# R EPORT 

# : A FFORDABILITY 

# A NALYSIS OF 

# BART O PTIONS 

# F OR 

# N AVAJO 

# G ENERATING 

# S TATION
EPA Contract No. EP

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# Final Report January 14 , 2013

P REPARED FOR 

## E C/R I NCORPORATED BY 

## E NERGY 

## S TRATEGIES 

## , LLCEPA Contract No. EP

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

### P REFACE 

### This document discusses the assessment process undertaken by and the findings resulting from Energy Strategies, LLC efforts on behalf of E C/R Incorporated in its work for the U. S. Environmental Protection Agency in regards to EPA Contract No. EP

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.

A UTHORS 

### & C ONTRIBUTORS 

### 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 85012EPA Contract No. EP

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

A FFORDABILITY A NALYSIS OF P ROPOSED EPA BART D ETERMINATION ON

N AVAJO G ENERATING S TATION (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 Depreciati on

- Supplemental Modeling

................................ ................................ .............. 49

MATS

– Supplemental Scenario Modeling

................................ ................................ .............................. 50
Decision Environment & Additional Factors

................................ ................................ ............................... 53
Environmental Regulation

................................ ................................ ................................ ...................... 54 ADDENDUM: Water Cost Impacts

................................ ................................ ................................ .............. 61EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 4 A FFORDABILITY A NALYSIS OF BART O PTIONS F OR N AVAJO G ENERATING S TATION (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 (N GS ) . This report focuses on the assessment methodology utilized and the findings specific to NGS

. Th e Executive Summary discu sses 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 asso ciated with SCR or SNCR implementation to a baseline case with low

- NO x 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 ho urs 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 model ed 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 own ers of NGS would elect to install controls on one unit per year to meet the 2018 compliance date.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 5 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 a dditional 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 S N CR

Case SCR

Case Market Cases

Unit 1 Plant as of

2011 with LNB/SOFA : BOR, SRP & IOU Cases BAU +

S N CR BAU +

SCR Low

Trend Mid

Trend High

Trend

Unit 2 BAU + S N CR BAU +

SCR

Unit 3 BAU + S N CR BAU +

SCR

Investment Schedule I.D. Description Installation Years by Unit A SCR on all units by 2018 # 2

- 201 6 , # 1

- 201 7 , # 3

- 201 8 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
utilit ies, also known as the Mercury and Air Toxics Standard s (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”.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 6 Cash Flow Case Results

T able E

- 2 below illustrate s 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 operati ng agreem ent

. To address the shift in ownership, t he 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 LA DWP share is acquired by a public ly

- owned utility or POU (as shown below) like S alt R iver P roject (SRP) . In these IOU and POU cases, the share represented as coming from LA DWP 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 illustrate s the 25 year NPVs for the combined plant cases where LA DWP’s share is acquired by
a P OU

.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 7 Table E

- 3 2016/2017 /201 8 SCR Installation Schedule: 25 Year NPV and 20 1 8 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

ass ociated with the retrofit case s

.

 R ate base for the BAU c ase includes an estimation of bo ok 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 Separate d Overfire Air (LNB/SOFA) on all three NGS units ( modeled as completed in
2011 ) , t he model assumes no new capital deploy ment 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 in stalled costs depending on how the dates change from
the assumed dates. Lower capital and operating costs would reduce the mod el results for the

cost to produce electricity.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 8  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 rep orted.
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 Rat e s & CAWCD Water Rate s

Since the model addresses cost at the wholesale level and by itself does not produce results regarding retail rates, secondary assessment s w ere 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 filing s and SRP’s share of the incremental cost associated with the retrofit s . 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 es timate the potential impact s of SCR or SNCR on a subset of Central Arizona Water Conservation District’s (CAWCD) water rates 2 . 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 calculate d 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 estimate d 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. governme nt for reimbursable costs of construction of the CAP aqueduct.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 9 Table E

- 4 2016/2017 /201 8 SCR Installation Impact on 201 8 CAP Water and SRP Electric Rates

The table above s how s the 201 8 Energy 1 rates respectively would increase $8.40 /AF ( 1 4.5 % ) when compare d to the estimated 201 8 CAP Energy 1 . Th is 201 8 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 ov erall 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 i s 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 rat e impacts are compared against an average utility rate that is unchanged from 2011 and does not account for potential changes in the utilit y’s costs, including other environ mental investments, large
investments in renewable energy, and other costs. Likewise, CAWCD rate results do not assume

any impact s 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, a n 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 entit led Water Cost Impacts

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 10 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 , ha s been estimated by other recent studies. Four particular studies o f
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: av ailability and cost of CO2 emission s offsets, CO2 allowance prices , growth in market

area e lectricity demand, and forward n atural gas prices. The latter three studies analyzed potential power and water costs under different BART scenari os, including SCR and SCR with b aghouse (note
that the EPA has indicated it does not consider b aghouse 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 differ ent modeling approaches and var ied 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.

T able E

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

. As portrayed in the table, t he “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 1 4.5 % 10.5% 13

– 16%EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 11 Sensitivity Cases & Supplemental Modeling

S everal 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 mo deling 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 accelerate d depreciation. The report contains a section entitled "Sensitivity Analyses" within which the outcomes of sensitivity and supplem ental 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 res ul ts in an NPV f or SCR that is 6.5 % higher than
the NPV for low market.

 Case outcomes are moderately sensitive to changes in lease cost

. A n increase in lease cost of $5 million annually (compared to the assumed $15 million annually) resulted in a
moderate reduction in NP V.

 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 +
b aghouse supplemental model, the CAP Energy Rate 1 rate would increase in 201 8 by

n early 30% over the estimated 201 8 rate.

Market Power Cases
There are several important considerations to keep in mind when interpreting the outcomes of market case s

.

 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, m arket pricing can be very volatile and may exceed the boundaries within the forecasted ranges in any given year by a significant amount.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 12  As discussed more fully in the report , m arket cases in this analysis do not include transmission related costs for purchased power or further downstream distribution cost s

.

 Finally, th e market scenarios make no assumptions regarding the recovery of stranded investments

– such as plant no longer used and useful and/or underutilized assets like long

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

Additional Factors

The decision

- making process of plant owners at NGS with respect to invest ment in SCR or other

man dated emissions controls will include consideration of other factors that are likely to materialize during the life of the plant. As discussed in the report, t hose factors are likely to include:

 GHG Emissions Regulation

 California Climate Change Regulat ions

 Plant Ownership

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

 Consideration of the Combined Effects of SCR and Additional FactorsEPA Contract No. EP

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## I ntroduction

The U.S. Environmental Protection Agency Region IX (“EPA”) is developing a Federal Implementation Plan to implement the Best Available Retrofit Technology (“BART”) requirement of the Regional Haze Rule on the Navajo Nation Indian Reservation

. The t wo emissions sources subject to BART on the Navajo Nation are the Four Corners Power Plant (“FCPP”) , near 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 Na tive 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 Th e document describes the actions taken by Energy Stra tegies 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 C AWCD

.



### 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 , t he plant operator, Salt River Project (“ SRP ”) , and the participating ow ners, had embarked upon a program to
install Low NOx Burners with Separated Overfire Air ( LNB/SOFA ) , on all three units at NGS 4

. 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 . T he 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 wh ich SRP

3 A second assessment and report prepared by Energy Strategies for E C/R addresse s FCPP and its unique market and economic circumstances 4 “ Navajo Generation Station SCR & SNCR Cost Study ”, SRP, July 25, 2008EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 14 stated that the total cost of the LNB/SOFA installations would be $45 million. 5 Estimates by
CAWCD 6 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” case s for NOx
reduction under in vestigation for this assessment involved installation of SCR or SNCR on each unit
at the NGS.
SRP’s August 2010 filing 7 of revised capital and operating cost estimates for SCR included three options:

 SCR only

 SCR with direct sorbent injection

 SCR with poli shing baghouse

For this assessment the retrofit technology option s 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 b aghouse s for MATS compliance, or compliance with possible future permitting requirements, as a BART requirement

. Multiple stakeholders, including the plant owners, have commente d 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 A vailable 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, 200 9
7 “ BART SCR and Baghouse Capital Cost Estimate Report ”, Sargent & Lundy” , SL

- 010214 , Re vision D , August 17, 2010EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 15 stakeholders have filed comments regarding their concern that the large CAPEX and incremental
OPEX for SCR would, at a minimum, substantially raise electric ity 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 International 8

. Noting the economic importance of NGS to the Navajo and Hopi communities, ICF addressed the question of whether mandating SCR investment at the NG S 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 a t risk for shutdown if natural gas prices were at or below $5.6/MM Btu (2008$). 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.

I ncremental CAPEX and OPEX at any power plant increase s 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
wil l 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 o perations (“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 wholes ale 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 Na vajo Generating Station ”.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 16 (“Marke t” 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 wou ld place on the long

- term economic life of NGS , many stakeholders voice d a concern that BART for NOx is only one
item on a long er list of issues that are likely to multiply the uncertainty of the plant’s future operations. The additional factors include green house gas (GHG) regulations, plant ownership change s , and other regulatory compliance issues. The potential impact of those issues and how they may be considered separately and in concert with a BART determination would be useful
information for EPA to consider in its BART determination process.

Therefore, the objectives of 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 t he 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 201 8

. 9 Also for comparative purposes, low, mid, and high trend ma rket 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 assume s that m arket purchases would be phased in over time, starting w ith wholesale power acquisitions to make up for the shutdown of Unit 2 at the end of 201 6 , followed by shutdown
of Unit 1 a t year end 201 7 , and finally Unit 3 at year end 201 8

. The affordability model returns net present values (“NPVs”) for a 25

- year period starting in 2012 and ending in 2036.

Th e remainder of this document describe s the modeling of SCR and SNCR cost implications , how
the y may impact the long

- term cost of power from NGS and water delivered by CAWCD

. Later on, this report addresse s a set of additional factors that, although not analyzed through model ing 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 comp liance date.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 17 

## Affordability Modeling Methodology & Case Analysis

The modeling employed to estimate the cost impacts of SCR and SNCR as well as market price case s consists of t he following six cases ( one existing plant case , two retrofit case s , 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 case s was depreciated on a Straight Line for plant in service

 The SCR and SNCR retrofit installation schedule was modeled as 201 6 , 201 7 , then 201 8 respectively

 For sensitivity testing, SCR was also treated with accelerated depreciat ion 10

 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 incrementa l 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 pe r interpretation of 26 U.S.C. § 169: US Code

- Section 169: Amortization of Pollution Control FacilitiesEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 18 Market Price Cases 11

Notes for All Market Price Cases:

 Market power costs are modeled to be phase d 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 pri ce 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 , 2 012 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 EIA 12 Low, Reference (for Mid), and High Macroeconomic Cases

A potential SCR investment decision, as well as any economic choice to shutter the plant rat her than install SCR, will be potentially long

- lived decisions ; 20 years or longer. E ach 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 i lluminating for some purposes, isn’t helpful for comparing the cost of sourcing energy from the market if NGS ceases operations. As stated above,

many comm enters expressed concern that retrofitting NGS would impact its competitiveness and potentially caus e , or greatly contribute to , a decision to close the plant. Commente rs conclude that
the loss of NGS as a resource to serve retail customer s 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 case s assume that the plant shut s 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 shutdown s in accordance with the
installation scenario described above

. For purposes of modeling the market cases, t he model

assumes a n 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 201 1 ”, U.S. Energy Information Administration,EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 19 generation is replaced with market purchases of forward, firm energy pri ced 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 relati ve 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 cost s especially as they may or may not perform well economically against the BAU and emissions
controls retrofit case.

I t 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 include s existing costs of the historical plant through 2011 13

– 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 below 14 . The respective year of
installation for SCR or SNCR for each unit is represented in Table 2 belo w :

Table 2 Year of Emissions Control Installation by Schedule Scenario

Unit No. Installation Scenario

Unit 2 20 16

Unit 1 20 17

Unit 3 20 18

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 ma jor maintenance cycl es for NGSEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 20 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 case s 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 allo ws comparison between 25

- year NPV s for each case analyzed.

The Model and Assumptions

T he 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 include d since the analysis is focused at the
wholesale cost level. Moreover, the NGS model accommodates differe nces 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 deprecia tion 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 recognit ion of the different owners’ capital recovery rates. In order to accommod ate 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 ow ner - specific dataEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 21 utilized for each specific cash flow 15

. 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 LA DWP 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 SC R
retrofit case.

F or 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 LA DWP's plan to divest it s 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 LA DWP will not continue to own its share of NGS in the
future , the model produces t w o full plant cash flow scenarios , one which combine s LA DWP's share as if that share continued as a publicly owned utility ("POU”), and a second scenario where the
LA DWP 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 w eighted a verage a pproved ROEs and w eighted a verage r ate s 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.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 22 the LA DWP share is assumed to take on capital recovery characteristics of either a POU (SRP in this case) or the IOU s

.

Capital and Operating Cost Inputs

Table 4 below il lustrates the capital and operating expenses assumed for each unit at NGS

.

Table 4 CAPEX & OPEX Assumptions 16

For mod eling 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 d iscussed 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 conducted 17 . The accelerated depreciation impacts are discussed in the “Sensitivity Analyses” section of this report. The BAU and SNCR case s 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 app lying to the federal government for certification status. This assessment assumes that the plant would qualify for certification and that all retrofit technologies, in the accelerated depreciation sub

- cases, would be eligible technologies under the Code. Confirmation of this assumption would require the consultation with tax accounting and tax law expertise.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 23 any depreciati on 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

.

T he followi ng pages refer to table s 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.

201 6 /201 7 /201 8 Installation Scenario

T able 5 illustrates the BAU net present value for the BOR, SRP and IOU ownership cash flows. T able
5 also illu strates 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 201 8 total power cost for each cash flow for the year 201 8 . For this installation scenario, 201 8 r epresents the highest cost year because in 201 8 the last of three units would have been retrofitted. After that time, capital depreciation reduces plan t 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 201 6 /1 7 /1 8 Installation Schedule ScenarioEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 24 As will be the case throughout this discussion of discounted cash flow comparisons, the highest
incrementa l 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 case s

.

T h e assessment not only compare s 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 LA DWP share of NGS, while the second table below assumes that an investor owned utility acquires the LA DWP share of NGS.

Both of these tables report out the net present value of the combined B AU , 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 table s indicate the estimate of BAU , SNCR and SCR case s 201 8 total power costs, as well as the 201 8 incremental dollar per megawatt hour cost. The percentage difference between 201 8 BAU and 201 8
SCR and SNCR power costs are also reported.

Table 6 25 Year NPV by Case for Total Plant ( LA DWP Share to POU) : SCR Installation in 201 6 /1 7 /1 8EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 25 Table 7 25 Year NPV by Case for Total Plant ( LA DWP Share to IOU): SCR Installation in 201 6 /1 7 /1 8

A comparison of Table s 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 N PV for SCR in the LADWP to POU case is lower than th e NPV of the low market case. However, the IOU

- Only case produces a higher NPV for SCR t han 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 appro priate 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 mod el outcomes.
Capital Cost Considerations
The model incorporates both the existing capital at the plant (BAU) and capital associated with the
SCR and SNCR retrofit case s . 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 poi nts about capital are
worth y 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 t he BAU c ase requires an estimation of the book value of the plant in service. T his value is derived by a set of calculations that assumesEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 26 original plant in service costs (from EIA 923, FERC F

- 1 filings , and other owner

- published cost filings ) and s traight 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 t o 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 estimate s 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 wo uld be consumed by the increase in the time value of the money expended.

4. For purposes of imparting a cost for capital invested, t he model uses a capital recovery rate for existing and new capital specific to each owner of the plant . This capital rec overy 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 base d 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 r etail electricity rate and water cost impact analyses for specific participants, t he mod el 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 leve l and not at the retail level, thus only generation

costs from NGS are wi thin this analysis. This distinction is important to note because retailEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 27 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, t he implications of SCR to retail electricity (and water) rates are discussed.

Market Power Cases
An important aspec t of this project has been creation of a model that will allow compari sons 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 mar ket 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 p ublicly 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 recent ly 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, b eyond 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 th e point by building the low, mid and high price forecasts for each relative

year 18

.

18 The same methodological approach was utilized in a previously completed analysis conducted under the same EPA Work Authorization with respect to e conomic impacts for BART determination at Four Corners Power Plant.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 28 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 project ed 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 forecas t, 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 stron g pric e 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

19 201 1 US EIA Annual Energy Outlook. http://www.eia.gov/oiaf/aeo/overview.htmlEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 29 Coordinating Council / Rocky Mountain Power Area and Arizona

- New Mexico

- Southern
Nevada Power Area are illustrated in Chart 2 below 20

.

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 m arket 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 201 6 , and n o longer operates a single unit by 201 9 , t he 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 PlantEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 30 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 long

lived 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 stran ded 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 o f 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)

. U nlike 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’ tota l annual energy production isEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 31 approximately 17,400,000 MWh 21 . 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 pote ntial impact to the value of excess power sales, are important considerations for CAWCD. As indicated above, w hen 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 L ower 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 S CR 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 certificate d 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 C olleen McKaughan , EPA Region IX , December 18, 2009 22 Modeer, December 18, 2009Prep ared for E C/R Incorporated by

Energy Strategies, LLC 32 Table 9Prep ared for E C/R Incorporated by

Energy Strategies, LLC 33 The incremental, non

- discounted cost of power from NGS as a result of SCR begins in 201 6 . 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 t h e yellow highlight ing in the table above. In general, the impact to SRP average retail electric rates is
estimated to be less than one percent in 201 8 scenario.

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

 The incremental “Who lesale Cost” as listed above represents each year’s non

- discounted, incremental cost resulting from SCR at NGS. The incremental cost peaks in 201 8 when the
third and final NGS unit is retrofitted.

 2011 average retail rates equal the total retail sales revenue as reported in 20 11. Subsequent year revenues ($) and sales (MWh) are each grown at 1.5% annually from 20 11 reported volumes . The escalation of revenues and sales c onservatively account s for the rate impact dilution that could occur as other cos ts, besides just NGS, also increase over time.

 Average retail electricity rates were held constant between 2011 and 201 4

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 inte rpret SCR’s impact on retail rates to occur in the highest incremental cost year without acknowledgement that costs might decline going forward.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 34 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 determinati on at NGS is clearly a critical area of importance to CAP/CAWCD and all its municipal, industrial, agricultural , and government al water users. The model employed allow ed 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 EPA 23

. H owever, those estimates may not comport to some assumptions that are incorporated in the model. F or instance , at the time of their filing in 200 8 , 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 i nclusion 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 CAW CD 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 the ir project ed 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 po wer 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

- I ndian agricultur al (NIA) water users as a result of costs associat ed 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, 2009EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 35 Th e assessment assumes that incremental capital and operating expense as a result of SCR
installation will be reco vered 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 fol lowing
T able 1 0 illustrates the annual estimated rate impacts for installation of SCR.Prep ared for E C/R Incorporated by

Energy Strategies, LLC 36 Table 1 0 Water Rate Impacts of Incremental CAPEX & OPEXPrep ared for E C/R Incorporated by

Energy Strategies, LLC 37 Table 10 illustrates Energy Rate 1 impacts as a result of SCR installation. As discussed above with respect to electricity rate impacts , t he yellow

- highlighted year represent s the highest incremental cost period as a result of SCR investment. Under the 201 6 /201 7 /201 8 installation schedule, the highest incremental cost year would be 201 8 when the CAP En ergy Rate 1 would increase $8.40 per acre foot, or 14.5 % of the estimated 201 8 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

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

Table 1 1 CAWCD Agricultural (Energy only) Rate Schedule (June 2011 )



## Comparison with Other Availabl e 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 analys e s 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 ( Proj ected 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 va riety 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 stud y 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) indica te s 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 toEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 38 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 inv estments associated with BART.

This study used c apital 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 Sar gent 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 parti cipating 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 b onds. 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 po wer 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 co st 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 c apital cost estimates for the various BART related t echnologies 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 wereEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 39 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 ann ual 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% f or 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 th e 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 r esources . 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 absorb ed by BOR would then be rolled into the power cost charged to the CAWCD. NREL
addressed the estimated im pact 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 20 11/12 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

- rel ated 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
increas e 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, inEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 40 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 rep lacing 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 onl y 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 + b aghouse 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 add itional 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
det ermined, 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 cont ained 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 CA P rates were then applied to the expanded water requirements of theEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 41 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 i ndicated 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 LC BDF, 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 N GS 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 afor ementioned 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
2 010 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 m acro 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 theEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 42 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 a nd 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 ass umed 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 developmen t 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 u nder 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 cumul ative 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 CA WCD 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 toEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 43 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 ‘stead y 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 surp lus 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 an d other expenses incurred in CAP operations.

The comparison of the NREL, HE and this study show s that each employed different methodological approaches to address a similar set of questions, those being the potential impact to power cost and
CAP water ra tes 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. E ach study basically indicates that the SCR p lus 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 fundame ntal 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 d iffer between studies.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 44 T able 1 2 presents a summary of the key assumptions and resulting outcomes of each modeling approach.

Table 1 2 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 p owerEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 45 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 pl ant 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 o ver 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 signi ficant 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 install ation 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 previou sly 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 a t 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 ou tcomes 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 assum ing that the LA DWP 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 th ese sensitivity analys e s are displayed in the following T able 1 3

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 46 Table 1 3 Market Power Price Sensitivity Outcomes

The first set of columns in Table 1 3 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 compariso n to the baseline model, where low market is 9 % greater than BAU, a 20% increase in low market would increase the pe rcentage 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 mar ket 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 it s lease payment to the Navajo
N ation for use of the Four Corners Power Plant site increased roughly $7 million per year followingEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 47 its recent lease contract negotiations 24

. 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 1 4 Lease Cost Sensitivity Outcomes

For sensitivity modeling purposes, an assumption was made that plant site lease cost s would
increase only $5 million annually versus the $15 million per year assumption utilized in the base
case mode l

. , 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 th e analysis are displayed in T able 1 4

. As illustrated in the table, increases in annu al lease costs of $5 million compared to the $15 million do es 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

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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 chang es 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 T able 1 5

.

Table 1 5 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.EPA Contract No. EP

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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 mod eling approach utilizing accelerated depreciation 25 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 $12 4 million lower 25 year NPV.

Table 1 6

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 dep reciation sub

- cases, would be eligible technologies under the Code. Confirmation of this assumption would require the consultation with tax accounting and tax law expertise.EPA Contract No. EP

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### MATS

– Supplemental Scenario Modeling

E stimated 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 scenario s , baghouse capital and operating

expenses 26 , and their respective year of installation, are identi fied in Table 1 7

.

Table 1 7 Bagh ouse, SNCR & SCR CAPEX & OPEX Inputs

Table 1 7 lists CAPEX and OPEX in 201 2 dollars. C apital and operating expenses were escalated by
the standard rate of inflation in the model from 201 2 to the year of their installation. Th e sensitivity analysis was based on the 201 6 /201 7 /201 8 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 t o occur on NGS units 2, 1, and then 3, in that order
in successive beginning in 201 5 . As previously defined, the retrofit installations occur on units 2, 1
and then 3 in that order in successive year beginning in 201 6

.

B aghouse CAPEX is 21% higher than t he 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 201 2 dollars. The incremental CAPEX and OPEX of baghouse
investments for MATS compliance increase the total capital investment by approximately 1 18 %
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 billi on 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 $76 0 million higher

.

26 Salt River Project Navajo Generating Station

- Units 1, 2, 3 SCR and Baghouse C apital Cost Estimate Report, Table 9

- 3, SL

- 010214, Revision D ; August 17, 2010

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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 2 0 below illustrate the dollar and percentage increases over the BAU case as a result of SCR + baghouse.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 52 Table 19 Estimate Average Retail Rate Impact for SRP

Table 2 0 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

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 53 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 impact s

.

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 pote ntial 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 En vironment & 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 mandate d 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

r ange 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. S everal owners are common to both plants and a decision on one plant is highly likely to influence the d ecision on the other.



## Additional FactorsEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 54 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 fu ture of the plant . The additional factors that may impact decision making are:

 G reenhouse gas (GHG) emissions regulation

 California climate change regulations

 Power plant ownership

 MATS

 F ly ash & ash handling regulations

 C oal 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 descr ibed 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 f ollowing 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 EP A, 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

.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 55 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% i ncremental 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 em itted 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 co al plant.

California C

limate C hange R egulations & Plant Ownership

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

to enact plans to reduce GHG emissions to 1990 levels by 2020. AB32 specifically require s CARB to create a plan and enact such plan to achieve the emissions reduction target.

Senate Bill 1368 (SB13 6 8) became law in April 2006 and set performance standards with regards
to emissions of GHG from electric generators. Specifically, SB 1368 sets standards for new long

term financial investments in electricity generation located in California as well as electricity imported into the State to serve Calif ornia 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 n oticeable in the utility industry in California. These two statutes, along with an expansion of the California renewable portfolioEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 56 standard 27 has shaped planning decisions for many California utilities and influenced the following specific actions:

 Souther n California Edison announced its intention to vacate its ownership interest in FCPP
when its contract ual 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 ent ail 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 thei r operating agreements, or to a th ird 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 t his 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. T he 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

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- 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.jspEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 57 agencies, investor owned utilities (IOUs) and public power entities as indicated above. Table 2 1
below illustrates the respective MW share from each unit owned by each shareholder.

Table 2 1 Navajo Generating Station Utility Share of Operating Capacity (MW)
Unit # BOR SRP LADWP APS NV Energy TEP Total
1 182 163 159 105 85 56 750 2 182 163 159 105 85 56 750 3 182 163 159 105 85 56 750 Total 547 488 477 315 254 169 2,250 % of Plant 24% 22% 21% 14% 11% 8% 100%
While FCPP is owned almost entirely by the parents of IOUs (APS, SCE, TEP & EPE account for 93% of total plant ownership), roughly 2/3 rds of NGS is owned by governmental entities (BOR, SRP & LADWP). As indicated by the blue lettering above, the three largest electric utilities in Arizona each own shares of both plants. Only one of the eight entitie s 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, m any 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 stak eholders (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:

Tabl e 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/alternativesEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 58 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 presu mably 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 f o r handling and disposal of Coal Combustion Residuals (CCR) 32 have the potential to increase the cost of production for c oal

- 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 increment al 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
vie wed 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.

Co ntractual 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 o r market costs. Those entities that have the greatest to gain

31 Docket No. EP A

- HQ

- OAR

- 2009

- 0234
32 Docket No. E PA

– HQ

– RCRA

– 2009

– 0640, Hazardous and Solid Waste Management System; Identification and Listing of Special Wastes; Disposal of Coal Combustion Residuals From Electric UtilitiesEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 59 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 reas onable 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 rel y 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.

There fore, 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 w ould 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 serv ice 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 t heir 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 CAWC D are not electric utilities per se, their decisions must be guided by service to their water customers and the federal agencies.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 60 Evaluating Multiple Risks

T he 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 s uch 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 diff erent, 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 sensitiv ity 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 eq uations 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 alte rnatives. 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 disc ussed 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. Th is 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 probabil ity
distributions for each of the Additional Factors as well as all other CAPEX and OPEX variables.EPA Contract No. EP

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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 N GS 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 re sult in a 0.6 5 percent
increase to the average retail electricity rate for customers of SRP.

Th e 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 fo r Municipal & Industrial ("M&I") and non

- Indian Agricultural ("NIA") water users 33 . Although EPA requested information from tribes regarding current and projected water volumes and costs for this study,

s ufficient information was unavailable at the time the analysis was conducted; therefore, impacts to
total water supply costs to tribes could not be included in th is assessment. The assessment described below utilized the incremental CAWCD Energy Rate 1 results from the NGS Affordability Analysis model for th e 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”) desc ribes 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.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 62 As indicated in the chart above, the sources of water used in Arizona includes surface water (Colorado River water, including CAP wa ter, and in

- state surface water), groundwater and reclaimed water or effluent. Arizona water supplies for the period of 2001

- 2005 34 , averaged approximately 7,500,000 acre

- feet per year, as summarized by ADWR. During that time, CAP provided approximately 1 5% of the state’s water suppl y . 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 statew ide water data published by ADWR and available at the time of this assessment.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 63 counties respectively are called the Phoenix AMA, Pinal AMA, and Tucson AMA. Their total average
annual water demands from 2001

- 2005, including Indian water us age , 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 wit h 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 specific ally
located in the three AMAs that receive CAP water.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 64 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. A ll 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%
N on - 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 R iver 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. Th at 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 purchasedEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 65 in the wholesale power marke t. 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 fiv e 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 instanc e, 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 s tudy. 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 pr ojected increase in the NGS Affordability Analysis . The differences are

gre ater, however, in the SCR with b aghouse scenario (again, for 2020 )

- $ 12.90/AF vs. $ 16.11/AF in
the NGS Affordability Analysis.

CAP Water Rate Impact
The following table combin es the output reported in the NGS Affordability Analysis ’s Table 13 regarding the incremental CAP water rate impacts associated with SCR costs for the
201 6 /201 7 /201 8 installation schedule.Prep ared for E C/R Incorporated by

Energy Strategies, LLC 66 Table A

- 1 SCR Incremental Power & CAP Energy Rate 1 Cost by Installation ScenarioPrep ared for E C/R Incorporated by

Energy Strategies, LLC 67 The estimated increases in CAP Energy Rate 1 as identified in the pr ior 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 d elivering 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 cu stomers 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 CAWCD 35 , 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

su bcontractor 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 sp ecifically total approximately 471,000 in this listing.EPA Contract No. EP

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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

a nd 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.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 69 Respondents were encouraged to provid e 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 percen tage of water use represented by CAP supplies for each Municipal user’s unique water supply portfolio.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 70 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 ear lier 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 il lustrates 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 c osts indicated in Table
A

- 1 are applied to each user’s CAP water supply volumes under the 201 6 /201 7 /201 8 installation
schedule.Prep ared for E C/R Incorporated by

Energy Strategies, LLC 71 Chart A

- 1Prep ared for E C/R Incorporated by

Energy Strategies, LLC 72 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. T he highest impact year is the final year of installation, namely 201 8. The 201 8 incremental cost impacts range fro m 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 lowes t 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 use rs would experience escalating water costs beginning in 201 6 , peaking in
201 8 as a result of SCR under a 201 6 /201 7 /201 8 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.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 73 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 Agri cultural (“NIA”) users. NIA water use is
discussed below in this section. The ADWR publishes a planning document call ed 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 A rea includes the Prescott, Phoenix, Pinal, Santa Cruz, and Tucson AMAs as indicated in the following map

.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 74 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 an d 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 a lmost 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 demandEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 75 should not significantly increase within the AMAs as may occur in non

- AMA planning
areas. Ad ditionally, 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 i nformation 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 Commiss ion’s (WRDC) 2011 Water Supply and Demand Working Group Report , acres under cultivation (non

Indian) within the Phoenix, Pinal, and Tucson AMAs are expected to continue the trend of decline
that has been exhibited in recent years

. The WRDC report 36 develop ed 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 , AppendixEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 76 As evidenced by the data represented in the following chart, f rom 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 non

Indian 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 2,153,90 0EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 77 The estimated future agricultural water needs discussed above represent demand s satisfied by a variety of water sources, including CAP water. With respect to NIA demands that may be satisfied specifically by CAP water, a ccording 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 histor ical quanti t y 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 non

Indian

- 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 Sett lement” water will cease by 2031, and the availability of water decreases over time according to the followingEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 78 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 tha t 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. Th e 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

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 79 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 quick ly. 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 Atla s , the average for the ten years ending
in 2006 for NIA non

- CAP water supply as s percentage of total was approximately 64%.EPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 80 Water Cost Impact Estimation

NIA water users who use CAP water have the temporary benefit of access to CAP supply due to

agree ing 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 neces sary 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 w ater 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 e normous amount of information, cost has not been a n 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
NI A 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 su pply 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 madeEPA Contract No. EP

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Prep ared for E C/R Incorporated by Energy Strategies, LLC 81 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
NIA 37 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 t he 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 co st 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 l ow Non

- CAP price is based on discussions wi th stakeholder s regarding pumping energy costs

- Estimated m id Non

- CAP price set to a point similar to the estimated 2014 CAP price

- The estimated h igh Non

- CAP price is set above the m id 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 f or 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

. T hus , 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.Prep ared for E C/R Incorporated by

Energy Strategies, LLC 82 Table A

- 2