REPORT: 

ECONOMIC ANALYSIS OF PROPOSED EPA

BART DETERMINATION ON 

FOUR CORNERS POWER PLANT 

EPA Contract No. EP-D-05-087 

Work Assignment No. 4-07

9/8/2010

Final Report

PREPARED FOR E C/R INCORPORATED

BY ENERGY STRATEGIES, LLC
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 2

PREFACE TO THE FINAL REPORT

This document discusses the assessment process undertaken by and the 

findings resulting from Energy Strategies, LLC efforts on behalf of E C/R 

Incorporated in its work for the U. S. Environmental Protection Agency in 

regards to EPA Contract No. EP-D-05-087, Work Assignment No. 4-07.

AUTHORS & CONTRIBUTORS TO THE FINAL REPORT

Richard Anderson, Principal

Kevin Higgins, Principal

Gary Mirich, Senior Consultant

Neal Townsend, Senior Consultant

Marian Bonar, Analyst

Energy Strategies, LLC

215 South State Street, Suite 200

Salt Lake City, UT 85111
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 3

ECONOMIC ANALYSIS OF

PROPOSED EPA BART DETERMINATION ON 

FOUR CORNERS POWER PLANT (FCPP) 

Table of Contents

Executive Summary................................................................................................................................................................ 4

Capital Cost Considerations....................................................................................................................................... 6

Market Power Cases ..................................................................................................................................................... 6

Introduction.............................................................................................................................................................................10

Scope & Approach ............................................................................................................................................................10

Economic Modeling Methodology & Case Analysis.................................................................................................13

Total Cost Approach ...................................................................................................................................................13

Modeling Output & Discussion of Results...............................................................................................................16

Straight Line Depreciation Outcomes..................................................................................................................17

Accelerated Depreciation Outcomes....................................................................................................................19

Discussion of Modeling Results ..................................................................................................................................20

Capital Cost Considerations.....................................................................................................................................21

Market Power Cases ...................................................................................................................................................22

Decision Environment & Additional Factors..............................................................................................................25

Additional Factors ............................................................................................................................................................25

Environmental Regulation............................................................................................................................................26

GHG Emissions Regulation.......................................................................................................................................26

California Climate Change Regulations...............................................................................................................27

Utility MACT & Ash Handling (Coal Combustion Residues).......................................................................28

Contractual Contingencies ............................................................................................................................................28

Coal Contract Renewal & Pricing, Plant Site Lease Renewal & Other Lease Renewals ..................30

Consideration of the Combined Effects of SCR and Additional Factors ................................................30

Consideration of Multiple Investment Risks..............................................................................................................31

Utility Investment Decision Making..........................................................................................................................31

Potential Methodology for Addressing Multiple Risks......................................................................................31

Simulation.......................................................................................................................................................................31
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 4

Executive Summary

Energy Strategies, LLC was engaged by E C/R Incorporated (“EC/R”) on behalf of EPA with respect 

to EC/R’s scope of work regarding the BART assessments for Four Corners Power Plant (FCPP) and 

Navajo Generating Station (NGS). This report focuses on the assessment methodology utilized and 

the findings specific to FCPP. This Executive Summary lists in brief the findings of the assessment 

more fully discussed in the full report. 

Economic Modeling

25-year discounted cash flow modeling was conducted on the following set of six total pollution 

control retrofit and market energy purchase cases. Each case was also run through two 

depreciation methods for the retrofit capital investments only. 

Unit No.

Case Definitions*

BAU LNB/OFA SCR Case Market Cases

Unit 1 Continued 

Operations With 

Plant As of 

12/31/2009 

BAU + LNB BAU + SCR Low, Mid, and High 

Trend Cases For 

Replacement of 

Energy That Plant 

Produces Today

Unit 2 BAU + LNB BAU + SCR

Unit 3 BAU + LNB/OFA BAU + SCR

Unit 4 BAU + LNB/OFA BAU + SCR

Unit 5 BAU + LNB/OFA BAU + SCR

* LNB/OFA costs are modeled using from APS estimates of capital and operating expense. SCR case 

costs were supplied by EPA. One additional case was modeled based on APS cost input data for an 

SNCR investment. That case is not reported out in this document.

Capital and Operating Cost Inputs

The following table illustrates the capital and operating expenses assumed in the economic model 

for each unit at FCPP as well as the estimated date of installation. 

Unit No.

Year

Installed

Capital

Expense

Operating 

Expense

Unit 1 2015 $ 90,337,340 $ 2,948,000

Unit 2 2015 $ 97,663,260 $ 2,896,000

Unit 3 2015 $ 94,180,720 $ 3,178,000

Unit 4 2013 $ 217,727,260 $ 8,189,000

Unit 5 2014 $ 217,727,260 $ 8,189,000

Capital and Operating Expense Assumptions

2008$

For modeling purposes, the costs above (2008 dollars) were adjusted to 2010 dollars then further 

adjusted between 2010 and their respective year of installation using a 3% rate of inflation. 

Operating expenses for all new capital as well as existing plant were escalated at 3% per year for 

the entire 25-year cash flow period. 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 5

Utilizing the assumptions above and others described in the full report and within the economic 

model itself, the model produced the following NPV outcomes and unit costs assessments for each 

case modeled.

1,2,3,4,5

BAU Case LNB Case

(BAU + LNB)

SCR Case

(BAU + SCR)

Market

Low Trend

Market

Mid Trend

Market

High Trend

$ 5,688 $ 5,776 $ 6,892 $ 7,008 $ 7,356 $ 7,746

 $ 88 $ 1,204 $ 1,320 $ 1,668 $ 2,058 

 % 2% 21% 23% 29% 36%

 $ 1,116 $ 1,232 $ 1,581 $ 1,970 

19% 21% 27% 34%

$ 33.95 $ 34.51 $ 41.35 $ 44.51 $ 48.09 $ 51.92

$/MWh Incremental to BAU $ 7.40 $ 10.55 $ 14.13 $ 17.97

Units Modeled with SCR >>

FCPP - Summary Cost Comparisons

(2011-2035) Straight Line Depreciation

Per MWh Costs (25 year non-discounted $ cost / 25 year MWh)

NPV 25 Year Cost by Case ($Million)

Difference in Cost for Case vs. BAU Case ($Million)

Difference in Cost for Case vs. LNB Case ($Million)

 % 

Summary comments regarding cash flow output:

 The BAU Case NPV is ~29% lower cost over the study period than the mid market case.

 The LNB/OFA and SCR Cases result in 25-year NPV’s that are approximately $1.6B to 

$500M lower respectively than the mid trend market case. 

 Under either straight line or accelerated depreciation, the difference between the NPV’s 

of the BAU Case and the LNB/OFA Case is less than 2%.

 Accelerated depreciation would have a material impact on the 25-year costs for the SCR 

case (approximately $188 million more than the straight line depreciation cash flows) if 

implemented as modeled.

 The modeled SCR Case NPV is statistically similar (1.7% and 4.5% higher) to the low 

trend market price under straight line depreciation and accelerated depreciation 

respectively.

 SCR investment and operations over 25-years results in an incremental, non-discounted 

cost of $7.40 per megawatt-hour over the Business as Usual (BAU) case.
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 6

Discussion of Critical Inputs, Modeling Limitations, and Output Interpretation

The use and interpretation of the output of the economic model developed for this project is best

conducted in consideration of the model’s inputs and limitations. The following summarizes areas 

in the full report intended to identify those variables and assumptions considered particularly 

critical as they may impact outcomes within the model and interpretation of the economic results. 

Capital Cost Considerations

 The model incorporates cost recovery for existing capital at the plant as well as capital 

associated with each retrofit case. Cost recovery for capital includes depreciation 

expense (principal), debt, and rate of return on rate base. 

 Rate base for the BAU Case includes an estimation of book value of the plant in service

based on FERC Form 1 filings for FCPP and estimations of timing of plant investments. 

 Also consistent with a revenue requirement model (basically what a utility would need 

to charge customers to recover its cost plus a regulated rate of return) the model uses a 

15% capital cost recovery factor. 

 The model assumes no new capital deployment in the next 25 years on the existing 

plant (BAU). If a substantial cost were incurred, especially in the early years of the 

model, then the BAU case could conceivably increase in cost materially with respect to 

the other cases.

 The dates of installation for capital equipment can influence the outcomes of the 

economic model but producing lower or higher installed costs depending on how the 

dates change from the assumed dates. Lower capital and operating costs would reduce 

the model results for the wholesale cost to produce electricity.

 Initial research suggests that pollution control bonds may be accessible for the retrofit 

cases on a tax-free basis. If this were the case then the ultimate cost of the retrofit cases 

would be lower than reported. 

Finally, model addressees cost at the wholesale level and not at the retail level. This distinction is 

important since retail consumers receiving power from FCPP would pay more than the costs 

returned by this model. The model is not designed to address “downstream” costs related to 

transmission, distribution, and customer services performed by the local utility. Addressing costs 

at the wholesale level allows comparison to market power cases (see below) where a shutdown at 

FCPP would require wholesale market purchases to replace the absence of FCPP supply.

Market Power Cases

There are several important considerations to keep in mind when interpreting the outcomes of 

market case versus investment case NPVs.

 The forward electricity price forecast used in the model is considered to be reasonable and 

appropriate both in regards to source data and methodology. Price forecasts are, however, 

rarely if ever accurate and require frequent updates to maintain their currency. 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 7

 In addition to being difficult to forecast, market pricing can be very volatile and may exceed 

the boundaries within the forecasted ranges in any given year by significant amount. 

 As stated in the previous section, market cases do not include transmission related costs for 

purchased power, nor further downstream distribution costs. 

 Finally, the market scenarios make no cost assumptions regarding the recovery of stranded 

investments – such as plant no longer used and useful and/or underutilized assets like longlived high voltage transmission facilities, nor any costs related to decommissioning and 

salvage. 

Additional Factors

The decision-making process of plant owners with respect to investment in SCR or other mandated 

emissions controls will include consideration of other factors that are likely to materialize during 

the life of the plant. Those factors are briefly discussed below.

GHG Emissions Regulation

The precise path that ultimately leads to GHG emissions regulation at the federal level is unclear as 

of this writing. 

 Whether GHG emissions are regulated via command and control rulemaking or through a 

market-based mechanism like cap and trade, the owners of coal-fired electric generation 

are anticipating additional costs related to compliance. 

 The regulatory and oversight authorities of those entities that serve retail customers with 

electricity generated by coal combustion are also aware of that higher costs are on the 

horizon. 

 The cost of carbon for FCPP is estimated to add between $20/MWh to $50/MWh based on 

APS’ estimate of future carbon pricing – representing 60% to 150% incremental cost to the 

modeled BAU case. 

California Climate Change Regulations 

The impacts of both AB32 and SB1368, along with an expansion of the California renewable 

portfolio standard has shaped planning decisions for many California utilities and resulted in the 

following specific actions by plant owners at FCPP and NGS:

 Southern California Edison will vacate its ownership interest in FCPP when its contractual 

obligations expire in mid-2016 

 Los Angeles Department of Water and Power will divest from its NGS ownership interest in 

2019, as well as other coal position to meet a “coal free” by 2020 target
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 8

Utility MACT & Ash Handling (Coal Combustion Residues)

Pending environmental regulation dealing with Utility Maximum Available Control Technology 

(MACT) for mercury and other hazardous air pollutants as well as EPA’s open docket on handling 

and disposal of Coal Combustion Residues (CCR) have the potential to increase the cost of 

production for coal-fired plants. 

Plant Ownership 

As stated above, SCE will divest its share of FCPP in 2016. The fate of the ‘returned’ capacity is 

unknown and a substantial risk to the remaining owners of the plant. 

 The combined total of turned back capacity from FCPP and NGS will be of 1,189 MW

 Represent a very large “acquisition” of for the owners to consider, especially those like APS 

and SRP with long coal positions today

Coal Contract Renewal & Pricing, Plant Site Lease Renewal & Other Lease Renewals 

Unlike most of the other issues, coal contracts and leases should not pose the same level of 

uncertainty with regards to investment decisions.

 Those entities that have the greatest to gain or lose with respect to contractual 

renegotiations – especially if they could possibly result in a stalemate that closes the plant -

are also those most in control of the outcomes. 

 It is reasonable to assume that the parties that rely on the continued operations of the 

mines and plants could be reasonably expected to make an economic decision and 

negotiate new leases that allow the plant to operate economically.

Consideration of the Combined Effects of SCR and Additional Factors

It is reasonable to assume that many of these factors will materialize during the 20-year expected 

life of an SCR investment and thereby impact costs and electricity pricing out of FCPP. Each plant

participant will certainly consider the combined potential impacts of these factors when they weigh 

a decision to invest in SCR and seek cost recovery from their regulator. 

Each one of the plant owners must ask themselves whether or not an investment in SCR meets the 

long-term needs of their stakeholders (rate payers, regulators, and owner boards) and 

shareholders within a range of acceptable risk. To answer that question utilities are likely to 

consider each of the following categories of risk within their individual decision frameworks: 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 9

Risk Type Key Issues by Risk Type

Regulatory Risk  Additional investment for new regulation

 Compliance schedules

 Prudency determination by ratemaking authority

Economic Risk  Construction budget & timing

 Asset performance & asset life 

Market Risk  Ownership divestiture

 Increased share and/or commitment

 Market price of power/alternatives
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 10

Introduction

The U.S. Environmental Protection Agency Region IX (“EPA”) is developing a Federal 

Implementation Plan to implement the Best Available Retrofit Technology (“BART”) requirement of 

the Regional Haze Rule on the Navajo Nation Indian Reservation. The two emissions sources 

subject to BART on the Navajo Nation are the Four Corners Power Plant (“FCPP”), near Farmington, 

New Mexico, and the Navajo Generating Station (“NGS”) near Page, Arizona. On August 28, 2009, 

EPA published in the Federal Register an Advanced Notice of Proposed Rule Making (ANPRM) that 

put forth EPA’s analysis regarding two of the five-factors required for the BART analyses for FCPP 

and NGS. EPA received numerous comments on the ANPRM, including comments on potential 

economic impacts of additional controls for BART on electricity consumers and the Navajo Nation.

Energy Strategies, LLC was engaged by E C/R Incorporated (“EC/R”) on behalf of EPA with respect 

to EC/R’s scope of work regarding the BART assessments for FCPP and NGS. Even though both 

plants share many issues with respect to the BART assessment, this report focuses on the 

assessment methodology utilized and the findings specific to FCPP.1This document describes the 

actions taken by Energy Strategies in support of EC/R’s needs for economic assessment in the 

matter of FCPP. This report is offered with the hope that the information contained herein will be 

valuable to EC/R as it supports EPA on a broad slate of BART-related issues, only one of which is 

the area of investigation described in this report.

Scope & Approach

The eventual outcome of EPA’s determination of BART for NOx at FCPP may require installation of 

emissions controls on all five units by 2015. The plant operator, Arizona Public Service Company 

(“APS”) concludes in its December 2008 cost update filing “there are still three dominant 

technology options for NOx control at Four Corners”. The three technology options they define 

include combinations of: (a) Combustion Controls [Low NOx Burners (LNB) and Low NOx Burners 

with Overfire Air (LNB/OFA)], (b) Selective Non-Catalytic Reduction (SNCR) 2, and (c) Selective 

Catalytic Reduction (SCR).3 The table below itemizes the technology combinations by plant unit 

number that make up the three options identified by APS. The ANPRM focused only on Options 1 

and 3.

Unit No.

APS Technology Option No. & Description

Option 1

Option 2

(adds SNCR)

Option 3

(adds SCR)

Unit 1 LNB Option 1 + SNCR Option 1 + SCR

 

1 A second assessment and report prepared by Energy Strategies for E C/R addresses NGS and its unique 

market and economic circumstances 

2

SNCR was modeled for this project, however, is not reviewed in this document with regards to cost or other 

considerations.

3 APS’ December 2008 BART Cost Updates 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 11

Unit 2 LNB Option 1 + SNCR Option 1 + SCR

Unit 3 LNB/OFA Option 1 + SNCR Option 1 + SCR

Unit 4 LNB/OFA Option 1 + SNCR Option 1 + SCR

Unit 5 LNB/OFA Option 1 + SNCR Option 1 + SCR

NOTE: The initial modeling conducted for the project utilized statements from the APS 

December BART cost filing including their stated expectation that SNCR or SCR would be 

additive to LNB/OFA if either SNCR or SCR were determined to be BART. The table above 

illustrates APS’ assumptions on that point. 

After discussions regarding the modeling assumptions employed in the initial model, based 

on their determination of the potential operational challenges associated with LNB/OFA, 

EPA requested the economic model be revised so that the SCR case only includes its 

respective costs and not those of LNB/OFA, and that the report not include the SNCR case. 

Depending on the BART determination ordered by EPA, the capital costs for control measures are 

estimated in 2008 dollars to range from $44 million for Option 1 to $890 million Option 34. APS’ 

conclusion is that BART for NOx at FCPP should be Option 1. The modeling described in this report 

for SCR is based on estimated costs supplied by EPA for capital and operating expense5. The 

LNB/OFA costs in the model and this report, as well as SNCR costs, were filed by APS with EPA.

Multiple stakeholders, including the plant owners, have commented specifically about their concern 

that a BART determination that mandates SCR could have severe economic impacts on the plant 

owners, utility consumers, Native American communities, and others. In their opinions, the capital 

expense (CAPEX) and associated operating expense (OPEX) increases associated with SCR would 

represent a material change to the cost structure of the 40 year-old power plant. Most of the FCPP 

stakeholders state their concern that the large CAPEX and incremental OPEX for SCR would, at a 

minimum, raise electric rates for regional retail electric customers and, at worst, precipitate a 

decision to close the plant. Many have opined that the economic impacts of FCPP ceasing 

operations would be especially detrimental to the Navajo due to their economic dependence on coal 

leases and royalties and the number of jobs dependent on continued plant operations. 

Irrespective of the type of investment (emissions controls or otherwise), clearly any incremental 

CAPEX and OPEX at FCPP will contribute to higher costs of production and likely higher prices to 

ultimate consumers. What is not as clear is the difference in long-term costs driven by the type of 

technology implemented to achieve NOx reduction as well as the cost of a market purchase option. 

Quantifying the cost differences between cases would be useful for EPA to consider in its BART 

determination process.

In addition to the uncertainty that higher incremental costs from SCR capital and operations would 

place on the long-term economic life of FCPP, many stakeholders voiced a concern that the BART 

 

4 Range of costs indicates the LNB/OFA and SCR capital costs as provided by Arizona Public Service in its 

letter to EPA in March 16, 2009 reflecting their August 2008 BART cost estimate revisions.

5 In comparison the revised capital costs supplied by EPA and modeled for this report define an SCR case with 

capital costs of approximately $729M (2008$)
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 12

for NOx determination is only one item on a longer list of issues that are likely to multiply the 

uncertainty of the plant’s future operations. The additional factors include green house gas (GHG) 

regulations, plant ownership changes, and other regulatory compliance issues. The potential impact 

of those issues and how they may be considered separately and in concert with a BART 

determination would be useful information for EPA to consider in its BART determination process.

Therefore, the objectives of Energy Strategies’ efforts in this instance were two fold. The first was a 

quantitative assessment of the economic performance of a limited set of emissions controls cases 

(the APS Options described above) and a comparison between those cases – specifically in terms of 

how each scenario may impact the cost of power in future years from FCPP. In each of those 

scenarios FCPP was assumed to be operated for at least 20 years after the last of 5 units were 

retrofitted in 2015. Also for comparative purposes, Energy Strategies’ developed low, mid, and high 

trend market energy price scenarios to represent the replacement wholesale power costs that may 

be experienced if every future megawatt-hour (MWh) of anticipated FCPP generation were instead 

purchased from the market. 

The second objective was the consideration of emerging market and regulatory issues (e.g. CO2 

regulation) that may influence decisions regarding investment and a possible plant shutdown. 

Third, and finally, was the development of an economic model to quantify the impacts to plant 

costs, and utility rates in general, stemming from a range of NOx emissions reduction technologies. 

The economic model developed for this effort also incorporated estimates for market power 

purchase costs to compare against the investment alternatives in the event that plant ownership 

were to decide to forego capital investment for NOx control and terminate plant operations.

The following sections of this document describe the actions taken by Energy Strategies in support 

of EC/R’s needs in these matters, specifically, economic modeling of a range of investment options 

for NOx emissions reduction and how those options may impact the long-term cost of power from 

FCPP. Later on, this report addresses a set of additional factors that, although not analyzed through 

economic modeling for purposes of this report, are likely to impact the decision processes of the 

plant owners and shareholders, as well as their regulatory stakeholders.

[Continued on next page]

|

|

|

|

|

|

|

|

|
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 13

Economic Modeling Methodology & Case Analysis

The modeling employed to estimate the cost impacts of a set of NOx control technology investments 

(as well as market price cases) consists of the following seven cases (1-existing plant, 3-retrofit 

cases, and 3-market cases). A summary of the cases and assumptions follows:

Case Name

APS 

Option 

No.

Descriptions & Key Assumptions

Technology Cases

Notes for All Technology Cases: 

 CAPEX and OPEX cost estimates were converted from 2008$ to 2010$ by the CPI adjustment 

factor, then escalated at the inflation rate until their installation date year

 The rate of inflation for CAPEX and OPEX is equivalent in all cases

 Incremental capital for retrofit cases was depreciated by two methods:

o Straight Line for plant in service 

o 5 Year Accelerated (per interpretation 26 U.S.C. § 169: US Code - Section 169: 

Amortization of pollution control facilities)

 CAPEX includes pre-tax rate of return on existing plant-in-service

Business As Usual

(BAU)

NA  Plant as it was operated & reported in 2009 FERC F-1

 OPEX escalated from 2009 values for 2010-2035

 $0.00 incremental capital in 2010-2035

 Plant-in-service depreciated straight line 

LNB Option 1  BAU plus the cost of LNB and LNB/OFA

 OPEX escalated from 2008 estimates to installed year then 

escalated annually until 2035

SNCR* Option 2  BAU + CAPEX and OPEX for SNCR

SCR Option 3  BAU + CAPEX and OPEX for SCR

Market Price Cases

Notes for All Market Price Cases:

 Market price forecasts impact market case NPV’s starting in 2016 based on the assumption 

that until the plant shutdowns the applicable costs will be BAU costs

 Forward Palo Verde prices used for 2011-2014 based on 7/15/2010 market close prices as 

reported in Platts for on and off-peak hours converted to full year round the clock prices

 Palo Verde prices, upon which the longer term curves in the market cases are based, are 

highly volatile and were representative of actual market prices only on the day quoted

 Market price scenarios do not include transmission-related costs or any other costs related to 

shutting down the plant 

Low Trend Market

Mid Trend Market

High Trend Market

NA Starting in 2014, yearly changes in price for 2015 to 2035 are 

calculated based on year to year percentage changes from 

2014-2035 for the EIA Annual Energy Outlook Low, Reference

(for Mid), and High Macroeconomic Cases

* SNCR was modeled using APS-supplied cost values but is not discussed in this report

Total Cost Approach

Each of the BART technology investments (including the economic choice to shutter the plant 

rather than install controls) will be potentially long-lived decisions; 20 years or longer. And each
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 14

will have a unique incremental capital and operating cost profile over its installed life. However, 

comparison of only incremental cost, while illuminating for some purposes, isn’t helpful for 

comparing the cost of sourcing energy from the market if FCPP ceases operations. As stated above, 

many commenters expressed concern that retrofitting FCPP would impact its competitiveness and 

potentially cause, or greatly contribute to, a permanent plant shut down. Commenters conclude 

that the loss of FCPP as a resource to serve retail customers would require them to buy capacity 

and energy to replace their former position in FCPP with purchases from the wholesale power 

market. 

It is reasonable to expect that the price at which the FCPP participants could find replacement 

capacity and energy would be priced at the most liquid pricing point in the desert southwest –

namely, the Palo Verde hub. Therefore, the modeled market case assumes that the plant shuts

down and the utilities acquire replacement capacity and energy from the market starting in 2016. 

The model assumes a full shutdown of all units and that 100% of the historical net generation is 

replaced with market purchases and that purchases are made predominantly for forward, firm 

supply. Thus, the cost of replacement power, as modeled, is intended to be equivalent to the nonshutdown cases in as much as those cases receive cost recovery of all generator costs (fixed and 

variable) going forward, likewise, the market cases assume that market providers are also receiving 

full cost recovery and not just variable expense recovery. The Palo Verde forward prices are firm 

prices which assume capacity as well as energy. 

For those reasons, it was determined that a total cost approach, founded upon an estimated 

Business as Usual (BAU) case where the plant operates “as is” into the future, would be the proper 

means to model the full cost of generation with each technology option. The model includes

existing costs of the historical plant through 20096 – projected forward 25 years from 2010 to 

2035. For each case except the market cases, the model layers in the incremental CAPEX and OPEX 

as those investments occur according to this assumed retrofit schedule7:

Unit No. Estimated Year

Unit 4 2013

Unit 5 2014

Unit 1 2015

Unit 2 2015

Unit 3 2015

The BAU case includes cost recovery for the plant as it was reported in the 2009 FERC Form 1 

filings made by the plant owners and includes rate of return on plant in service and associated 

depreciation expense as well as operating expense plus escalation for inflation. The CAPEX and 

OPEX costs for each retrofit case are additive to the BAU so that a revenue requirement for the full 

 

6

Federal Energy Regulatory Commission Form 1 data used as the source for 2009 costs

7

Dates provided by EPA and represent their best estimate of when plant retrofits are likely to occur given 

history major maintenance cycles for FCPP
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 15

plant can be calculated in each of 25 years, then discounted back to current day. The output of the 

model is a set of discounted cash flows that allows comparison between a single 25-year Net 

Present Value (NPV). 

The Model and Assumptions

The discounted cash flow model developed for this project resembles a ‘revenue requirements’ 

model. A revenue requirement for an electric utility represents the level of revenue a utility 

would need to collect from its rate payers to cover the cost of generating and delivering power, 

including the utility’s authorized rate of return on the utility’s “rate base” – which includes plantin-service. In the case of the FCPP model, only the power generation costs are includes since the 

analysis is focused at the wholesale cost level.

Retail electricity rates (themselves not the focus of this effort) were not estimated for several 

reasons. First, retail rates are derived from each utility’s unique costs of generation, transmission 

and distribution and this study was focused on generation cost impacts. Secondly, the power 

generation cost which each utility recovers are the result of a portfolio of owned and purchased 

power resources rather than one individual plant, thus the impact on retail rates would be 

variable by utility and entail a much broader assessment into the construction of retail rates for 

each entity. 

This form of economic modeling requires historical cost data, estimated cost data, and projected 

cost data utilizing a host of assumptions ranging from discount factors to inflation rates to 

depreciation schedules to power market futures. The set of assumptions required to properly 

interpret the outcomes described below are contained above to this report and in greater detail in 

the model’s own assumptions section. Readers of this report, and especially users of the 

electronic model transmitted with this report, are strongly urged to read, understand, and follow

the assumptions and directions provided in the model.

Capital and Operating Cost Inputs

The following table illustrates the capital and operating expenses assumed in the economic model 

for each unit at FCPP. 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 16 Unit No.

Year

Installed

Capital

Expense

Operating 

Expense

Unit 1 2015 $ 90,337,340 $ 2,948,000

Unit 2 2015 $ 97,663,260 $ 2,896,000

Unit 3 2015 $ 94,180,720 $ 3,178,000

Unit 4 2013 $ 217,727,260 $ 8,189,000

Unit 5 2014 $ 217,727,260 $ 8,189,000

Capital and Operating Expense Assumptions

2008$

For modeling purposes, the costs above (2008 dollars) we adjusted to 2010 dollars then further 

adjusted between 2010 and their respective year of installation using a 3% rate of inflation. 

Operating expenses for all new capital as well as existing plant were escalated at 3% per year for 

the entire 25-year cash flow period. 

Modeling Output & Discussion of Results

As discussed previously, the economic modeling developed for this assessment includes seven 

specific cases. The discounted cash flows for the three retrofit cases are further divided by the 

application of different depreciation methodologies. The BAU case is always and only depreciated 

on a straight line basis and the market cases do not receive any depreciation treatment since no 

capital assets are assumed to be involved. On the following pages the report will refer to tables, 

graphs, and contain discussion the model and its output specific to cost summaries –

Straight Line Depreciation: (see Table 1 & Graph 1) - where straight line depreciation is 

applied to all non-market power cases

Accelerated Depreciation: (see Table 2 & Graph 2) – where accelerated depreciation is 

applied on all retrofit pollution control cases, while continuing to apply straight line 

depreciation on the underlying BAU case. The accelerated depreciation case is based upon 

an interpretation of federal tax code that permits accelerated depreciation on pollution 

controls retrofits for older facilities like FCPP.8 

The graphic below quantifies the NPV impact of using accelerated depreciation versus straight line 

depreciation. The “savings” caused by accelerated depreciation are understandably more 

 

8

26 U.S.C. § 169: US Code - Section 169: Amortization of pollution control facilities. Energy Strategies’ 

interpretation of the Code suggests an allowance for accelerating depreciation within a 5 year period from the 

date of installation. The code also indicates that a facility must be certified for this purpose by applying to the 

federal government for certification status. This assessment assumes that the plant would qualify for 

certification and that all retrofit technologies, in the accelerated depreciation sub-cases, would be eligible 

technologies under the Code. Confirmation of this assumption would require the consultation with tax 

accounting and tax law expertise. 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 17

pronounced when the capital investment cost is highest. In all retrofit cases, the timing of capital 

investment is exactly the same. 

$-

$100 

$200 

BAU Case LNB Case

(BAU + LNB)

SCR Case

(BAU + SCR)

$ 0 $11

$188

Cost Reduction by Case Using Accelerated 

Depreciation over Straight Line

2011-2035 NPV ($Million)

Straight Line Depreciation Outcomes

Table 1

1,2,3,4,5

BAU Case LNB Case

(BAU + LNB)

SCR Case

(BAU + SCR)

Market

Low Trend

Market

Mid Trend

Market

High Trend

$ 5,688 $ 5,776 $ 6,892 $ 7,008 $ 7,356 $ 7,746

 $ 88 $ 1,204 $ 1,320 $ 1,668 $ 2,058 

 % 2% 21% 23% 29% 36%

 $ 1,116 $ 1,232 $ 1,581 $ 1,970 

19% 21% 27% 34%

$ 33.95 $ 34.51 $ 41.35 $ 44.51 $ 48.09 $ 51.92

$/MWh Incremental to BAU $ 7.40 $ 10.55 $ 14.13 $ 17.97

Units Modeled with SCR >>

FCPP - Summary Cost Comparisons

(2011-2035) Straight Line Depreciation

Per MWh Costs (25 year non-discounted $ cost / 25 year MWh)

NPV 25 Year Cost by Case ($Million)

Difference in Cost for Case vs. BAU Case ($Million)

Difference in Cost for Case vs. LNB Case ($Million)

 % 

Straight Line Depreciation Discussion

As illustrated above in Table 1, under the modeling approach utilizing straight line depreciation on 

all cases, the 25-year NPVs of the retrofit cases range from $5.8 for the LNB/OFA Case to $6.9B for 

SCR, while market costs produce NPVs from Low, Mid, and High trend cases of $7.0B, $7.4B and 

$7.7B respectively. The NPV of the SCR case under straight line depreciation is lower than the 

market cases by 1.7%, 6.7%, and 12.4% respectively for the low, mid, and high market outcomes. 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 18

Graph 1A below illustrates the 25-year NPV for each case under straight line depreciation.

Graph 1A

$-

$2,000 

$4,000 

$6,000 

$8,000 

BAU Case LNB Case

(BAU + LNB)

SCR Case

(BAU + SCR)

Market

Low Trend

Market

Mid Trend

Market

High Trend

$5,688 $5,776

$6,892 $7,008 $7,356 $7,746

25 Year Cost of Power by Case - Straight Line Depreciation

2011-2035 NPV ($Million)

Graph 1B below illustrates the 25-year incremental NPV for each case compared to the BAU case 

under straight line depreciation.

Graph 1B

$-

$500.00 

$1,000.00 

$1,500.00 

$2,000.00 

$2,500.00 

BAU Case LNB Case

(BAU + LNB)

SCR Case

(BAU + SCR)

Market

Low Trend

Market

Mid Trend

Market

High Trend

$88 

$1,204 $1,320 

$1,668 

$2,058 

25 Yr Cost Incremental to BAU - Straight Line Depreciation

2011-2035 NPV ($Million)
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 19

Accelerated Depreciation Outcomes

Table 2

1,2,3,4,5

BAU Case LNB Case

(BAU + LNB)

SCR Case

(BAU + SCR)

Market

Low Trend

Market

Mid Trend

Market

High Trend

$ 5,688 $ 5,764 $ 6,704 $ 7,008 $ 7,356 $ 7,746

 $ 76 $ 1,016 $ 1,320 $ 1,668 $ 2,058 

 % 1% 18% 23% 29% 36%

 $ 939 $ 1,243 $ 1,592 $ 1,981 

16% 22% 28% 34%

$ 33.95 $ 34.44 $ 40.21 $ 44.51 $ 48.09 $ 51.92

$/MWh Incremental to BAU $ 6.26 $ 10.55 $ 14.13 $ 17.97

Per MWh Costs (25 year non-discounted $ cost / 25 year MWh)

FCPP - Summary Cost Comparisons

(2011-2035) Accelerated Depreciation

NPV 25 Year Cost by Case ($Million)

Difference in Cost for Case vs. BAU Case ($Million)

Difference in Cost for Case vs. LNB Case ($Million)

 % 

Units Modeled with SCR >>

Accelerated Depreciation Discussion

As illustrated in Table 2 above, under the modeling approach utilizing accelerated depreciation on 

all retrofits cases (but continuing straight line depreciation on the BAU case), the 25-year NPVs of 

the retrofit cases range from $5.8B for the LNB/OFA Case to $6.7B for SCR. Market-based costs 

understandably produce the same NPVs as in the straight line case, ranging for the Low, Mid, and 

High trends from $7.0, to $7.4B and $7.7B respectively. The NPV of the SCR case under accelerated 

depreciation is 4.3%, 9.5%, and 15.3% lower than the low, mid, and high market outcomes 

respectively. Graph 2 above illustrates the incremental NPV for each case over the BAU case. 

Graph 2A

$-

$2,000 

$4,000 

$6,000 

$8,000 

BAU Case LNB Case

(BAU + LNB)

SCR Case

(BAU + SCR)

Market

Low Trend

Market

Mid Trend

Market

High Trend

$5,688 $5,764

$6,704 $7,008 $7,356 $7,746

25 Year Cost of Power by Case - Accelerated Depreciation

2011-2035 NPV ($Million)
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 20

Graph 2B

$-

$500.00 

$1,000.00 

$1,500.00 

$2,000.00 

$2,500.00 

BAU Case LNB Case

(BAU + LNB)

SCR Case

(BAU + SCR)

Market

Low Trend

Market

Mid Trend

Market

High Trend

$76 

$1,016 

$1,320 

$1,668 

$2,058 

25 Yr Cost Incremental to BAU -Accelerated Depreciation

2011-2035 NPV ($Million)

Discussion of Modeling Results 

The following discussion is intended to highlight certain outcomes from the modeled discounted 

cash flows and provide information to facilitate an informed interpretation of the data. 

 The BAU NPV is ~29% lower cost over the study period than the mid market case.

 The LNB/OFA and SCR Cases result in 25-year NPV’s that are approximately $1.6B to 

$500M lower respectively than the mid trend market case. 

 Under either straight line or accelerated depreciation, the difference between the NPV’s of 

the BAU Case and the LNB/OFA Case is less than 2%.

 Accelerated depreciation would have a material impact on the 25-year costs for the SCR 

case (approximately $191 million more than the straight line depreciation cash flows) if 

implemented as modeled

 The modeled SCR Case NPV is statistically similar (1.7% and 4.5% higher) to the low trend 

market price under straight line depreciation and accelerated depreciation respectively.

 As modeled, the SCR Case over 25-years results returns a lower incremental, nondiscounted cost per megawatt-hour than the LNB/OFA Case and all market cases. Under 

the straight line and accelerated depreciation cases respectively, the SCR Case creates an 

incremental, non-discounted cost over the BAU of $7.40 per MWh and $6.26 per MWh 

respectively. 

The results described above are the product of a large set of carefully developed inputs, 

interactions, and assumptions. The model structure and methodology were conceived by the 

project team in a manner considered to be appropriate for the task and consistent with experiential 

project work. The use and interpretation of the output of the economic model developed for this 

project, like all models, is appropriate when conducted in consideration of the model’s inherent

limitations. The following discussion is intended to identify for the reader, and future users of the 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 21

economic model, those variables and assumptions that Energy Strategies considers particularly 

critical and/or potentially controversial as they may impact outcomes within the model and 

interpretation of the economic results. 

Capital Cost Considerations

The model incorporates both the existing capital at the plant (BAU) and capital associated with each 

retrofit case. The model treats cost recovery for all capital cases as the combination of depreciation 

expense and rate of return on rate base. This is consistent with a revenue requirements modeling 

approach as described above. Several points about capital are worth of discussion:

1. The rate base is the capital asset for which a plant owner would get a rate of return –

thereby creating a cost to the consumer. That value declines each year as the plant is 

depreciated. Defining the rate base for the BAU Case requires an estimation of the book 

value of the plant in service. In the model, this value is derived by a set of calculations that 

assumes original plant in service costs (from FERC F-1 filings) and straight line depreciation 

ending in 2035 for a series of plant improvements from 1967 to 2009. The model’s rate 

base calculation for the BAU Case yields ~$770M in for 2011, the first year in the 

discounted cash flow. The initial economic model was modified to incorporate additional 

information regarding historical plant investment in order to account for relatively newer

plant investments (1985 pollution control as well as annual increases in installed plant 

between 1995 and 2009) and their contribution to rate base. This approach resulted in an 

approximate increase in the rate base starting in 2010 of $220M and is considered to more 

appropriately represent the likely value of plant in service.

2. A critical assumption about the BAU Case is that no new capital is deployed in the next 25 

years, either to extend the plant life, replace major equipment like boilers or steam turbines, 

or adapt to changes in regulatory or market issues. If a substantial cost were incurred, 

especially in the early years of the model, then the BAU case could conceivably increase in 

cost materially with respect to the other cases. 

3. The capital cost estimates, received from EPA and used in the retrofit cases, were escalated 

from 2008 dollars to 2010 dollars then escalated to their year of installation. Earlier 

installation of retrofits could produce lower installed costs; however, a portion of that lower 

cost would be consumed by the increase in the time value of the money expended. 

4. The capital costs used in the model were based on revisions by EPA to costs estimated by 

Black and Veatch for APS. EPA determined their revisions to the cost estimates to result in 

costs that are more consistent with EPA air pollution control cost estimation methodologies 

that still remain conservative because they largely rely on vendor estimates. Lower capital 

and operating costs would reduce the model results for the wholesale cost to produce 

electricity.

5. The model uses a 15% capital recovery factor. This factor incorporates both after-tax debt 

on capital equipment and a rate of return on rate base equipment. The economic model 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 22

uses a regulated utility revenue requirements approach to cost recovery versus a typical 

capital investment modeling approach. The revenue requirements approach entails 

accounting for all the costs a utility would charge a customer in rates in order to repay 

principal and interest on rate base equipment (including all existing equipment prior to 

retrofits), as well as the utilities regulated rate of return on that rate base. 

Finally, retail electricity rates include costs for power generation, transmission, and distribution. 

The modeling for this project addresses cost at the wholesale level and not at the retail level, thus 

only generation costs – and again only generation costs from FCPP – are within this analysis. This 

distinction is important to note because retail electricity consumers receiving power through their 

electric utility from power sourced in part from FCPP pay more than the costs returned by this 

model. The model is not designed to account for “downstream” costs related to transmission, 

distribution, and customer services performed by the local utility. Addressing costs at the 

wholesale level allows comparison to market power cases (see below) where a shutdown at FCPP 

would require wholesale market purchases to replace the absence of FCPP supply. 

Market Power Cases

An important aspect of this project has been creation of a model that will allow comparisons 

between investment cases (i.e. LNB/OFA and SCR) and a market price scenario that assumes a plant 

shut down would have the owners replace that power with market purchases. There are several 

important considerations to keep in mind when interpreting the outcomes of market case versus 

investment case NPVs.

1. The forward electricity price forecast used in the model is considered by the authors to be 

reasonable and appropriate both in regards to source data and methodology. All 

information utilized in the forecast is from publicly available sources and reasonably 

current. Price forecasts are, however, rarely if ever accurate and require frequent updates 

to maintain their currency. The forecast approach utilizes in the model starts with actual 

Palo Verde market prices for 2011 -2014. Beyond those dates the market is not very liquid 

and considered less ‘reliable’ as an indicator of future price. Beyond 2014 the model uses

EIA data to draw price curves, but the foundational price in 2014 is an actual market 

quotation. 

The graph below illustrates that point by combining the low, mid and high price forecasts 

onto the same point for each relative year. The fact that there is no low or high case around 

a mid trend case is, for the purposes of this assessment moot since the market scenarios 

assume that all production at FCPP continues until the end of 2015. By that time, the 

market forecast does include a band around the mid trend case.
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 23

$30.00 

$35.00 

$40.00 

$45.00 

$50.00 

$55.00 

$60.00 

$65.00 

$70.00 

2011201320152017201920212023202520272029203120332035

$ per MWh

Projected Palo Verde Forward Prices

Low $/MWh

Mid $/MWh

High $/MWh

With respect to the 2015 – 2035 projected Palo Verde prices illustrated above, the bands 

formed by the low and high trends are derived from low and high macroeconomic cases for 

wholesale electricity as projected by the U.S. Energy Information Administration.9 As shown 

above, the difference between the low and high trend prices grows over time as would be 

expected with uncertainty assigned in future periods. The range between low and high 

trend prices in 2016 is 4.3% around a mid trend price of $48/MWh, while the low to high 

range in 2020 is 30% around a mid trend price of $58/MWh. 

The reason for highlighting the difference in price ranges between nearer and more distant 

years is because term cash flows have more value than future years on a discounted basis. 

If forward power prices, specifically those starting in 2016 and for next five to ten years of 

the 20-year NPV, were to change significantly from the forecast, then the impact on NPV 

outcomes could swing materially. Conversely, changes to projected prices in the later years 

would have less impact on the NPV outcomes. Although the Palo Verde prices available in 

the market for 2011 to 2014 exhibit strong price escalation, prices today are relatively 

depressed due to the recessionary impacts on the cost of electricity – primarily the cost of 

natural gas, which is the marginal fuel in this market and the fuel whose price fluctuations 

also strongly influence the prices at the Palo Verde hub. U.S. EIA’s natural gas price forecast 

for the Rocky Mountain Western Electricity Coordinating Council / Rocky Mountain Power 

Area and Arizona-New Mexico-Southern Nevada Power Area are illustrated in the following 

graph. 

 

9 2010 US EIA Annual Energy Outlook. http://www.eia.doe.gov/oiaf/aeo/index.html
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 24

$-

$1.0 

$2.0 

$3.0 

$4.0 

$5.0 

$6.0 

$7.0 

$8.0 

$9.0 

$10.0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 $ / MMBTU

Natural Gas Forecast - EIA Annual Energy Outlook May 2010 

(Tables 83 , Reference Macroeconomic Case, 2008$ converted to 2010$)

2. The second reason for this discussion on market pricing is to comment on the potential for 

the power market to be volatile. As recently as 2008, the Palo Verde daily average price was 

approximately $63.50/MWh. Notice in the Projected Palo Verde Forward Prices graph in

item 1 above that even the highest 25 year price on the high trend case is less than the Palo 

Verde average in 2008. This indicates that the market is capable of price volatility that 

could drive prices above the forecast before the end of the model’s time horizon – and 

higher market prices earlier in the cash flow model years would have a larger impact on 

NPVs of the market case.

3. The third reason for discussing market price involves the case assumptions themselves. 

First, even though the underlying assumption in each market case is that plant no longer 

operates starting in 2016, the market prices cases do not include any assumptions 

regarding the cost of shutting down the power plant. Costs of terminating operations would 

be reasonably included in the market cases. Secondly, the market cases do not include 

transmission related costs for purchased power. Transmission costs are typically a very 

small portion of the overall cost of wholesale generation, but nonetheless, are not assumed 

in the model. One reason for the absence of modeling the transmission is that the plant 

owners themselves are transmission owners and it is reasonable to assume that some 

portion of power they would be from market sources would be moved over their lines that 

exist today. However, one could argue that an additional cost would or could be incurred. 

4. A final comment about the market scenarios that has some connection to the issue of plant 

salvages cost above. The market scenarios do not make any assumptions regarding the 

recovery of stranded investments – such as plant no longer used and useful and/or 

underutilized assets like long-lived high voltage transmission facilities. It is reasonable to 
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 25

expect that utilities will not be willing to have shareholders absorb the full cost of losses 

related to stranded cost. 

Decision Environment & Additional Factors

The economic modeling conducted for this project and all the preceding discussion was limited to a 

singular investment environment where the capital investment decision was impacted by the cost 

of alternatives with respect to mandated NOx reduction only. As many commenters have 

suggested, the market and regulatory environment is replete with other factors that may impact the 

economic viability of the FCPP. Prior to this point of the report comments have been limited to 

FCPP and to a range of investment options including SCR. From this point forward the discussion 

will include NGS and focus on SCR. 

FCPP and Navajo Generating Station (“NGS”) have many common characteristics and interests. 

Both plants share a regional location, power markets, fuel types, emissions profiles, Native 

American affiliations, and several utility participants. With respect to this docket and a potential 

BART rulemaking requiring Selective Catalytic Reduction (SCR), both plants share in common a set 

of additional factors that will impact economic decisions regarding plant shutdown. From this 

point forward the additional factors that may influence decision making with discuss both plants, 

especially given that several owners are common to both plants and a decision on one plant is 

highly likely to influence the decision on the other.

Additional Factors

The following discussion will identify and discuss a range of market and regulatory factors that, in 

conjunction with a potential investment decision in SCR, will influence economic decision making 

regarding a potential shutdown for both of these generating facilities. The additional factors that 

may impact plant shutdown decision making that are discussed below are:

1. Greenhouse gas (GHG) emissions regulation

2. California climate change regulations 

3. Power plant ownership 

4. Utility MACT 

5. Fly ash & ash handling regulations

6. Coal and other lease renewals 

The six factors listed above can be categorized into two groups; Environmental Regulations and 

Contractual Contingencies, as follows:

1. Environmental Regulations

a. CO2e emissions (federal and/or California)

b. Utility MACT

c. Coal combustion waste management

2. Contractual Contingencies

a. Plant ownership

b. Coal supply contract renewal & pricing

c. Power plant site lease renewal
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 26

Environmental Regulation

The plant owners point out that several environmental issues on the horizon will demand 

consideration and are expected to compound the complexity of any decision process regarding a 

potential investment in SCR. The following discussion is intended to explain how those issues may 

impact the economic performance of the plants and the investment decision processes.

GHG Emissions Regulation

The precise path that ultimately leads to GHG emissions regulation at the federal level is unclear as 

of this writing. Whether GHG emissions are regulated via command and control rulemaking or 

through a market-based mechanism like cap and trade, the owners of coal-fired electric generation

are anticipating additional costs related to compliance. The regulatory and oversight authorities of 

those entities that serve retail customers with electricity generated by coal combustion are also 

aware of that higher costs are on the horizon.

Cost of Carbon

The ratio of carbon dioxide emissions to power produced for a coal-fired plant is approximately 

1:1. Where, 1 metric ton CO2 is emitted for every per MWh produced. As an example, between 

2005 and 2009 FCPP emitted on average each year 15,718,974 MT of CO2 while producing 

15,301,146 MWh of net generation. Given the 1:1 relationship between CO2 emissions and MWh 

production, calculating the carbon compliance cost impact to a coal plant at varying level of 

carbon price on a $/MT is very straight forward. The $/MT of carbon roughly equals the $/MWh 

adder for carbon to the power cost of a coal plant.

APS’ states in its public meetings10 that for purposes of sensitivity analysis within it integrated 

resource plan (IRP) process that they assume a cost range for carbon from $20/MT to $50/MT. 

Those values, when applied to FCPP, would result in a range of incremental cost of $20/MWh to 

$50/MWh respectively. The FCPP BAU Case non-discounted unit cost over 25 years was 

estimated to be $33.95/MWh. Therefore, $20/MWh and $50/MWh carbon cost adders to the 

BAU Case cost would represent approximately 60% and 150% increases respectively. The 

impact of carbon-related cost increases at one plant such as FCPP would flow into a broader rate 

impact calculation based on the entire portfolio of APS generation assets and purchases power 

contracts. Some of APS’ owned and contracted supplies emit half the CO2 emissions of a coal 

plant (i.e. gas turbine plants) and others that have zero CO2 emissions (i.e. nuclear and nonemitting renewables). This weighted average effect is likely the reason that APS estimates that 

$20/MT to $50/MT carbon prices would result in system wide cost increases to rate payers of 

10% to 25% respectively. .

 

10

http://www.aps.com/_files/various/ResourceAlt/Paul_Smith__Climate_Change_and_RP_Presentation_04201

0.pdf
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 27

California Climate Change Regulations 

In 2006, Governor Schwarzenegger of California signed into law Assembly Bill 32 (AB32), known as

the Global Warming Solutions Act of 2006. AB32 directs the California Air Resources Board (ARB) 

to enact plans to reduce GHG emissions to 1990 levels by 2020. AB32 specifically require ARB to in 

effect create a plan and enact the plan to achieve the emissions reduction target. 

Senate Bill 1368 (SB138) became law in April 2006 and set performance standards with regards to 

emissions of GHG from electric generators. Specifically, SB 1368 sets standards for new long-term 

financial investments in electricity generation located in California as well as electricity imported 

into the state to serve California electric load. The standard allows new capital investments in 

power plants for baseload generation by any load-serving entity only if the GHG emissions related 

to that capital investment or power purchase agreement are as low as or lower than the GHG 

emissions from new, combined-cycle natural gas power plant. Under the performance standard, 

existing contracts are allowed to continue until their expiration without having to meet the 

standard. 

The impacts of both AB32 and SB1368 have been very noticeable in the utility industry in 

California. These two statutes, along with an expansion of the California renewable portfolio 

standard11 has shaped planning decisions for many California utilities and resulted in the following 

specific actions by plant owners at FCPP and NGS:

 Southern California Edison announced its intention to vacate its ownership interest in FCPP 

when its contractual obligations expire in mid-2016 12

 Mayor Villaraigosa of the City of Los Angeles has announced the City’s plan to be coal-free 

by 2020, which would entail exiting the NGS ownership group in 2019 and an eventual 

termination of power imports from the Intermountain Power Plant in Utah.13

 The shares of FCPP and NGS to be relinquished by SCE and LADWP are 712 MW and 477 

MW respectively for a total of 1,189 MW of coal-fired base load generation. Those 

quantities are assumed to become available to existing plant participants according to their 

operating agreements, or to a third party if that is also allowed by the agreement. 

Similar to the efforts of the U.S. Congress to pass climate change legislation – specifically cap and 

trade market enabling legislation – AB32 has been controversial. At this time California has a 

November ballot initiative (Proposition #23) that seeks to suspend AB32. The goal of Prop 23 is to 

freeze the implementation of AB 32 (including implementation of a cap and trade market in 

California) until California's unemployment rate drops to 5.5% or lower for four consecutive 

quarters. California’s unemployment rate was last below 5.5% in 2007.

 

11 Electric utilities regulated by the California Public Utilities Commission are under executive order to obtain 

33% of their electric supply from renewable sources by 2020. The California Assembly is current pursuing 

enabling legislation to support the Governor’s directive.

12 Southern California Edison 2009 10-K filed with U.S. Securities and Exchange Commission. 

http://www.sec.gov/Archives/edgar/data/92103/000104746910001605/0001047469-10-001605-

index.htm

13 http://mayor.lacity.org/Issues/Environment/Next4/index.htm
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 28

In Arizona, where utilities are not faced with legislation such as AB32 or SB1368, APS, SRP, and TEP

all have commented in their integrated resource planning workshops that they view coal plant 

investment going forward as very challenging, citing the risks associated with permitting and 

operating those facilities, in addition to the cost of carbon. The interest of the remaining plant 

participants to acquire the relinquished shares at FCPP or NGS is therefore difficult to gauge.

Utility MACT & Ash Handling (Coal Combustion Residues)

Pending environmental regulation dealing with Utility Maximum Available Control Technology 

(MACT) for mercury and other hazardous air pollutants as well as EPA’s open docket on handling 

and disposal of Coal Combustion Residues (CCR)14 have the potential to increase the cost of 

production for coal-fired plants. An estimation of the capital and operating costs of either Utility 

MACT or CCR has not been conducted for this assessment. However, even without cost estimations, 

it would be reasonable to assume that compliance costs would be incremental to the existing cost of 

production for both plants. In addition to direct costs of compliance, carbon injection for mercury 

control may affect the quality of the fly ash sold by these plants and would be viewed by the owners 

as lost revenue or as another incremental cost. All of these potential costs are certain to draw 

scrutiny from the plant owners in the broader context of long-term economic uncertainties that 

could influence an SCR investment decision. 

Contractual Contingencies

Plant ownership, coal supply contract renewal and pricing, and power plant site lease renewal 

issues are grouped together in the following discussion in that these issues, unlike those covered 

previously, are to some degree under the control of the owners and in many ways are correlated. 

Plant Ownership

Plant ownership has been previously discussed in regards to environmental factors. In this section 

plant ownership is covered from the perspective of who the owners are and how them may 

undertake their decision making process. NGS and FCPP are owned by a mixture of governmental 

agencies, investor owned utilities (IOUs) and public power entities. As illustrated in the following 

tables, while each plant is owned by six entities, their respective percentages of ownership by the 

type entity are quite different. 

Plant Ownership Parent (Utility) and Percentage Owned

FCPP NGS

Pinnacle West Capital Corp (APS) 39% United States Government (BOR) 24%

Edison International (SCE) 35% Salt River Project (SRP) 22%

PNM Resources Inc (PNM) 9% L.A. Dept Water & Power (LADWP) 21%

Salt River Project (SRP) 7% Pinnacle West Capital Corp (APS) 14%

UniSource Energy Corp. (TEP) 5.0% NV Energy (NV Energy) 11%

El Paso Electric Co (EPE) 5.0% UniSource Energy Corp (TEP) 8%

 

14 EPA–HQ–RCRA–2009–0640, Hazardous and Solid Waste Management System; Identification and Listing of 

Special Wastes; Disposal of Coal Combustion Residuals From Electric Utilities
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 29

Four Corners Power Plant

Utility Share of Operating Capacity (MW)

Unit # APS SCE PNM SRP TEP EPE Total

1 170 - - - - - 170

2 170 - - - - - 170

3 220 - - - - - 220

4 113 360 98 75 53 53 750

5 113 360 98 75 53 53 750

Total 785 720 195 150 105 105 2,060

% of 

Plant 39% 35% 9% 7% 5% 5% 100%

Navajo Generating Station

Utility Share of Operating Capacity (MW)

Unit # BOR SRP LADWP APS NV Energy TEP Total

1 182 163 159 105 85 56 750

2 182 163 159 105 85 56 750

3 182 163 159 105 85 56 750

Total 547 488 477 315 254 169 2,250

% of 

Plant 24% 22% 21% 14% 11% 8% 100%

While FCPP is owned almost entirely by the parents of IOUs (APS, SCE, TEP & EPE account for 93% 

of total plant ownership), roughly 2/3rds of NGS is owned by governmental entities (BOR, SRP & 

LADWP). As indicated by the blue lettering above, the three largest electric utilities in Arizona each 

own shares of both plants. Only one of the eight entities listed above, the Bureau of Reclamation 

(BOR), is neither a regulated electric utility nor a public power agency serving retail electric load. 

As the discussion above illustrates, not all the owners of these two power plants are traditional 

electric utilities. Even so, many of the investment decision “drivers” associated with a regulated 

electric utility would be expected to apply to each of the participants. Each one of the plant owners 

must ask themselves whether or not an investment in SCR meets the long-term needs of their 

stakeholders (rate payers, regulators, and owner boards) and shareholders within a range of 

acceptable risk. To answer that question utilities are likely to consider each of the following 

categories of risk within their individual decision frameworks: 

Risk Type Key Issues by Risk Type

Regulatory Risk  Additional investment for new regulation

 Compliance schedules

 Prudency determination by ratemaking authority

Economic Risk  Construction budget & timing

 Asset performance & asset life 

Market Risk  Ownership divestiture

 Increased share and/or commitment

 Market price of power/alternatives
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 30

For the purposes of this discussion, the phrase “plant shutdown decision” really describes a 

decision to NOT investment in measures that would comply with, or adapt to, one or more of the six 

factors. The regulatory implications of such a decision would presumably precipitate an eventual 

plant shutdown. To some degree, the plant shutdown decision criteria for different entity types 

are likely to vary. 

As stated above, the fate of the shares of FCPP and NGS that will be turned back is unknown and a 

substantial piece of the plant ownership uncertainty to be discussed in this section. The combined 

total of 1,189 MW for both SCE and LADWP’s relinquished coal positions would represent a very 

large acquisition of for any single entity, especially those like APS and SRP whose coal positions 

may be longer today than they may desire given the uncertainty of carbon emissions regulations.

Coal Contract Renewal & Pricing, Plant Site Lease Renewal & Other Lease Renewals 

Unlike most of the other issues addresses previously, coal contracts and leases should not pose the 

same level of uncertainty with regards to investment decisions as, for example, regulatory or 

market costs. Those entities that have the greatest to gain or lose with respect to contractual 

renegotiations – especially if they could possibly result in a stalemate that closes the plant - are also 

those most in control of the outcomes. It is reasonable to assume that a coal supplier would wish 

to reach a mutually beneficial and economically sustainable agreement with its customer (the 

power plant) if the only customer for that coal were that power plant. Likewise, the tribal 

communities that rely on the continued operations of the mines and plants for so much of their 

annual revenues could be reasonably expected to make an economic decision and negotiate new 

leases that allow the plants to operate economically and for years into the future.

Therefore, in the case of contracts between the stakeholders (coal, land, rights of way, etc), the 

likelihood that no economic agreement can be reached that extends the existing business 

relationships, thereby causing a plant to shut down, would seem remote. Similarly, one would 

expect that the costs imbedded in new agreements would be economic for all parties since there 

isn’t any foreseeable opportunity for substitution.

Consideration of the Combined Effects of SCR and Additional Factors

It is reasonable to assume that many of these factors will materialize during the 20-year expected 

life of an SCR investment and thereby impact costs and electricity pricing out of each facility. Each 

plant participant will certainly consider the combined potential impacts of these factors when they 

weigh a decision to invest in SCR and seek cost recovery from their regulator. The discussions 

below address each of the six factors in isolation in order to assess the unique characteristics of that 

factor and its potential to influence a plant closure decision. The discussion continues with an 

assessment of the interrelation between factors, primarily as each factor may interact in the 

decision process when combined with a BART finding requiring SCR.
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 31

Consideration of Multiple Investment Risks

Utility Investment Decision Making

Investment decisions made by utility managers are shaped by their desire to simultaneously satisfy 

regulatory stakeholder needs and investor shareholder interests. Utilities have an obligation to 

provide reliable, safe, and reasonably-priced electric service within a certificated service territory. 

In consideration of that obligation, utilities are given a monopoly within that territory. This is 

known as the ‘regulatory compact’. The regulatory compact also guarantees cost recovery of 

prudently incurred costs and a rate of return on certain assets. The regulatory compact does not 

guarantee a profit nor cost recovery on “imprudent” investments. 

Investor owned utilities have a corporate mandate to return value to their shareholders through 

the value of their stocks and bonds. Public utilities, while not ultimately owned by stockholders, 

are owned by their customers and thus have a fiduciary responsibility to provide service 

economically and in a financially sustainable manner. And while the BOR and CAWCD are not 

electric utilities per se, their decisions must be guided by service to their water customers and the 

federal agencies. 

Potential Methodology for Addressing Multiple Risks

All the preceding discussion points to a situation best described as a set of simultaneous equations -

multiple variables and multiple unknowns. The set of uncertainties facing the plant owners 

comprises the three categories of risk discussed above: regulatory, economic, and market. 

Underlying each category, of course, is a wide range of uncertainties such as technology cost risks, 

credit, construction, performance, timing, market energy prices, and others. Many of the risks 

would be expected to be correlated, such as the cost of capital equipment and the installation date. 

In the midst of so many different, but sometimes related factors, the plant owners may seek out a 

means to quantify and address that uncertainty and still produce meaningful, economic decision 

support information for their stakeholders and shareholders. One way to test the sensitivity of a 

variable on the economic outcomes is to utilize a model such as the one designed for this project 

that allows the user to change key variables and test “what if” scenarios. This form of sensitivity 

testing is typically limited by the user’s ability to run additional cases while changing one variable 

at a time. 

Simulation

Utilities are very versed at using stochastic simulation to solve multiple equations for sets of 

correlated variables across ranges of uncertainty for each variable. The energy industry commonly 

uses probabilistic modeling to determine a range of outcomes rather than a single point 

(deterministic) result for their investment alternatives. Simulation might be useful in the process 

of interrelating the economic cases for multiple pollution controls investment options (BAU, 

LNB/OFA, SNCR, SCR, and other retrofits), along with a range of costs and probabilities for the 

additional factors discussed above: CO2 regulation cost, MACT cost, etc.
EPA Contract No. EP-D-05-087

Work Assignment No. 4-07

Prepared for E C/R Incorporated by

Energy Strategies, LLC 32

Stochastic modeling can provide a probabilistic assessment of cost outcomes, where all variables 

interact over thousands of iterations simultaneously within their own probability distribution, and 

in correlation to other variables and their distributions. As in a deterministic modeling, simulation 

requires the modeler to start by assigning estimated values for each variable. Unlike deterministic 

modeling, a simulation model applies a probability distribution to the estimated value of each 

variable. 

By design, the model in use for this project is deterministic and not probabilistic. Even so, the

estimated values for each variable in the model (e.g. capital costs, power costs, operating expense, 

etc) would be equivalent to the assumed mean resulting from a probability distribution for that 

variable. As such, the economic model generates an expected value (NPV) that is the product of 

interrelating the mean values for all variables without accounting for a range of uncertainty. If 

necessary for purposes of sensitivity testing, individual variables can be adjusted within the model. 

With respect to simulation, the process of defining the range of uncertainties for each variable is of 

vital importance and is best accomplished when tighter rather than wider probability distributions

can be assigned. This all the more crucial for variables whose significant influence on the outcome

warrants cautious application of a probability distribution. A stochastic model of FCPP’s revenue 

requirement would entail quantification of the expected values and probability distributions for 

each of the Additional Factors as well as all other CAPEX and OPEX variables. 

|

|

|

|

|

|

|

|

|

|

|

|

|

END OF REPORT