 20122

• AEPCO’s August 22, 2012 Integrated Resource Plan presentation to the Arizona Corporation 

Commission (ACC).

.

• EIA Form-861 data for member cooperatives sales, revenues & customer counts for 2011.

The following discussion is categorized in two main sections: 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 Earthjustice.

Incremental Cost Model

The Incremental Cost Model (“Model”), constructed by Energy Strategies in Microsoft Excel, utilizes the 

inputs 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 Earthjustice 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.
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Prepared by Energy Strategies, LLC for

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EPA Contract EP-D-10-096, WA 3-04

($/MWh) for power generated at the Apache Station. The Model assigns costs in a time series for years 

beginning in 2019 and ending in 2031. The reason for selecting 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, even though AEPCO Exhibit 1 indicates that 2017 is the first year of increasing revenue 

requirement due 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 rates) for the SCR investment would trail 

the installation by perhaps one or more years. The assumption, therefore, that the largest incremental 

cost impact would 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 year 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 Member 

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. 

RETAIL RATES

The system impact estimates discussed above, and reported in Appendix 1, represent AEPCO system 

costs and cannot be directly applied to retail rate impacts on a dollars per MWh basis. For example, the 
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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 Scenarios A and B were applied to each Member co-op in order to analyze specific rate and 

customer cost impacts for each Member. Utilizing EIA Form-861 data, the assessment calculated the

2011 residential, commercial and industrial rates and customer costs for each Member cooperative. 

Using the Allocated Capacity Percentages, or “ACP” as identified by AEPCO (Comments to EPA on BART, 

June 29, 2012, pg. 2), the annual incremental SCR revenue requirement was allocated to each Member 

on a percentage basis. Each rate for each Member 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 Costs Would Impact 2011 Retail Rates)

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: Members 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 reported 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 “average” 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 assumptions regarding the actual 2019 retail rate; 

rather, compares the most currently reported retail rates to those same rates with the incremental cost of SCR in 

2019.
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Prepared by Energy Strategies, LLC for

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EPA Contract EP-D-10-096, WA 3-04

from 2011 to 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 considered 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 the

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 using 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 differs 

from the AEPCO estimate of $26,367,378 (Attachment 3) by less than 0.5%. In 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, although the results 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; however, the outcome is materially different (16% 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 ($192 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 Model, the resulting revenue requirement was an 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, when these higher independently-derived incremental 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 the 
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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

estimate. The modeled residential electric rate impacts in the following 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 their 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.

• There are several key assumptions and methods that are influencing the comparative analysis 

between the independent assessment and those of AEPCO and Earthjustice. These 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 ~$164M
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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 production 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 of the 

sum of the Member co-ops’ energy needs is sold in the wholesale market, AEPCO may 

be able to dispose of 524,881 MWh in 2019 by selling that production into the bulk 

power market. AEPCO’s Attachment 3, conversely, appears to assign the entire 

incremental cost of SCR to it system customers. Thus, instead of applying the $27 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 Member 

co-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 volumes 

and not only allocated to member rates.

o AEPCO’s use of 2019 costs applied to the 2012 revenue requirement

Attachment 3 from AEPCO compares a revenue requirement of SCR of $26,367,378 (as 

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 Attachment 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 and data provided by AEPCO in the 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 indicates

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 results in reduced total revenue requirements in these years and, 

therefore, higher estimated SCR rate impacts in terms of the percent increase than 

would otherwise be expected. 
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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 that 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 incremental 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. Report it is states that “The Coop assumes a capital cost of 

$80 million...”, and on page 8 of the same report it states that “Exhibit 1 reports that 

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 

support 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. It appears that the 

consultant’s report for Earthjustice continued to use the numbers 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 drives a very different expectation of revenue 

requirement, where the Earthjustice estimated incremental revenue requirement as 

modeled ($15,520,000) was approximately 44% lower than the incremental revenue 

requirement reported by AEPCO in their Exhibit 1. 

It appears 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 estimates in AEPCO’s August 2012 

Exhibit 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.
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Prepared by Energy Strategies, LLC for

ECR Incorporated

EPA Contract EP-D-10-096, WA 3-04

Appendix 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 Model
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Prepared by Energy Strategies, LLC for

ECR Incorporated

EPA Contract EP-D-10-096, WA 3-04

Appendix 1 (continued)

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 Model
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Prepared by Energy Strategies, LLC for

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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