REPORT: 

AFFORDABILITY ANALYSIS OF BART

OPTIONS FOR NAVAJO GENERATING 

STATION

EPA Contract No. EP-D-10-096 

Work Assignment No. 3-04

Final Report

January 14, 2013

PREPARED FOR E C/R INCORPORATED

BY ENERGY STRATEGIES, LLC
EPA Contract No. EP-D-10-096

Work Assignment No. 3-04

Prepared for E C/R Incorporated by

Energy Strategies, LLC 2

PREFACE 

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-10-096, Work Assignment No. #2-04,

"Support for Region 9 Power Plant Rulemaking and Permitting Work".

AUTHORS & CONTRIBUTORS 

Richard Anderson, Principal

Gary Mirich, Director

Neal Townsend, Director

Don Hendrickson, Senior Consultant

Justin Farr, Senior Consultant

Energy Strategies, LLC

215 South State Street, Suite 200

Salt Lake City, UT 85111

3033 North Central Avenue, Suite 900

Phoenix, AZ 85012
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AFFORDABILITY ANALYSIS OF PROPOSED EPA BART DETERMINATION ON 

NAVAJO GENERATING STATION (NGS) 

Table of Contents

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

Introduction ................................................................................................................................................13

Scope & Approach...................................................................................................................................13

Affordability Modeling Methodology & Case Analysis...............................................................................17

Modeling Output & Discussion of Results ..................................................................................................22

Modeling Outcomes................................................................................................................................23

Discussion of Modeling Results ..............................................................................................................25

SCR Cost Impacts on Retail Electricity Rates and Water Prices..............................................................30

Comparison with Other Available Studies..................................................................................................37

Sensitivity Analyses.....................................................................................................................................45

Market Power Forecast...........................................................................................................................45

Lease Cost ...............................................................................................................................................46

Fuel OPEX................................................................................................................................................48

Accelerated Depreciation - Supplemental Modeling..............................................................................49

MATS – Supplemental Scenario Modeling..............................................................................................50

Decision Environment & Additional Factors...............................................................................................53

Environmental Regulation ......................................................................................................................54

ADDENDUM: Water Cost Impacts ..............................................................................................................61
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AFFORDABILITY ANALYSIS OF BART OPTIONS FOR

NAVAJO GENERATING STATION (NGS)

Executive Summary

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

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

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

utilized and the findings specific to NGS. The Executive Summary discusses in brief the findings of 

the assessment more fully discussed in the body of this report. 

The primary purpose of the analysis was to develop and apply a deterministic affordability model 

to estimate the incremental cost of producing power at NGS as a result of a retrofit installation, 

within five years of a final EPA rulemaking,1 of Selective Catalytic Reduction ("SCR"), and Selective 

Non-Catalytic Reduction (“SNCR”). The objective was to juxtapose economic metrics that compared 

incremental costs associated with SCR or SNCR implementation to a baseline case with low-NOx

burners with separated overfire air (LNB/SOFA) that were installed and operational over 2009 –

2011 but without SCR or SNCR. In addition to comparing the relative power costs associated with 

the Business as Usual (“BAU”), SNCR, and SCR cases, the analysis also includes comparative 

outcomes to low, mid, and high market trend cases – meant to represent the cost of acquiring 

power on the wholesale market to replace the volume of megawatt hours if NGS were not in 

operation and in recognition of the ongoing responsibility each NGS owner to provide power to its 

customers.

Affordability Modeling

A 25-year discounted cash flow modeling was conducted for capital investment scenarios against a

set of BAU, SNCR, SCR, and market purchase cases. In order to estimate the potential impact of 

accelerated depreciation on net present values (“NPVs”), one of the capital investment schedule 

scenarios was modeled utilizing both straight line and accelerated depreciation methods. BAU, 

 

1

For the purposes of this analysis, we assumed: (1) EPA would issue a final rulemaking in 2013 with a 

compliance date by 2018, and (2) the owners of NGS would elect to install controls on one unit per year to 

meet the 2018 compliance date.
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SNCR, SCR, and market cases were run for each individual plant owner separately then combined 

for a total plant perspective. 

The following table summarizes the cases discussed in this report. Results from additional cases 

(e.g., SNCR) are included in the affordability analysis spreadsheet, but are not discussed in 

significant detail in this report.

Table E-1

Affordability Modeling Assumptions

Unit 

No.

Case Definitions

BAU

SNCR 

Case

SCR 

Case

Market Cases

Unit 1 Plant as of 

2011 with 

LNB/SOFA: 

BOR, SRP & 

IOU Cases

BAU + 

SNCR

BAU + 

SCR

Low 

Trend

Mid 

Trend

High

Trend

Unit 2 BAU + 

SNCR

BAU + 

SCR

Unit 3 BAU + 

SNCR

BAU + 

SCR

Investment Schedule 

I.D. Description Installation Years by Unit

A SCR on all units by 2018 #2 - 2016, #1 - 2017, #3 - 2018

B SNCR on all units by 2018 #2 - 2016, #1 - 2017, #3 - 2018

Although the primary purpose of the study focused on incremental costs associated with 

compliance of possible NOx emissions standards (e.g. SCR), sensitivity modeling was also 

conducted relative to installation and operation of capital equipment of a potential option for 

complying with EPA’s rulemaking to reduce emissions of hazardous air pollutants from electric 

utilities, also known as the Mercury and Air Toxics Standards (MATS). A discussion of that analysis, 

along with other factors and their influence on the model outputs, can be found below in the section 

on “Sensitivity Analyses”.
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Cash Flow Case Results

Table E-2 below illustrates the capital and operating expenses assumed in the Affordability Analysis 

model for each unit at NGS. For modeling purposes, the 2012 dollar costs were escalated to their 

respective year of installation using a 3% rate of inflation. Operating expenses were escalated at 

3% per year for the entire 25-year cash flow period. Expenses shown in Table E-2 represent SCR 

only. The costs associated with installation of LNB/SOFA (over 2009 – 2011) are included in BAU 

(as of 2011) case.

Table E-2

SCR Estimates: CAPEX & OPEX

Combined Owner Cash Flow Cases

Los Angeles Department of Water and Power (LADWP), one of the current owners of NGS, does not 

intend to maintain ownership of their share of NGS past the end of its current operating agreement. 

To address the shift in ownership, the model includes cases where outputs for other owners of NGS

are combined with LADWP’s share in two ways. One, where the LADWP share is assumed to 

transfer to an investor owned utility or IOU, and a second case where the LADWP share is acquired 

by a publicly-owned utility or POU (as shown below) like Salt River Project (SRP). In these IOU and 

POU cases, the share represented as coming from LADWP is applied against the same financial 

metrics for purposes of cash flow modeling as the IOU only case and the POU case. The following 

table illustrates the 25 year NPVs for the combined plant cases where LADWP’s share is acquired by 

a POU.

Unit No.

Capital

Expense

Operating 

Expense

1 $ 137,527,000 $ 3,982,000

2 $ 188,585,000 $ 3,982,000

3 $ 170,294,000 $ 3,982,000

Total $ 496,406,000 $ 11,946,000

Capital & Operating Expense Assumptions

2012$
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Table E-3

2016/2017/2018 SCR Installation Schedule: 25 Year NPV and 2018 Impacts

Discussion of Critical Inputs, Modeling Limitations, and Output Interpretation

The output of the model is best understood in light of the model’s inputs and limitations. The 

following summarizes those variables and assumptions considered particularly critical to the 

model’s results and interpretation of such results. 

Capital Cost Considerations

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

associated with the retrofit cases. 

 Rate base for the BAU case includes an estimation of book value of the plant in service based on

EIA and FERC filings for NGS and estimations of timing of plant investments. 

 With the exception of the incremental capital associated with installation of Low NOx Burners 

with Separated Overfire Air (LNB/SOFA) on all three NGS units (modeled as completed in 

2011), the model assumes no new capital deployment in the next 25 years on the existing plant 

(BAU). However, there is an assumed increase in plant site lease cost of $15 million annually 

starting in 2020. This assumption comports to the increase in lease cost recently transacted at 

the Four Corners Power Plant, adjusted for the larger NGS facility. 

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

model by 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 

cost to produce electricity.

NPV $ millions

BAU SNCR SCR

Low 

Market

Mid 

Market

High 

Market BAU SNCR SCR SNCR SCR

$ 7,766 $ 8,021 $ 8,414 $ 8,439 $ 8,717 $ 8,806 $ 35.64 $ 37.37 $ 41.25 $ 1.73 $ 5.60

Total Plant w DWP Share to POU $ 255 $ 648 $ 673 $ 951 $ 1,040 4.9% 15.7%

Total Plant w DWP 

Share to POU

NPV by Case

 ($ million)

SCR NPV

Vs. BAU NPV

($ million)

2018 Incremental 

$/MWh for Total 

Plant Cost

 % Greater than BAU 

>> 

2018 Total Cost of Power

by Cash Flow Case 

($/MWh)
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 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. 

Addressing costs at the wholesale level allows comparison to market power cases (see “Market 

Power Cases” below) where a shutdown at NGS would require wholesale market purchases to 

replace the NGS supply.

Estimated Impacts on Retail Electric Rates & CAWCD Water Rates

Since the model addresses cost at the wholesale level and by itself does not produce results 

regarding retail rates, secondary assessments were undertaken to estimate the impact of SCR or 

SNCR on retail electricity rates for SRP, the utility owner with the largest ownership share in NGS. 

The outcomes from the model for the years reflecting the largest incremental cost impact due to

SCR or SNCR were applied to an average system electric rate calculation based on 2011 utility 

filings and SRP’s share of the incremental cost associated with the retrofits. The estimated impact 

to average retail rates for SRP in the highest cost year for the installation schedule is shown in the 

following table. 

A similar assessment was utilized to estimate the potential impacts of SCR or SNCR on a subset of 

Central Arizona Water Conservation District’s (CAWCD) water rates2. The CAWCD relies almost 

exclusively on power from NGS to pump water from the Colorado River to its customers in Arizona

through the Central Arizona Project (CAP) sytem. In the same fashion as with the rate analysis, the 

model calculated the impact to the Energy Rate 1 CAP water pumping rate based on the BOR’s share 

of NGS and its unique cash flows. 

Those incremental costs for SCR or SNCR are converted into pumping costs on a dollar per acre foot 

basis. Similarly to the SRP electric rate impacts, the estimated impact to the CAP Energy Rate 1 for 

CAWCD in the highest cost year for each installation schedule scenario is shown in the following 

table.

 

2 The Central Arizona Water Conservation District (CAWCD) is a multi-county taxing authority created under 

Arizona law (A.R.S. Title 48, Chapter 22). The CAWCD governs the Central Arizona Project (CAP), an aqueduct 

system that delivers Colorado River water into the CAP's service area counties of Maricopa, Pinal and Pima. 

CAWCD was established in 1971 as a means for Arizona to repay the U.S. government for reimbursable costs 

of construction of the CAP aqueduct. 
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Table E-4

2016/2017/2018 SCR Installation Impact on 

2018 CAP Water and SRP Electric Rates

The table above shows the 2018 Energy 1 rates respectively would increase $8.40/AF (14.5%)

when compared to the estimated 2018 CAP Energy 1. This 2018 CAP rate estimate is

conservatively assumed to be the same as the 2016 advisory rate published by CAWCD for CAP 

water rates effective June 2011.

SRP’s overall average rate impact as a result of SCR is less than 1% in the peak investment year. SRP 

rates, comparatively, are impacted to a far lesser degree than are the rates of CAWCD. The reason 

for such a vast difference is the fact that SRP has a wide portfolio of generation assets from which to 

source its retail electricity, whereas CAWCD is the sole customer of BOR and thereby absorbs the 

total incremental cost associated with BOR’s share of the generation plant. 

The estimated rate results for both SRP and CAWCD use simplifying assumptions. SRP rate impacts 

are compared against an average utility rate that is unchanged from 2011 and does not account for 

potential changes in the utility’s costs, including other environmental investments, large 

investments in renewable energy, and other costs. Likewise, CAWCD rate results do not assume 

any impacts on CAP water rates from any other costs that may be incurred by CAWCD except those 

quantified in the model for SCR or SNCR CAPEX and OPEX incremental to the BAU. The annual cost 

impacts are outlined in greater detail in the body of this report. 

In conjunction with the incremental power cost analysis, an additional analysis was conducted 

regarding water cost impacts to tribal, non-Indian agriculture, and municipal water users as a result 

of costs associated with NOx reduction investments. Those findings are referenced in the 

addendum at the end of this report entitled Water Cost Impacts. 

$/AF Change 

in CAP Rate 

(SCR)

% Change in

AF Rate 

(SCR)

% Change in

CAP Rate 

(SNCR)

% Change in

SRP Rate 

(SCR)

BOR Share Only $ 8.40 14.5% 5.2%

SRP Only 0.66%

Impact of SCR (or SNCR) Incremental Costs in 2018 on

Estimated 2018 CAP Energy 1 Water Pumping Rate and SRP 

Average Electric Rate

Cash Flow Case
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Comparison with Other Available Studies

The issue of how a BART implementation would affect the affordability of NGS power rates and 

ultimately CAP water cost, has been estimated by other recent studies. Four particular studies of 

interest are: the ICF analysis commissioned by the Hopi Tribe and submitted to EPA in 2010, the 

analysis undertaken by the National Renewable Energy Laboratory (Navajo Generating Station and 

Air Visibility Regulations: Alternatives and Impacts – January 2012) and two studies undertaken by 

the consulting firm Harvey Economics; one study on behalf of the Gila River Indian Community 

(Projected Impacts of EPA BART Implementation on the GRIC – revised edition, March 2012) and 

the other on behalf of Salt River Project (The Economic Impact of EPA Proposed BART 

Implementation at Navajo Generating Station – April 2012). The ICF study assessed the risk of NGS 

closure in light of several potential environmental regulations and energy market conditions, 

including: availability and cost of CO2 emissions offsets, CO2 allowance prices, growth in market 

area electricity demand, and forward natural gas prices. The latter three studies analyzed potential 

power and water costs under different BART scenarios, including SCR and SCR with baghouse (note 

that the EPA has indicated it does not consider baghouse for MATS compliance as a BART 

requirement). Additionally, these latter three studies analyzed impacts that would be attributable 

to a situation in which owners of the NGS shut down operations. 

The studies took slightly different modeling approaches and varied in some key assumptions. 

Capital cost, future wholesale power prices, financing cost, and the volume of water necessary to 

meet agriculture production appear to be key assumptions that differ between studies. Given these 

variations in assumed input values, the resulting estimates of impacts on power and water rates 

also vary. However, despite the variation in approaches and inputs, the studies produce results that

are not fundamentally different. 

Table E-5 below presents a snapshot of the water and power impacts from each study reported. As 

portrayed in the table, the “EPA” study refers to this assessment and report. 

Table E-5

Key Comparisons of SCR Impacts to Electricity & Water Rates

EPA Harvey 

Economics

NREL

Impact on Retail Electric Rates 0.66% (SRP only) Not provided 0.2 – 0.6%

Impact on CAP Pumping Rate 14.5% 10.5% 13 – 16%
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Sensitivity Cases & Supplemental Modeling

Several sensitivity cases and supplemental modeling runs were also conducted to test for potential 

impact across a range of values for specific variables. In each case, individual variables were 

adjusted between a low and high range value while all other modeling inputs were held constant 

relative to the baseline model.

The specific variables modeled across a range of values to determine sensitivity included: 

forecasted market electricity price, land lease cost, and fuel OPEX. In addition to these, this 

assessment also included supplemental modeling relative to potential compliance needs for MATS

(baghouse) and accelerated depreciation. The report contains a section entitled "Sensitivity 

Analyses" within which the outcomes of sensitivity and supplemental modeling are discussed. The 

following items summarize key findings related to the sensitivity analysis.

 Case outcomes are highly sensitive to changes in projected market prices. A reduction of 

10% in projected market power prices results in an NPV for SCR that is 6.5% higher than 

the NPV for low market.

 Case outcomes are moderately sensitive to changes in lease cost. An increase in lease cost 

of $5 million annually (compared to the assumed $15 million annually) resulted in a 

moderate reduction in NPV. 

 Case outcomes for additional CAPEX and OPEX for baghouse installation indicate that 

incremental NPV compared to BAU is roughly double that of SCR alone. Under the SCR + 

baghouse supplemental model, the CAP Energy Rate 1 rate would increase in 2018 by 

nearly 30% over the estimated 2018 rate.

Market Power Cases

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

market cases.

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

appropriate both in regards to source data and methodology. The price forecast utilized in 

the analysis was based upon values of November 27, 2012. 

 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 a significant amount. 
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 As discussed more fully in the report, market cases in this analysis do not include 

transmission related costs for purchased power or further downstream distribution costs. 

 Finally, the market scenarios make no 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 at NGS 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. As discussed in the report, those factors are likely to 

include:

 GHG Emissions Regulation 

 California Climate Change Regulations 

 Plant Ownership 

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

 Consideration of the Combined Effects of SCR and Additional Factors
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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 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 Native American 

communities, as well as comments with respect to water costs for customers of the Central Arizona 

Water Conservation District (“CAWCD”).

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 specific to NGS.

3

The document describes the actions taken by Energy Strategies in 

support of EC/R’s needs for an affordability assessment in the matter of NGS and an initial 

assessment of the impact of a BART determination on water pumping rates for the CAWCD. 

Scope & Approach

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

emissions controls on one or more of the existing three NGS units. Prior to this study, the plant

operator, Salt River Project (“SRP”), and the participating owners, had embarked upon a program to 

install Low NOx Burners with Separated Overfire Air (LNB/SOFA), on all three units at NGS4. 

Records from the plant owners indicate that the first LNB/SOFA installation was completed in 2009 

and that the final LNB/SOFA installation was completed in 2011. The analysis conducted for this 

study assumes a Business as Usual (“BAU”) case that includes the LNB/SOFA capital and operating 

costs as reported by SRP in their fiscal year ending 2010 audited financial statement in which SRP 

 

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

market and economic circumstances 

4

“Navajo Generation Station SCR & SNCR Cost Study”, SRP, July 25, 2008
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stated that the total cost of the LNB/SOFA installations would be $45 million.5 Estimates by 

CAWCD6 regarding NOx-related emissions controls costs for NGS, assuming a BART determination 

requiring Selective Catalytic Reduction (“SCR”), combine the cost of LNB/SOFA with an estimated 

cost for SCR. NGS with LNB/SOFA represents the “status quo”, and as such, is the applicable BAU 

case for comparison to any retrofit case. Therefore, the applicable “retrofit” cases for NOx 

reduction under investigation for this assessment involved installation of SCR or SNCR on each unit 

at the NGS.

SRP’s August 2010 filing7of revised capital and operating cost estimates for SCR included three 

options:

 SCR only

 SCR with direct sorbent injection

 SCR with polishing baghouse

For this assessment the retrofit technology options selected were SCR and SNCR only. As defined 

by SRP’s consultant in the August 2010 revised cost estimate, capital cost for the SCR only option is 

$544 million. However, because there is a possibility that NGS may need to install one or more new 

baghouses to comply with EPA’s final Mercury and Air Toxics Standard (MATS), this study did 

examine the combined impact of SCR with polishing bag houses as reported in the section titled 

“Sensitivity Analyses.” EPA has indicated it does not consider installation of baghouses for MATS 

compliance, or compliance with possible future permitting requirements, as a BART requirement.

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, water users, and others. In their 

opinions, the capital expense (CAPEX) and associated operating expense (OPEX) increases 

associated with SCR would represent a significant change to the cost structure of NGS. Several NGS

 

5 In SRP’s Notes to the Combined Financial Statements, April 30, 2010 and 2009, SRP states, “The LNB/SOFA 

equipment has been installed on two units and the third unit will be completed in early 2011. The total cost 

for this project is $45 million, of which the District's share will be $9.8 million.” The $45 million cost 

described by SRP is assumed to better represent actual final cost than projections made in previous filings, 

including SRP’s July 29, 2008 letter to EPA regarding “Best Available Retrofit Technology (BART) Analysis -

Cost Information Navajo Generating Station” which indicated then that the original $30 million estimate was 

being revised to $12 million per unit, or $42 million. The model utilizes that $45 million cost in its

consideration of the BAU case economics.

6 David Modeer, General Manager, CAWCD, to Colleen McKaughan, EPA Region IX, December 18, 2009

7 “BART SCR and Baghouse Capital Cost Estimate Report”, Sargent & Lundy” , SL-010214, Revision D, August 

17, 2010
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stakeholders have filed comments regarding their concern that the large CAPEX and incremental 

OPEX for SCR would, at a minimum, substantially raise electricity and water rates for regional retail 

consumers and, at worst, weigh heavily on a potential decision to close the plant. Many 

commenters believe that the economic impacts of NGS closing down would be especially painful to 

Native American communities whose revenues are closely tied to the plant through a combination 

of royalties, leases, and employment. 

The impact on the Navajo Nation and particularly the Hopi Tribe was a central focus of an economic 

analysis performed (under contract with the Hopi Tribe) by the consulting firm ICF International8. 

Noting the economic importance of NGS to the Navajo and Hopi communities, ICF addressed the 

question of whether mandating SCR investment at the NGS units would undermine the power 

plant’s economic viability. ICF employed their internal power cost model, combined with a host of 

assumptions regarding future fuel prices, power prices, and capital investment cost, etc., to 

estimate the impact of SCR on the plant’s future competitiveness. Also included in the modeling 

were implied values for carbon allowance and carbon emission offsets. The study’s conclusion was

that the NGS plant was at risk for shutdown if natural gas prices were at or below $5.6/MMBtu 

(2008$). Additionally, the risk for shutdown was assumed heightened due to the combination of 

other potential future environmental controls (carbon and mercury) coupled with the forecasted 

low natural gas values.

Incremental CAPEX and OPEX at any power plant increases the overall cost of production. Cost

recovery of incremental generation expense will understandably drive higher wholesale prices and 

regulated utility rates. Clearly any incremental CAPEX or OPEX at NGS as a result of SCR investment 

will contribute to higher costs of production, which could be reasonably expected to result in higher 

prices to ultimate consumers of both power (for those buying electricity from NGS) and those 

buying water from the CAWCD – for whom NGS is effectively its exclusive source of power for 

Central Arizona Project operations (“CAP”) operations. What isn’t as clear, however, is how a 

higher cost of production due to SCR investment would compare with an alternative of replacing all 

NGS-generated energy with wholesale market purchases. Many stakeholders suggest that the 

relatively high incremental cost of SCR would precipitate a shutdown of NGS, after which the energy 

needs previously filled by NGS-generated power would be replaced by market energy purchases 

 

8

Letter from L. Shingoitewa, Chairman, Hopi Tribal Council to J. Blumenfeld, EPA Region IX, March 1, 2010, 

referencing the ICF International report “Analysis of Economic Impacts on the Hopi Tribe and Navajo Nation 

of a Stringent NOx BART Decision for the Navajo Generating Station”. 
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(“Market” case). Thus, quantifying the cost differences between the BAU case, the SCR case, and 

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

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

long-term economic life of NGS, many stakeholders voiced a concern that BART for NOx 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 this assessment were as follows. The first, to develop a quantitative 

assessment of the performance of a limited set of emissions controls cases and a comparison 

between those cases – specifically in terms of how each scenario may impact the cost of power in 

future years from NGS and an initial assessment of the impact to CAWCD’s water rates. In each of 

those scenarios NGS was assumed to remain in operation for at least 20 years after the last of the 

three NGS units were retrofitted with SCR in 2018.

9 Also for comparative purposes, low, mid, and 

high trend market energy price scenarios were developed in order to estimate the replacement 

wholesale power costs that may occur if NGS generation were instead purchased from the market. 

The model assumes that market purchases would be phased in over time, starting with wholesale 

power acquisitions to make up for the shutdown of Unit 2 at the end of 2016, followed by shutdown 

of Unit 1 at year end 2017, and finally Unit 3 at year end 2018. The affordability model returns net 

present values (“NPVs”) for a 25-year period starting in 2012 and ending in 2036.

The remainder of this document describes the modeling of SCR and SNCR cost implications, how 

they may impact the long-term cost of power from NGS and water delivered by CAWCD. Later on, 

this report addresses a set of additional factors that, although not analyzed through modeling for 

purposes of this report, are likely to impact the decision processes of the plant owners and 

shareholders, as well as their local utility regulators.

 

9

For the purposes of this analysis, we assumed: (1) EPA would issue a final rulemaking in 2013 with a 

compliance date by 2018, and (2) the owners of NGS would elect to install controls on one unit per year to 

meet the 2018 compliance date.
EPA Contract No. EP-D-10-096

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Affordability Modeling Methodology & Case Analysis

The modeling employed to estimate the cost impacts of SCR and SNCR as well as market price cases

consists of the following six cases (one existing plant case, two retrofit cases, and three market 

cases). A summary of the cases and assumptions included in this report follows in Table 1 on the 

following page:

Table 1

Case Type Affordability Modeling Assumptions

Capital Cases

Notes for Capital Cases: 

 Historical reported OPEX is escalated at rate of inflation, and included in all capital cases

 Incremental capital for SCR cases was depreciated on a Straight Line for plant in service

 The SCR and SNCR retrofit installation schedule was modeled as 2016, 2017, then 2018 respectively

 For sensitivity testing, SCR was also treated with accelerated depreciation10

 CAPEX includes capital cost recovery based on individual plant owner metrics, allocated according to 

ownership shares. Public utility capital cost recovery rates are assumed to approximate the utility’s

bonding / borrowing cost without margins or return on investment. This approach is applied to BOR’s 

share of NGS as well as to those shares owned by SRP and LADWP.

 Pre-tax rate of return applied to investor owned utility shares of existing plant-in-service & applicable 

incremental capital

 Assumed increase in plant site lease cost of $15 million annually beginning 2020

Business As Usual

(BAU)

 Plant as it was operated and reported in 2011 

 OPEX escalated from 2011 values at assumed rate of inflation of 3%

 $0.00 incremental capital

 Plant-in-service depreciated straight line on estimated plant in service 

SCR or SNCR  BAU + CAPEX and OPEX for SCR or SNCR

 

10 Accelerated depreciation applied per interpretation of 26 U.S.C. § 169: US Code - Section 169: Amortization 

of Pollution Control Facilities
EPA Contract No. EP-D-10-096

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Market Price Cases11

Notes for All Market Price Cases:

 Market power costs are modeled to be phased in as NGS units are assumed to be shutdown. 

Shutdowns are modeled to occur the year after a scheduled install year under the assumption that the 

unit would go off line if it hasn’t retrofit to SCR by the end of the targeted installation year. Market 

price cases include BAU costs in those years where a unit continues to operate until the year it is 

assumed to be shutdown

 Forward Palo Verde index prices beginning in 2016 based on November 27, 2012 market close prices 

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

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

down the plant 

Low, Mid and High 

Trend Market

Starting in 2017, yearly changes in price for 2017 to 2036 were calculated based 

on year to year percentage changes from 2017-2036 for the EIA12 Low, Reference 

(for Mid), and High Macroeconomic Cases

A potential SCR investment decision, as well as any economic choice to shutter the plant rather than 

install SCR, will be potentially long-lived decisions; 20 years or longer. Each will result in a unique 

cost profile and incremental cost difference relative to the BAU over the analysis period. 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 NGS ceases operations. As stated above, 

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

potentially cause, or greatly contribute to, a decision to close the plant. Commenters conclude that 

the loss of NGS as a resource to serve retail customers would require the owning electric utilities to 

buy capacity and energy from the wholesale power market to replace their former position in NGS.

The most applicable market price at which the NGS participants could find replacement capacity 

and energy would be based on the most liquid pricing point in the desert southwest – namely, the 

Palo Verde index. For that reason, the Market cases assume that the plant shuts down and the

utilities acquire replacement energy from the market at Palo Verde prices starting in the year the 

first unit is taken out of service, followed by additional unit shutdowns in accordance with the 

installation scenario described above. For purposes of modeling the market cases, the model 

assumes an eventual full shutdown of all units and assumes that 100% of the historical net 

 

11 The Market Price Case forward curves utilized in this assessment are identical in methodology to the 

curves utilized for the same purposes in a another assessment and report prepared by Energy Strategies for 

E C/R Incorporated regarding Four Corners Power Plant and its unique market and economic circumstances 

12 “Annual Energy Outlook, May 2011”, U.S. Energy Information Administration,
EPA Contract No. EP-D-10-096

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Energy Strategies, LLC 19

generation is replaced with market purchases of forward, firm energy priced at the Palo Verde. The

cost of replacement power, therefore, attempts to estimate the cost of replacing an equivalent 

volume of wholesale power as would be produced by NGS in the BAU and emissions control retrofit 

cases, where those cases also attempt to account for cost recovery of all generator costs (fixed and 

variable). Similarly, the Market cases assume that market providers are also receiving full cost 

recovery and not just variable expense recovery for the power they sell to NGS participants. The 

Palo Verde index forward prices utilized in the Market cases are firm prices which assume capacity 

as well as energy. 

Even though the assessment utilized forward price estimates ranging from low to high trend cases, 

for purposes of comparing relative performance between BAU, SCR, SNCR and market, this report 

discusses business as usual and the retrofit cases in relation only to the low market price forecast. 

This approach was utilized in order to represent a conservative outlook on future power costs 

especially as they may or may not perform well economically against the BAU and emissions 

controls retrofit case.

It was determined that a total cost approach, founded upon an estimated BAU case where the plant 

operates “as is” into the future (including cost escalation), would be the proper means to model the 

full cost of generation with the additional cost of SCR and SNCR. The model includes existing costs

of the historical plant through 201113 – projected forward 25 years from 2012 to 2036. For each 

case except the market cases, the model layers in the incremental CAPEX and OPEX as those 

investments occur according to the assumed retrofit schedule below14. The respective year of 

installation for SCR or SNCR for each unit is represented in Table 2 below:

Table 2

Year of Emissions Control Installation by Schedule Scenario

Unit No. Installation Scenario

Unit 2 2016

Unit 1 2017

Unit 3 2018

 

13 U.S. EIA Form 923 information was utilized for operating expenses data

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

historical major maintenance cycles for NGS
EPA Contract No. EP-D-10-096

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The BAU case includes cost recovery for the plant as it was reported for 2011 by the plant operator. 

The CAPEX and OPEX for the SCR and SNCR cases are additive to the BAU so that a revenue 

requirement for the full plant can be calculated in each of 25 years, then discounted back to 2012. 

The output of the model is a set of discounted cash flows that allows comparison between 25-year 

NPVs for each case analyzed. 

The Model and Assumptions

The discounted cash flow model 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 plant-in-service. In the case 

of the NGS model, only the power generation costs are included since the analysis is focused at the 

wholesale cost level. Moreover, the NGS model accommodates differences in capital cost recovery 

in recognition that the plant is owned by a range of entities.

This form of modeling requires both historical and projected cost data utilizing a host of 

assumptions ranging from discount factors to inflation rates to depreciation schedules to power 

market prices. The set of assumptions described below are provided in greater detail in the 

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

electronic model transmitted with this report, are urged to review the assumptions and directions

provided in the model.

Discounted Cash Flows

The spreadsheet model produces discounted cash flows for BAU, SCR, SNCR and market cases for 

the assumed installation scenario. Operating expense on a per megawatt hour basis is assumed to 

be equal for each plant participant, and is therefore allocated by the number of megawatt hours 

produced according to each participant’s ownership share. Capital expense however is treated 

differently in recognition of the different owners’ capital recovery rates. In order to accommodate 

differences between owners, the model includes discounted cash flows for each individual owner

based upon metrics specific to that entity. The following Table 3 illustrates the owner-specific data 
EPA Contract No. EP-D-10-096

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utilized for each specific cash flow15. The investor owned utilities (IOUs) referenced in Table 3 

include Arizona Public Service, NV Energy (Nevada Power Company), and Tucson Electric Power. 

Table 3

Modeled Finance/Capital Recovery Rates by NGS Owner

Each owner’s share of the plant is represented in the second column in the table above. LADWP 

currently owns 21% of NGS; however that share will be transferred given public statements made 

by Los Angeles. The disposition of the LADWP share is further discussed below. Each owner’s share 

is assigned a capital recovery rate for existing plant and incremental plant. Existing plant capital 

recovery applies to the BAU plant as of 2011 while incremental capital recovery applies to the SCR 

retrofit case.

For purposes of discounted cash flow modeling, the discount rate is assumed to be 7% for all 

participants. Discounting cash flows were run for each ownership scenario with the exception of 

LADWP in recognition of LADWP's plan to divest its share of NGS. Annual BOR-specific incremental 

costs were utilized to estimate CAWCD water rate impacts. Similarly, annual SRP-specific 

incremental costs were utilized to estimate SRP electric rate impacts.

On a full plant basis, due to the fact that LADWP will not continue to own its share of NGS in the 

future, the model produces two full plant cash flow scenarios, one which combines LADWP's share 

as if that share continued as a publicly owned utility ("POU”), and a second scenario where the 

LADWP share is assumed to be acquired by an investor owned utility ("IOU"). In those scenarios, 

 

15 The BOR capital recovery rate for existing plant is based upon a weighted average recovery rate as 

identified in the Arizona Water Settlements Act as 3.342% on 73% of CAP assets and 0% on the balance. 

Capital recovery rates for investor owned utilities (IOUs) are pretax rate to return based upon a weighted 

average of actual investor-owned utility debt/equity ratios applied against weighted average approved ROEs 

and weighted average rates of interest on debt in capital structure as reported by each utility in 2011. SRP 

and LADWP capital recovery rates are assumed to equal 7%, consistent with statements made by SRP on the 

record.

Existing 

Plant

Increm. 

Plant

BOR Share Only 24% 7.00% 2.4% 6.5%

SRP Only 22% 7.00% 7.0% 7.0%

IOUs Only 33% 7.00% 14.9% 14.9%

LADWP 21% 7.00% 7.0% 7.0%

Cash Flow Case

Share 

of 

Plant

Discount 

Rate

Capital Recovery 

Rates
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Energy Strategies, LLC 22

the LADWP share is assumed to take on capital recovery characteristics of either a POU (SRP in this 

case) or the IOUs.

Capital and Operating Cost Inputs

Table 4 below illustrates the capital and operating expenses assumed for each unit at NGS. 

Table 4

CAPEX & OPEX Assumptions16

For modeling purposes, the costs above in 2012 dollars were adjusted between 2012 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 modeling results include six specific cases (BAU, SCR, SNCR, Market 

Low, Market Mid, and Market High). In addition, a discounted cash flow for the SCR case using both 

straight-line and accelerated depreciation was conducted17. The accelerated depreciation impacts 

are discussed in the “Sensitivity Analyses” section of this report. The BAU and SNCR cases are only

depreciated on a straight-line basis. The wholesale price portion of the market cases do not receive 

 

16 CAPEX and OPEX estimates were provided by EPA

17 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. 

Unit No.

Capital

Expense

Operating 

Expense

1 $ 137,527,000 $ 3,982,000

2 $ 188,585,000 $ 3,982,000

3 $ 170,294,000 $ 3,982,000

Total $ 496,406,000 $ 11,946,000

Capital & Operating Expense Assumptions

2012$
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any depreciation treatment since no capital assets are involved, however, straight-line depreciation 

on the BAU plant portion of the market cases is applied between 2012 and the year each unit is 

assumed to be shutdown in under that installation scenario. 

The following pages refer to tables and graphs and provide discussion regarding the model and its 

output, under straight-line depreciation, relative to the comparative cases and the installation 

scenarios.

Modeling Outcomes

The following discussion includes the summary outputs of the modeling. Comparison between case 

outcomes is explained at the end of this section.

2016/2017/2018 Installation Scenario

Table 5 illustrates the BAU net present value for the BOR, SRP and IOU ownership cash flows. Table

5 also illustrates the incremental NPV between the owner-specific BAU case and the SCR and low 

market cases. Finally, the following table compares the BAU, SNCR and SCR 2018 total power cost 

for each cash flow for the year 2018. For this installation scenario, 2018 represents the highest cost 

year because in 2018 the last of three units would have been retrofitted. After that time, capital 

depreciation reduces plant in service and thereby the total power cost impact of the retrofit.

Table 5

Cash Flow Case NPVs, Incremental NPVs, and

Power Production Cost by Case in High Cost Year for 2016/17/18 Installation Schedule Scenario

NPV $ millions

BAU SNCR SCR

Low 

Market BAU SNCR SCR

BOR Share Only $ 1,826 $ 60 $ 136 $ 151 $ 32.69 $ 34.35 $ 37.34

SRP Only $ 1,728 $ 54 $ 125 $ 87 $ 34.91 $ 36.58 $ 39.72

IOUs Only $ 2,796 $ 88 $ 265 $ 78 $ 38.78 $ 40.65 $ 46.14

Cash Flow Case

2018 Total Cost of Power

by Cash Flow Case 

($/MWh)

Incremental NPV 2012-2036

Case Vs. BAU

($ million)
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As will be the case throughout this discussion of discounted cash flow comparisons, the highest 

incremental cost impact as a result of the retrofits results from the IOUs Only cash flow case. This 

result is due to the higher capital recovery rate assigned under the assumptions described above. A 

comparison of incremental NPV for SCR and low market versus BAU indicates that the incremental

cost of SCR is lower than the low market cost in the BOR case. Incremental NPV for SCR is higher 

than low market in both the SRP and IOU cases.

The assessment not only compares owner-specific cash flows but also attempts to quantify the total 

plant impact of SCR, SNCR or market purchases compared to BAU. The following two tables 

combine net present values on a weighted average basis from each owner-specific cash flow. To 

accommodate the eventual transfer of LADWP’s share of NGS, the first table below assumes that 

another publicly owned utility acquires the LADWP share of NGS, while the second table below 

assumes that an investor owned utility acquires the LADWP share of NGS.

Both of these tables report out the net present value of the combined BAU, SNCR and SCR cases and 

low market net present values. Similar to the table above, the combined tables also report out the 

incremental cost difference between SCR and low market versus the BAU. In addition, the tables

indicate the estimate of BAU, SNCR and SCR cases 2018 total power costs, as well as the 2018

incremental dollar per megawatt hour cost. The percentage difference between 2018 BAU and 2018

SCR and SNCR power costs are also reported.

Table 6

25 Year NPV by Case for Total Plant (LADWP Share to POU): SCR Installation in 2016/17/18

NPV $ millions

BAU SNCR SCR

Low 

Market BAU SNCR SCR SNCR SCR

$ 7,766 $ 8,021 $ 8,414 $ 8,439 $ 35.64 $ 37.37 $ 41.25 $ 1.73 $ 5.60

Total Plant w DWP Share to POU $ 255 $ 648 $ 673 4.9% 15.7%

Total Plant w DWP 

Share to POU

NPV by Case

 ($ million)

SCR NPV

Vs. BAU NPV

($ million)

2018 Incremental 

$/MWh for Total 

Plant Cost

 % Greater than BAU 

>> 

2018 Total Cost of Power

by Cash Flow Case 

($/MWh)
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Table 7

25 Year NPV by Case for Total Plant (LADWP Share to IOU): SCR Installation in 2016/17/18

A comparison of Tables 6 and 7 illustrates the differences in net present value between BAU, SNCR, 

SCR, and low market cases for both ownership scenarios relative to disposition of the LADWP share 

of NGS. As indicated, the NPV for SCR in the LADWP to POU case is lower than the NPV of the low 

market case. However, the IOU-Only case produces a higher NPV for SCR than for low market.

Discussion of Modeling Results 

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

interactions, and assumptions. The use and interpretation of the output of the model, 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 model those 

variables and assumptions that are particularly critical as they may impact model outcomes. 

Capital Cost Considerations

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

SCR and SNCR retrofit cases. The model treats cost recovery for capital as the combination of 

depreciation expense and rate of return on rate base (in this case, value representing a blend of 

capital recovery factors for both investor owned and public utilities). This is consistent with a 

revenue requirements modeling approach as described above. Several points about capital are 

worthy 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. This value is derived by a set of calculations that assumes 

NPV $ millions

BAU SNCR SCR

Low 

Market BAU SNCR SCR SNCR SCR

$ 7,915 $ 8,174 $ 8,613 $ 8,523 $ 36.46 $ 38.24 $ 42.61 $ 1.78 $ 6.15

Total Plant w DWP Share to IOU $ 259 $ 698 $ 608 4.9% 16.9%

Total Plant w DWP 

Share to IOU

NPV by Case

 ($ million)

SCR NPV

Vs. BAU NPV

($ million)

2018 Incremental 

$/MWh for Total 

Plant Cost

 % Greater than BAU 

>> 

2018 Total Cost of Power

by Cash Flow Case 

($/MWh)
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original plant in service costs (from EIA 923, FERC F-1 filings, and other owner-published 

cost filings) and straight line depreciation ending in 2036 for a series of plant 

improvements from 1974 to 2011. The model’s rate base calculation for the BAU case

yields approximately $1.084 billion in 2011, the first year in the discounted cash flow. 

2. A critical assumption about the BAU case used in order to isolate the incremental impact of 

the retrofit cases 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. 

3. The capital cost estimates for the retrofit cases were escalated by a rate of 3% per year

from the year the cost was estimated to their year of installation. Earlier installation of 

retrofits than scheduled could produce lower installed costs as a result of avoiding inflation 

in the model; however, a portion of that lower cost would be consumed by the increase in 

the time value of the money expended. 

4. For purposes of imparting a cost for capital invested, the model uses a capital recovery rate 

for existing and new capital specific to each owner of the plant. This capital recovery is 

intended to represent the cost of debt on capital equipment and a rate of return on rate base 

equipment, where applicable for investor-owned utilities. The revenue requirements 

approach entails accounting for all the costs a utility would charge a customer in its rates in 

order to repay capital and debt on rate based equipment (including all existing equipment 

prior to retrofits), as well as the utilities regulated rate of return on that rate base (if that 

applies depending on the type of utility involved). In order to produce relevant incremental 

cost data for use in retail electricity rate and water cost impact analyses for specific 

participants, the model uses a utility revenue requirements approach to cost recovery

tailored to address each participant’s unique cost recovery circumstances, in recognition of 

the fact that NGS is owned by a diverse set of investor-owned and public utilities, as well as

a U.S. governmental agency. 

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

The modeling addresses cost at the wholesale level and not at the retail level, thus only generation 

costs from NGS are within this analysis. This distinction is important to note because retail 
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electricity consumers receiving power through their electric utility from power sourced in part 

from NGS 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 NGS would require wholesale market purchases to replace the 

absence of NGS supply. However, because it is known to be of interest to various stakeholders, the 

implications of SCR to retail electricity (and water) rates are discussed.

Market Power Cases

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

between investment cases and a market price scenario that assumes a plant shut down. 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 remain current. The forecast approach utilized in the model starts with recently 

published Palo Verde market prices for the calendar year 2016. Beyond that date the 

market is not very liquid and considered less ‘reliable’ as an indicator of future price. 

Therefore, beyond 2016 the model uses published EIA data to draw price curves for low, 

mid, and high market price cases whose origin is the actual PV price for 2016. Chart 1 below 

illustrates the point by building the low, mid and high price forecasts for each relative 

year18. 

 

18 The same methodological approach was utilized in a previously completed analysis conducted under the 

same EPA Work Authorization with respect to economic impacts for BART determination at Four Corners 

Power Plant.
EPA Contract No. EP-D-10-096

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Chart 1

With respect to the 2016 – 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.19 As 

shown above, the difference between the low and high trend prices grows modestly over 

time as would be expected due to uncertainty of future periods. 

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 2012 to 2016 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 

 

19 2011 US EIA Annual Energy Outlook. http://www.eia.gov/oiaf/aeo/overview.html

$20.00 

$25.00 

$30.00 

$35.00 

$40.00 

$45.00 

$50.00 

$55.00 

2012201320142015201620172018201920202021202220232024202520262027202820292030203120322033203420352036

$ per MWh

Projected Palo Verde Index Forward Prices

Low Trend

$/MWh

Mid Trend

$/MWh

High Trend

$/MWh
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Coordinating Council / Rocky Mountain Power Area and Arizona-New Mexico-Southern 

Nevada Power Area are illustrated in Chart 2 below20. 

Chart 2

2. As recently as 2008, the Palo Verde daily average price was approximately $63.50/MWh. 

Notice in the Projected Palo Verde Forward Prices graph (Chart 1) 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 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 NGS begins to 

shutter units in 2016, and no longer operates a single unit by 2019, the market prices cases 

do not include any assumptions regarding the cost of shutting down the power plant. 

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 

 

20 A similarly sourced set of values were referenced in a previously completed analysis conducted under the 

same EPA Work Authorization with respect to economic impacts for BART determination at Four Corners 

Power Plant

$3.00

$3.50

$4.00

$4.50

$5.00

$5.50

$6.00

$6.50

$7.00

$7.50

$8.00 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 - Electric Power Projections for EMM Region, Western Electricity 

Coordinating Council / Southwest, EIA AEO 2011 (2009$)
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modeling the transmission is that the plant owners themselves are transmission owners 

and it is reasonable to assume that some portion of power 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. 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 longlived high voltage transmission facilities. It is reasonable to expect that utilities will not be 

willing to have shareholders absorb the full cost of losses related to stranded cost and 

would therefore seek to pass costs to ratepayers. 

In summary, the prices utilized in the model for all market cases are believed to be very 

conservative in that they account only for wholesale purchase costs and do not attempt to estimate 

any additional transmission or other costs that may be related to a power purchase transaction. 

Moreover, the market cases do not include any estimated costs for plant decommissioning, 

environmental abatement, etc. which could be very likely in the event of a plant shutdown.

SCR Cost Impacts on Retail Electricity Rates and Water Prices

NGS is currently owned by one U.S. government agency, two public utilities, and three investor

utilities. Table 8 below illustrates the ownership percentages for NGS.

Table 8

NGS Ownership

Owner & Percent Share

United States Government (BOR) 24%

Salt River Project (SRP) 22%

L.A. Dept Water & Power (LADWP) 21%

Pinnacle West Capital Corp (APS) 14%

NV Energy (NV Energy) 11%

UniSource Energy Corp (TEP) 8%

The largest share of NGS is owned by the U.S. Bureau of Reclamation (BOR). Unlike the load served 

by NGS’ electric utility owners, BOR’s share of NGS power goes to operate the CAP. CAP’s annual 

requirement for energy pumping is 2,800,000 MWh while NGS’ total annual energy production is 
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approximately 17,400,000 MWh21. Based on BOR’s 24% share of NGS, 2,800,000 MWh represents 

66% of BOR’s share of produced energy. The balance of approximately 1,400,000 MWh, therefore,

represents energy in excess of CAP pumping requirements that is sold to market. 

Although power costs at the retail level for CAP operations are not central to this assessment, the 

cost of power generation resulting from increased costs at NGS, and potential impact to the value of 

excess power sales, are important considerations for CAWCD. As indicated above, when BOR’s 

share of NGS output exceeds CAWCD’s requirements, BOR/CAWCD sells excess power in the 

market, the proceeds of which contribute to the Lower Colorado Basin Development Fund 

(“Fund”)22. If all other factors remained static then the “margin” that CAWCD could extract from 

excess power sales on behalf of the Fund would serve as an offset to increasing cost from NGS–

whether as a result of an SCR investment or other reasons. 

The future economic impact to CAP tribal water users who benefit from the value of excess power 

sales will hinge on many different variables, including the market price of power as it may influence 

contracted power sales prices, NGS’ cost of production, NGS’ power production volumes, CAP 

pumping requirements, and others.

Retail Electricity Rate Impacts

The second largest owners of NGS by share are SRP and LADWP – both of whom serve retail 

consumers in their certificated utility territories. As previously discussed, LADWP will be divesting 

its share of NGS. Therefore, this assessment focused on estimating the impact of SCR costs on the 

retail rates of SRP through a series of calculations based on SRP’s share of SCR cost, as illustrated in 

the following Table 9.

 

21 David Modeer, General Manager, CAWCD, to Colleen McKaughan, EPA Region IX , December 18, 2009

22 Modeer, December 18, 2009
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Table 9

Salt River Project Electricity Rates: Impact of Emissions Control Scenarios

Assumptions (Sources: 2011 EIA 923, FERC F-1, & Audited Financial Statements)

2011 SRP Retail Revenues $ 2,416,903,000

2011 SRP Retail Sales Volumes 26,097,780,000 kWh

NGS 2011 Net Generation 16,951,775,000 kWh

SRP Share of NGS Net Generation 21.7%

SRP Share of NGS 2011 Net Generation 3,678,535,175 kWh

2011 Average Retail Rate $ 0.09261 kWh

Escalation Factors (User defined)

Revenue Escalation 1.5% Escalates Retail Revenues each year below from 2011 reported revenues

Sales Escalation 1.5% Escalates Retail Sales (kWh) each year below from 2011 reported volumes

SCR - 2016/2017/2018 Installation

Cost Impacts 2014 2015 2016 2017 2018

NGS Incremental Production Cost ($/kWh) $ - $ - $ 0.00177 $ 0.00314 $ 0.00480

Utility Share of Incremental $ $ - $ - $ 6,520,804 $ 11,556,747 $ 17,666,823

Rate Impacts 

Estimated Retail Revenues $ 2,527,303,202 $ 2,565,212,750 $ 2,603,690,941 $ 2,642,746,305 $ 2,682,387,500

Utility's Share of Emissions Measure Incremental Cost $ - $ - $ 6,520,804 $ 11,556,747 $ 17,666,823

Estimated Total Utility Retail Revenues $ 2,527,303,202 $ 2,565,212,750 $ 2,610,211,745 $ 2,654,303,052 $ 2,700,054,323

Estimated Retail Sales (kWh) 27,289,884,182 27,699,232,444 28,114,720,931 28,536,441,745 28,964,488,371

Estimated Retail Rate w/Emissions Measure ($/kWh) $ 0.09261 $ 0.09261 $ 0.09284 $ 0.09301 $ 0.09322

Est. Retail Rate Without Emissions Measure ($/kWh) $ 0.09261 $ 0.09261 $ 0.09261 $ 0.09261 $ 0.09261

Incremental Rate Impact of Emissions Measure ($/kWh) $ - $ - $ 0.00023 $ 0.00040 $ 0.00061

% Increase In Retail Rates due to Emissions Measure 0.000% 0.000% 0.250% 0.437% 0.659%

Comments

Analysis estimates the impact of SCR at NGS on the average utility retail rate by applying modeled incremental cost to historical & estimated retail revenues

The incremental NGS cost for each year coming from the Economic Analysis is in nominal dollars 

Assumes that between 2011 and 2014 rates are constant - thereafter revenues and sales grow equally, thereby not impacting average rates

Assumes that 100% of NGS incremental cost is passed on to utility's customers in utility's retail rates

0% escalation in either or both retail revenues or sales would be very unexpected. 1.5% growth in both categories each year is conservative & within range of historical results

Underlying Economic Analysis of NGS incremental cost does not include:

 Impacts to utility retail rates as a result of change in ownership at NGS

 Any life extending capital investment in NGS

 Any carbon-related cost or other emissions/environmental costs
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The incremental, non-discounted cost of power from NGS as a result of SCR begins in 2016. NGS 

power generation costs climb as more capital is deployed then gradually declines as the book value 

for ratemaking purposes slowly erodes. 

For purposes of articulating the potential for rate impacts to their management and customers, 

many utilities will focus on the highest cost year. The highest cost years are identified in the yellow 

highlighting in the table above. In general, the impact to SRP average retail electric rates is 

estimated to be less than one percent in 2018 scenario. 

The analysis utilized to create the previous table is based on the following assumptions:

 The incremental “Wholesale Cost” as listed above represents each year’s non-discounted, 

incremental cost resulting from SCR at NGS. The incremental cost peaks in 2018 when the 

third and final NGS unit is retrofitted. 

 2011 average retail rates equal the total retail sales revenue as reported in 2011. 

Subsequent year revenues ($) and sales (MWh) are each grown at 1.5% annually from 2011

reported volumes. The escalation of revenues and sales conservatively accounts for the 

rate impact dilution that could occur as other costs, besides just NGS, also increase over 

time.

 Average retail electricity rates were held constant between 2011 and 2014

As previously mentioned, one would expect that each utility would characterize the impact of SCR 

on their customers as a rate increase coinciding with the highest cost year – and not the average of 

multiple future years. Rate making experience has also shown that, for a variety of reasons, rates 

rarely decline over time. Thus, it would also be reasonable to expect the utilities to interpret SCR’s 

impact on retail rates to occur in the highest incremental cost year without acknowledgement that 

costs might decline going forward.
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CAWCD Water Pumping Rate Impacts

NGS stakeholders have expressed concern regarding the potential impact to retail power and water 

rates for downstream consumers. The following sections discuss estimated impacts to a limited set 

of retail power rates and water delivery rates.

The potential impact on CAWCD water rates as a result of the EPA’s BART determination at NGS is 

clearly a critical area of importance to CAP/CAWCD and all its municipal, industrial, agricultural,

and governmental water users. The model employed allowed for an initial assessment of how the 

increase in power costs may impact CAWCD water rates. 

CAWCD provided an estimate of SCR cost impacts on water rates in a filing to the EPA23. However, 

those estimates may not comport to some assumptions that are incorporated in the model. For 

instance, at the time of their filing in 2008, CAWCD provided an estimate of the water rate impact 

due to SCR that also included costs for installation of LNB/SOFA. For this project, LNB/SOFA is part 

of the BAU case and not an incremental cost. 

Secondly, it must be noted that in addition to the inclusion of LNB/SOFA costs in their water rate 

impact estimate, CAWCD was also operating under markedly higher capital cost assumptions at the 

time. The cost assumptions utilized by CAWCD in 2008 ($660M for SCR) are fully $120M higher 

than the most recent estimates from the owners. 

Finally, the Energy Rate 1 in CAWCD’s estimate was their projected 2010 rate ($49/AF). Based on 

CAWCD’s own filed “advisory” rates, all CAWCD water rates are set to increase in the coming 

several years. For that reason, the most appropriate water rate comparison is between the 

projected CAWCD rates in those years with and without SCR.

Additional Water Impact Analyses

In conjunction with the incremental power cost analysis and resulting CAWCD rate 

impact analysis discussed below, a secondary analysis was conducted regarding 

water cost impacts to municipal and industrial (M&I) as well as non-Indian 

agricultural (NIA) water users as a result of costs associated with SCR NOx

reduction investment. Those findings are referenced in the addendum at the end of 

this report entitled Water Cost Impacts. 

 

23 David Modeer, General Manager, CAWCD, to Colleen McKaughan, EPA Region IX, December 18, 2009
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The assessment assumes that incremental capital and operating expense as a result of SCR 

installation will be recovered through the CAP Energy Rate 1. As a component part of other 

published CAP rates, the Energy Rate, and any increases to it, will impact all user classes of CAP 

water including municipal and industrial as well as non-Indian agricultural users. The following 

Table 10 illustrates the annual estimated rate impacts for installation of SCR.
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Table 10

Water Rate Impacts of Incremental CAPEX & OPEX

CAP Energy Rate 1: Impact of Emissions Control Scenarios

Assumptions

Annual pumping (AF) 1,550,000

Annual pumping energy (MWh) 2,800,000

2014 2015 2016 2017 2018

$ 51.00 $ 56.00 $ 58.00 $ 58.00 $ 58.00

2014 2015 2016 2017 2018

Incremental Power Cost ($/MWh) $ - $ - $ 1.71 $ 3.04 $ 4.65

Incremental Water Cost ($/AF) $ - $ - $ 3.09 $ 5.49 $ 8.40

Resulting Energy 1 Rate ($/AF) $ 51.00 $ 56.00 $ 61.09 $ 63.49 $ 66.40

0.0% 0.0% 5.3% 9.5% 14.5%

CAP Energy Rate 1: Advisory Rates as 

approved by CAWCD June 2011

Pumping & energy consumption volumes as reported 

by CAWCD 12/18/2009 Letter to EPA

% Increase over Preliminary CAP Rates

ESTIMATED ENERGY 1 

RATE

SCR - 2016/2017/2018 Installation
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Table 10 illustrates Energy Rate 1 impacts as a result of SCR installation. As discussed above with 

respect to electricity rate impacts, the yellow-highlighted year represents the highest incremental 

cost period as a result of SCR investment. Under the 2016/2017/2018 installation schedule, the 

highest incremental cost year would be 2018 when the CAP Energy Rate 1 would increase $8.40 per 

acre foot, or 14.5% of the estimated 2018 rate. 

The following table contains CAWCD’s published estimates for Energy Rate 1 through 2016 as of 

June 2011. This table is helpful for interpreting the results in Table 11. Note that the 2016 advisory 

rate is held constant through 2021 when used for comparison purposes in the Table above.

Table 11

CAWCD Agricultural (Energy only) Rate Schedule (June 2011)

Comparison with Other Available Studies

The issue of how capital investment necessary to meet a BART requirement would affect power and 

CAP water rates has been addressed in other recent studies. Three particular studies of interest are 

the analyses undertaken by the National Renewable Energy Laboratory (Navajo Generating Station 

and Air Visibility Regulations: Alternatives and Impacts – January 2012) and two studies undertaken 

by the consulting firm Harvey Economics; one study on behalf of the Gila River Indian Community 

(Projected Impacts of EPA BART Implementation on the GRIC – revised edition, March 2012) and the 

other on behalf of Salt River Project (The Economic Impact of EPA Proposed BART Implementation at 

Navajo Generating Station – April 2012). Each study analyzed a variety of potential impacts under 

different BART scenarios; LNB/SOFA, SNCR, and SCR (SCR with baghouses was also included in the 

analyses even though baghouses are not under consideration by the EPA as a potential BART 

requirement). Additionally, each study estimated impacts to power and water costs should a 

substitution of market power for NGS power be necessary due to a plant shutdown. 

A comparison of the modeling conducted on behalf of EPA to efforts undertaken by NREL and 

Harvey Economics (HE) indicates that each study employed slightly different approaches to 

investigate the BART scenarios. Each study did incorporate the fundamental question of how the 

required capital investment at the NGS would impact the cost of power from the plant. As 

discussed elsewhere in this report, this assessment approached the question of potential impacts to 

Type Firm Provisional

Year 2011 2012 2013 2014 2015 2016

$/AF $ 53 $ 49 $ 50 $ 51 $ 56 $ 58

Advisory
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power and water costs by utilizing a discounted cash flow model. The study estimated the future 

revenue requirement of the NGS plant in light of the new capital investments associated with BART. 

This study used capital cost estimates for SCR that were based on EPA revisions to the capital costs 

estimates of Sargent and Lundy. Capital cost estimates for baghouses used similar estimates of 

Sargent and Lundy. The Sargent and Lundy cost data was also utilized in both the NREL and HE 

studies as baseline data. 

One area of difference between the models was the assumption regarding financing cost. In HE’s 

initial study for the Gila River Indian Community a 3.62% interest rate was employed, a value 

reported to be predicated on existing SRP bonds. In the second and more expansive HE study, the 

author employed a weighted average cost of capital of 6.2%, a figure representing the average cost 

of capital for all six NGS participating entities. NREL, on the other hand, used specific cost of capital 

numbers for each entity, ranging from 6.0% for LADWP to a high of 9.8% for SRP. For the BOR, 

NREL employed a 5.0% rate reflecting the cost of borrowing on CAWCD municipal revenue bonds. 

In comparison, the approach to modeling financing cost utilized in this assessment, similar to that 

taken by NREL, was to apply individual capital recovery rates for BOR, SRP and investor-owned 

utilities. 

NREL’s approach to estimating impacts on power and water rates centered on developing an 

assessment of how each BART scenario would impact the capital structure of each utility involved 

and how such incremental cost would be ‘rolled in’ to their base rates. NREL analyzed both changes 

in capital cost and production cost that resulted from the BART implementation. While production 

cost showed only a slight change, the additional capital cost resulted in measurable change to base 

rates. NREL used capital cost estimates for the various BART related technologies derived from two 

sources; as mentioned above, the 2010 Sargent and Lundy study and, secondly, a cost study 

undertaken by the National Park Service. The Sargent and Lundy study had projected an annual 

cost for SCR of $71.7 million while the NPS study forecasted an annual cost of $67.6 million. NREL 

used both of these estimates in their analysis, thereby creating a range of annual cost reflecting the 

two studies’ findings. Additionally, NREL noted that the impact of environmental upgrades would

differ between the investor-owned utilities engaged at NGS and the Bureau of Reclamation since the 

IOU’s diversified generation portfolios allowed the increase in capital cost to be somewhat 

‘absorbed’ across its entire cost of generation. Therefore the magnitude of rate impacts differed 

between the IOUs and the BOR. Thus, since the BOR would potentially internalize any capital cost 

increases into the cost of power used by CAWCD, its only customer, impact on water rates were 
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more pronounced. HE addressed the power rate impact on the ‘Arizona utilities’ (SRP, APS and 

TEP) as a group. 

The NREL study provided estimated rate impacts for each BART scenario. Capital cost was 

amortized over a 20 year time frame. The estimated annual increase in cost was then spread across 

the utility’s retail rates for all customers (approximated by applying the annual increase in cost to 

total retail sales). Under the SCR only scenario, NREL’s analysis indicated retail power rates would 

increase from as low as 0.2% (NV Energy) to as high as 0.6% (TEP and SRP). These values were 

compared with the estimated rate increase under a SCR with baghouses scenario which indicated 

rate increases ranging from as low of 0.5% for NV Energy to a high of 1.2% for TEP. Under a SNCR 

scenario with its lower overall capital cost, rate impacts were much smaller, ranging from a low of 

0.02% for NV Energy to a high of 0.06% for TEP. 

NREL performed a separate analysis for the Bureau of Reclamation. This was due to the BOR’s 

unique circumstance at NGS. Any incremental capital cost incurred impacts the BOR more so than 

it does the other entities who are NGS partners since CAP water is pumped almost exclusively by 

NGS power whereas the other owners have a portfolio of resources. For the BOR, a likely option 

would be to shift the increase in capital cost to the CAWCD, its only customer. Thus all cost 

increases absorbed by BOR would then be rolled into the power cost charged to the CAWCD. NREL 

addressed the estimated impact on BOR by focusing on likely changes in CAP water rates since 

changes in water rates would be a proxy for the change in power cost levied by BOR. 

NREL’s approach to modeling the specific BART scenarios and their impact on CAP water rates 

centered on establishing a ‘base case’ for comparative purposes. The base case was predicated upon 

the current/projected CAP rates as reflected in CAWCD’s ‘Final 2011/12 Rate Schedule Update 

(June 2, 2011).’ The NREL model incorporated the assumed incremental capital cost for BOR, a 20 

year amortization at 5%, a flat production cost at NGS of $30/MWh, and an inelastic demand for 

water by CAWCD clients. The BART-related increase in capital cost impacted the going forward 

charge levied by CAWCD. Since NREL chose to use a range of capital cost, the resulting impacts on 

CAP rates also were reported as ranges. For the SCR only scenario, it was estimated that the 

increase in the cost of power incurred by CAWCD would increase between $3.93 and $4.75 per 

MWh. Subsequently, this increase was estimated to result in a rise in the CAP energy rate of $7.10-

$8.58/AF, an increase of 13% to 16% in pumping rates. For the SCR plus baghouse scenario, the 

estimated increase in cost of power to CAWCD ranged between $8.61 and $9.43 per MWh. This, in 
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turn, was estimated to increase CAP energy rates between $15.55/AF and $17.03/AF, an increase 

ranging from 29 to 32%. 

NREL ran an additional estimation of CAP rate impacts under a scenario where NGS is shutdown. In 

this analysis, NREL utilized a range of wholesale market power prices reflecting replacement cost in 

light of the shutdown. The wholesale prices ranged from $32.44 per MWh in the low market case to 

$49.48 per MWh in the high market price scenario. The difference in wholesale cost resulted in a 

significant difference in the estimated impacts on CAP rates. The increase in power cost to CAWCD

as a result of replacing NGS power with market purchases was estimated to be 8% higher than 

power cost from NGS in the low market case and 64% higher in the high market case. Resulting 

changes in CAP energy rates also varied widely, estimated to be $4.39/AF or $35.16/AF. Obviously 

the assumption regarding the future wholesale market in the western grid and its market prices is 

an assumption of substantial sensitivity in estimating future impacts when the scenario is a NGS 

shutdown.

As mentioned above, the initial HE study focused on the economic impact to the GRIC arising from 

the added cost at NGS under the different BART scenarios. The study estimated that the impact on 

CAP rates from the incremental capital expenditure at NGS would be (at peak in 2020) 10.5% for 

SCR only and 20.4% for SCR plus baghouse. These numbers were compared to the NGS closure 

scenario which HE estimated would impact CAP rates by as much as 55%. Note that the estimated 

impacts for the SCR and SCR + baghouse cases are similar in magnitude to those derived in the 

NREL study. This is not surprising since both studies employed capital cost derived from the 

Sargent and Lundy study. 

The initial HE study employed a time frame from 2012-2044, assuming the current NGS lease 

would be extended for an additional 25 years, from 2019 to 2044. Similar to the other studies, the 

model included the assessment of direct cost impacts on the BOR share of NGS power and how 

those impacts would affect CAP water rates. Once the adjustment in CAP water rates were 

determined, those values were imported into the IMPLAN input/output model for determination of 

macro effects on employment, personal income and the value of commodity sales (in this case, 

agriculture produced and sold by the GRIC). A critical assumption contained within the analysis is 

the forecast by the GRIC of additional acreage to be put into production and subsequent increases 

in water demand necessary to meet this increase in agriculture cultivation over the study period. 

The forecasted increases in CAP rates were then applied to the expanded water requirements of the 
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GRIC. Thus, not only did the CAP water increase on an acre-foot basis, the total cost of water to the 

GRIC increased due to the substantial increase in the demand for water. 

The model indicated that the forecasted increase in CAP rates would have a direct impact on 

margins (profits) that were to be derived from the expanded agriculture production. The study 

estimated that margins would decrease over the 2012-2044 timeframe by roughly 4.7% under the 

SCR only scenario and 9.1% under the SCR plus baghouse scenario. Margins were estimated to 

decrease roughly 49% under the NGS closure scenario. Additionally, the increased CAP water rates 

were projected to have a detrimental effect on the LCBDF, thereby impacting negatively on the 

Tribe as well. Overall, both direct and indirect monetary effects on the GRIC were estimated to 

range from roughly $9 million for a LNB/SOFA scenario to as high as $930 million for SCR plus 

baghouses scenario. A NGS plant closure was estimated to create a monetary loss in the range of 

$2.3 billion. The analysis concluded that with the predicted decline in future margins, the GRIC 

would find it uneconomical to develop agricultural production to the level currently envisioned in 

their expansion plans and would suffer greater economic loss the more stringent the BART 

determination. The impact analysis for all scenarios in this study extended from 2012 to 2044.

The second HE study (on behalf of SRP) replicated the aforementioned analysis on CAP water rates 

and economic impacts but expanded the economic impact analysis to include the estimated 

employment and income effects on the Native American tribes who are contractors for CAP water 

and the State of Arizona as a whole. As mentioned above, analysis was conducted on how the BART 

scenario would impact retail rates of Arizona based utilities. Like the NREL study, capital costs 

were assumed to be amortized over a 20 year time horizon and operating cost reflected the NGS 

2010 values. Capital cost of the environmental upgrades utilized the Sargent and Lundy 2010 data. 

The impact analysis for all scenarios in this study extended from 2012 to 2044.

The HE study indentified capital cost and operational cost as key drivers of the model outcomes. 

HE developed estimates of increases in CAP rates under the different BART scenarios and imported 

these values into the IMPLAN model (similar to its initial study for GRIC). The IMPLAN model then 

provided estimated impacts to the key macro metrics of employment, income, sales, and tax 

revenue. (As noted below, this ‘macro’ approach differed from the Arizona State University study 

by modeling specific BART scenarios vs. a macro assessment of the current economic contribution 

of NGS and the Kayenta Mine to the State of Arizona.) Similar to the conclusions reached in the 
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initial HE study, the analysis indicated that under more stringent BART scenarios requiring 

substantial capital investment, jobs, personal income, the economic values of goods/services, and 

taxes would all be negatively affected. Impacts on CAP water rates differed according to the BART 

scenario with rates rising (to their highest level) roughly only one percent under a LNB/SOFA 

scenario to 4.9% for SNCR, 10.5% with SCR and 20.4% with SCR plus baghouse. Should NGS close, 

the HE model estimated a 50% increase in water rates (peak year).

Both the NREL and the HE studies addressed the issue of how surplus sales from the NGS plant 

would be affected given an increase in power cost arising from the environmental upgrades. The 

issue is of importance due to the link between surplus sales revenue and funding of LCBDF. Critical 

to each study was the assumption regarding the future price of power on the wholesale market. 

NREL assumed a $30/MWh flat price for its analysis. HE assumed price recovery from today’s low 

market price ($31/MWh) to $50/MWh by 2025. Both studies acknowledged under the new SRP 

contract for surplus power from NGS, an annual flow into the fund of $25 million. 

The impact to the Fund was calculated in the HE study by subtracting the amount of power 

required for CAP pumping from the NGS steady production level (note: this included the significant 

expansion of required water for the GRIC agriculture development plan, 2012-2044), then valued 

the surplus power according to the assumed prevailing wholesale power price. The resulting value 

flowed into the Fund as an offset to the CAWCD annual repayment obligation ($55 million). The 

value of the surplus sales fell over the 32 year time frame due to the reduced amount of volume of 

power available for surplus sales not being offset by a requisite increase in the wholesale value of 

power. The estimated negative impact to the surplus revenue ranged from $6.9 million under 

LNB/SOFA to as high as $236.7 million under SCR with baghouses. Surplus power revenue was 

forecasted to be reduced by almost $2 billion under a NGS closure scenario. These reductions in the 

surplus power sales revenues resulted in an estimated cumulative loss to the Fund of roughly $4.2 

million under LNB/SOFA to $849 million under the NGS closure scenario. (Due to the CAWCD

repayment, the model indicated that the Fund did not begin to experience a negative value until 

2019 at which time the annual CAWCD repayment no longer offsets the loss from declining 

wholesale power revenues.) 

NREL approached the value of surplus power in a different manner. Recognizing that as of October 

1, 2011 under the new contractual arrangement governing the sale of excess power at NGS, surplus 

revenue will be a function of the market price at a given point in time and the production cost at 

NGS. NREL used a ‘back casting technique’ to estimate how the surplus sale contribution used to 
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offset the CAWCD financial obligation would vary under the new contractual arrangement. Note 

that unlike the HE approach which assumed a growing demand for CAP water and therefore more 

generation devoted to CAP related activities, the NREL model assumes a ‘steady state’ of surplus 

power available for the wholesale market (1.28 TWh per year). The back casting model estimated 

the contribution to the Fund from surplus sales under the new contractual arrangement. The 

model results indicated that under the contract, the surplus sales contributions to the Fund would 

have declined in 2009 and 2010 (this assumed a $30 per MWh cost of production at NGS and 

wholesale market values of $27 in 2009 and $30 in 2010). The modeling demonstrated the critical 

link to the wholesale market value, both in terms of contributions to offset the $55 million annual 

repayment obligation of CAWCD as well as contributions to the ‘second cascade’ of funds, those 

being surplus dollars in excess of the $55 million that are available to help meet O&M and other 

expenses incurred in CAP operations. 

The comparison of the NREL, HE and this study shows that each employed different methodological 

approaches to address a similar set of questions, those being the potential impact to power cost and 

CAP water rates resulting from the BART related capital expenditure at NGS. Interestingly, all three 

studies, despite the difference in approach, arrive at similar conclusions, at least in terms of the 

trend of outcomes. Each study basically indicates that the SCR plus baghouse scenario is roughly 

twice that of the SCR only scenario. Each study is also consistent by showing that the greatest 

impact will result from a closure of the NGS plant. 

Differences in the outcomes thus do not appear to be linked to a fundamental difference in 

modeling approach but more to the set of assumptions each author employed. Capital cost, future 

wholesale power prices, financing cost, and the volume of water necessary to meet agriculture 

production appear to be key assumptions that differ between studies. 
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Table 12 presents a summary of the key assumptions and resulting outcomes of each modeling 

approach. 

Table 12

Comparative Data & Outcomes

It should be noted that in addition to the studies discussed above is a study undertaken by the 

Seidman Research Institute at Arizona State University (Navajo Generating Station and Kayenta 

Mine: an Economic Impact Study). The study’s focus is a macroeconomic assessment of the NGS and 

its dedicated coal mine to the Arizona economy. Employing the REMI regional input/output model, 

the study measures the contributions of the power plant and mine to macro values such as 

employment, income, and tax revenue. It also provides an assessment of these impacts at the 

county specific level. The study differs from those previously discussed in that it concentrates on 

the overall value of NGS and the Kayenta Mine to the Arizona economy and did not attempt to 

measure changes in power and water rates resulting from new capital investment at the power 

EPA Harvey Economics NREL

2012-2036 2012-2044 2012-2032

20 years 20 years 20 years

Varied by entity 6.2%

(expanded study) Varied by entity

Operational 

Costs EIA Form 923 SRP data* $30/MWh (assumed)

Water

Rates

Rate Type

Emissions 

Control EPA Harvey Economics NREL

SCR 0.66% (SRP only)

Not provided. 

Only total cost incurred

2012-2044

0.2% - 0.6%

SCR + Baghouse 1.38% (SRP only)

Not provided. 

Only total cost incurred

2012-2044

0.5% - 1.2%

SCR 14.50% 10.50% 13 - 16%

SCR + Baghouse 30.50% 20.40% 29 - 32%

Estimated Impacts to Retail Electricity Rates and CAP Water Pumping Rates

Retail 

Electricity 

Rates

CAP Water 

Pumping

Data Sets

Time Frame of Analysis

Capital Amortization Period

Financing Costs

2011 CACWD Current & Projected 5 Yr Rates

* The Harvey Economics study did not identify a specific source of cost of production at the NGS but 

did identify SRP as a source of data
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station. Accordingly, it did not conduct different scenarios reflecting various BART related capital 

expenditures, but instead, took current prevailing data and provided estimations of future job, 

income and taxes that would be attributable to the plant and mine’s continued operation. 

The model output supports the argument that the plant and mine are substantial contributors to 

the state (and multiple counties) economic base. The study employed a time frame of 2011-2044. 

The model estimated that over this time horizon, approximately 113,000 full-time job years (one 

person working one full year) were attributable to the plant and mine’s operation. Of this number, 

nearly 33,000 were directly related to the two facilities. Additionally, Gross State Product was 

estimated to increase by roughly $20.5 billion and Real Personal Disposal Income by over $11 

billion during the time frame. The report’s conclusions suggest that, over the time frame noted, the 

operation of the plant and mine result in a significant macroeconomic benefit to the state.

Sensitivity Analyses

Affordability modeling by its nature utilizes many assumptions. The economic modeling underlying 

this report is no exception. The primary construction of the model, and indeed a significant portion 

of this report, addresses the sensitivity surrounding capital installation schedules. The following 

sections of the report discuss the influence that certain variables would have on the outcomes of 

the model and are offered here to better frame the findings already presented to this point.

Market Power Forecast

As previously described, the NPV's for BAU and the retrofit cases were compared against the NPV 

for replacement of NGS-generated power under the assumption that if NGS were shut down all 

power currently generated at the power plant would be sourced from the market at market prices. 

Market prices as also described above, were forecasted using a combination of forward Palo Verde 

prices adjusted over time according to EIA market projections for regional generation prices.

In order to test the sensitivity of the model outcomes to variations in market price projections 

specifically against the low market price projection, a sensitivity analysis was run by adjusting 

future market prices down by 10% and up by 20%. The sensitivities were run against the full plant 

model assuming that the LADWP share is transferred to a POU. All other variables in the model 

were held at their original values in order to determine the impact of just these variables alone. The 

outcomes of these sensitivity analyses are displayed in the following Table 13.
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Table 13

Market Power Price Sensitivity Outcomes

The first set of columns in Table 13 equate to the original modeled outcomes described previously 

in the report. Each case (BAU, SCR and low market) has a reported net present value. Below the 

NPV's of each case is a calculation of the difference between that case and BAU and the difference 

between low market and SCR. The table indicates that a 10% reduction in the power price forecast 

would result in low market returning a lower NPV than SCR. Note that under the baseline model the 

low market scenario has a 9% premium over BAU. In contrast, under a 10% reduction of market 

power prices, that premium is reduced to 2%.

This analysis also indicates that a 20% increase in market price would result in a 13% premium of 

low market over SCR. In comparison to the baseline model, where low market is 9% greater than 

BAU, a 20% increase in low market would increase the percentage difference to BAU to 23%. The 

relatively narrow range of market price forecast sensitivities tested yields similarly leveraged 

effects when comparing baseline and sensitivity adjusted market price forecasts to baseline SCR. 

The outcomes indicate that the comparative differences between BAU, SCR and low market are 

highly influenced by changes in market price forecast.

Lease Cost 

With respect to potential future lease costs, a sensitivity analysis was run to compare the baseline 

model to an outcome in which the assumed cost of the plant site lease is less than what was 

incorporated into the original model runs. APS has indicated that its lease payment to the Navajo 

Nation for use of the Four Corners Power Plant site increased roughly $7 million per year following 

($ million) BAU SCR 

 Low 

Market BAU SCR 

 Low 

Market BAU SCR 

 Low 

Market 

Case NPV $ 7,766 $ 8,414 $ 8,439 $ 7,766 $ 8,414 $ 7,897 $ 7,766 $ 8,414 $ 9,522

$ Difference to BAU $ - $ 648 $ 673 $ - $ 648 $ 131 $ - $ 648 $ 1,756

% Difference to BAU 0% 8% 9% 0% 8% 2% 0% 8% 23%

$ Difference to SCR $ - $ 24 $ - $ (517) $ - $ 1,108

% Difference to SCR 0% 0% 0% -6% 0% 13%

 Market Power Price Forecast

Baseline Model -10% 20%
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its recent lease contract negotiations24. While it is unclear at this time what, if any, incremental 

lease cost will result from the negotiations surrounding NGS, the increase experienced at FCPP 

provides some insight as to the incremental cost increase that can be expected at NGS. 

Table 14

Lease Cost Sensitivity Outcomes

For sensitivity modeling purposes, an assumption was made that plant site lease costs would 

increase only $5 million annually versus the $15 million per year assumption utilized in the base 

case model. , In each case, the incremental lease cost is assumed to begin in 2020 following the 

expiration of the current lease in 2019. The $5 million increase in the lease costs was run through 

the full plant case assuming that all other variables remained consistent with the baseline model. 

The results of the analysis are displayed in Table 14. As illustrated in the table, increases in annual 

lease costs of $5 million compared to the $15 million does not cause a shift in relative outcomes 

between the cases.

 

24 Testimony of Mark A. Schiavoni, On Behalf of Arizona Public Service Company, before the Arizona 

Corporation Commission, Docket No. E-01345A-10-0474, July 15, 2011, Page 327. 

($ million) BAU SCR 

 Low 

Market BAU SCR 

 Low 

Market 

Case NPV $ 7,766 $ 8,414 $ 8,439 $ 7,705 $ 8,354 $ 8,439

$ Difference to BAU $ - $ 648 $ 673 $ - $ 648 $ 733

% Difference to BAU 0% 8% 9% 0% 8% 10%

$ Difference to SCR $ - $ 24 $ - $ 85

% Difference to SCR 0% 0% 0% 1%

 $5 million

Annual Lease Cost ($ million)

Baseline Model
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Fuel OPEX 

Another variable identified by plant stakeholders as one which may experience change as a result of 

renegotiation (and assumedly the influence of market price factors) is fuel operating expense. For 

purposes of testing sensitivity to fuel OPEX, the baseline model was adjusted to reflect a range of 

fuel OPEX representing a 20% decrease and 20% increase in forecasted costs. Sensitivity testing for 

changes in fuel OPEX was applied to the baseline model starting in 2020, after the expiration of 

current royalty agreements relative to the mine supplying coal to NGS. The impact of those 

sensitivity analyses are presented in Table 15.

Table 15

Fuel OPEX Sensitivity Outcomes

Understandably, changes in fuel OPEX affect only the BAU and SCR cases. Also, changes in fuel 

OPEX do not impact the relative outcomes between BAU and SCR cases, since each of those cases is 

similarly affected by the change in fuel OPEX. The changes worthy of note, however, occur between 

BAU and low market as well as SCR and low market. As indicated above, a 20% reduction in 

projected fuel OPEX would significantly increase the cost difference between market and BAU as 

well as market and SCR. Conversely, a 20% increase in fuel OPEX would cause the low market NPV 

to be lower than the SCR NPV, albeit still higher than the BAU NPV.

($ million) BAU SCR 

 Low 

Market BAU SCR 

 Low 

Market BAU SCR 

 Low 

Market 

Case NPV $ 7,766 $ 8,414 $ 8,439 $ 7,339 $ 7,988 $ 8,439 $ 8,193 $ 8,841 $ 8,439

$ Difference to BAU $ - $ 648 $ 673 $ - $ 648 $ 1,099 $ - $ 648 $ 246

% Difference to BAU 0% 8% 9% 0% 9% 15% 0% 8% 3%

$ Difference to SCR $ - $ 24 $ - $ 451 $ - $ (402)

% Difference to SCR 0% 0% 0% 6% 0% -5%

Fuel OPEX (coal)

Baseline Model -20% 20%
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Accelerated Depreciation - Supplemental Modeling

The prior discussion focused on variables whose range could have material impacts on the model 

results. Although not technically a sensitivity, supplemental modeling was conducted in order to 

develop an estimate for the economic impact of accelerated depreciation in the LADWP share to an 

IOU case. The IOU case was selected for this individual sensitivity run due to the greater likelihood 

that an IOU would enact an accelerated depreciation schedule than would a POU. 

As illustrated in the table below, under a modeling approach utilizing accelerated depreciation25 on 

incremental SCR (but continuing straight-line depreciation on the underlying BAU case), the 25-

year NPV of SCR is $8.48 billion compared with $8.61 billion under straight-line. Between the two 

methods of depreciation, accelerated depreciation is estimated at the full plant level to return a 

$124 million lower 25 year NPV.

Table 16

Although it is unclear how many of the plant owners would elect to treat SCR-related costs under an 

accelerated depreciation approach, it appears that accelerated depreciation may yield a lower NPV 

in some cases.

 

25 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.

Straight-line Accelerated Difference

$ 8,613 $ 8,489 $ 124

NGS Full Plant - Cash Flow Comparison (25 Yr NPV)

Under Different Depreciation Methodology
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MATS – Supplemental Scenario Modeling

Estimated costs related to compliance with MATS via investment and operations of baghouse on 

each NGS unit were run through the model along with the SCR CAPEX and OPEX discussed in prior 

sections of this report. SCR and SNCR installation scenarios, baghouse capital and operating 

expenses26, and their respective year of installation, are identified in Table 17.

Table 17

Baghouse, SNCR & SCR CAPEX & OPEX Inputs

Table 17 lists CAPEX and OPEX in 2012 dollars. Capital and operating expenses were escalated by 

the standard rate of inflation in the model from 2012 to the year of their installation. The sensitivity 

analysis was based on the 2016/2017/2018 SCR installation schedule scenario. It should be noted, 

however, that the year of baghouse and the retrofits for each NGS unit are not in alignment. 

Specifically, baghouse installations are modeled to occur on NGS units 2, 1, and then 3, in that order 

in successive beginning in 2015. As previously defined, the retrofit installations occur on units 2, 1 

and then 3 in that order in successive year beginning in 2016. 

Baghouse CAPEX is 21% higher than the SCR CAPEX while the baghouse OPEX is 27% lower than its 

SCR counterpart. Combined, CAPEX AND OPEX for baghouse and SCR total approximately $1.1 

billion and $20.6 million in 2012 dollars. The incremental CAPEX and OPEX of baghouse 

investments for MATS compliance increase the total capital investment by approximately 118% 

over the SCR-only case. 

Modeling Results SCR + Baghouse Scenario & Comparison of the to the SCR-only Case

As illustrated in Table 18, the 25-year NPV of SCR + baghouse is $9.1 billion compared to the BAU 

case of $7.7 billion, a difference of nearly $1.4 billion. Compared to the low market case NPV of $8.4

billion, the SCR + baghouse NPV is nearly $760 million higher. 

 

26 Salt River Project Navajo Generating Station - Units 1, 2, 3 SCR and Baghouse Capital Cost Estimate Report, 

Table 9-3, SL-010214, Revision D; August 17, 2010.

Unit No.

Year

Installed

Capital

Expense

Operating 

Expense

Year

Installed

Capital

Expense

Operating 

Expense

Capital

Expense

Operating 

Expense

1 2016 $ 220,359,000 $ 2,896,000 2017 $ 137,527,000 $ 3,982,000 $ 13,066,667 $ 6,333,333

2 2015 $ 205,111,000 $ 2,896,000 2016 $ 188,585,000 $ 3,982,000 $ 13,066,667 $ 6,333,333

3 2017 $ 161,341,000 $ 2,896,000 2018 $ 170,294,000 $ 3,982,000 $ 13,066,667 $ 6,333,333

Total $ 586,811,000 $ 8,688,000 $ 496,406,000 $ 11,946,000 $ 39,200,000 $ 19,000,000

Baghouse SCR SNCR

Capital and Operating Expense Assumptions - Baghouse, SCR and SNCR

2012$
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Table 18

Table 18 shows that the percentage increase in incremental cost for SCR + baghouse compared to 

BAU is over twice that of SCR only, 18% compared to 8%. 

Retail Electricity and Water Cost Impacts: SCR + Baghouse Scenario

As a higher cost retrofit scenario, SCR + baghouse would have similarly larger impacts than SCR 

alone on retail electricity rates and CAP water rates. Tables 19 and 20 below illustrate the dollar 

and percentage increases over the BAU case as a result of SCR + baghouse.

BAU SNCR SCR

SCR + 

Baghouse

Market

Low Trend

$ 7,766 $ 8,021 $ 8,414 $ 9,197 $ 8,439

 $ $ 255 $ 648 $ 1,431 $ 673 

 % 3% 8% 18% 9%

NGS - Summary Cost Comparisons

(2012-2036) Straight Line Depreciation

NPV 25 Year Cost by Case ($Million)

Difference in Cost for Case vs. BAU Case ($Million)
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Table 19

Estimate Average Retail Rate Impact for SRP

Table 20

CAP Water Rate Impacts

The yellow-highlighted cells signify the highest estimated incremental cost year for both the SRP 

retail rate and Energy Rate 1 water rate impact caused by SCR + baghouse costs when applied to 

estimated SRP and CAWCD rates for that year. 

SCR + Baghouse - (SCR 2016/2017/2018 Installation)

Cost Impacts 2014 2015 2016 2017 2018

NGS Incremental Production Cost ($/kWh) $ - $ 0.00189 $ 0.00569 $ 0.00859 $ 0.01012

Utility Share of Incremental $ $ - $ 6,944,901 $ 20,930,219 $ 31,586,624 $ 37,226,078

Rate Impacts 

Estimated Retail Revenues $ 2,527,303,202 $ 2,565,212,750 $ 2,603,690,941 $ 2,642,746,305 $ 2,682,387,500

Utility's Share of Emissions Measure Incremental Cost $ - $ 6,944,901 $ 20,930,219 $ 31,586,624 $ 37,226,078

Estimated Total Utility Retail Revenues $ 2,527,303,202 $ 2,572,157,650 $ 2,624,621,159 $ 2,674,332,929 $ 2,719,613,578

Estimated Retail Sales (kWh) 27,289,884,182 27,699,232,444 28,114,720,931 28,536,441,745 28,964,488,371

Estimated Retail Rate w/Emissions Measure ($/kWh) $ 0.09261 $ 0.09286 $ 0.09335 $ 0.09372 $ 0.09389

Est. Retail Rate Without Emissions Measure ($/kWh) $ 0.09261 $ 0.09261 $ 0.09261 $ 0.09261 $ 0.09261

Incremental Rate Impact of Emissions Measure ($/kWh) $ - $ 0.00025 $ 0.00074 $ 0.00111 $ 0.00129

% Increase In Retail Rates due to Emissions Measure 0.000% 0.271% 0.804% 1.195% 1.388%

CAP Energy Rate 1: Impact of Emissions Control Scenarios

Assumptions

Annual pumping (AF) 1,550,000

Annual pumping energy (MWh) 2,800,000

2014 2015 2016 2017 2018

$ 51.00 $ 56.00 $ 58.00 $ 58.00 $ 58.00

2014 2015 2016 2017 2018

Incremental Power Cost ($/MWh) $ - $ 1.82 $ 5.49 $ 8.30 $ 9.79

Incremental Water Cost ($/AF) $ - $ 3.29 $ 9.92 $ 14.99 $ 17.69

Resulting Energy 1 Rate ($/AF) $ 51.00 $ 59.29 $ 67.92 $ 72.99 $ 75.69

0.0% 5.9% 17.1% 25.9% 30.5%

SCR + Baghouse - (SCR 2016/2017/2018 Installation)

% Increase over Preliminary CAP Rates

CAP Energy Rate 1: Advisory Rates as 

approved by CAWCD June 2011

Pumping & energy consumption volumes as reported 

by CAWCD 12/18/2009 Letter to EPA ESTIMATED ENERGY 1 

RATE
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Summary

In summary, where the capital costs associated with the SCR + baghouse compared to the SCR-only 

case are approximately double, the model returns a similar 2x increase in incremental 25-year NPV 

cash flows as well as average retail electricity rate impacts and CAP water rate impacts.

It is reasonable to assume that many of these factors may 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.

Decision Environment & Additional Factors

The 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 NGS. Prior to this point of the report comments have been limited to NGS and to a 

range of investment options including SCR. From this point forward the discussion will include 

FCPP and focus on SCR. 

NGS and FCPP 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 SCR, 

both plants share in common a set of additional factors that will impact economic decisions 

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

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

regarding the future of the plant. The additional factors that may impact decision making are:

 Greenhouse gas (GHG) emissions regulation

 California climate change regulations 

 Power plant ownership 

 MATS

 Fly ash & ash handling regulations

 Coal and other lease renewals 

The factors listed above can be categorized and discussed in two groups as follows: Environmental 

Regulations and Contractual Contingencies. Several of these additional factors were explored in the 

sensitivity analyses described above.

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 process that ultimately leads to comprehensive GHG emissions regulation at the federal level is 

underway. Regulation has been promulgated by EPA that requires new major sources of GHG 

emissions and modifications at existing major sources that exceed the GHG significance thresholds 

to apply for a permit under the EPA’s Prevention of Significant Deterioration (“PSD”) permitting 

program. 

Aside from foreseeable rulemaking from EPA, there is great uncertainty with respect to the timing 

of a future market-based or taxing mechanism (e.g. cap and trade, carbon tax, etc.), that the U.S.

Congress and the Executive Branch may promote. Even so, most owners of coal-fired electric 

generation, including owners of NGS as indicated in their comments, are anticipating additional 

costs related CO2-specific regulation. 
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The cost of carbon for NGS is estimated to add between $20/MWh to $50/MWh based on APS’ 

estimate of future carbon pricing in their comments on the EPA’s docket regarding BART at Four 

Corners Power Plant. Costs in that range would represent a 60% to 140% incremental cost to the 

modeled BAU case. 

Cost of Carbon

The ratio of carbon dioxide emissions to power produced for a coal-fired plant is approximately 1:1. 

That is, one metric ton CO2 is emitted for every MWh produced. Given the 1:1 relationship between 

CO2 emissions and MWh production, calculating the carbon compliance cost impact to a coal plant 

at varying levels of carbon price on a $/MT is straight forward. The $/MT of carbon roughly equals 

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

California Climate Change Regulations & Plant Ownership

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 (CARB) 

to enact plans to reduce GHG emissions to 1990 levels by 2020. AB32 specifically requires CARB to 

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

Senate Bill 1368 (SB1368) 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 longterm 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 base load generation by any load-serving entity only if the GHG 

emissions related to that capital investment or power purchase agreement are as low or lower than 

the GHG emissions from a 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 
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standard27 has shaped planning decisions for many California utilities and influenced the following 

specific actions:

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

when its contractual obligations expire in mid-2016 28

 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.29 LADWP has 

also proposed an accelerated exit from NGS as early as 2014 according to their 2010 

Integrated Resource Plan.30

 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. APS may 

become the owner of the FCPP share of SCE if their proposals are accepted, however the fate 

of Los Angeles’ share of NGS is much less certain.

In Arizona, 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 potential cost of carbon. The 

interest of the remaining plant participants to acquire the relinquished shares at FCPP or NGS is 

therefore difficult to gauge.

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 they may 

undertake their decision making process. NGS is owned by a mixture of six entities; governmental 

 

27 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.

28 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

29 http://mayor.lacity.org/Issues/Environment/Next4/index.htm

30 LADWP Integrated Resource Plan, December 2010; http://www.ladwp.com/ladwp/cms/ladwp001967.jsp
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agencies, investor owned utilities (IOUs) and public power entities as indicated above. Table 21

below illustrates the respective MW share from each unit owned by each shareholder. 

Table 21

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 NGS 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 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: 

Table 22

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

decision to NOT invest 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. 

MATS & Ash Handling (Coal Combustion Residuals)

EPA’s rulemaking for electric utilities on the Mercury and Air Toxics Standards (MATS)31, also 

known as the Utility Maximum Achievable Control Technology (MACT), as well as EPA’s open 

docket for handling and disposal of Coal Combustion Residuals (CCR)32 have the potential to 

increase the cost of production for coal-fired power plants. With respect to the proposed Utility 

MACT, SRP’s estimation of the capital and operating costs were input into the model and run as a 

supplemental scenario in order to quantify potential incremental power costs from a combination 

of the MACT and SCR-related emission control investments. Affordability modeling was not 

conducted with respect to CCR. 

Even without cost estimations and incremental cost modeling for CCR, compliance costs would 

logically result in additional incremental costs to the existing cost of production for NGS. In 

addition to the direct costs of compliance of the Utility MACT scenario, activated carbon injection 

for mercury control may affect the quality of the fly ash sold by these plants and thus may be 

viewed by the owners as lost revenue or 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

Unlike some of the other issues addressed relative to risk and sensitivity, agreements related to 

coal royalties and land use leases may not pose the same level of uncertainty as, for example, 

variable surrounding regulatory risk or market costs. Those entities that have the greatest to gain 

 

31

 Docket No. EPA-HQ-OAR-2009-0234

32 Docket No. 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
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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), failure 

to extend the existing business relationships, thereby causing NGS to shut down, would not appear 

to be in the best interest of the parties. 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. That said, there is likely to be some variability in plant operating expenses associated 

with both the site lease and future fuel cost. The sensitivity analyses were conducted as a way of 

assessing those variables and the relative impact on the performance of the modeled cases.

Consideration of Multiple Investment Risks

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. 
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Evaluating Multiple Risks

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. 

Utilities are 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, SNCR, SCR, and other 

retrofits), along with a range of costs and probabilities for the additional factors discussed above: 

CO2, MATS, CCR, etc.

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 is all the more crucial for variables whose significant influence on the 

outcome warrants cautious application of a probability distribution. A stochastic model of NGS’ 

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.
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ADDENDUM: Water Cost Impacts

In conjunction with findings related to the incremental increase in the energy-only component of 

the CAP water rate, an additional analysis was undertaken to evaluate how the incremental 

increase in CAP water rates may impact overall water supply costs for distinct CAP water groups. 

This analysis is analogous to that presented in the report to estimate the impact of increasing 

power generation costs on electricity rates to retail customers. As previously discussed, percent 

increases in generation costs at NGS do not necessarily result in equivalent percent increases to 

retail rates of utilities depending on the utility’s degree of reliance on NGS for power and the 

proportion of other costs that contribute to the customer’s overall rate. For example, a projected 

16.4 percent increase in power generation costs at NGS is projected to result in a 0.65 percent 

increase to the average retail electricity rate for customers of SRP. 

The Water Cost Impact Addendum provides discussion and estimations of the impact of 

incremental increases in CAP water cost to the total cost of water supplies for Municipal & 

Industrial ("M&I") and non-Indian Agricultural ("NIA") water users33. Although EPA requested 

information from tribes regarding current and projected water volumes and costs for this study, 

sufficient information was unavailable at the time the analysis was conducted; therefore, impacts to 

total water supply costs to tribes could not be included in this assessment. The assessment 

described below utilized the incremental CAWCD Energy Rate 1 results from the NGS Affordability 

Analysis model for the years during which incremental CAPEX and OPEX for the proposed BART 

investments resulted in the highest incremental power cost and water rate impacts. 

Background

In its 2010 Arizona Water Atlas, the Arizona Department of Water Resources (“ADWR”) describes 

the sources and uses of water within seven distinct “planning areas” which encompass the entire 

State of Arizona. 

 

33 Indian agricultural water use accounts for a substantial portion of current and projected CAP water 

volumes. 
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As indicated in the chart above, the sources of water used in Arizona includes surface water 

(Colorado River water, including CAP water, and in-state surface water), groundwater and 

reclaimed water or effluent. Arizona water supplies for the period of 2001-200534, averaged 

approximately 7,500,000 acre-feet per year, as summarized by ADWR. During that time, CAP 

provided approximately 15% of the state’s water supply. For the same time period, ADWR 

attributed demand to the following broad categories of water use as a percentage of total water 

demand. 

Water User Category % of Total Water Demand

Agriculture 75%

Municipal 20%

Industrial 5%

Five of the seven planning areas mentioned above are designated as “Active Management Areas”, or 

AMAs. Water use within each AMA must follow prescribed water management practices, the 

objective of which is the preservation of groundwater supplies. Three of the five AMAs have access 

to water from CAP via the 336-mile Hayden-Rhodes Aqueduct. CAP water is delivered to multiple 

classes of water users in Maricopa, Pinal, and Pima counties. The AMAs responsible for those 

 

34 The ADWR Arizona Water Atlas published September 2010 contains statewide data through 2005 and 

represents the most current summation of statewide water data published by ADWR and available at the time 

of this assessment. 

Groundwater

43%

Non-CAP 

Surface Water

39%

CAP Water

15%

Effluent

3%

Average Annual Water Supplies Utilized in Arizona 

2001-2005 (in % of total)

Source: ADWR 2010 Water Atlas Volume 1
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counties respectively are called the Phoenix AMA, Pinal AMA, and Tucson AMA. Their total average 

annual water demands from 2001-2005, including Indian water usage, was reported by ADWR as 

indicated below.

2001-2005

AF/year

Groundwater Surface Water CAP Effluent Total 

Phoenix

Municipal 295,600 384,100 317,200 41,600 1,038,500

Industrial 88,800 7,900 2,400 63,300 162,400

Agricultural 429,900 298,700 295,800 28,200 1,052,600

Total 814,300 690,700 615,400 133,100 2,253,500

% of Total 36% 31% 27% 6%

Pinal AMA 

Municipal 24,700 600 3,100 500 28,900

Industrial 13,200 0 900 600 14,700

Agricultural 439,600 67,900 465,300 1,700 974,500

Total 477,500 68,500 469,300 2,800 1,018,100

% of Total 47% 7% 46% 0%

Tucson AMA 

Municipal 124,100 100 44,300 12,200 180,700

Industrial 51,400 200 400 400 52,400

Agricultural 76,400 0 32,100 0 108,500

Total 251,900 300 76,800 12,600 341,600

% of Total 74% 0% 22% 4%

Total 

Municipal 444,400 384,800 364,600 54,300 1,248,100

Industrial 153,400 8,100 3,700 64,300 229,500

Agriculture 945,900 366,600 793,200 29,900 2,135,600

Grand Total 1,543,700 759,500 1,161,500 148,500 3,613,200

% of Grand Total 43% 21% 32% 4%

When combined, the Phoenix, Pinal, and Tucson AMAs, totaling over 3,600,000 acre-feet per year, 

account for approximately 48% of the entire water demand in Arizona. CAP contributes 32 percent 

of the total water usage in these three AMAs. In accordance with laws and rules associated with the 

construction of, and allocations from, the CAP, these three AMAs also account for 100% of the 

state’s CAP water use. Of the CAP water used by these three AMAs, 68 percent of that is consumed 

by Agriculture, 31 percent by Municipalities, and 0.3 percent by Industries. Therefore, and for 

purposes of this assessment, the incremental total user costs driven by a BART determination at 

NGS will focus on the impacts to Municipal and Non-Indian Agricultural water users specifically 

located in the three AMAs that receive CAP water. 
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The table below indicates Non-Indian Agriculture and Indian Agricultural water use from all 

sources in the AMA’s equated to 83% and 17% respectively. All Non-Indian and Indian water use in 

the AMA’s accounted for approximately 90% and 10% of total water use respectively.

Total All AMAs

Groundwater 

Surface 

Water CAP Effluent Total 

Municipal 

Non-Indian 435,500 384,600 364,600 54,300 1,239,000

Indian 8,900 200 0 0 9,100

Total 444,400 384,800 364,600 54,300 1,248,100

Industrial 

Non-Indian 152,100 8,100 3,700 64,300 228,200

Indian 1,300 0 0 0 1,300

Total 153,400 8,100 3,700 64,300 229,500

Agriculture 

Non-Indian 810,300 243,400 684,800 29,900 1,768,400

Indian 135,600 123,200 108,400 0 367,200

Total 945,900 366,600 793,200 29,900 2,135,600

Grand Total 1,543,700 759,500 1,161,500 148,500 3,613,200

Non-Indian Agricultural Water Use as % of Total Ag Water Use 83%

Indian Agricultural Water Use as % of Total Ag Water Use 17%

Non-Indian Total Water Use 3,235,600

% of total Water Use 90%

Indian Total Water Use 377,600

% of Total Water Use 10%

In the NGS Affordability Analysis, the incremental cost analysis translated the power cost impacts 

into impacts on CAP water rates. The study specified the impact to the Energy Rate 1 – itself a 

component of both the applicable agricultural and M&I rates. 

Two studies were undertaken by the consulting firm Harvey Economics; one study on behalf of the 

Gila River Indian Community (Projected Impacts of EPA BART Implementation on the GRIC – revised 

edition, March 2012) and the other on behalf of Salt River Project (The Economic Impact of EPA 

Proposed BART Implementation at Navajo Generating Station – April 2012). The result of the GRIC 

study was incorporated into the more expansive SRP study. That study includes analyses of the 

potential impact on the cost of agricultural water from different scenarios, including a SCR-only, a 

SCR + baghouse and a scenario whereby all power needs required in the CAP system are purchased 
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in the wholesale power market. Additionally, the report analyzes the impact on the GRIC 

agriculture industry as a result of the corresponding water cost increase. 

With regards to the impact on water cost that the CAP (and its users) would experience, both the 

analysis conducted in our NGS Affordability Impact and the Harvey study estimate that CAP water 

would experience relatively significant increases, particularly in the first few years of the SCR 

implementation. Both also suggest a trend of declining impacts after roughly a five year period as 

the control equipment is amortized for depreciation purposes. One can point to two critical input 

values that do differ, and are probably reflective of a set of larger values that do not match perfectly 

between the approaches. For instance, the assumed capital cost for SCR in the Harvey study is 

roughly $544 million (from the Sargent and Lundy study) while the capital cost employed in the 

NGS Affordability Analysis is roughly $496 million based on EPA’s revisions to the Sargent and 

Lundy study. Additionally, the assumed CAP energy cost in the Harvey study is $53/AF compared 

to $56/AF for 2015 in the NGS Affordability Analysis. The differences in these values alone, given 

their importance to the overall assessment, would produce differing results. Overall, however, the 

studies produce somewhat similar results for the projected values for 2020. The 2020 cost increase 

associated with a SCR-only scenario is estimated in the Harvey study at $6.60/AF (cost over the 

base case) vs. a $7.68/AF projected increase in the NGS Affordability Analysis. The differences are 

greater, however, in the SCR with baghouse scenario (again, for 2020) - $12.90/AF vs. $16.11/AF in 

the NGS Affordability Analysis. 

CAP Water Rate Impact

The following table combines the output reported in the NGS Affordability Analysis’s Table 13 

regarding the incremental CAP water rate impacts associated with SCR costs for the 

2016/2017/2018 installation schedule.
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Table A-1

SCR Incremental Power & CAP Energy Rate 1 Cost by Installation Scenario

CAP Energy Rate 1: Impact of Emissions Control Scenarios

Assumptions

Annual pumping (AF) 1,550,000

Annual pumping energy (MWh) 2,800,000

2014 2015 2016 2017 2018

$ 51.00 $ 56.00 $ 58.00 $ 58.00 $ 58.00

2014 2015 2016 2017 2018

Incremental Power Cost ($/MWh) $ - $ - $ 1.71 $ 3.04 $ 4.65

Incremental Water Cost ($/AF) $ - $ - $ 3.09 $ 5.49 $ 8.40

Resulting Energy 1 Rate ($/AF) $ 51.00 $ 56.00 $ 61.09 $ 63.49 $ 66.40

0.0% 0.0% 5.3% 9.5% 14.5%

CAP Energy Rate 1: Advisory Rates as 

approved by CAWCD June 2011

Pumping & energy consumption volumes as reported 

by CAWCD 12/18/2009 Letter to EPA

% Increase over Preliminary CAP Rates

ESTIMATED ENERGY 1 

RATE

SCR - 2016/2017/2018 Installation
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The estimated increases in CAP Energy Rate 1 as identified in the prior table form the basis for total 

water cost estimates for the M&I and NIA water users. The following sections discuss the analyses 

for each user group. 

Municipal Water

Municipal CAP water users constitute a significant customer group, consuming nearly one-third of 

the delivered CAP water, and a distinct ratepayer class for the CAWCD. The characteristics of the 

Municipal water users vary widely, from large city systems delivering hundreds of thousands of 

acre-feet per year, to rural private water companies and water cooperatives. Each Municipal class 

water user has its own unique set of supply resources and costs – where some users rely very little 

on CAP water and thus have limited exposure to CAP costs, while others have considerable and 

nearly total exposure to CAP costs as they represent a large portion of the Municipal user’s water 

supply portfolio. 

The study endeavored to evaluate a limited set of Municipal CAP customers whose water supply 

portfolios would represent both a wide range of reliance on CAP water and whose combined CAP 

volumes would constitute a significant portion of total CAP Municipal water deliveries. The 

following two-column list identifies CAP M&I water users in a descending order based on 2011 CAP 

water allocations in acre-feet per year. According to CAWCD35, the M&I CAP water allocations for 

2011 are as follows:

 

35 “CAP Subcontracting Status Report, CAP Non Indian Municipal and Industrial Subcontracts”, April 1, 2011, 

http://www.cap-az.com/Portals/1/Files/SubcontractReport04012011.docx. The quantities indicated in the

subcontractor report total over 600,000 acre feet and include non-municipal government entities including 

agricultural improvement and irrigation districts, industrial water users and private water companies. 

Allocations for municipal government entities specifically total approximately 471,000 in this listing. 
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M&I Subcontractor AF/yr M&I Subcontractor AF/yr

Tucson, City of 144,172 Community Water Co. of Green Valley 2,858 

Phoenix, City of 122,120 Cave Creek, Town of 2,606 

Scottsdale, City of 52,810 Arizona-American Water Co. 2,372 

Mesa, City of 43,503 Eloy 2,171 

Arizona State Land Dept. 32,076 Florence 2,048 

Peoria, City of Peoria 25,236 Arizona Water Co. (Coolidge System) 2,000 

ASARCO Incorporated (Ray Mine) 21,000 Green Valley Water Impr. Dist. 1,900 

Glendale, City of 17,236 Vail Water Company 1,857 

Metropolitan Domestic Water Imp. Dist. 13,460 Marana, Town of 1,528 

Arizona-American Water Co. (Agua Fria) 11,093 Carefree Water Co. 1,300 

Goodyear 10,742 Arizona Water Co. (White Tank Sys.) 968 

Oro Valley, Town of 10,305 Rio Verde Utilities, Inc. 812 

Surprise, City of 10,249 AVRA Water Co-op, Inc. 808 

Chaparral City Water Co. 8,909 Maricopa County Parks & Rec. 665 

Arizona Water Co. (Casa Grande) 8,884 El Mirage, City of 508 

Chandler 8,654 Queen Creek, Town of 348 

Central Arizona Water Conservation 7,996 Chandler Heights Citrus I.D. 315 

Gilbert 7,235 Superior, Town of 285 

Arizona Water Co. (Superstition) 6,000 Valley Utilities Water Co. 285 

Avondale 5,416 San Tan Irrigation District 236 

Tempe, City of 4,315 Pine Water Company 161 

Arizona-American Water Co. (Sun City) 4,189 H2O Water Co. 147 

Circle City Water Co. 3,932 Alderwoods (Arizona), Inc. 84 

AZ-American Water Co. (Paradise Vly) 3,231 Tonto Hills Domestic Water Improv. 71 

Spanish Trail Water Co. 3,037 Water Utility of Greater Tonopah 64 

Water Utilities Community 2,919 Valencia Water Company 43 

Phelps Dodge Miami, Inc. 2,906 Buckeye 25 

Flowing Wells Irrigation District 2,873 Total 620,678

A subset of these users was selected for detailed water supply and cost evaluation. Based on the 

volumes identified in the list above, and initial research into their supply portfolios, the four largest 

Municipal CAP water users were selected according to their 2011 CAP allocations and based on 

their volumes as a percentage of the total CAP M&I water user allocations. The four Municipal users 

selected were the cities of Tucson, Phoenix, Scottsdale, and Mesa. Their combined allocations 

account for nearly 60% of the total 2011 CAP M&I allocation. 

Study Methodology

The selected Municipal water users were contacted for this study and asked to provide historical 

and projected volumetric (AF/year) and cost ($/year) data. A data template was provided to each 

and their water services staffs graciously accepted the invitation to provide their volumetric and 

cost estimates according to a template. A sample portion of the data template, for years 2009-2013, 

is shown below. 
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Respondents were encouraged to provide estimated volumes and costs as far into the future as they 

were able. Data received from respondents were reviewed to confirm that all applicable CAP rate 

components were included in the total cost estimates. 

The following table illustrates the percentage of water use represented by CAP supplies for each 

Municipal user’s unique water supply portfolio.

Water Sources & Costs by Year Color indicates input cells

2009 2010 2011 2012 2013

CAP Supply - - - - -

All Non-CAP Supply

#1 Description - - - - -

#2 Description - - - - -

#3 Description - - - - -

#4 Description - - - - -

#5 Description - - - - -

Subtotal (Non-CAP Deliveries) - - - - -

Total Deliveries - - - - -

2009 2010 2011 2012 2013

CAP Supply (from above) $ - $ - $ - $ - $ -

CAP Water $/AF #DIV/0! #DIV/0! #DIV/0! #DIV/0! #DIV/0!

All Non-CAP Supply (from above)

$ - $ - $ - $ - $ -

$ - $ - $ - $ - $ -

$ - $ - $ - $ - $ -

$ - $ - $ - $ - $ -

$ - $ - $ - $ - $ -

Subtotal (Non-CAP Cost) $ - $ - $ - $ - $ -

Non-CAP Water $/AF #DIV/0! #DIV/0! #DIV/0! #DIV/0! #DIV/0!

Total Cost $ - $ - $ - $ - $ -

All Water Sources $/AF #DIV/0! #DIV/0! #DIV/0! #DIV/0! #DIV/0!

ANNUAL COST (Dollars per year)

VOLUMES (Delivered in acre feet per year)

Source & Description

Source & Description

HISTORICAL

HISTORICAL

 ESTIMATED > > 

 ESTIMATED > >

#1

#2

#3

#4

#5

CAP Water as % of Total 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

 Tucson 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

 Phoenix 45% 48% 45% 45% 45% 45% 45% 45% 45% 45%

 Scottsdale 64% 71% 72% 72% 73% 73% 74% 74% 75% 75%

 Mesa 54% 57% 53% 56% 56% 56% 55% 55% 55% 55%

VOLUMES 

(Delivered in AF/Yr)

HISTORICAL ESTIMATED > > 
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It warrants mention that the 100% reliance on CAP water for municipal water uses for the City of 

Tucson will not align with the water uses reported earlier in this addendum for the entire Tucson 

AMA because the Tucson AMA is broader than the City of Tucson’s water service area and 

encompasses other sources and uses besides those reported by the City of Tucson. 

The combination of projected annual CAP and non-CAP costs, and their corresponding CAP and 

non-CAP volumes for each of the four Municipal users noted above were used to estimate how their 

total water costs would be impacted by incremental CAP water rate increases due to SCR. The 

following chart illustrates the total water supply cost impacts for each of the four municipalities as 

a result of SCR. Chart A-1 below illustrates the incremental CAP water supply cost impact as a 

percentage of total water cost for each M&I user when the incremental CAP costs indicated in Table 

A-1 are applied to each user’s CAP water supply volumes under the 2016/2017/2018 installation 

schedule. 

 
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Chart A-1

2014 2015 2016 2017 2018 2019 2020

Increm. Cost Tucson 0.0% 0.0% 2.2% 3.8% 5.7% 5.5% 5.3%

Increm. Cost Phoenix 0.0% 0.0% 1.6% 2.8% 4.2% 4.1% 3.9%

Increm. Cost Scottsdale 0.0% 0.0% 1.9% 3.3% 4.9% 4.7% 4.6%

Increm. Cost Mesa 0.0% 0.0% 2.1% 3.5% 5.1% 4.7% 4.3%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0% Annual Percentage Increase over Projected Total Water Cost

Percentage Increase in Total M&I Water Supply Costs Resulting From SCR at NGS for 

2016/17/18 Install Scenario
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As shown in the Chart A-1 above, incremental cost impacts driven by CAP water begin in the first 

year associated with installation of SCR. The highest impact year is the final year of installation, 

namely 2018. The 2018 incremental cost impacts range from 4.2% for the City of Phoenix, up to 

5.7% for the City of Tucson.

As a result of varying levels of reliance on CAP water, the impacts of incremental CAP water costs 

due to SCR also varies. Even though it’s percentage increase in water costs is the lowest of the four 

cities studied, as a result of using the largest volumes of CAP water, the City of Phoenix would have 

the largest dollar impact at $1.23 million, followed closely by Tucson $1.21 million. The similar cost 

outcome is to be expected given the similarity in their respective CAP volumes. The dollar cost 

impact to Mesa and Scottsdale is less than 50% of the cost to either Phoenix or Tucson, also in 

keeping with their respective allocations and projected CAP usage.

Summary

Municipal CAP water users would experience escalating water costs beginning in 2016, peaking in 

2018 as a result of SCR under a 2016/2017/2018 installation scenario. The costs that are caused by 

the potential SCR investments, as they impact individual M&I water users, are driven by two 

factors; namely, the amount of CAP water a Municipal water utility uses, and the percentage that 

CAP water represents of each city’s total water supply portfolio. 
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Agricultural Water

Agricultural water users have access to and utilize individual and unique water supply portfolios 

that include groundwater, surface water, CAP water, and reclaimed water or effluent. Agricultural 

water users include Indian Agricultural and Non-Indian Agricultural (“NIA”) users. NIA water use is 

discussed below in this section. The ADWR publishes a planning document called the Arizona 

Water Atlas. The April 2010 edition of that publication focuses on water demand and supply 

planning for the five AMAs in the state. Those five AMAs, based on five groundwater basins, are 

called the AMA Planning Area. The AMA Planning Area includes the Prescott, Phoenix, Pinal, Santa 

Cruz, and Tucson AMAs as indicated in the following map.
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The 2010 Water Atlas reports that between 2001 and 2005 water use in the Planning Area 

averaged 3,659,480 acre-feet per year for agricultural, municipal and industrial purposes. Of this 

total demand, approximately 43% was groundwater, 32% was CAP water, 21% was other surface 

water and 4% was effluent or reclaimed water. The following table contains data from the Water 

Atlas for all three AMAs relative to Non-Indian Agricultural water demand:

Of the 1,768,500 acre feet of NIA water demand, the Phoenix and Pinal AMAs accounted for almost 

all those volumes, representing 44% and 45% respectively of the total. 

Future Water Demands

In regards to future agricultural water use, the Water Atlas states: 

“Agricultural water use within AMAs is subject to Groundwater Code regulations that

limit groundwater use for irrigation purposes. Due to the AMA regulations that 

restrict new irrigated acres and require improved efficiencies, agricultural demand 

2001-2005 

(acre-feet) 

Phoenix AMA 

Groundwater 354,500

Surface Water 183,100

CAP 273,000

Effluent 28,200

Total 838,800

Pinal AMA 

Groundwater 379,400

Surface Water 60,300

CAP 391,700

Effluent 1,700

Total 833,100

Tucson AMA 

Groundwater 76,400

CAP 20,200

Effluent 0

Total 96,600

Subtotal Phoenix, Pinal, Tucson AMAs 1,768,500

Average Annual Non-Indian Agricultural Demand

in the AMA Planning Area
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should not significantly increase within the AMAs as may occur in non-AMA planning 

areas. Additionally, as the AMA population centers grow, urbanization is expected to 

result in a decrease in agricultural demand over time”.

The focus of the Water Atlas is the historical 5-year period ending 2005 and, as such, provides only 

directional forms of information that suggest future impacts on water supply volumes and costs. A 

more recent study was published in mid-2011 that projects water use from 2010 to 2060. As 

discussed in the water demand forecasts found in the Water Resources Development Commission’s 

(WRDC) 2011 Water Supply and Demand Working Group Report, acres under cultivation (nonIndian) within the Phoenix, Pinal, and Tucson AMAs are expected to continue the trend of decline 

that has been exhibited in recent years. The WRDC report36 developed by a consortium of water 

stakeholders in the state (including representation from all classes of CAP water users) provided 

future demand estimates for the NIA water users in the three AMAs that receive CAP water. 

 

36 Water Resources Development Commission (WRDC) Water Supply and Demand Working Group Report, 

Agricultural Demand Subcommittee Report, 2011, Appendix
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As evidenced by the data represented in the following chart, from 2010 forward, agricultural water 

use in these three AMAs is projected to decline by 17% in 2020, 34% in 2030, all the way to 62% in 

2060. The data clearly illustrates the large projected decline in NIA water use in the Phoenix, Pinal, 

and Tucson AMAs.

CAP Supply

Based data from the 2010 Water Atlas, the following data in Table A-3 breaks out Indian and nonIndian water demands across the three broad categories of Municipal, Industrial and Agriculture. 

The data contained in the following table represents an average of 2001-2005. 

Agricultural Water Demands 2001-2005, Phoenix, Pinal, Tucson AMAs

Groundwater 

Surface 

Water CAP Effluent Total 

Non-Indian 826,800 243,800 684,800 31,300 1,786,700

Indian 135,600 123,200 108,400 0 367,200

Total 962,400 367,000 793,200 31,300 2,153,900

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

20102012201420162018202020222024202620282030203220342036203820402042204420462048205020522054205620582060

Acre Feet Per Year

Projected Agricultural Water Use in the 

Phoenix, Pinal & Tucson AMAs

Source: Water Resources Development Commission Water Supply and Demand 

Working Group Report, Agricultural Demand Subcommittee Report, 2011

Phoenix

AMA

Pinal

AMA

Tucson

AMA
EPA Contract No. EP-D-10-096

Work Assignment No. 3-04

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The estimated future agricultural water needs discussed above represent demands satisfied by a 

variety of water sources, including CAP water. With respect to NIA demands that may be satisfied 

specifically by CAP water, according to the 2010 Water Atlas, NIA water use within the combined 

AMA’s that receive CAP water averaged approximately 685,000 acre-feet each year between 2001 

and 2005. That historical quantity of CAP water is larger than future CAP volumes earmarked for 

NIA users – volumes that will change dramatically over the next 25 years. As indicated in the 

Arizona Water Settlements Act, and footnoted in WRDCs modeling files used for the 2011 report, 

NIA CAP water deliveries will decline over time based on the following schedule:

Begin Year End Year AF/yr

2007 2016 400,000

2017 2023 300,000

2024 2030 225,000

2031 NA 0

Graphically, the reduction between 2010 and 2035 is as follows:

As reported in the WRDC modeling footnotes, 

“The reduction in non-Indian ag deliveries is a result of the Arizona Water 

Settlements Act (AWSA). As a part of this overall settlement, the CAP nonIndian-agricultural (NIA) contractors relinquished their NIA priority water (due 

to its high cost) for a temporary pool of less costly CAP excess water. The 

availability of this “Non-Indian Agriculture Settlement” water will cease by 2031, 

and the availability of water decreases over time according to the following 
EPA Contract No. EP-D-10-096

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schedule: 400,000 acre-feet through 2016; 300,000 acre-feet from 2017 through 

2023; and 225,000 acre-feet from 2024 through 2030. 

Over time, as delivery systems for transportation of Indian water allocations are completed, Indian 

Agriculture is expected to increase. Whereas today the tribes do not take all their settlement 

allocations, in the future the expectation by the WRDC is that tribal water use will increase to the 

point of using their full allocations. 

CAP versus Non-CAP NIA Water Supplies

Utilizing modeling data from the WRDC study, which includes estimations of water availability due 

to trends in yearly water production, the following table was constructed to estimate how much 

NIA water would be supplied from CAP and how much would be required to come from other 

sources, including groundwater, surface water, and effluent. The table assumes that the difference 

between NIA demand in a given year and projected CAP supply (as interpreted from the WRDC 

data) is supplied by a mixture of all other available sources. In other words, a shortfall in supply is 

not developed in the following table because all demand is supplied as a base assumption.
EPA Contract No. EP-D-10-096

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The values in the column labeled “NIA Settlement CAP Volumes” are the amounts that may be 

assigned to NIA (the most junior priority in the CAP water allocation scheme as defined by the 

AWSA) if the water year so allows. The WRDC “Forecast of Available NIA CAP Water” includes the 

water/climate modeling affects and the estimated impacts of expanded Indian deliveries on the 

available water for NIA use. As a result, NIA CAP use as a percentage of total water demand 

declines very quickly. From 2011, where Non-CAP water accounts for 75% of all NIA demand, 

within seven years NIA demand would be satisfied nearly entirely by non-CAP supplies.

Key variables in the assumptions for the table above include the pace at which Indian Agriculture 

utilizes its settlement volumes and thus draws down the available excess for NIA to utilize, the 

available water in a given year for NIA use based on seasonal conditions, and the NIA demand itself. 

For comparison purposes, according to the 2010 Water Atlas, the average for the ten years ending 

in 2006 for NIA non-CAP water supply as s percentage of total was approximately 64%.

Total NIA 

Demand

NIA 

Settlement 

CAP Volumes

Forecast of 

Available NIA CAP 

Water

Calculation of nonCAP Supply 

Requirement

% Supplied 

by Non-CAP 

Water

2011 1,602,083 400,000 400,000 1,202,083 75%

2012 1,577,457 400,000 400,000 1,177,457 75%

2013 1,553,389 400,000 400,000 1,153,389 74%

2014 1,529,847 400,000 400,000 1,129,847 74%

2015 1,506,805 400,000 400,000 1,106,805 73%

2016 1,479,228 400,000 400,000 1,079,228 73%

2017 1,444,992 400,000 361,232 1,083,760 75%

2018 1,411,134 300,000 75,446 1,335,688 95%

2019 1,377,636 300,000 60,729 1,316,907 96%

2020 1,344,475 300,000 46,158 1,298,318 97%

2021 1,312,167 300,000 31,010 1,281,157 98%

2022 1,280,140 300,000 16,454 1,263,686 99%

2023 1,248,379 300,000 1,870 1,246,509 100%

2024 1,216,869 300,000 0 1,216,869 100%

2025 1,185,599 225,000 157,368 1,028,231 87%

2026 1,160,236 225,000 119,490 1,040,747 90%

2027 1,135,676 225,000 94,133 1,041,543 92%

2028 1,111,884 225,000 56,299 1,055,585 95%

2029 1,088,817 225,000 18,146 1,070,671 98%

2030 1,066,437 225,000 0 1,066,437 100%

2031 1,044,808 225,000 0 1,044,808 100%

2032 1,023,852 0 0 1,023,852 100%

2033 1,003,534 0 0 1,003,534 100%

2034 983,829 0 0 983,829 100%

2035 964,708 0 0 964,708 100%
EPA Contract No. EP-D-10-096

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Water Cost Impact Estimation

NIA water users who use CAP water have the temporary benefit of access to CAP supply due to 

agreeing on a declining allocation as described above. As part of the AWSA they are also granted 

access to a reduced rate for CAP water. In order to gauge the overall impact to NIA users of a 

potential increase in CAP water rates due to BART; it becomes necessary to estimate the non-CAP 

costs that are also a part of each individual’s supply portfolio.

A prefatory comment regarding any implied accuracy of the following estimates is required. Unlike 

the detailed survey technique employed for the Municipal CAP water users discussed previously, in 

the case of NIA water users, attempts were made to uncover underlying costs without direct 

contact with individual users. Following initial research in the matter, the conclusion was reached 

that each user (e.g. farm, association, and water district) has a unique set of circumstances that 

drive their water portfolio costs. Some may be able to utilize groundwater in higher volumes and at 

lower lifting costs depending on their unique situation with respect to geology and local aquifers. 

As a result, the approach used for sampling Municipal CAP water users was felt to be inappropriate 

for the NIA users.

And although the ADWR does amass a huge amount of data for its Water Atlas, and the work of the 

WRDC also provides an enormous amount of information, cost has not been an area of study. For 

this project, inquiries to the ADWR regarding any projections regarding cost they may have done or 

underway were met with the explanation that statewide investigatory efforts on price have not 

been conducted and are therefore unavailable. 

Without a more precise methodology to estimate cost impacts that BART may impose on overall 

NIA water costs, it is possible to use the discussion above regarding supply portfolios to make some 

imprecise but true statements. Specifically, the following two conclusions could be reached:

 Over time, CAP costs (and the effect of CAP cost increases over time) will cease to impact 

NIA as their access to CAP water eventually ceases. 

 The fact that NIA users today already get 75% of their supply from non-CAP sources 

indicates a “hedge” of sorts (all other factors remaining static) on the impact to overall costs 

if CAP-related water supply costs were to increase

In an effort to conduct a more thorough cost estimation exercise, public documents were examined 

in order to uncover some form of pricing disclosure that might allow a rough estimate to be made 
EPA Contract No. EP-D-10-096

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regarding how much changes in CAP costs might move overall water costs. The CAP costs, as 

described in the earlier portion of this report, can be projected using CAP water rate estimates 

driven by outcomes from the NGS Affordability Analysis modeling. For the portion of the Average 

NIA37 water user’s non-CAP costs, some ranges of values can be estimated based on research. The 

table at the end of this addendum utilizes CAP water rates impact estimates from the NGS 

Affordability Analysis and a range of non-CAP water costs, applied against the percentages of CAP 

versus non-CAP supply discussed earlier for the “Average NIA” CAP water user. 

Summary

The following table indicates that the significant percentage of non-CAP supply that serves NIA 

users in this analysis would act to dampen the cost impacts to the total user cost of water given a 

CAP cost increase arising from SCR. 

Table A-2 below indicates the results from this analysis. The highest incremental cost years are 

highlighted in bold. The varying percentage-of-cost impact of the SCR cases is caused by the 

shifting percentage of CAP supply that the WRDC estimates will be consumed by NIA over time. 

The estimates in this table are based on assumptions that include the following:

- Estimated low Non-CAP price is based on discussions with stakeholders regarding pumping 

energy costs

- Estimated mid Non-CAP price set to a point similar to the estimated 2014 CAP price

- The estimated high Non-CAP price is set above the mid price based on the same difference 

between the low and mid prices. ($25 spread)

- Assumes no changes in Non-CAP prices/costs over the period

Unlike the water cost impacts for M&I users discussed above, the highest impact years for NIA users 

as a result of an SCR investment do not necessarily coincide with the investment year for SCR due to 

the percentage of total supply represented by CAP in a given year..

 

37 The “Average NIA” water user clearly doesn’t exist given the highly variable supply portfolios they employ.

Thus, the term is used here to discuss only the values applied in the assessment which are themselves based 

upon overall and average NIA water data from ADWR.
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Table A-2

 

Low 

Range 

Est. Cost

Mid 

Range 

Est. Cost

High 

Range 

Est. Cost

Incr. Cost 

Impact 

($/AF) Low Mid High

2014 74% $ 25.00 $ 50.00 $ 75.00 26% $ 51.00 $ - 0.0% 0.0% 0.0%

2015 73% $ 25.00 $ 50.00 $ 75.00 27% $ 56.00 $ - 0.0% 0.0% 0.0%

2016 73% $ 25.00 $ 50.00 $ 75.00 27% $ 58.00 $ 3.09 2.5% 1.6% 1.2%

2017 75% $ 25.00 $ 50.00 $ 75.00 25% $ 58.00 $ 5.49 4.1% 2.6% 1.9%

2018 95% $ 25.00 $ 50.00 $ 75.00 5% $ 58.00 $ 8.40 1.7% 0.9% 0.6%

2019 96% $ 25.00 $ 50.00 $ 75.00 4% $ 58.00 $ 8.24 1.4% 0.7% 0.5%

2020 97% $ 25.00 $ 50.00 $ 75.00 3% $ 58.00 $ 8.08 1.1% 0.6% 0.4%

*2014 through 2016, CAP June 2011 CAP advisory rates, 2017 through 2020, estimated

Year

2016/17/18 Install: 2018 Compliance:

 % Chg in Total Supply Cost

(CAP + Non-CAP)

% of 

Supply 

from NonCAP 

Sources

ESTIMATED RANGE of NonCAP Water Supply Costs 

($/AF)

% of 

Supply 

from CAP

CAP 

Energy 

Rate 1*