# R EPORT 

# : E CONOMIC 

# A NALYSIS OF 

# P ROPOSED 

# EPA
BART D ETERMINATION ON 

# F OUR 

# C ORNERS 

# P OWER 

# P LANT

EPA Contract No. EP

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# 9/8/2010

Final Report

P REPARED FOR 

## E C/R I NCORPORATED

BY 

## E NERGY 

## S TRATEGIES


## , LLCEPA Contract No . EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 2 

### P REFACE TO THE 

### F INAL 

### R EPORT



### 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

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.

A UTHORS 

### & C ONTRIBUTORS TO THE 

### F INAL 

### R EPORT 

### 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 85111EPA Contract No . EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 3 

### E CONOMIC 

### A NALYSIS OF 

### P ROPOSED 

### EPA BART D ETERMINATION ON 

### F OUR 

### C ORNERS 

### P OWER 

### P LANT 

### (F C PP)

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 Envir onment & Additional Factors

................................ ................................ ................................ .............. 25

Additional Factors

................................ ................................ ................................ ................................ ............................ 25

Environmental Regulation

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

................................ ................................ ................................ ................................ ....... 26

Californ ia 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

Consideratio n of Multiple Investment Risks

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

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

................................ ................................ ...................... 31

Simulation

................................ ................................ ................................ ................................ ................................ ....... 31EPA Contract No . EP

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## 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 (N GS ) . 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.

For modeling purposes

, th e costs above (2 008 dollars ) we re 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

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 5 Utilizing the assum ptions 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.

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 th e 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 $1 88 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

- discou nted
cost of $7.40 per megawatt

- hour over the Business as Usual (BAU) case.EPA Contract No . EP

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Prep ared 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 mo del 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 int erpretation of the economic results.

Capital Cost Considerations

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

ass ociated with each retrofit case. Cost recovery for capital includes depreciation

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

 R ate base for the BAU Case includes an estimation of bo ok 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) th e model uses a
15% capital cost recover y factor.

 The model assumes no new capital deploy ment 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 ca n influence the outcomes of the economic model but producing lower or higher in stalled 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 electr icity.

 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 a t 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

tra nsmission, 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 abs ence 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 rea sonable 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

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 7  In addition to being difficult to forecast, m arket pricing can be ve ry volatile and may exceed the boundaries within the forecasted ranges in any given year by significant amount.

 As stated in the previous section, m arket cases do not include transmission related costs for purchased power , nor further downstream distribution costs

.

 Finally, th e 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 long

lived high voltage transmission facilities , nor any costs related to decommissioning and salvage.

Additional Factors

The decision

- making process of plant owners with respect to invest ment in SCR or other man dated emissions controls will include consideration of other factors that are likely to materializ e 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 oversi ght 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’ e stimate 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

- 201 6

 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 targetEPA Contract No . EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 8 Utility MACT & Ash Handling (Coal Combustion Residues)

Pending environmental regulation d ealing 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 f rom 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

Un like most of the other issues, c oal c ontract s 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 i n 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

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Prep ared 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 & a sset life
Market Risk  Ownership divestiture

 Increased share and/or commitment

 Market price of power/alternativesEPA Contract No . EP

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## 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 t wo emissions sources subject to BART on the Navajo Nation are the Four Corners Power Plant (“FCPP”) , near Far mington, 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 enga ged 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. 1 This 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 offer ed with the hope that the information co ntained 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 F CPP 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 a t 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. & Descripti on

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
considerat ions.

3 APS’ December 2008 BART Cost UpdatesEPA Contract No . EP

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Prep ared 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 L NB/OFA, EPA requested the economic model be revised so that the SCR case only include s 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 3 4

. 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 s upplied by EPA for capital and operating expense 5 . 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 asso ciated 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 regio nal 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 h igher 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 voice d a concer n 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 compari son t he 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

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 12 for NOx determination is only one item on a long er 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 change s , 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 bet ween 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. Als o 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 we re 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 th e 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 pow er 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.

Th e following sections of this document describe the actions take n by Energy Strategies in support of EC/R’s needs in th ese matter s , 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 model ing 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

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Prep ared 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 case s ) consists of t he following seven cases (1

- exis ting plant, 3

- retrofit cases, and 3

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

Case Name APS

Option
No. Description s & 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 r etrofit 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) N A  P lant 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
Note s for All Market Price Cases :

 Market price forecasts impact market c ase NPV’s starting in 2016 based on the assumption that until the plant shutdown s 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

 P alo V erde 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 Case s

* 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 e achEPA Contract No . EP

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Prep ared 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 fr om the market if FCPP ceases operations. As stated above,

many comm enters expressed concern that retrofitting FCPP would impact its competitiveness and potentially cause , or greatly contribute to

, a permanent plant shut down . Commenters conclude
that th e loss of FCPP as a resource to serve retail customer s 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 part icipants 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 assume s that the plant shut s 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 non

shutdown cases in as much as those cases receive cost recovery of all generator costs (fixed and variable) going forward, likewise, the market cases a ssume 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 approa ch, 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 include s existing costs of the historical plant through 2009 6

– 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 schedule 7 :

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 ma jor maintenance cycles for FCPPEPA Contract No . EP

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Prep ared 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

T he discounted cash flow model developed for this project re sembles 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 plant

in

- 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, r etail 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
gener ation cost which each utility recovers are the result of a portfolio of owned and purchase d

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 constru ction 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

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 16 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 w ere 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 asse ts are assumed to be involved

. On the following pages the report will refer to table s , graphs, and contain discussion the model and its output specific to cost summaries

–

Straight Line Depreciation : (see Table 1 & Graph 1)

- w here straight line deprecia tion is applied to all non

- market power cases

Accelerated Depreciation : (see Table 2 & Graph 2)

– where a ccelerated depreciation is applied on all retrofit pollution control cases

, while continuing to apply straight line deprecia tion 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 acce lerated 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 Cod e 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 as sessment 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 wi th tax accounting and tax law expertise.EPA Contract No . EP

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Prep ared 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 th e same.

Straight Line Depreciation Outcomes
Table 1

S traight 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

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Prep ared 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 1 A

Graph 1B below illustrates the 25

- year incremental NPV for each case compared to the BAU case under straight line depreciation.

Graph 1BEPA Contract No . EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 19 Accelerated Depreciation Outcomes
Table 2

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 2 AEPA Contract No . EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 20 Graph 2B



### Discussion of Modeling Results The following discussion is intended to highlight certain outcomes from t he 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 peri od than the mid market case.

 The LNB/OFA and SCR Case s result in 25

- year NPV’s that are approximately $1. 6 B 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 w ould 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 a ccelerated depreciation respectively

.

 As modeled

, the SCR Case over 25

- years results returns a lower incremental, n on

discounted 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. T he following discussion is intended to identify for the reader

, and future users of theEPA Contract No . EP

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Prep ared 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 cap ital 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 t he BAU C ase requires an estimation of the book value of the pl ant 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 mod el’s rate base calculation for the BAU Case yields
~ $ 770M in for 2011 , the first year in the
discounted cash flow

. The i nitial economic model was modified to incorporate additional information regarding historical plant investment in order to account for relatively new er 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 incre ase in cost materially with respect to the other cases.

3. The capital cost estimate s, 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 esti mates. 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 o n rate base equipment. The economic modelEPA Contract No . EP

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Prep ared 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 woul d 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 incl ude costs for power generation, transmission, and distribution.
The modeling for this project addresses cost at the wholesale leve l and not at the retail level, thus only generation costs

– and again only generation costs from FCPP

– are within this analy sis. 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 p rice 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 foreca sts 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

an d 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 a nd 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 unt il the end of 2015. By that time, the
market forecast does include a band around the mid trend case.EPA Contract No . EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 23 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 project ed 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

year s is because term cash flows have more value than future years on a discounted basis. If forward power prices, specifically those starting i n 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 stron g 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 Powe r 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.htmlEPA Contract No . EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 24 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 P rices 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, t he market prices cases do not include any assumptions regarding the cost of shutting down the power plant. Costs of terminating operations would be reasonably in cluded 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 t he 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 r egarding 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 toEPA Contract No . EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 25 expect that utilities will not be willing to have shareholders a bsorb 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 . P rior to this point of the report comments have been limited to

FCPP and to a range of investment op tions 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 wi ll 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 econom ic 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. G reenhouse gas (GHG) emissions regulation
2. California climate cha nge regulations
3. Power plant ownership
4. Utility MACT 5. F ly ash & ash handling regulations
6. C oal and other lease renewals

The six factors listed above can be categorized into two groups ; Environmental Regulations and Contractual Contingencies, as follows : 1. Environmental R egulation s

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 renewalEPA Contract No . EP

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### 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 i nvestment in SCR . The follow ing discussion is intended to expl ain how those issue s may impact the economic performance of the plants and the investment decision process es

.
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

- bas ed mechanism like cap and trade, the owners of coal

- fired electric generation are anticipating additional costs related to compliance. The regulatory and oversig ht 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, bet ween 2005 and 2009 FCPP emitted on average each year 15,718,974 MT of CO2 while prod ucing
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 v ery straight forward. The $/MT of ca rbon roughly equals the $/MWh adder for carbon to the power cost of a coal plant.

APS’ states in its public meetings 10 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.

Thos e 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 6 0 % and 15 0 % increase s 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 non

emitting renew ables). 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 increase s 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.pdfEPA Contract No . EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 27 California C limate C hange R egulations

I n 2006, Go vernor Schwarzenegger of California signed into law A ssembly Bill 32 (AB32), known as the Global Warming Solutions Act of 2006 . AB32 directs the Calif ornia Air Resources Board (ARB)

to enact plans to reduce GHG emissions to 1990 levels by 2020. AB32 spec ifically 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 . Spec ifically, 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 p erformance standard, existing contracts are allowed to continue until their expiration without having to meet the
standard.

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

Ca lifornia. Th es e two statutes
, along w ith an expansion of the California renewable portfolio
standard 11 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 contract ual 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 be com e available to existing plant participant s according to their operating agreements, or to a th ird 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 seek s 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 t he 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 Cal ifornia Edison 2009 10

- K filed with U.S. Securities and Exchange Commission

. http://www.sec.gov/Archives/edgar/data/92103/000104746910001605/000104 7469

- 10

- 001605

- index.htm

13 http://mayor.lacity.org/Issues/Environment/Next4/index.htmEPA Contract No . EP

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Prep ared 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 plan ning workshop s that they view coal plant investment going forward as very challenging

, citing the risk s 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 (C CR) 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 pl ants 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 previou sly, 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 pl ant 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) 3 5 % 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 E PA

– HQ

– RCRA

– 2009

– 0640

, Hazardous and Solid Waste Management System; Identification and Listing of Special Wastes; Disposal of Coal Combustion Residuals From Electric UtilitiesEPA Contract No . EP

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Prep ared 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 2/3 rds 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 t he 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

s takeholders (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/alternativesEPA Contract No . EP

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Prep ared 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 adap t 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 state d 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 posit ions 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 C ontract R enewal & P ricing
, Pl ant S ite L ease R enewal & Other Lease R enewals Unlike most of the other issues addresses previously, c oal c ontract s and leases should not pose the same level of uncertainty with regards to investment decisions as, for example, regulatory or
market cost s. 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 ass ume 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 cont inued 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, i n the case of contracts between the stakeholders (coal, land, rights of way, etc), the
likelihood that no economic agreement can be reached that extend s 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 reas onable 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 potenti al 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 po tential 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

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## 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 obligatio n 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 regula tory 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 mand ate 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 p receding 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, e conomic, 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, s uch 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 decisi on 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 equatio ns 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 i n t e r r e l a t i n g the economic cases for multiple pollution controls investment options (BAU, LNB/OFA , SNCR, SCR, and other retrofits), along with a range of costs and probabilitie s for the
additional factors discussed above : CO2 regulation cost, MACT cost, etc

.EPA Contract No . EP

- D

- 05

- 087 Work Assignment No. 4

- 07

Prep ared 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 probab ility distribution

, and
in correlation to other variables and their distributions

. As in a deterministic modeling, s imulation requires the modeler to start by assigning estimated value s for each variable . Unlike deterministic modeling

, a simulation mode l applies a probability distribution to the estimated value of each
variable

.
By design, t he m odel 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
interrelat ing 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, t he process of defining the range of uncertainties for each variable is of
vital importan ce and is best accomplished when tigh t er rather than wider probability distribution s can be assigned . This all the more crucial for variables whose significant influence on the outcome

warrants cautio us 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 variable s

.

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END OF REPORT