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Energy

Analysis

Navajo Generating Station

Navajo Generating Station and Air 

Visibility Regulations: 

Alternatives and Impacts

David J. Hurlbut, Scott Haase, Gregory Brinkman, 

Kip Funk, Rachel Gelman, Eric Lantz, 

Christina Larney, David Peterson, 

Christopher Worley

National Renewable Energy Laboratory

Ed Liebsch

HDR Engineering, Inc.

Prepared under Task No. WFJ5.1000

Technical Report

NREL/TP-6A20-53024 đƫ!2%/! ƫMarch 2012

Contract No. DE-AC36-08G028308

Produced under direction of the U.S. Department of the Interior by the National Renewable Energy Laboratory (NREL) under 

Interagency Agreement R11PG30024 and Task No. WFJ5.1000.
ERRATA SHEET 

NREL REPORT/PROJECT NUMBER: NREL/TP-6A20-53024

DOE NUMBER: N/A

TITLE: Navajo Generating Station and Air Visibility Regulations: Alternatives and 

Impacts, Energy Analysis, NREL (National Renewable Energy Laboratory) 

AUTHOR(S): David J. Hurlbut, Scott Haase, Gregory Brinkman, Kip Funk, Rachel 

Gelman, Eric Lantz, Christina Larney, David Peterson, Christopher Worley 

National Renewable Energy Laboratory 

Ed Liebsch 

HDR Engineering, Inc. 

ORIGINAL PUBLICATION DATE: 1/18/2012 

DATE OF CORRECTIONS (MM/DD/YYYY): 3/15/2012 

Revised March 2012:

x Page 75: Replaced incorrect data in Table 5-1. 

x Page 84: Replaced incorrect data in Table 5-6. 

x Page 106: Replaced incorrect data in Table 7-1. 

This report, as originally published, also contained editorial errors that have been 

corrected in this revision. No changes, except those noted here, affect the substance of the 

report or the authors’ intent. 

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ii

Executive Summary

The U.S. Environmental Protection Agency (EPA) 

intends to issue rules for controlling emissions from 

the Navajo Generating Station (Navajo GS) that 

contribute to haze at the Grand Canyon and at several 

other national parks and wilderness areas. The ¿nal 

rule will be based on what EPA determines is the best 

available retro¿t technology (BART) for the control of 

haze-causing air pollutants, especially nitrogen oxides 

(NOx

). 

Several factors make this case unusually complex. 

Unlike other coal plants in the West, Navajo GS came 

into being at the initiative of the federal government. 

Low-cost power from Navajo GS runs the massive 

pumps of the Central Arizona Project (CAP)—a major 

water delivery project built to ful¿ll terms of the 

Colorado River Compact, a multistate water agreement 

that many consider to be one of the most contentious 

in U.S. history. ,n addition, the plant and the coal mine 

that supplies it are located on tribal lands. The U.S. 

Bureau of Reclamation (Reclamation) owns the largest 

share of the plant on behalf of the federal government. 

Some of Reclamation’s sister agencies within the U.S. 

Department of the ,nterior, however, have missions 

relating to tribal affairs, national parks management, 

and habitat protection that in this case are not easily 

reconciled with Reclamation’s job of supporting the 

CAP with low-cost power.

Many of the analyses conducted by and for parties 

in this case have contemplated three possible BART 

outcomes: 

Ŷ accepting existing plant improvements as the 

standard with no additional retro¿t

Ŷ adopting a new control technology such as 

selective catalytic reduction (SCR) as the 

standard or 

Ŷ shutting down Navajo GS because of the 

cost of SCRs and other upgrades that may be 

required under future emission rules. 

The two SCR scenarios include SCR only, and SCR 

plus additional controls (baghouses and sorbent 

injection) in anticipation of future emission regulations. 

Navajo GS owners are also considering selective noncatalytic reduction, which would cost less than SCR 

but would remove less NOx

.

Under any outcome, the burden of compliance will 

probably fall most heavily on those who rely on the 

federal government’s 24.3% share of the power plant. 

Furthermore, the web of needs laying claim to the 

government’s share is uniquely complex. Therefore, a 

BART outcome that met ,nterior’s interests—secure 

sources of power for CAP, no additional disruption of 

tribal economic development, and good stewardship 

of national parks and other public lands—would in 

all likelihood be adaptable to the needs of the utilities 

that rely on Navajo GS for part of their conventional 

supply needs. This would especially be true if the 

outcome allowed time for ,nterior to prepare for a 

smooth transition to cleaner energy sources for CAP, 

and allowed the utilities time to fully depreciate their 

current investments in Navajo GS.

EPA’s statutory authority in this particular proceeding 

focuses on visibility at national parks and other 

priority areas. The analysis and ¿ndings of this report 

(conducted by NREL for the Department of the 

,nterior) focus on these statutory issues and therefore 

address only a small subset of the issues facing 

coal-¿red power plants throughout the country. This 

report does not address the larger question of whether 

Navajo GS should continue operating or should retire. 

Rather, the questions have to do with how proposed 

changes to the plant are likely to affect visibility. (A 

supplemental volume examines the feasibility of using 

clean generating technologies to achieve comparable 

outcomes.)

With respect to BART determinations, the Clean Air 

Act requires EPA to

...take into consideration the costs of compliance, 

the energy and nonair quality environmental 

impacts of compliance, any existing pollution 

control technology in use at the source, the 

remaining useful life of the source, and the 

degree of improvement in visibility which may 

reasonably be anticipated to result from the use 

of such technology.1

1 CAA Sec. 169A, Sec. 42 USC 7491 (g)(2).
iii

This report’s main conclusions 

address these statutory factors.

Cost of compliance

Economic analysis suggests 

that, holding all other factors 

the same, installing SCRs at 

Navajo GS would likely cost 

less than shutting it down and 

replacing it with power from 

unused capacity elsewhere in 

the West. Key uncertainties 

that could affect the basic 

economics include (among other 

factors) investment recovery 

timelines, changes in future 

plant ownership, changes in 

transmission path ratings, 

renegotiating the site lease 

with Navajo Nation, and delivery commitments under 

long-term power contracts.2

 Figure ES-1 shows likely 

ranges of additional annual costs associated with two 

SCR scenarios, and with shutting down the plant and 

replacing it with the West’s least expensive unused 

capacity. 

The cost burden of either SCR option or shutdown 

would probably fall more heavily on the Bureau of 

Reclamation than it would on any of the ¿ve utilities 

that also own shares of Navajo GS. This is due to the 

fact that Reclamation and the Central Arizona Water 

Conservation District rely on Navajo GS for 92% of the 

total electricity needed for the CAP, while the utility 

partners rely on the plant for only 9% to 26% of their 

total electricity supply.

SCR capital costs would result in a likely retail 

rate increase of between 0.02 cents to 0.06 cents 

per kilowatt-hour for Navajo GS’ utility partners. 

This would translate into a rate impact of 0.2% to 

0.6%. Other uncertainties could result in increased 

business costs besides capital costs that would also be 

recovered in retail rates. Separately, The operation and 

maintenance (O&M) costs associated with SCRs would 

increase Navajo GS variable production costs by 3% 

to 4%, which would leave the plant still as one of the 

lowest-cost generators in the Desert Southwest.

2 Chapters 1 and 2 contain additional explanation of these uncertainties.

Unlike its utility partners, Reclamation lacks an 

established rate mechanism for recovering its share 

of future capital costs for Navajo GS. Assuming no 

federal appropriations, the additional capital costs and 

production costs associated with SCRs would probably 

increase power costs for the CAP by 0.39 cents to 

0.48 cents per kilowatt-hour. For agricultural users 

and ,ndian tribes, water rates from CAP would likely 

increase between 13% and 16%. For municipal and 

industrial users, the increase would likely be between 

5% and 7%. Baghouses and sorbent injection would 

roughly double the impact on water rates.

Energy impacts of compliance

,nstalling SCRs would not signi¿cantly change the 

amount of energy provided by Navajo GS. On-site 

employment at the power plant and the mine would 

be unchanged, except for the possible addition of a 

small number of jobs at the power plant to operate and 

maintain the SCR equipment.

Shutting down Navajo GS would change the regional 

Àow of power. Least-cost redispatch would tend toward 

replacement power from combined cycle natural gas 

plants in Nevada, Arizona and Southern California 

that already exist and have spare capacity. Southern 

California currently obtains a large portion of its 

electricity supply from Arizona and Nevada. Shutting 

down Navajo GS would tend to reduce these Àows, 

$-

$200

$100

$400

$300

$500

SCR only SCR, baghouse, sorbent

injection

Replacement

(shutdown)

(millions)

Figure ES-1. Likely ranges of additional annual costs for retrofits, shutdown

Baseline for comparison: existing controls as BART (no additional cost).
iv

with more of the power that is generated in Arizona 

remaining in state. 

Nonair quality environmental impacts 

of compliance

Environmental impacts aside from air quality 

primarily affect the Navajo and Hopi populations 

living near the power plant and the mine that supplies 

its coal. Non-governmental organizations express 

concerns about harm to health and groundwater in 

particular. No epidemiological studies have speci¿cally 

examined health impacts resulting from either Navajo 

GS emissions or coal mining operations. ConÀicting 

studies offer different conclusions about the effect of 

mining operations on local ground water. Nevertheless, 

these impacts—regardless of their true extent—are 

largely a function of whether the plant operates 

at all. 9isibility-related retro¿ts that would result 

in continued operations at the plant and the mine 

would likely cause no discernible change in these 

environmental impacts. 

Existing pollution control technology

Scrubbers installed at the three Navajo GS units in 

2000 have reduced SO2

 emissions by more than 95%. 

Low-NOx

 burners and separated over¿re air systems 

have reduced NOx

 emissions by 40%, relative to what 

the plant’s air permit allowed before these controls 

were added. This compares to the 78% reduction that 

could be achieved with the addition of SCRs, and the 

50% to 60% reduction estimated for SNCR controls. 

Remaining useful life

Navajo GS will have been in service 45 years when its 

site lease with Navajo Nation expires in 2019. While 

45 years was a typical useful lifespan for smaller coal 

plants in the U.S. built prior to Navajo GS, larger coal 

plants built around the time of Navajo GS appear to be 

lasting longer, in that relatively fewer of their group 

are retiring early and the ones that remain continue 

to sustain high capacity factors. The utility partners’ 

capital investments in Navajo GS (including retro¿ts to 

date) are on track to be fully depreciated no later than 

2026, when the plant will have had more than 50 years 

in service.

Degree of improvement in visibility

While conclusions in this report regarding the 

electricity sector are clear, those regarding visibility 

must be more circumspect. The question fundamental 

to this proceeding—how reducing NOx

 from Navajo 

GS would contribute to improving visibility at the 

Grand Canyon and other areas of concern—requires 

a deeper inquiry and more time than was allowed for 

this project, and it requires expertise in atmospheric 

chemistry and air transport modeling, not power sector 

expertise. Evidence suggests that NOx

 emissions from 

Navajo GS are a likely incremental contributor to 

haze at the Grand Canyon. Whether the incremental 

contribution is signi¿cant or even perceptible is a 

matter of debate among experts in the ¿eld of visibility 

science.

Monitoring and other evidence suggests NOx

 is a 

weaker contributor than SO2

, which has already 

declined 95% at Navajo GS since the installation 

of scrubbers in 2000. The body of research to date 

(summarized in this report) is inconclusive as to 

whether removing approximately two-thirds of the 

current NOx

 emissions from Navajo GS would lead to 

any perceptible improvement in visibility at the Grand 

Canyon and other areas of concern. 

Summary of Tribal Benefits and 

Impacts

The EPA’s BART determination will have diverse 

impacts on Arizona’s tribes. There are two primary 

categories of effects: those related to power generation 

and mining, and those affecting the cost of CAP water 

delivered to tribes who have signed water settlement 

agreements, including potential funding that could 

be made available through the Lower Colorado River 

Basin Development Fund (Development Fund).

Tribal economic bene¿ts associated with the direct 

operations of both the Navajo GS and Kayenta mine—

more than $150 million per year—would continue to 

accrue under all future scenarios with the exception 

of complete plant shut down, or the shutdown of one 

or more individual units. Approximately 450 Native 

Americans are employed at the Navajo GS, and 400 

are employed at the mine. The total wages and bene¿ts 
v

paid to Native employees of the plant and mine are 

approximately $100 million per year. ,n addition, the 

Kayenta mine also makes annual payments of just over 

$50 million per year to the Navajo Nation and Hopi 

Tribe ($13 million to Hopi, $37 million to Navajo) 

for coal royalties and bonuses, groundwater usage, 

and purchase of electricity from the Navajo Tribal 

Utility Authority. Additional bene¿ts for the tribes 

include several hundred thousand dollars per year 

in scholarship funds, and local property taxes which 

primarily go to schools in the region. SRP also pays 

the Navajo Nation about $1 million/year in lease and 

air permit fees for the Navajo GS itself. 

A signi¿cant increase in the cost of power from 

Navajo GS could affect settlements with some ,ndian 

tribes who surrendered future water right claims in 

exchange for low-cost access to CAP water and other 

bene¿ts. ,nstallation of SCR controls at Navajo GS 

would likely increase tribes’ water delivery rates by 

13% to 16% ($7 to $9 per acre-foot) SCR controls with 

baghouses would double that impact. A more detailed 

examination of the implications for tribal water 

settlements (for example, determining the threshold at 

which the rate increase would be materially signi¿cant) 

would require a legal analysis that was beyond the 

scope of this study. ,f Navajo GS were to shut down, 

the ,ndian and Agricultural users of CAP water would 

see per acre-foot increases of as much as 66%, while 

municipal and industrial users would see increases up 

to 52%.

A signi¿cant area of concern for CAP water-using 

tribes relates to the potential for sales of surplus 

Navajo GS power to exceed the $55 million annual 

CAP repayment obligation. ,n cases where annual 

revenue into the fund exceed $55 million, the “second 

cascade” of funding disbursements would kick-in, with 

initial funds in the second cascade going to reduce 

the ¿xed operations, maintenance and replacement 

charges associated with the delivery of CAP water to 

,ndian tribes. Under a new agreement related to the 

sales of surplus Navajo generation, approximately 1 

TWh of primarily off-peak power would be up for 

sale on the general wholesale power market, making 

this portion of excess power revenue more directly 

subject to market prices. Current power prices are not 

high enough to support Àows into second-cascade 

disbursements, nor have they been since 2008. Two 

factors could mitigate against higher power prices in 

the future: success of energy ef¿ciency programs in 

Arizona and other Southwest states, and additional 

natural gas supplies resulting from the development of 

shale gas. 
vi NREL/TP-6A20-53024

Table of Contents

Executive Summary ii

Introduction 1

1 Navajo GS Origin and Operations 7

1.1 Regulatory Background and Ownership Interests 9

1.2 Navajo GS in the Utility Partners’ Generating Fleets 15

1.3 Power Plant Operations 22

2 Regional System Impacts of Retiring Navajo GS 27

2.1 Selection of modeling approach 28

2.2 Redispatch: What the system would use to replace Navajo GS 32

2.3 Production costs: How expensive to do without Navajo GS? 35

2.4 Impact on Bureau of Reclamation and CAP 40

3 Control Technologies—Cost of Retrofits 43

3.1 Technologies Implemented for Emission Controls 44

3.2 Particulate Matter Reduction and Sorbent Injection 49

3.3 Conclusion 52

4 Central Arizona Project and Navajo Generating Station 53

4.1 Background to CAP 53

4.2 CAP Repayment Obligations and the Development Fund 54

4.3 Navajo GS and CAP Water Rates 58

4.5 Summary 69
NREL/TP-6A20-53024 vii

5 Assessment of Visibility Science 71

5.1 Regulatory Framework 71

5.2 Emissions and Visibility Trends for Southwestern States 74

5.3 Modeling Studies of Navajo GS Visibility Impacts 76

5.4 Monitoring and Related Studies at Regional Class I Areas 80

5.5 Visibility Monitoring Metrics and Regional Trends 83

5.6 Control Technology Options and Cost/Benefit Analysis 85

5.7 Summary of Key Points 90

6 Impacts on American Indian Tribes in Arizona 93

6.1 Tribes and Power Generation 93

6.2 Tribes with CAP water allocations 101

7 Economic and Employment Impacts 105

7.1 Estimation of primary and secondary effects related to Navajo GS 105

7.2 Economic and employment profile of the three-county region 106

Conclusions 111
viii NREL/TP-6A20-53024

Figures

Figure ES-1. Likely ranges of additional annual costs for retrofits, shutdown iii

Figure 1-1. Navajo Generating Station and Central Arizona Project 8

Figure 1-2. Age, capacity factor and size of coal units in WECC 16

Figure 1-3. Estimated Share of SCR Retrofits Based on Current Ownership 

($ millions) 20

Figure 2-1. Balancing authority areas modeled by NREL 30

Figure 2-2. Bus points included in the model 30

Figure 2-3. Navajo GS in the power supply curve for the Desert Southwest 31

Figure 2-4. Spot price of natural gas at the Permian Basin Hub, 2008 to date 31

Figure 2-5. Annual net generation by BA, base case 34

Figure 2-6. Change in net generation without Navajo GS 34

Figure 2-7. LMP distribution with and without Navajo GS (Natural Gas: $6.90 per mmBtu) 38

Figure 2-8. Change in average annual LMPs when retiring Navajo GS 39

Figure 3-1: Estimates of SCR capital costs in the Western Interconnection 48

Figure 4-1. Revenue flows into the development fund 54

Figure 4-2. Distribution of CAP water deliveries in 

2010 (acre-feet) 58

Appendix A: First Cascade of the Settlements Act Payment Priorities 70

Figure 5-1. Navajo GS location relative to PSD Class I areas within 300 km 72

Figure 5-2. Relationship between atmospheric light extinction, deciviews, and visual range 73

Figure 5-3. SO2

 emission trends for large power plants in the vicinity of the GCNP 76

Figure 5-4. NOx

 emission trends for large power plants in the vicinity of the GCNP 76

Figure 5-5. Annual and seasonal wind roses for Flagstaff, Arizona 82

Figure 5-6. Annual profile of sulfate, nitrate and sulfate:nitrate ratio for Indian Gardens 85

Figure 5-7. PM2.5, sulfate and nitrate annual average trends for Bryce Canyon 85

Figure 5-8. PM2.5,sulfate and nitrate annual average trends for Canyonlands 86

Figure 5-9. PM2.5, sulfate and nitrate annual averagetrends for GCNP/Hance Camp 86

Figure 5-10. PM2.5, sulfate and nitrate annual average trends for GCNP/Indian Gardens 87
NREL/TP-6A20-53024 ix

Figure 5-11. PM2.5, sulfate and nitrateannual average trends for Mesa Verde 87

Figure 5-12. PM2.5, sulfate and nitrate annual average trends for Petrified Forest 88

Figure 6-1. Navajo generating station tribe map 94

Figure 6-2. Navajo Nation, Kayenta Mine revenues and general fund budget 2002-2005 ($ millions) 99

Figure 7-2. Total wages, by Sector, Apache, Coconino, and Navajo Counties, AZ, 2001-2010. 108

Tables

Table 1-1. Navajo Generating Station Ownership 10

Table 1-2. EPA Regulatory Actions Affecting Navajo Generating Station 12

Table 1-3. National Environmental Policy Act (NEPA) Actions Affecting Navajo Generating Station 13

Table 1-4. Other Regulatory Actions Affecting Navajo Generating Station 14

Table 1-5. Contribution of Navajo Generating Station to Utility Partners’ Generating Fleets 

(Owned, Operating Capacity Only) 14

Table 1-6. Utility Partners’ Interests in Navajo Generating Station $ in thousands 17

Table 1-7. Major Differences Between Capital Costs and Production Costs 18

Table 1-8. SCR Capital Cost Relative to Net Utility Plant 18

Table 1-9. SCR, Baghouse, Sorbent Injection Capital Costs Relative to Net Utility Plant 18

Table 1-10. Retail Rate Impact of SCR Capital Cost 19

Table 1-11. Retail Rate Impact of SCR, Baghouse, Sorbent Injection (Cents per kWh) 19

Table 1-12. Retail Rate Impact of SCR, SNCR, SCR with Additional Controls (% of Retail Rates) 19

Table 1-13: Impact of SCR, Baghouse, Sorbent Injection Capital Costs on CAP Pumping Power Cost 23

Table 1-14: Impact of SCR, Baghouse, Sorbent Injection Costs on CAP Water Rates SNL Energy; 

www.snl.com 24

Figure 1-4. Navajo GS monthly capacity factor 24

Table 1-15. Navajo GS Operation Summary (2010) 25

Table 1-16. Maximum Adjusted Nitrogen Oxide Emission Rates, 2009 – 2011 (lb/mmBtu) 25

Table 1-17. Average Adjusted Nitrogen Oxide Emission Rates, 2009 – 2011 (lb/mmBtu) 26

Table 2-1. Distribution of Navajo GS Production as Modeled in Base Case 33

Table 2-2. BA Replacement Needs Resulting from Retiring Navajo GS 33

Table 2-3. Types of Generators Used to Replace Navajo GS 35

Table 2-4. Interconnection-wide Production Costs ($ millions) 36

Table 2-5. Interconnection-wide LMP Averages, Minima and Maxima ($/MWh) 37
x NREL/TP-6A20-53024

Table 2-6. Changes in BAs’ Average LMP Assuming Navajo GS Retirement 40

Table 2-7. LMP Sensitivities for Natural Gas Price, Navajo GS Retirement 42

Table 2-8. Regression Analysis of Mohave Retirement and Wholesale Power Prices in California 42

Table 3-1: Nitrogen Oxide Emission Reduction Technologies 44

Table 3-2: NOx

 Permit Limits and Technology Performance 44

Table 3-4: Plants With Installed SCR Technology (Texas and Western interconnections) 45

Table 3-3: Selective catalytic reduction in U.S. power plants 45

Table 3-5: Power Plants With Installed SCR Technology (Eastern Interconnection) 46

Table 3-6: Two estimates for SCR installation at Navajo GS 47

Table 3-7: Capital Costs of SCR Installations Proposed in the Western Interconnection 47

Table 3-8: Selective non-catalytic reduction in 

U.S. power plants 50

Table 3-9: US Installations of SNCR’s By State 50

Table 3-10: SNCR Capital, Operation and Maintenance Estimated Costs 50

Table 3-11: Cost for SCR and Polishing Baghouse 51

Table 4-4. Scenario in which $10 million is Available for Second Cascade of Payment Priorities ($ M) 58

Table 4-1. Actual Revenues into the Development Fund, 2009 and 2010 55

Table 4-2. Net Values of Navajo GS Surplus Power Sales Revenues into the Development 

Fund, Backcast Based on the Post Four-Party Agreement Revenue 

Arrangement (in $ million) 56

Table 4-3. Revenues into the Development Fund in 2009 and 2010, Backcast Analysis 

Based on the Post Four-Party Agreement arrangement ($ M) 57

Table 4-5. Projected Costs of CAP Water by Component ($/AF) 58

Table 4-6. CAP Water Delivery Rates ($/AF) 59

Table 4-7. Net Value of Navajo GS Surplus Power Under a 2011 Base Case Scenario ($ M) 61

Table 4-8. Revenues into the Development Fund Under the 2011 Base Case Scenario 61

Table 4-9. Impact of SCR Installation on CAWCD’s Navajo GS Power Costs 61

Table 4-10. Increase in the CAP Pumping Energy Charge under the SCR Installation Scenario 62

Table 4-11. Changes in CAP Water Rate Components Under Low and High Cost SCR 

Installation Scenarios 63

Table 4-12. Increase in CAP Water Rates Under the Low Cost SCR Installation Scenario 63

Table 4-13. Increases in the Pumping Energy Charge Under the High Cost SCR Installation Scenario 63
NREL/TP-6A20-53024 xi

Table 4-14. Impact of SCR plus Baghouse & Sorbent Injection Installation on CAWCD’s 

Navajo GS Power Costs 64

Table 4-15. Increases in the CAP Pumping Energy Charge under the SCR plus Baghouse & 

Sorbent Injection Installation Scenario 65

Table 4-16. Increase in CAP Water Rate Components Under the SCR plus Baghouse & 

Sorbent Injection Scenario ($/AF) 65

Table 4-17. Increase in CAP Water Rates under the Low Cost SCR plus Baghouse & 

Sorbent Injection Installation Scenario 65

Table 4-18. Increase in CAP Water Rates Under the High Cost SCR plus Baghouse & 

Sorbent Injection Installation Scenario 66

Table 4-19. Impact of a Navajo GS Shutdown Scenario on CAP Pumping Power Costs 67

Table 4-20. Increases in the CAP Pumping Energy Charge and CAP Repayment Recovery 

Charge Under the Navajo GS Shutdown Scenario 67

Table 4-21. Increase in CAP Water Rate Components Under the Navajo GS Shutdown Scenario 

($/AF) 68

Table 4-22. Increase in CAP Water Rates Under the Navajo GS Shutdown Scenario (Low Power Price) 68

Table 4-23. Increase in CAP Water Rates Under the Navajo GS Shutdown Scenario (High Power Price) 68

Table 4-24. Increase in CAP Water Rates Under Various Navajo GS Scenarios ($/AF) 69

Table 4-25. Percentage Increase in CAP Water Rates Under Various Navajo GS Scenarios ($/AF) 70

Table 5-1. SO2

 and NOx Emissions Trends from 2002-2008 in Southwestern United States 75

Table 5-2. Comparison of Modeling Procedures for SRP and EPA Visibility Studies on Navajo GS 77

Table 5-3. CALPUFF Results for Original Navajo GS Baseline and for LNB/SOFA Operation 78

Table 5-4. CALPUFF Results for Navajo GS with SCR Operation 79

Table 5-5. CALPUFF Results for Navajo GS, SCR Improvement over LNB/SOFA 79

Table 5-6. Ammonium Nitrate Concentration Trends 84

Table 5-7. Navajo GS Cost/Benefit Analysis Ranges for SCR Based on SRP and EPA/NPS Analyses 90

Table 5-8. Visibility Cost/Benefit Comparisons 91

Table 6-1. Poverty Rates on Navajo and Hopi Reservations, 2005-2009 95

Table 6-2. Tribal Benefits Paid by PWCC ($ Millions) 96

Table 6-3. Hopi Tribal Revenue from Kayenta Mine Operations ($ Millions) 96

Table 6-4. Navajo Nation Revenue from Kayenta Mine Operations ($ Millions) 96

Table 7-1. Estimated On-site and Regional Employment Effect of Navajo GS 106

Table 7-2. Population and Ethnicity by County and Tribe 107

Table 7-3. Apache, Coconino, and Navajo County Employment and Wages by Industry 109

NREL/TP-6A20-53024 1

Introduction

The Navajo Generating Station has a distinctive role in the 

West’s story of electric generation and water development. 

,t is the western grid’s largest coal-¿red power plant. 

,ts stacks are 15 miles from where the Colorado River 

enters Grand Canyon National Park. ,t anchors the 

local economies of the Navajo and Hopi ,ndian tribes 

in northeastern Arizona. ,t powers the massive pumps 

for the Central Arizona Project (CAP)— a major water 

delivery project built to ful¿ll terms of the Colorado 

River Compact, a multistate water agreement that many 

consider to be one of the most contentious in U.S. history. 

,ts largest owner is not a traditional utility, but the federal 

government itself.

Pursuant to the Clean Air Act (CAA), the U.S. 

Environmental Protection Agency (EPA) announced in 

2009 its intent to issue rules for controlling emissions 

from Navajo GS that could affect visibility at the Grand 

Canyon and at several other national parks and wilderness 

areas. The ¿nal rule will conform to what EPA determines 

is Navajo GS’ best available retro¿t technology (BART) 

for the control of haze-causing air pollutants, especially 

nitrogen oxides (NOx

). 

The CAA’s statutory requirement for a BART 

determination will likely have collateral effects on other 

statutory mandates for several federal agencies, many 

of which are under the U.S. Department of the ,nterior. 

Also at play are policies regarding the long-term strategic 

transformation of electric generation in the United 

States, and ,nterior’s role in that transformation as the 

manager of federal lands and trusts. As a result, ,nterior 

has to reconcile diverse and sometimes divergent policy 

missions with respect to Navajo GS. A full and accurate 

understanding of the power sector is crucial to a wellconsidered response, and for that reason ,nterior requested 

assistance from the U.S. Department of Energy and 

its National Renewable Energy Laboratory (NREL) in 

developing an objective base of technical knowledge. This 

study is NREL’s response to ,nterior’s request.

While EPA is ultimately responsible for setting Navajo 

GS’ BART standards in its ¿nal rule, it will be ,nterior’s 

responsibility to manage compliance and the related 

impacts insofar as the BART determination affects the 

missions of its agencies. The likely range of options for 

what ,nterior and its agencies can do, however, is one 

set of questions EPA must consider in making its BART 

determination. This study by NREL aims to assist both 

,nterior and EPA by providing an objective assessment of 

issues relating to the power sector that may be outside the 

primary expertise of either, yet nevertheless will be crucial 

to a BART determination for Navajo GS.

NREL has taken an interdisciplinary approach to this 

study, drawing on its experience in systems analysis, 

economics, ¿nance, policy development, and research into 

advanced clean energy technologies. The objective is to 

provide base information and insights into:

Ŷ the role Navajo GS plays in the overall power 

supply picture

Ŷ how BART-related changes to the cost and 

operation of Navajo GS are likely to impact 

electricity customers, CAP water customers, and 

Tribes and

Ŷ how issues present in the Navajo GS case relate 

to the increasing use of cleaner energy sources, 

a transition that is happening throughout the 

electricity sector. 

This report draws on work NREL has done and is 

currently doing with the Western Governors’ Association, 

the Western Electricity Coordinating Council (WECC), 

regional organizations, and several western states. ,nsights 

from these efforts inform how NREL models bellwether 

changes in policy, technology or fuel supply that might 

affect electric generation in the Western ,nterconnection. 

All of these activities have involved close collaboration 

with state policy makers, regulators, industry and other 

stakeholders to ensure the assumptions and inputs are 

consistent with real-world experience. The detailed 

inputs that NREL uses in this analysis with respect to 

plant operating costs, Àow limits on each transmission 

element, local electricity demand, and many other system 

characteristics are identical to those used by WECC (the 

Western ,nterconnection’s regional reliability organization) 

in its own studies of regional system reliability. 
2 NREL/TP-6A20-53024

Aims of this study

Two closely woven imperatives shape the scope of 

this analysis. First are the statutory factors that the 

CAA requires EPA to consider in determining which 

technologies constitute BART for Navajo GS. The law 

requires EPA to

...take into consideration the costs of 

compliance, the energy and nonair quality 

environmental impacts of compliance, any 

existing pollution control technology in use 

at the source, the remaining useful life of the 

source, and the degree of improvement in 

visibility which may reasonably be anticipated 

to result from the use of such technology.1

Navajo GS’ role as the primary source of power for the 

water pumps of the Central Arizona Project (CAP) adds 

a formidable layer of complexity to some aspects of this 

statutory requirement, particularly with respect to the cost 

of compliance, the energy impacts of compliance, and 

the remaining useful life of the source. Environmental 

impacts other than air quality occur primarily on the 

lands of Navajo Nation and the Hopi Tribe, which brings 

into play the federal government’s trust responsibilities 

to Native American peoples. The tribal impacts involve 

economic development bene¿ts as well as potential health 

concerns.

The second imperative affecting the scope of this study 

is the long-term transformation of how the United 

States generates its electricity. Numerous legislative and 

executive measures have aimed to increase the utilization 

of clean energy sources, and major initiatives by the 

Department of the ,nterior are consistent with those 

goals. Transformation is more than a goal, however, as the 

change is already occurring. Coal’s share of U.S. electric 

generation has decreased over the past two decades, 

while at the same time generation from cleaner sources 

such as natural gas and renewable energy has increased. 

Sectoral transformation—as policy and as a fact—shapes 

the options ,nterior will have in responding to whatever 

EPA determines to be BART for Navajo GS. Taking the 

next step forward to a clean energy future, and doing 

so without unnecessary economic disruption, requires 

understanding the sector as it is today. 

1 CAA Sec. 169A, Sec. 42 USC 7491 (g)(2).

Looking solely at retro¿t technologies discounts broader 

energy policy goals that ,nterior is attempting to promote 

in various venues. For this reason, the study will include 

a supplemental volume examining alternative generating 

options. While we recognize that this may be outside a 

strict reading and short-term interpretation of the statutory 

factors cited previously, sectoral transformation towards 

clean energy technologies is a factor in evaluating the 

long-term cost of compliance and the long-term energy 

impacts of compliance with respect to extending the useful 

life of a 35-year-old supercritical coal plant.2

 

Alternatives from cleaner energy sources

The analysis of the alternatives themselves will follow this 

report as a companion volume, due to the time constraints 

of this project. Much of the analysis presented in this 

volume is normally part of an in-depth NREL study, as 

it establishes the real-world context affecting how clean 

energy options would work. ,n this case, the contextual 

analysis is also relevant to many issues before ,nterior 

and its various agencies, apart from being background 

necessary to assessing the feasibility of clean energy 

alternatives. Timely publication of this background 

analysis will enable its consideration by EPA in developing 

its proposed BART rule for Navajo GS. We anticipate that 

EPA and commenters will have suf¿cient time to consider 

alternative technologies later in the rulemaking.

,n examining clean energy alternatives, NREL’s analytical 

objective is to identify which ones are the most applicable 

to Navajo GS, and how they may be integrated in the 

least disruptive manner. Analysis begins with examining 

the systems and the environment into which those 

technologies would connect.

2 ,n its ¿nal BART rule for the San -uan Generating Station in northwest 

New Mexico, EPA declined to consider coal-to-liquids technology as a 

possible BART. Although EPA encouraged the owners and Navajo Nation 

to examine the technology in detail, it concluded “we cannot consider it as 

a potential NOx

 BART technology as it would involve a complete redesign 

of the plant. We note the BART guidelines state that ‘[w]e do not consider 

BART as a requirement to redesign the source when considering available 

control alternatives.’ ” EPA, Final Rule, EPA-R06-OAR-2010-0846 FRL9451-1, Aug. 22, 2011, 76 Fed. Reg. 52388 (“San -uan Final Rule”).
NREL/TP-6A20-53024 3

The question of alternative generation involves more 

than a simple megawatt-for-megawatt replacement of 

Navajo GS’ capacity. This is especially true for renewable 

resources such as wind, solar and geothermal. The 

replacement might be nowhere near the current plant site, 

if the nearby natural resources are not of suf¿cient quality 

to be commercially viable. Or, the replacement might not 

have the technical characteristics of a base load plant, 

which would require changes in how other units on the 

grid are dispatched. Many such factors apart from the 

technology itself determine whether a given alternative is 

practically and economically feasible.

The analysis in chapters 1, 2 and 3 indicate that the basic 

costs of early retirement of Navajo GS would likely be 

more than the capital and production costs of retro¿tting 

the plant, regardless of what EPA’s BART determination 

turns out to be (subject to the caveats detailed in those 

chapters). A consequence of this ¿nding is that the 

remaining useful life of Navajo GS constitutes a window 

of time for the Bureau of Reclamation, its utility partners, 

CAWCD, and the affected Tribes to prepare for a smooth 

transition from coal to clean energy. The transition need 

not be 2,250 MW of generation capacity located at one 

site, because as Chapter 1 will show, Navajo GS’ owners 

have various needs and different levels of dependency on 

the plant.

Examples of the alternatives to be covered in the 

supplement are:

Ŷ Solar augmentation at one of the existing 

Navajo GS units. This technology uses both coal 

combustion and concentrating solar thermal power 

to create steam, reducing the amount of coal 

needed to generate the same amount of electricity. 

,t also preserves the ability of the solar-augmented 

unit to continue providing base load capacity.

Ŷ Geothermal as a potential base load replacement. 

N9 Energy’s ownership position in Navajo GS 

is equivalent to 250 MW of base load capacity, 

which historically has served Las 9egas and the 

rest of southern Nevada. A major transmission 

line currently under construction would, for the 

¿rst time, provide southern Nevada access to 

northern Nevada’s rich geothermal resources. 

With the new line, N9 Energy could replace all of 

the base load capacity it currently has at Navajo 

GS by expanding further into one of the most 

active geothermal plays in the country.

Ŷ On-site solar at CAP pumping stations. The 

federal government’s purpose in developing 

Navajo GS was to provide power for CAP pumps. 

CAP’s path through central Arizona has some 

of the country’s best areas for solar power. One 

option that NREL is already evaluating for 

,nterior is solar distributed generation (DG) at 

the site of CAP pumps. Every megawatt-hour 

produced on site is one megawatt-hour that does 

not have to come from Navajo GS, does not cause 

additional NOx

 emissions, and does not require 

long-distance transmission.

The supplemental report will include a preliminary 

analysis of these and other technologies for the purpose 

of identifying those that warrant further site-speci¿c 

analysis. The report will not recommend any alternative, 

as doing so would require site-speci¿c analysis. ,nterior 

and NREL anticipate a follow-on phase of this study that 

would provide a more detailed assessment of the most 

feasible alternative generating technologies.

Assumptions and key concepts

Many aspects of this report required making assumptions 

to address uncertainties that cannot be modeled. Some of 

these assumptions are based on historical data where such 

information is available. ,n other cases, the assumptions 

are based on reason and knowledge of how the power 

sector operates. We list here some of the key assumptions 

used throughout the analysis.

Ŷ This study takes state and federal policies on an 

“as is” basis. We do not examine scenarios with 

a carbon tax or a cap-and-trade program. While 

such analyses may be valuable, they are beyond 

this study’s time, resources and scope.

Ŷ We assume no additional federal appropriations 

to offset BART-related costs. We assume that the 

federal government’s share of BART-related costs 

will be 24.3% of the total cost, and that this share 

will be recovered entirely through water rates 

charged by CAWCD for the use of CAP water. 

Appropriations and federally backed ¿nancing 

have historically covered Reclamation’s share of 
4 NREL/TP-6A20-53024

the capital costs, and a future appropriation of 

any size would mitigate some of the impact on 

CAP water users and tribes. As of this writing, 

however, there is no clear indication that future 

appropriation or federal ¿nancing is forthcoming.

Ŷ The cost scenarios examined here focus on 

visibility-related technologies such as selective 

catalytic reduction (SCR). Some other analyses 

count the cost of technologies such as baghouses 

that do not address visibility, signi¿cantly 

increasing those estimates of BART costs. Here, 

we treat the cost of baghouses as elective and 

supplemental costs, not as costs that would be 

inherent to a BART decision. This is consistent 

with EPA ¿ndings in similar BART proceedings. 

We nevertheless provide separate estimates of 

baghouse costs for additional reference.

Ŷ We distinguish between a plant’s capital costs 

and its operating costs. An important implication 

of this assumption is that if installing BART 

upgrades increases Navajo GS’ capital cost but 

does not change its operating costs, the plant will 

run just as much with the new control technology 

as it does now.

Ŷ We assume that utilities will add their share of 

any capital improvements to their rate base just 

as they would any other capital investment. We 

further assume that the utility’s weighted cost 

of capital is the appropriate discount rate to use 

when annualizing capital cost, as it represents the 

utility’s true long-term time value of money.

Ŷ We assume that impacts relating to capital 

costs and production costs are the base of an 

economic comparison of outcomes, but we do not 

assume they represent the extent of the business 

costs associated with a given BART outcome. 

Present uncertainties such as renegotiating the 

Navajo GS site lease may impose additional 

costs of doing business and may have their own 

incremental impact on retail rates. Quantifying 

these uncertainties in a non-arbitrary manner is 

problematic, however. We therefore use capital 

costs and production costs as the basis for 

comparison, recognizing that additional costs may 

exist.

Ŷ We assume that the Bureau of Reclamation and 

CAWCD will not routinely sell surplus electricity 

on the wholesale power market at a loss. ,n 

other words, we assume they would act in an 

economically rational manner just as the utility 

partners would.

Ŷ We assume that Navajo GS’ replacement cost 

is represented by the cost of obtaining the same 

amount of power per year from spare capacity 

on existing generators. We use production 

cost modeling to estimate near-term power 

replacement costs. Over time, however, system 

load will increase and additional generating 

capacity will be required. This would be the 

case with or without Navajo GS, although the 

additional capacity would be needed sooner if 

Navajo GS were retired early.

Ŷ The results of production cost modeling represent 

an economically optimum outcome that accounts 

for known, quanti¿able constraints. Transaction 

costs such as existing power delivery obligations 

are not modeled, nor are other potential sources 

of inef¿ciency. Because they represent economic 

inef¿ciencies, these factors would likely increase 

the actual cost of replacement. Therefore, 

the replacement costs discussed in Chapter 2 

represent best-case, least-cost scenarios.

Ŷ We assume that any estimate of future costs 

or prices is best represented as a plausible 

range rather than as a single estimated number. 

Such future values are bounded by a band of 

uncertainty, and representing them as a single 

number imputes more certainty than they warrant. 

Ŷ The analysis is largely based on the current cost 

of operating Navajo GS because these costs are 

known. Future production costs may be higher 

depending on renegotiation of coal and the plant 

site leases, but these uncertainties cannot be 

quanti¿ed at this time.

Ŷ Continued participation of Los Angeles 

Department of Water and Power (LADWP) is 

uncertain for the reasons discussed in Chapter 1. 

For this analysis, we assume that the economic 

attributes of LADWP’s 21.2% share would transfer 

to a new owner if LADWP were to divest its 
NREL/TP-6A20-53024 5

position in Navajo GS. ,n other words, we assume 

that the consequences discussed in Chapters 1, 2, 

and 3 that are speci¿c to LADWP would largely 

hold true for a successor interest, although details 

such as cost of capital may be different. Assuming 

otherwise would require knowing who the 

successor interest would be. Generally, if LADWP 

or any of the other current owners decides not to 

continue to participate, continued operation would 

depend on another buyer being found, or the 

remaining participants absorbing the remainder of 

the costs.

Organization of this report

Chapter 1 provides baseline information about the 

plant’s history and its operational characteristics. 

This background is essential to understanding the 

remaining useful life of Navajo GS, and how the costs 

of compliance would be distributed. Key to this analysis 

will be depreciated capital, net plant in service, cost of 

capital, and other ¿nancial metrics. The chapter begins 

with an overview of the federal actions relating to water 

development that led to the creation of Navajo GS and 

the participation of the Department of the ,nterior. The 

regulatory discussion examines the plant’s role in each 

partner’s generation portfolio, and describes the current 

status of capital ¿nancing and net plant in service. ,t also 

contrasts the various types of owners (investor-owned 

utilities, a municipally owned utility, a public power 

utility, and the Bureau of Reclamation) and how each 

owner makes decisions with respect to operations and 

capital investment. 

Chapter 2 establishes analytical benchmarks for 

evaluating the energy impacts of compliance—

speci¿cally, how the local and regional power systems 

would respond in the event that retiring Navajo GS 

were more economical than BART retro¿ts. Retirement 

approximates a worst-case scenario, on the assumption 

that the owners of the Navajo GS plant would invest in 

additional emission controls if the resulting net cost were 

less than the cost of replacing the plant. The chapter 

uses production cost modeling to forecast where the 

replacement power would come from, and how much 

more it would cost utilities and their customers. The 

methodology used is similar to how utilities and regional 

reliability organizations would approach the question 

themselves. However, this chapter also pays close attention 

to Navajo GS’ largest owner, which is not a utility. The 

federal government’s position in Navajo GS lacks the 

Àexibility enjoyed by the plant’s utility partners, with the 

result that the effects of retirement would be greater. 

With the shutdown scenario fully examined, the report 

turns to retro¿t options in Chapter 3. This chapter focuses 

on SCR retro¿ts as the most aggressive with respect 

to NOx

 reduction. Other less-costly alternatives are 

addressed, including those recently installed at the plant. 

The chapter also describes supplemental retro¿ts such as 

baghouses.

The heavier ¿nancial impact on the federal share of 

Navajo GS would particularly affect CAP water users. 

These impacts are the subject of Chapter 4. The federal 

government authorized Navajo GS (and its unusual 

ownership arrangement) for the purpose of enabling 

Arizona to take possession of water that the Colorado 

River Compact entitled the state. Consequently, the 

Compact and all related laws and legal settlements de¿ne 

the federal government’s role in Navajo GS, which in 

turn constitutes a crucial element in assessing the cost of 

compliance. Chapter 4 examines the two major types of 

issues: impact on CAP water rates, and how additional 

power costs could affect the revenue streams used to retire 

CAP debt obligations.

Chapter 5 provides an overview of the science relating to 

atmospheric visibility. ,t summarizes information to date 

dealing with visibility issues at the Grand Canyon and 

other nearby Class , areas. 

Chapter 6 examines the impacts on the tribes and on local 

economies. ,t separately examines two groups of affected 

tribes: those that are close to the Navajo plant and the 

nearby coal mine that provides fuel and those that rely 

on CAP water. The Navajo and Hopi tribes constitute a 

signi¿cant portion of the on-site labor force at the plant 

and at the mine. ,n addition, leases and other agreements 

between the tribes and the plant owners, and between 

the tribes and the mine’s owner Peabody Coal, provide 

a stream of revenue to each tribal government. For the 

water-using tribes, the arrangements described in Chapter 

4 affect the water rates paid by the tribes, and they affect 

the availability of money to improve water delivery 

infrastructure.
6 NREL/TP-6A20-53024

Finally, Chapter 7 provides a baseline overview of Navajo 

GS’ role in the economy of northeastern Arizona.

Caveats

NREL makes no recommendation about what the ¿nal 

BART determination for Navajo GS should be. We offer 

conclusions about what outcomes are probable based 

on our empirical analysis of key scenarios, and we have 

a high degree of con¿dence in those conclusions. How 

those conclusions should be weighed against other factors 

outside our analysis requires value comparisons that would 

be inappropriate for NREL to make. These determinations 

are part of EPA’s charge under the CAA, and are subject to 

judicial review and legislative oversight. NREL is not an 

interested party to the Navajo GS BART proceedings, but 

is rather a resource to ,nterior and to EPA.

The work contained in this report represents the research 

and analysis that could be conducted and written within 

a three-month period. This short timeline necessarily 

limited the analysis for this report. The three-month 

window was set by EPA’s own timeline for issuing a 

proposed BART rule for Navajo GS, and by the timing 

of the interagency agreement between ,nterior and DOE 

that authorized NREL to begin work. NREL’s own 

procedures also require time for independent peer review 

of major reports, which reduced research time even 

more. Consequently, some aspects of Navajo GS and its 

upcoming haze rule may not be addressed in as much 

detail as would have been possible with additional time.

Acknowledgments

Others have contributed to this study, but only the 

principal contributors were listed as co-authors. This 

study has bene¿tted from the knowledge and advice of 

other NREL experts in many areas relating to the topics 

addressed here. We are also very grateful for comments 

and suggestions provided by our panel of outside experts, 

who gave of their time to serve as independent peer 

reviewers.
NREL/TP-6A20-53024 7

The Navajo Generating Station (Navajo GS), outside of 

Page, Arizona, has been producing energy since 1974. 

Congress authorized creation of the 2,250 MW coal-¿red 

power plant in conjunction with its creation of the Central 

Arizona Project (CAP), a 336-mile water distribution 

system built to deliver more than 1.5 million acre-feet 

of Colorado River water annually from Lake Havasu in 

western Arizona to agricultural users, ,ndian tribes, and 

millions of municipal water users in Maricopa, Pinal, and 

Pima counties.

 

Congressional authorization is an unusual genesis for a 

coal-¿red power plant. The special relationship between 

the plant and the CAP is an important factor in evaluating 

the consequences of a best available retro¿t technology 

(BART) determination for Navajo GS. The haze provisions 

of the Clean Air Act Amendments of 1990 require EPA to 

set BART standards for Navajo GS, but they also require 

EPA to take into consideration (among other factors) 

the costs of compliance, the remaining useful life of the 

source, and existing pollution control technology in use 

at the source. This chapter provides background on these 

statutory factors in particular. Subsequent chapters address 

other statutory factors, such as the energy impacts of 

compliance, environmental impacts other than air quality, 

and the degree of improvement in visibility that may 

reasonably be anticipated to result from the technologies 

under discussion.

As Figure 1-1 shows, the plant’s geographic area of 

inÀuence is wide, ranging from Peabody Western Kayenta 

Coal Mine (the source of the coal used to run the power 

plant) on the Navajo and Hopi reservations, to the Los 

Angeles Department of Water and Power, one of the ¿ve 

utilities with an interest in the plant. 

The ¿rst section of this chapter details the history of the 

federal government’s stake in Navajo GS, its current 

ownership structure, and how the corporate and oversight 

structure of different owners affects their method of 

paying for capital investments. ,t introduces many of the 

key players shown in the relational Àowchart depicted in 

Figure 1-1. The section also discusses uncertainties arising 

from other ongoing regulatory efforts beyond EPA’s 

current proceedings to establish a BART rule for the plant. 

The discussion then turns to the position of Navajo GS 

in each partner’s generation portfolio. This is a crucial 

element in understanding the cost of BART compliance, as 

the true impact is not solely a function of the technology’s 

capital cost. Equally important is the way the partner 

recovers its capital costs, and its options for getting power 

from other sources. The section describes the degree 

to which each owner depends upon the plant, and the 

¿nancial mechanisms it uses to recover costs. The last 

section discusses the operations of the plant, its coal use, 

and its emissions as reported to EPA. ,t also describes 

major emission controls installed at the plant.

1 Navajo GS Origin and Operations
8 NREL/TP-6A20-53024

Funding

Payments

Revenues

Power

Power

Water

Rates

Excess

Power Wholesale Market

Lower Colorado River Development Fund

Arizona Water Settlement,

Tribal Progams Water Customers

Central

Arizona

Project

Central Arizona

Water Conservation

Power Rates

Power Power

Kayenta Coal Mine

Navajo Generating

Station

U.S. Bureau of

Reclamation

Salt River Project

APS, TEP, LADWP,

Nevada Power

Power

Customers

Coal

CALIFORNIA

NEVADA

ARIZONA

UTAH

MEXICO

Kayenta

Coal Mine

Phoenix

Los Angeles

Las Vegas

Tucson

Navajo

Generating Station Los Angeles

Department of

Water & Power

Nevada Power

Company

Arizona Public

Service Company

Salt River

Project

Tucson Electric

Power Company

Los Angeles

Department of

Water & Power

500 kV Transmission

Network

Utility Service

Area

Central Arizona 

Project Canal

Metro Area

Pumping Station

(size indicates relative

annual energy use)

Grand Canyon

National Park

Figure 1-1. Navajo Generating Station and Central Arizona Project
NREL/TP-6A20-53024 9

1.1 Regulatory Background and 

Ownership Interests

The legislation establishing the CAP included authority 

for the Secretary of the ,nterior to participate in a 

power generation facility for the purpose of powering 

CAP’s pumping stations.1

 Originally, CAP supporters 

envisioned building hydroelectric dams in the Grand 

Canyon for this purpose. Strong public opposition to the 

proposed dams made it unlikely that Congress would pass 

the legislation authorizing the CAP without an alternative 

way to power it. A thermal power plant was determined 

to be more acceptable to the public and “[i]n place of 

the hydroelectric dams, the Secretary of the ,nterior was 

allowed to enter into an agreement with non-Federal 

power interests for entitlement to 24.3% of the power 

produced at the non-Federal Navajo Generating Plant.”2

 

Negotiations to plan and build a coal-¿red power plant 

began in -une 1968, and utilities in the Southwest were 

invited to participate. ,n a letter to President Nixon in 

1969, Assistant Secretary of ,nterior -ames R. Smith 

outlined the negotiations in which parties concluded: 

 “[t]he most feasible plan to supply the power 

requirements of the Central Arizona Project and 

to augment the Lower Colorado River Basin 

Development Fund is to acquire generation and 

transmission capacity by participation with nonFederal entities in the construction and operation of 

generation and transmission facilities.” 3

The steering committee included the Bureau of 

Reclamation and a representative from each interested 

utility. The utilities included the current ¿ve utility owners 

– Salt River Project, Los Angeles Department of Water 

and Power (LADWP), Arizona Public Service Company 

(APS), Nevada Power Company, and Tucson Electric 

Power (TEP)– as well as representatives from San Diego 

Gas and Electric Company, Southern California Edison 

1 Colorado River Basin Project Act, U.S. Code 43 (2010), §1523(b).

2 -ennifer E. =uniga, The Central Arizona Project, Bureau of Reclamation 

(2000), p. 30. http://www.usbr.gov/projects//,mageServer"imgName D

oc_1303158888395.pdf

3 -ames R. Smith, Assistant Secretary of the ,nterior, letter to President 

Richard Nixon, 30 September 30 1969, p. 6.

Company, El Paso Electric Company, and Public Service 

Company of New Mexico. El Paso Electric Company 

and Public Service Company of New Mexico withdrew 

in February 1969, while San Diego Gas and Electric 

Company and Southern California Edison Company 

withdrew in May 1969.4

Plant construction began in 1970 with the SRP leading the 

effort. Bechtel was the lead contractor for construction, and 

by 1976 all three of the plant’s 750 MW units were on line.

1.1.1 Ownership Interests

Other major coal plants in the West have multiple owners, 

but federal ownership makes Navajo GS unique. Of the 

six entities that have an ownership interest in the plant, 

the U.S. Bureau of Reclamation holds the largest—24.3%. 

The purpose of the federal government’s participation in 

Navajo GS is to ensure that CAP receives the necessary 

energy to power the pumps that move up to 1.5 million 

acre-feet or more of Colorado River water across Arizona, 

pursuant to federal law.5

 Figure 1-1 illustrates the intricate 

link between Navajo GS and CAP, which Chapter 4 

discusses in greater detail. The U.S. Department of the 

,nterior, Reclamation’s parent agency, has another level of 

interests arising from the connections between the plant, 

CAP and the federal government’s trust responsibility to 

the ,ndian Tribes. Another ,nterior agency, the Of¿ce of 

Surface Mining, regulates the coal mine—also on tribal 

land—that supplies the plant on an exclusive basis.

The Department of the ,nterior and the ¿ve utility partners 

executed the Navajo Project Co-Tenancy Agreement on 

March 23, 1976. Table 1-1 details the ownership shares. 

SRP, the largest utility owner, operates the plant and has 

responsibility for scheduling, operating, and maintaining 

the three units. The remaining owners receive their 

allotments of the power generated pro rata, and contribute 

to the cost of running the plant according to their initial 

investment. SRP and LADWP are the only owners other 

than Reclamation that have an interest greater than 20%.

4 Smith, p. 3.

5 Colorado River Basin Project Act, U.S. Code 43 (2010), §1523(b).
10 NREL/TP-6A20-53024

Table 1-1. Navajo Generating Station Ownership 

Owner Share Type of entity Oversight authority

U.S. Bureau of 

Reclamation 24.3% Federal agency within the 

Department of Interior Federal legislation

Salt River Project 21.7%

Political Subdivision of State of 

Arizona; Governed by the board 

of directors

Board of Directors (elected)

Los Angeles 

Department of Water 

and Power

21.2% Municipal Utility

Board of Commissioners 

(appointed by Los Angeles 

mayor)

Arizona Public 

Service Co. 14.0% Investor-owned utility (parent: 

Pinnacle West Capital Corp, LLC)

Regulated by Arizona 

Corporation Commission

Nevada Power Co. 11.3% Investor-owned utility 

(parent: NV Energy)

Regulated Nevada Public 

Utility Commission

Tucson Electric 

Power Co. 7.5% Investor-owned utility 

(parent: UniSource Energy)

Regulated by Arizona 

Corporation Commission

1.1.2 Regulatory Framework

Three of the owners fall under the jurisdiction of state 

utility regulators with authority to approve capital 

expansion, resource procurement plans, and customer 

rates. The Arizona Corporation Commission (ACC) 

regulates APS and TEP. The ability of these two utilities to 

recover through customer rates any costs associated with 

their ownership positions in Navajo GS is largely subject 

to ACC approval.

Nevada Power Company merged with Sierra Paci¿c Power 

Company in 1999. The merger resulted in one combined 

utility—N9 Energy—serving most of Nevada. Although 

operating ¿nancially as one utility, N9 Energy’s two 

transmission networks still operate separately: Nevada 

Power Company in the south, and Sierra Paci¿c in the 

north. N9 Energy is regulated by the Nevada Public 

Utilities Commission (NPUC). 

SRP and LADWP are both public power utilities 

responsible to a board (elected directors in the case of 

SRP, commissioners appointed by the Mayor of Los 

Angeles in the case of LADWP). Both SRP and LADWP 

have greater Àexibility with regard to planning and cost 

recovery sincethey are not regulated by a state PUC.6

 This 

6 Even though SRP is not under the jurisdiction of the ACC, it is statutorily 

required to receive approval from the Commission for siting power lines 

and thermal power plants greater than 100 MW (ARS 40-360). Also, SRP is 

statutorily required to go before the ACC for approval of its ¿nancings.

difference in governance structure marks a key distinction 

between investor-owned utilities (,OUs) and those owned 

by a public entity. ,n essence, publicly owned utilities are 

governed and regulated by the political entities that created 

them, while ,OUs are regulated by the state’s PUC. 

While ownership positions in Navajo GS have not changed 

during the entire time the plant has been operating, 

LADWP’s ownership interest will likely be affected soon 

by legislative action in the State of California. Senate 

Bill 1368 (2006 legislative session) precludes a utility 

from making investments to extend the life of a plant that 

exceeds the rate of emissions of greenhouse gases for 

combined-cycle natural gas power plant.7

 Navajo GS does 

not currently meet this emissions standard, and would 

not likely meet the standard if it were to install emissions 

control measures the EPA is currently considering through 

its BART rulemaking process.

For this analysis, we assume that the attributes of 

LADWP’s 21.2% share would transfer to a new owner 

if LADWP were to divest its position in Navajo GS. ,n 

other words, we assume that the consequences discussed 

in this chapter that are speci¿c to LADWP’s share of the 

plant would largely hold true for a successor interest, 

acknowledging that details may differ in ways that 

7 California Public Utility Code § 8340-8341. SB 1368 requires that the 

greenhouse gases emission performance not exceed the rate of emissions of 

greenhouse gases for combined-cycle natural gas base load generation.
NREL/TP-6A20-53024 11

cannot be predicted or modeled without knowing who 

the successor interest would be. Generally, if LADWP or 

any of the other current owners decides not to continue to 

participate, continued operation would depend on another 

buyer being found, or the remaining participants absorbing 

the remainder of the costs.

1.1.3 Environmental regulations

The proximity of the Navajo GS plant to eleven Class 1 

visibility areas is the focus of EPA’s current rulemaking, 

but various environmental regulations have affected the 

plant throughout its history. The most signi¿cant has been 

the Clean Air Act, including its amendments in 1977 

and 1990.8

 The 1977 amendments resulted in the need 

to install SO2

 scrubbers on all three units, which cost the 

partners $420 million in all.9

 Navajo GS’ SO2 emissions 

have declined considerably since the installation of 

scrubbers.

Several other ongoing or upcoming regulatory 

measures could affect Navajo GS beyond EPA’s BART 

determination. Tables 1-2, 1-3 and 1-4 provide a 

compilation of regulatory activities cited by Navajo GS’ 

utility owners as having the potential to affect the plant’s 

operation and its future. Together, these other pending 

actions create an additional layer of uncertainty that 

affects the present calculus of whether visibility-related 

BART upgrades would be economically viable.

Navajo GS has been operating for nearly thirty-¿ve 

years. The plant site lease is up for renewal in 2019 – 

approximately forty-¿ve years from the start of operation 

for its ¿rst unit. Other supporting agreements needed to 

continue operating Navajo GS expire within the next ten 

years. The renegotiation of these instruments – mainly the 

rights-of-way for transmission lines, plant site, railroad, 

and water intake and water line – is an added uncertainty 

and will trigger a National Environmental Policy Act 

(NEPA) review. 

The next few years will be crucial in determining how 

long the plant will continue operating. ,n 2011 alone, 

the plant faced new regulation under the GHG Tailoring 

8 The Clean Air Act, U.S. Code 43 §7401 et seq. (1970) amended by Clean 

Air Act Amendments of 1977 (91 Stat. 685, P.L. 95-95) Clean Air Act 

Amendments of 1990 (104 Stat. 2468, P.L. 101-549).

9 Does not include capitalized interest, taxes and other administrative and 

general costs. Salt River Project, Navajo Generating Station, http://www.

srpnet.com/about/stations/Navajo.aspx.

Rule, the Utility Boiler MACT, and the updated ESA work 

plan that listed species and critical habitats. ,n addition, 

Navajo GS will be facing new SO2

 NAAQS attainment 

designations, ozone attainment designations, coal 

combustion residual regulation, and cooling water intake 

structure mitigation measures by the end of 2012. Further 

uncertainties lie in actions that do not have ¿nal schedules 

at present. These actions include: Transport Rule ,, (NOx

)

Particulate Matter NAAQS Utility Boiler GHG NSPS

Final NEPA Guidance from the Council on Environment 

Quality on the effects of Climate Change and GHGs and 

the BART petition pertaining to Reasonably Attributable 

9isibility ,mpairment (RA9,).

Regulatory uncertainties are common for coal plants. 

Complicating these uncertainties in the case of Navajo GS 

is the plant’s link to the CAP and to the local economies 

– especially tribal economies – that CAP water sustains. 

A reasonable ¿rst step in sorting through the complexity 

to make the necessary decisions is to understand the 

plant’s business fundamentals using traditional utility 

measurements. The next section looks at Navajo GS from 

the perspective of its owners, focusing on the way each 

one ¿nances its share, and on the plant’s position in the 

utility’s resource portfolio.
12 NREL/TP-6A20-53024

Table 1-2. EPA Regulatory Actions Affecting Navajo Generating Station

Agency Actions Schedule Summary of Action

Utility Mercury and 

Air Toxics Standard 

(MATS) 

Proposed 

March 2011/

Final announced 

December 2011

Limit hazardous air pollutant emissions (i.e. mercury, 

arsenic, chromium, nickel, lead, and hydrochloric acid). 

Regulations will require existing and new coal-fired 

utility units to meet new emissions limits for mercury, 

non-mercury metals, acid gases. New emission controls, 

such as baghouses, could be required at Navajo GS to 

meet the emissions limits in the final rule. 

Greenhouse Gas 

(GHG) Tailoring 

Rule

Effective January 

2011

Sets thresholds for GHG emissions that define when 

permits under the New Source Review PSD and Title V 

Operating Permit programs are required for new and 

existing industrial sources. Sources that trigger PSD for 

GHG emissions are required to conduct a BACT analysis. 

EPA released technical guidance in March 2011 to assist 

States in determining BACT for new and modified 

sources subject to PSD for GHGs.

SO2 National 

Ambient Air 

Quality Standards 

(NAAQS)

Final June 2010; 

Initial Attainment 

Designations 

Summer 2012

Revised by EPA on June 2, 2010, creating a new 1-hour 

standard. Modeling of individual stationary sources, 

including Navajo GS, may be required to determine 

whether any emission reductions are needed to meet 

the new 1-hour NAAQS.

Cooling water 

intake structures

Proposed April 

2011/Final 2012

EPA to require all steam electric generating stations that 

have cooling water intake structures with design intake 

flows > 2MGD to implement technologies to prevent 

impingement/entrainment of aquatic life.

Coal Combustion 

Residuals

Proposed June 

2010/Final Pending

EPA to issue federal regulations for the disposal and 

long-term management of coal combustion residuals.

Ozone NAAQS 

Review

Proposed 

2013/Final pending

EPA is reviewing to determine whether a lower standard 

is required. A lower standard could create additional 

ozone nonattainment areas in AZ and the Western US. 

If EPA lowers the standard, additional NOx controls may 

be required on stationary sources as Navajo GS.

Particulate Matter 

(PM) NAAQS Pending

EPA to affirm or revise current PM NAAQS – if lowered, 

further emissions reductions for the power sector may be 

required.

Transport Rule II 

(NOx

)

Pending (schedule 

delayed due to 

late promulgation 

of revised ozone 

NAAQS)

When new NAAQS for ozone is issued, EPA plans to 

propose an updated interstate pollution transport 

rule for the revised NAAQS. A final rule is expected 

approximately one year after the proposed rule and could 

include the Western U.S.

Utility Boiler 

GHG New Source 

Performance 

Standards (NSPS)

New Schedule 

pending

EPA is under a court settlement to set NSPS standards 

for this source category for GHG emissions. When EPA 

establishes standards for new sources, the agency will 

also produces “guidelines” for regulating existing sources 

such as Navajo GS. This action could result in a GHG 

emission standard for Navajo GS.
NREL/TP-6A20-53024 13

Table 1-3. National Environmental Policy Act (NEPA) Actions Affecting Navajo Generating Station

Agency Actions Schedule Summary of Action

Draft NEPA 

Guidance on Effects 

of Climate Change 

and GHGs

(Council on 

Environmental 

Quality, CEQ)

Draft February 2010/

final pending

The draft guidance explains how 

Federal agencies should analyze the 

environmental impacts of GHG emissions 

and climate change when they describe 

the environmental impacts of a proposed 

action under NEPA. It provides tools for 

agency reporting, including a presumptive 

threshold of 25,000 metric tons of carbon 

dioxide equivalent emissions from the 

proposed action to trigger a quantitative 

analysis, and instructs agencies how to 

assess the effects of climate change on the 

proposed action and their design.

Federal Land

Rights-of-Way

(Bureau of Indian 

Affairs, Bureau of 

Land Management, 

National Park 

Service)

2019 – plant site and water 

intake/water line renewals due;

2021 – railroad and transmission 

line renewals due;

2022 – southern transmission 

line easement (Bureau of Land 

Management);

2032 – permit covering small 

parcel for water intake from 

Lake Powell (National Park 

Service)

Renegotiation will require NEPA review & 

approval.

Water Service 

Contract

(Bureau of 

Reclamation)

2014 Extension process has been initiated.

Mining Permits 

(Office of Surface 

Mining, OSM)

2024/25 Renegotiation will require NEPA review & 

approval.

Mining Plan 

Approval (Bureau of 

Land Management)

2024/25

Plan approval needed for future mining 

areas within Indian mining leases.
14 NREL/TP-6A20-53024

Table 1-4. Other Regulatory Actions Affecting Navajo Generating Station

Agency Actions Schedule Summary of Action

Endangered Species 

Act (ESA) listing 

work plan (U.S. Fish 

& Wildlife Service)

Listings and critical 

habitats published 2011 

– 2016 per settlement 

schedule

In response to litigation, USFWS agreed to a 

multi-year work plan to evaluate 250 species for 

listing and/or designation of critical habitat under 

the ESA. Of those 250 species, 29 occur in Arizona 

and 11 may impact current or future power 

generation.

BART Petition 

– Reasonably 

Attributable 

Visibility 

Impairment (RAVI)

Submitted to DOI May 

5, 2009; DOI responded 

March 8, 2011

On May 5, 2009 several environmental groups 

submitted a petition to DOI requesting that 

the agency certify that visibility impairment in 

the Grand Canyon is reasonably attributable to 

emissions from Navajo. DOI responded to the 

petition by letter on March 8, 2011, indicating 

that the EPA is in the process of establishing BART 

under the Regional Haze Rule. DOI explained 

that it reserves the right to certify RAVI if finds 

that the proposed BART determination does not 

adequately mitigate Navajo- purported visibility 

impact.

California 

Senate Bill 1368 Passed in 2006

GHG Emission Performance Standard to go into 

effect no later than 2019 (applies to baseload for 

publicly owned electric utilities). 

Table 1-5. Contribution of Navajo Generating Station to Utility Partners’ Generating Fleets 

(Owned, Operating Capacity Only)

SRP LADWP APS NV 

Energyb TEP

% ownership of Navajoa 21.7% 21.2% 14.0% 11.3% 7.5%

MW ownership of Navajo GS 488.3 477 315 254.3 168.8

Share of GWh generated, 2010 3,565.2 3,483.1 2,300.1 1,856.5 1,232.2

Coal fleet MW 2,209.5 477 1,747.1 928.1 753.2

Navajo share as % of coal fleet 22.10% 100.00% 18.00% 27.40% 22.40%

Total fleet MW 6,527.0 6,300.2 7,019.0 7,369.1 2,495.3(c) 

Navajo share as % of total fleet 7.50% 7.60% 4.50% 3.50% 6.80%

Total fleet 2010 GWh 26,113.5 13,337.3 21,208.1 20,570.9 5,427.4

Navajo share as % of total GWh 13.7% 26.1% 10.8% 9.0% 22.7%

Note: does not include contract power purchases or planned plants. Owned, operating plants only.

(a) The U.S. Bureau of Reclamation owns the remaining 24.3% of Navajo GS (546.8 MW 3,992.4 GWh generated in 2010).

(b) ,ncludes assets of Nevada Power Company and Sierra Paci¿c Power Company.

(c) Coal/gas fuel switching unit (Sundt Unit 4, 156 MW) included in both total Àeet MW and in coal Àeet MW count.
NREL/TP-6A20-53024 15

1.2 Navajo GS in the Utility Partners’ 

Generating Fleets

Navajo GS constitutes a varying portion of each utility 

partner’s owned generating asset portfolio, ranging from 

3.5% (N9 Energy) to 7.6% (LADWP) of each utilities’ 

overall owned generation portfolio.10 More signi¿cant, 

however, is the role of Navajo GS in each utility’s base 

load Àeet. A utility’s base load is its lowest level of hourly 

demand over the course of the year. The daily and hourly 

Àuctuations that are a natural part of electricity demand 

will always occur at levels that are more than the system’s 

base load. Demand above base load, therefore, is typically 

served by generators that cycle on and off (or that ramp 

up and down) on a daily basis. Generators serving base 

load, on the other hand, can theoretically run at the same 

constant level and are normally dispatched ¿rst in order to 

satisfy demand.

Coal and nuclear units typically operate as base load 

capacity. Their share of energy tends to be proportionally 

larger than the capacity they represent, due to the fact that 

they run more constantly throughout the year. This is the 

case for Navajo GS, as shown in Table 1-5.

Salt River Project (SRP)

SRP owns the largest share of the plant of any of the 

utility partners. SRP’s coal portfolio also includes a power 

purchase agreement (PPA) for the output from 100 MW 

of Unit 3 of the Springerville, Arizona coal-¿red facility, 

which is owned by Tri-State Generation.11 ,n addition to 

its share of Navajo GS and the Springerville PPA, SRP 

owns the 423 MW Unit 4 of the Springerville plant plus 

an additional 1,298 MWs of coal-¿red assets in Colorado, 

New Mexico and Arizona.12 SRP does not appear to have 

plans to retire any of its coal units in the near future.

Los Angeles Department of Water and Power 

(LADWP)

Although Navajo GS constitutes the entirety of LADWP’s 

owned coal assets, LADWP has a PPA with Utah 

Power and Light for up to 1,202 MW of the coal-¿red 

10 SNL Energy, SNL Web Platform Tool, http://www.snl.com/

SNLWebPlatform.aspx (web-based portal of news, data and research on the 

electric power sector) Salt River Project, Navajo Generating Station, http://

www.srpnet.com/about/stations/Navajo.aspx.

11 Salt River Project, SRP Contract Power Purchases http://www.srpnet.com/

about/stations/contractpower.aspx.

12 Salt River Project, Springerville Generating Station, http://www.srpnet.

com/about/stations/springerville.aspx SNL Energy 2011.

,ntermountain Power Project (,PP). Together, Navajo GS 

and ,PP currently account for 39% of the energy delivered 

to LADWP customers.13 To comply with the mandates 

established by SB 1368 as early as possible, LADWP plans 

to eliminate coal assets from its portfolio.14 LADWP’s 

,RP recommends adding a 500-MW combined cycle 

natural gas plant with a 52% capacity factor. LADWP 

estimates that divestment of Navajo GS in 2014 would 

reduce their GHG emissions by 10.5 million metric tons 

and bring in about $360 million in capital investment from 

the asset sale. LADWP anticipates the capital cost of the 

new natural gas plant to be $637 million.15

Arizona Public Service (APS)

,n addition to Navajo GS, APS has partial ownership 

in the Cholla coal-¿red power plant near -oseph City, 

Arizona, and the Four Corners plant near Farmington, 

New Mexico, adding approximately 1,432 MW of coal-

¿red assets to its portfolio. Neither of these plants is slated 

for retirement in the near future. 

NV Energy

Through its subsidiaries, Nevada Power Company and 

Sierra Paci¿c Power Company, N9 Energy owns 674 MW 

of coal-¿red assets in Nevada in addition to its share of 

Navajo GS. The North 9almy Generating Station, near 

9almy, Nevada, which operates at approximately a 63% 

capacity factor, is scheduled to retire Unit 1 (261 MW) 

in 2022. Sierra Paci¿c Power Company does not need to 

add a signi¿cant amount of generation to its portfolio to 

continue to meet projected load requirements until the 

9almy Unit 1 retirement.16

13 City of Los Angeles Department of Water and Power (LADWP), 2010 

Power ,ntegrated Resource Plan, http://www.ladwp.com/ladwp/cms/

ladwp014239.pdf.

14 LADWP, p. ES-4.

15 LADWP, p. M-19.

16 Sierra Paci¿c Power Company, Sierra Paci¿c Power Company ,ntegrated 

Resource Plan, Docket No. 10-07003, 9olume 3 of 22. 2010.
16 NREL/TP-6A20-53024

Tucson Electric Power Co. (TEP)

Of the utility partners, TEP has the 

smallest ownership, both in terms of 

total Àeet capacity installed and total 

GWh generated. TEP owns 584 MW 

of coal-¿red assets in New Mexico 

and Arizona in addition to its share 

of Navajo GS.17 This includes partial 

ownership of the Four Corners and San 

-uan plants in New Mexico, in addition 

to the Sundt Unit 4 coal/gas fuel 

switching facility in Arizona. None of 

these plants appear to be scheduled for 

retirement in the near future.

1.2.1 Age and remaining 

useful life of the plant

Navajo GS’ three units were 

constructed between 1974 and 1976, 

and in 2011 the units were 34, 35 and 36 years old. A 

scatter plot of operating coal units in WECC (Figure 1-2) 

shows that the three Navajo GS units are old relative to 

coal units of comparable size (the size of the bubble is 

determined by the unit’s capacity). Generally, units with 

lower costs of production run more often and therefore 

have higher capacity factors. 

The Navajo GS plant site lease is up for renewal in 

December 2019. According to the E,A-860 database, the 

average capacity-weighted age of a coal plant that had 

been retired by 2009 was approximately 48 years old—

practically the same as the service life of Navajo GS that 

the partners originally anticipated when they signed the 

initial agreement.18 This historical number might not be 

indicative of plants comparable to Navajo GS, however. 

Survival analysis conducted by NREL for other system 

modeling efforts suggests that among the cohort of coal 

plants comparable to Navajo GS, fewer are shutting down 

early when compared to the survival of earlier-generation 

plants over the same amount of time.19

17 SNL Energy 2011.

18 E,A-860 Database (2009), http://38.96.246.204/pub/electricity/f860y09.zip. 

Accessed November 28, 2011.

19 For more on the methodology NREL used to examine survival rates for 

coal plants, see Kaplan, E. L. Meier, P.: Nonparametric estimation from 

incomplete observations. -. Amer. Statist. Assn. 53:457–481, 1958.

Table 1-6 shows the utility partners’ current remaining 

capital interests in Navajo GS, based on net plant in 

service (the utility’s value of plant assets that has not 

yet been depreciated). The owners anticipate that the 

depreciation of their capital positions in the plant—their 

initial investments as well as all improvements and 

additions to date—will continue to as long as 2026. A 

signi¿cant amount of the undepreciated capital is in recent 

environmental retro¿ts to the plant. Additional capital 

costs associated with SCR retro¿ts could extend the 

depreciation period out to 2044.

1.2.2 Advanced Planning

Each partner utility currently has assets in advanced 

planning or under construction. SRP is planning to 

construct a 1,150 MW gas-¿red combined-cycle gas 

turbine (CCGT) plant at Pinal Central in Arizona. 

LADWP is planning two gas-¿red CCGT plants in 

California - a 500 MW addition to Haynes Repowering 

and the 900 MW Scattergood Repowering. The Solana 

plant, currently under construction by APS, will be 

the largest concentrating solar plant in Arizona with a 

capacity of 280 MW. Among the other partner utilities, 

several photovoltaic and solar thermal plants, two wind 

farms and two geothermal plants are also in advanced 

planning or are under construction in California, Arizona, 

,daho and Nevada.20

20 SNL Financial 2011.

Unit 1

Unit 2

Unit 3 Unit 1

Unit 2

Unit 3

Unit 

capacity 

factor in 

2010

100%

75%

50%

25%

0 10 20 30 40 50 60 70

Age of unit in 2010

Note: Navajo GS units in red. Unit 2 had a one-time outage in 2010 for LNB/SOFA installation its 2009 

capacity factor was 89%. Source: SNL Financial 2011

Figure 1-2. Age, capacity factor and size of coal units in WECC 
NREL/TP-6A20-53024 17

N9 Energy has two activities of particular relevance 

to its position in Navajo GS. First is the development 

of geothermal power in its Sierra Paci¿c balancing 

authority (BA) area. Projects totaling more than 800 

MW in maximum summer capacity are in N9 Energy’s 

interconnection queue.21 Second is the construction of a 

new 500 k9 transmission line that will be the ¿rst bulk 

power link between N9 Energy’s northern and southern 

BAs. Lines of this size typically provide as much as 1,500 

MW of transfer capability. Consequently, N9 Energy will 

soon have the capability of bringing to the Las 9egas area 

an amount of renewable base load power equal to what it is 

currently receiving from its share of Navajo GS (254 MW).

1.2.3 Navajo Generating Station Financing

A generator’s capital costs and its cost of production 

are apples and oranges in the world of utility ¿nance. 

,mproperly combining them analytically can, depending 

on the context, lead to spurious conclusions about the 

cost of retro¿tting an existing generator. This analysis 

examines and presents capital costs and production costs 

separately.

Table 1-7 highlights some of the crucial differences 

between capital costs and production costs. Production 

costs include O&M expenses as well as expenses for 

fuel. Nearly four-¿fths of Navajo GS’ O&M expenses are 

variable, meaning that they increase or decrease along with 

21 N9 Energy, ,PP OATT Applications for ,nterconnection (posted on Open 

Access Same-time ,nformation System), November 3, 2011.

Table 1-6. Utility Partners’ Interests in Navajo Generating Station

Utility Plant in 

Service

Accumulated 

Depreciation

Net Plant 

in Service

Construction 

Work in 

Progress

Source

SRP a $384,749 ($333,344) $51,405 $21,395 SRP 2011

LADWP 329,000 (298,000) 31,000 n/a Nguyen 2011

APS b 260,590 (163,281) 97,309 11,041 PNW 2011

NV Energy b 249,646 (141,326) 108,320 1 NV Energy 2011

TEP b 121,000 (84,000) 37,000 6,000 Unisource 2011

$ in thousands

(a) As of April 30th, 2010.

(b) As of December 31st, 2010.

changes in the amount of electricity generated at the plant. 

Only production costs make a plant more expensive to run. 

,f an upgrade to the plant were to increase capital cost but 

not production cost, then as a general rule the plant would 

run just as much as it did before the addition (assuming no 

other operational changes). The capital costs are recovered 

elsewhere in the utility’s rates, and that revenue is not 

affected by how much the plant runs.

All ¿ve utility partners use similar rate mechanisms to 

recover capital costs. Each regulated ,OU has an approved 

rate base that pools its depreciated capital investments 

(primarily power plants, transmission lines, substations, 

and distribution lines) and other eligible assets. The 

utility’s regulatory body (in the case of APS, TEP or N9

Energy, either the ACC or NPUC) decides which assets are 

included in the rate base and which are not. ,n addition, 

the regulators determine the rate of return that the utility 

is allowed to earn on its rate base. These two elements—

rate base and the rate of return—determine the utility’s 

revenue requirement, which is then allocated to all of the 

utility’s customers through base rates.

rate base × rate of return 

= revenue requirement

Public utilities such as SRP and LADWP have similar 

recovery mechanisms, except that the rate base and rate of 

return are determined by the utility’s governing entity, not 

by state regulators.
18 NREL/TP-6A20-53024

Table 1-7. Major Differences Between Capital Costs and Production Costs

Capital costs Production costs

Include operation and maintenance expenses (in 

addition to fuel expenses)

Treated as an asset; costs are financed with a 

combination of equity and long-term debt, 

depreciated over time

Treated as an expense; costs are paid as incurred, in 

cash or with short-term debt 

Obligation to pay does not stop if plant shuts down 

prematurely; it becomes a stranded cost Most expense occurs when plant operatesa

Adding capital cost does not increase the unit’s 

production cost, does not affect economic dispatchb

Adding O&M cost increases the unit’s production 

cost, tends to reduce economic dispatchb

Recovered as a fixed component of the base rates 

charged to all of the utility’s customers

Recovered as a pass-through charge allocated to all 

customers as needed

$/MWh for capital costs measures dollars per 

megawatt of power sold to all customers

$/MWh for production costs measures dollars per 

megawatt of power generated by the unit

(a) Some O&M costs are ¿xed and occur independent of how much the plant operates. Fixed O&M costs accounted for 22% of 

Navajo GS production costs in 2010.

(b) “Economic dispatch” refers to operating the least-cost plants most often, and running the highest-cost plants only when 

needed due to peak demand or system emergencies.

Table 1-8. SCR Capital Cost Relative to Net Utility Plant

Net utility 

planta

($ millions)

Share of capital 

cost 

($ millions)

Share of capital cost as % 

of current net utility plant

SRP $6,959 $100.9 to $118.1 1.4% to 1.7%

LADWP 6,703 98.6 to 115.4 1.4% to 1.7%

APS 9,146 65.1 to 76.2 0.9% to 1.1%

NV Energy 8,930 52.5 to 61.5 0.8% to 0.9%

TEP 2,410 34.9 to 40.8 0.5% to 0.6%

(a) Total plant in service less accumulated depreciation. Does not include non-utility property. ,nclusive of plant held for future use.

Sources: SRP 2011d, LADWP 2010b, PNW 2011, N9 Energy 2011, Unisource 2011, Sargent & Lundy 2010

Table 1-9. SCR, Baghouse, Sorbent Injection Capital Costs Relative to Net Utility Plant

Net utility 

plant a

($ millions)

Share of capital cost 

($ millions)

Share of capital cost as % of 

current net utility plant

SRP $6,959 $230.4 to $247.9 3.3% to 3.6%

LADWP 6,703 225.1 to 242.2 3.2% to 3.5%

APS 9,146 148.6 to 160.0 2.1% to 2.3%

NV Energy 8,930 120.0 to 129.1 1.7% to 1.9%

TEP 2,410 79.6 to 85.7 1.1% to 1.2%

(a) Total plant in service less accumulated depreciation. Does not include non-utility property. ,nclusive of plant held for future use.

Sources: SRP 2011d, LADWP 2010b, PNW 2011, N9 Energy 2011, Unisource 2011, Sargent & Lundy 2010
NREL/TP-6A20-53024 19

Table 1-10. Retail Rate Impact of SCR Capital Cost

Applied 

discount 

rate a

Annual revenue 

requirement 

over 20 years for 

capital cost of 

SCR

Annual utility 

retail sales 

(million kWh)

Rate impact of 

annual capital cost 

(cents per kWh)

SRP 9.8% $11.7 to $13.7 32,538 0.036 to 0.042

LADWP 6.0% 8.6 to 10.1 26,205 0.033 to 0.039

APS 8.3% 6.8 to 7.9 28,225 0.024 to 0.028

NV Energy 8.3% 5.5 to 6.4 29,261 0.019 to 0.022

TEP 8.0% 3.6 to 4.2 9,388 0.038 to 0.044

(a) Based on utility’s cost of capital rate provided by SRP includes a risk premium.

Table 1-11. Retail Rate Impact of SCR, Baghouse, Sorbent Injection (Cents per kWh)

Additional annualized 

capital costs

Additional production 

costs

SCR

(20 years)

SCR, 

baghouses, 

sorbent 

injectiona

(20 years)

SCR, 

baghouses, 

sorbent 

injectiona

(10 years)

SCR

SCR, 

baghouses, 

sorbent 

injectiona

SRP 0.036 to 0.042 0.087 0.122 0.008 to 0.011 0.014

LADWP 0.033 to 0.038 0.080 0.124 0.010 to 0.014 0.017

APS 0.024 tyo 0.028 0.058 0.085 0.006 to 0.008 0.010

NV Energy 0.019 to 0.022 0.045 0.066 0.005 to 0.006 0.008

TEP 0.038 to 0.044 0.092 0.135 0.010 to 0.013 0.016

(a) Only Sargent & Lundy estimated the combined costs of SCR, baghouses and sorbent injection. National Park Service did 

not provide comparable estimates.

Table 1-12. Retail Rate Impact of SCR, SNCR, SCR with Additional Controls (% of Retail Rates)

2010 average 

retail rate

(cents per 

kWh)

SCR 

(20 years)

SNCR

(20 

years)

SCR, baghouses, 

sorbent injection 

(20 years)

SCR, baghouses, 

sorbent injection 

(10 years)

SRP 9.26 0.5% to 0.6% 0.05% about 1.1% about 1.5%

LADWP 12.38 0.3% to 0.4% 0.04% about 0.8% about 1.1%

APS 10.63 about 0.3% 0.03% about 0.6% about 0.9%

NV Energy 10.58 0.2% to 0.3% 0.02% about 0.5% about 0.7%

TEP 8.94 0.5% to 0.6% 0.06% about 1.2% about 1.7%
20 NREL/TP-6A20-53024

range) to 0.044 cents per kilowatt hour for TEP (assuming 

SCR costs at the high end of the plausible cost range).

Tables 1-11 and 1-12 show the ultimate retail rate impacts 

of three scenarios, applying thesame approach broken 

down in Table 1-10. Table 1-11 includes each utility’s 

share of the additional production costs (as operation and 

maintenance costs based on current production levels), 

applied to total retail sales. The scenarios include the 

capital costs of SCR controls only, the capital cost of SCR 

controls combined with baghouses and sorbent injection, 

and the SCR/baghouse/sorbent injection scenario 

annualized across 10 years rather than 20 years. Estimated 

rate increases under the SCR-only scenario range from 

0.2% to 0.6%. Under the accelerated SCR/baghouse/

sorbent injection scenario, rates would increase by an 

estimated 0.7% to 1.7%.

Salt River Project 

SRP’s estimated original cost of Navajo GS, including the 

cost of the ESPs, was in the range of $220 to $240 million, 

which was ¿nanced through a combination of revenue 

bonds and corporate funds. These costs were added 

into SRP’s base rates as the Navajo GS units became 

operational in the mid-1970s.

The emission controls are similarly ¿nanced through 

revenue bonds and corporate funds set aside for capital 

improvements, derived from rate income from previous 

years. The costs are recovered through a rate increase, 

Retail base rates recover capital costs. Another billing 

component typically recovers costs that vary based on 

how much energy the utility’s generating Àeet produces

these costs generally include coal and other fuels used to 

generate power, and operation and maintenance (O&M) 

costs. Adding SCRs to a coal plant would increase the rate 

base, but once the equipment was in place the production 

costs would be little different from what they had been 

before. Consequently, the cost of running the upgraded 

plant would be largely unchanged. The cost of the upgrade 

would be recovered through the utility’s rate base, 

spreading the cost across all customer rates and making 

cost recovery independent of the electricity generated at 

the upgraded plant.

The cost of the SCR upgrade ranges from 0.5% to 1.7% of 

the utility partners’ net utility plant, a measure of the total 

plant in service less accumulated depreciation. This ¿gure 

is also inclusive of construction work in progress and any 

plant held for future use.

Table 1-6 shows the utility partners’ ¿nancial position in 

Navajo GS at the end of their last ¿scal years. Net plant 

in service indicates the capital investment in the plant 

minus depreciation. ,n the event of a shut down, once the 

plant is no longer generating revenue, any remaining net 

plant in service would be reÀected as a loss on the income 

statement, and therefore, as a one-time earnings impact. 

The capital investment in Navajo GS would also be 

removed from the regulated utilities’ rate base, resulting 

in a loss on the return on assets and ultimately impacting 

rates. The utilities would also realize a reduction in 

Operations & Maintenance (O&M) costs, which would 

decrease the cost of service that feeds into the variable 

portion of the rates charged to the customer.

Table 1-10 shows the impact of SCR capital costs on the 

rates ultimately paid by each utility’s retail customers. 

The increases in net utility plant shown in Table 1-8 

are treated in Table 1-10 as capital items with a 20-year 

economic life, and annualized according to each utility’s 

weighted average cost of capital. The annualized capital 

cost is spread across retail rates paid by all the utility’s 

customers, approximated here by applying the annualized 

cost to total retail electricity sales. The estimated increase 

ranges from 0.019 cents per kilowatt-hour for N9 Energy 

(assuming SCR costs at the low end of the plausible cost 

$-

SRP

LADWP

APS

NV ENERGY

TEP

RECLAMATION

$50 $100 $150

MILLIONS

$200 $250 $300

$101

$99

$65

$53

$35 $41

$113 $132

$61

$76

$115

$118

See Chapter 3 for derivation of SCR cost ranges.

Figure 1-3. Estimated Share of SCR Retrofits Based on Current Ownership 

($ millions)
NREL/TP-6A20-53024 21

which already occurred for the SO2 scrubber addition. The 

cost of the low-NOx

 burners will be added to SRP retail 

rates at the time of the next price process.22 Adding the 

SCR retro¿ts, estimated to cost between $100.9 and $118.5 

million, would likely be ¿nanced through revenue bonds 

and corporate funds, and SRP would recover the costs 

through a subsequent rate increase.

SRP is currently depreciating Navajo GS and the 

environmental control additions through 2019, based off 

of when the rights-of-way and land lease contracts expire. 

Any extension to the depreciation timeline, in addition to 

changes in rates and the recovery of costs, would have to 

be approved by SRP’s Board of Directors.

Los Angeles Department of Water and Power 

LADWP’s share of the construction cost of Navajo GS 

was $148.4 million, which was ¿nanced by the issuance of 

power project bonds. These bonds were not speci¿c to the 

Navajo GS plant, and included several power generation 

projects and transmission and distribution systems. 

The service on these bonds was immediately added to 

LADWP’s electric rate base. LADWP’s share of the ESPs 

was $42.4 million, its share of the SO2

 scrubbers was 

approximately $89 million and its share of the low NOx

burners was approximately $9.5 million. These additions 

were funded through power project bonds and cash 

reserves obtained from sales revenues.23

LADWP’s ¿nancial position in Navajo GS is relatively 

lighter than that of the other utility partners, based on 

net plant in service and on the utility’s plans for the early 

divestiture of its share of Navajo GS in 2014. LADWP is 

currently depreciating Navajo GS through 2019. LADWP’s 

share of the SCR cost would be between $98.6 and 

$115.7 million and would likely be ¿nanced through the 

issuance of power project bonds, cash reserves and a rate 

increase. However, investing in a major BART upgrade is 

economically rational only if LADWP does not divest and 

retains its ownership stake in Navajo GS beyond 2019. ,f 

this were to occur, the depreciation schedule would expand 

to Navajo GS’ full service life, which is currently pegged 

at 2044.24

22 Cooper, Thomas. Salt River Project, email correspondence, September 28, 

2011. www.nrel.gov/navajo.

23 Nguyen, Luan. LADWP, email correspondence, September 19, 2011. 

www.nrel.gov/navajo.

24 Nguyen 2011.

Arizona Public Service Co. 

APS’ share of the original construction cost of Navajo 

GS is estimated to be approximately $105 million, based 

on its ownership share and was added to APS’ rate base 

between 1974 and 1976. The SO2

 scrubbers cost $58.8 

million, while the low-NOx

 burners cost an additional 

$6.6 million. While the total cost of the SO2

 scrubbers 

was directly added to APS’ rates, the low-NOx

 system was 

eligible for Environmental ,mprovement Charge credits, 

as part of the Arizona Corporation Commission Decision 

Number 69663. The cost of the low-NOx

 system, less the 

aforementioned credits, has been added to the rate base in 

the current rate case, ¿led earlier in 2011.25

The SCR addition is estimated to cost APS between $65.1 

and $76.4 million.26 ,f APS follows the traditional utility 

¿nancing model, the capital costs of the SCR addition 

would be included in its rate base and would be ¿nanced 

with a combination of 40% debt and 60% equity. 

Tucson Electric Power Co. 

TEP’s share of the original construction cost of Navajo 

GS was approximately $56 million. TEP’s share of Navajo 

GS units 1 and 2 was factored into rates in 1978, and unit 

3 was included in rates in 1982.27 The SO2

 scrubbers 

cost TEP approximately $31.5 million and were ¿nanced 

through tax-exempt pollution control bonds, the service on 

which was included in TEP’s 2008 retail rate order. TEP’s 

share of the low-NOx

 burners was about $3.4 million and 

was paid with available cash.

TEP has depreciated Navajo GS over its full expected 

service life, which the ACC has approved to reÀect the 

current terminal date of 2026. ,f the SCRs were installed, 

this would only alter TEP’s depreciation timeline if the 

addition impacted the terminal date. Due to TEP’s small 

ownership stake in Navajo GS, the SCR addition will 

likely cost TEP between $34.9 and $40.9 million. TEP 

expects to ¿nance the SCRs with a combination of 40% 

debt and 60% equity, though that combination may shift 

towards 45% debt and 55% equity in the future.28 

25 Samuel -r., Gordon. Arizona Public Service (APS), email correspondence, 

November 10, 2011.

26 Sargent & Lundy 2010.

27 Gin, Don, Tucson Electric Power. email correspondence, October 4, 2011. 

www.nrel.gov/navajo.

28 Grant, Kent, Tucson Electric Power, telephonic conversation, October 20, 

2011.
22 NREL/TP-6A20-53024

NV Energy

N9 Energy’s share of the cost to build the Navajo GS plant 

was approximately $84 million. This was ¿nanced through 

a traditional utility mix of close to 40% debt and 60% 

equity, and the cost was added to N9 Energy’s rate base 

shortly after the construction was completed. The cost of 

the SO2

 scrubbers was $14.3 million and $12.4 million for 

units 1 and 2, respectively. Unit 3’s cost was unavailable 

in the time allowed for this study, but is currently included 

in N9 Energy’s latest rate case. The cost of the low-NOx

burners was $1.6 million and $1.8 million for units 1 and 

2, respectively. Similarly, unit 3’s cost was unavailable but 

is included in the current rate case. These environmental 

control additions were ¿nanced with a traditional utility 

mix of debt and equity. N9 Energy expects to ¿nance the 

proposed SCR additions in the same way.29 ,t is estimated 

that the SCRs would cost N9 Energy in the range of $52.5 to 

$61.7 million.30

With the current environmental controls installed, N9

Energy anticipates the Navajo GS plant to be fully 

depreciated in 2024, 2025 and 2026 (for units 1, 2 and 3, 

respectively), though its net plant in service is currently the 

highest of any of the utilities. ,f the SCRs were added to 

the plant, N9 Energy could potentially request the Public 

Utilities Commission of Nevada that the depreciation 

timeline be altered through a LSAP, or life span analysis 

process.31

U.S. Bureau of Reclamation

The Bureau of Reclamation has used several approaches 

to fund its share of Navajo GS plant capital expenditures 

over the history of the plant. The original cost of the plant 

to the Bureau of Reclamation, including the ESPs, was 

$200 million. The Southern Transmission and Western 

Transmission Systems cost another $25 and $12 million, 

respectively. The SO2

 scrubbers cost an additional $102 

million. All of this was funded through CAP construction 

appropriations and the cost of the construction, the 

transmission systems, and the SO2

 scrubbers were 

ultimately allocated to project purposes. These costs were 

deemed as reimbursable and the CAWCD is repaying the 

29 Geraghty, Kevin. N9 Energy, telephonic conversation, October 28, 2011.

30 Sargent & Lundy 2010.

31 Geraghty 2011.

federal government for these costs through payments into 

the Lower Colorado Basin Development Fund over a 50-

year period.

Lower Colorado Basin Development Fund revenues 

funded the Bureau’s $11 million share ($3.7 million per 

year over a three-year construction period) of the cost of 

the low-NOx

 burners. These costs were then reimbursed 

by SRP on an amortized basis and the remaining balance 

was reimbursed by CAWCD.32

The Bureau of Reclamation’s share of the cost of the SCRs 

is estimated to be between $113.0 and $132.6 million. This 

analysis assumes CAWCD would be responsible for the 

entirety of this cost, and that the probability of securing 

appropriations to fund all or part of the SCR cost is low. ,n 

the absence of guidance otherwise, this analysis assumes 

that all of the federal share would be passed on to CAWCD 

for recovery from CAP rates, ¿nanced through revenue 

bonds. CAWCD’s Replacement Fund could assist with the 

funding of the SCR however, the fund will not cover the 

full cost of the SCR installation.

Table 1-13 shows the estimate impact of various BART 

outcomes, based on the capital cost of retro¿ts, and the 

cost they would add to CAP pumping power. O&M costs 

for SCRs, baghouses and sorbent injection would add 

another 0.11 cents to 0.14 cents per kilowatt hour. Chapter 

4 follows these likely costs through CAWCD rates in 

detail. Table 1-14 summarizes the ultimate impact on 

water rates as explained in that chapter.

1.3 Power Plant Operations

Navajo GS is con¿gured with three 750 MW supercritical 

tangentially ¿red boilers, supplied by Combustion 

Engineers, Co. (now Alstom Power, Co.). The ¿rst unit of 

the power plant was commissioned and began commercial 

operation in 1974, with the other two units following in 

1975 and 1976. The plant original construction costs were 

$650 million.33

32 Stemmer, Matthew, U.S. Bureau of Reclamation, email correspondence, 

September 27, 2011. www.nrel.gov/navajo.

33 SRP Website: www.srpnet.com/about/stations/Navajo.aspx
NREL/TP-6A20-53024 23

Navajo GS converts coal, mined at the Kayenta Mine, into 

electricity through combustion. The power plant utilizes 

approximately 8 million tons of low-sulfur bituminous 

coal per year.34 The Kayenta Mine is located on Hopi and 

Navajo lands on a highland plateau called Black Mesa, 

approximately 78 miles from the Navajo Generating 

Station. Kayenta Mine processes the coal through 

crushers, then transports the product 17 miles to storage 

silos. The coal is transported to the storage silos using 

a conveyor system, and then to the power plant using an 

electric closed loop rail line. The Kayenta Mine employs 

approximately 422 tribal members, and the mine is owned 

by Peabody Western Coal Company. The Kayenta Mine 

began operation in 1973.

Navajo Generating station was originally con¿gured as 

three units, each unit with the capability of generating 750 

34 Part 71 Federal Operating Permit Draft Statement of Basis, Peabody 

Western Coal Company – Black Mesa Complex Permit No. NN-OP 09-010: 

Peabody Energy Website: http://www.peabodyenergy.com/content/276/

Publications/Fact-Sheets/Kayenta-Mine.

Table 1-13: Impact of SCR, Baghouse, Sorbent Injection Capital Costs on CAP Pumping Power Cost

2010 pumping 

power cost (cents 

per kWh)

Annual 

capital cost ($ 

millions)

Impact of annual capital cost 

(cents per kWh) %

SCR only 3.09 $9.1 to $10.6 0.324 to 0.380 10.5% to 

12.3%

SCR/baghouse/ 

sorbent 

injection

3.09 $20.7 to $22.3 0.739 to 0.796 23.9% to 

25.8%

Note: Calculations assume CAWCD uses municipal revenue bonds at 5%, and annual CAP pumping power requirements are 

2,800 million kWh. Total pumping power costs for 2010 are calculated at 3.09 cents per kwh, based on CAWCD reported data 

for total energy purchased for pumping (2,940 GWh) and total power expenses ($90.8 million) for that year.a

(a) CAWCD, 2012/2013 Biennial Budget, November 2011.

MW power. The facility operates under a Title 9, Major 

Source Operating Permit, with SRP as the managing 

participant. The plant also operates with an Acid Rain 

permit and Part 71 Permit. The current Title 9 was 

issued -uly 3, 2008 by the Navajo Nation Environmental 

Protection Agency, and expires -uly 3, 2013.35

All three units are con¿gured with a pulverized coal-

¿red supercritical tangentially ¿red boilers using No. 2 

fuel oil for ignition/start-up fuel. The stacks are equipped 

with SO2

 and NOx monitoring through a Continuous 

Emissions Monitoring System (CEMS). The material 

handling equipment was originally integrated with dust 

collection systems to control particulate at each transfer 

point, and water suppression has been utilized to control 

dust at storage locations and from unpaved roads.36 The 

plant generates electricity using a three-pressure steam 

cycle, including a re-heat section for improved system 

35 Permit Number NN-ROP-05-06. Navajo Nation EPA Website: www.

navajonationepa.org

36 Title 9 Permit to Operate, Permit  NN-ROP-05-06, 07/03/2008.

Table 1-14: Impact of SCR, Baghouse, Sorbent Injection Costs on CAP Water Rates

Water customer class Increase from 

SCR only

SCR/baghouses/sorbent 

injection 

Municipal and Industrial

Long-term Subcontract

Non-Subcontract

Recharge

AWBA Interstate Recharge

6%-7%

5%-6%

5%-6%

4%-5%

13%-14%

11%-12%

11%-12%

9%-10%

Federal (Tribes) 13%-16% 29%-32%

Agricultural 13%-16% 29%-32%
24 NREL/TP-6A20-53024

ef¿ciencies. The plant is cooled using mechanical draft 

cooling towers. The plant uses about 28,000 acre-feet of 

water per year from Lake Powell for the cooling, acid 

gas scrubbing, boiler water make-up, and other auxiliary 

water uses. A zero liquid discharge system uses a brine 

concentrator and crystallizer to help disposal of highly 

concentrated brine. Each unit is con¿gured with four 

feed-water heaters, one direct contact deaerator, and three 

indirect feed water heaters.

Originally the facility was con¿gured with hot side 

electrostatic precipitators (ESP). ,n 1997-1999, NGS 

underwent modi¿cations that included spray-type 

Àue gas desulfurization (FGD) systems and ef¿ciency 

improvements of the steam turbines to increase gross 

power generation. The steam turbine ef¿ciency increases 

were implemented to compensate for the loss of net 

power generation, due to the additional air quality control 

equipment auxiliary power usage. These modi¿cations 

maintained the 7,725 MBtu/hr boiler input and 750 MW 

net generation.

Currently, Navajo GS operates with low-NOx

 burners 

(LNB) and separated over¿re air (SOFA) to reduce NOx

formation during combustion and control the excess air 

required for complete combustion, while maintaining 

furnace temperatures. Reducing the amount of excess air 

and maintaining combustion temperatures minimizes the 

quantity of NOx

 formed. 

1.3.1 Operational Data

The Navajo Generating Station operates as a base load 

plant, but its capacity factor Àuctuates as shown in Figure 

1-4. Table 1-15 summarizes the facility’s 2010 operations. 

Navajo GS’ capacity factor for this year was somewhat 

below normal, due to additional planned outages for the 

installation of low NOx

 burners and SOFA.

Throughout recent years, the plant’s capacity factor has 

been fairly stable (taking into account the time needed 

to install the low-NOx

 burners), indicating the equipment 

and systems have been maintained. Seasonal drops in 

monthly generation coincide with planned maintenance 

outages. Each units is maintained on a six-year cycle, 

alternating between 4-week minor outages and 8-week 

major outages every three years. Somewhat longer 

seasonal outages from 2009 to 2011 correspond to the 

installation of low-NOx

 burners.

1.3.2 SO2 controls

As Chapter 5 discusses in greater detail, SO2 is another 

emission that contributes to the formation of regional 

haze. Amendments to the Clean Air Act in 1990 led to 

more stringent emission requirements for coal plants 

across the country. Plant owners installed scrubbers at 

Navajo GS, after which SO2

 emissions from the plant 

declined by more than 95%. 

SNL Energy www.snl.com 

Figure 1-4. Navajo GS monthly capacity factor

0% 

25%

75%

50%

100%

Jan 2005

Jan 2006

Jan 2007

Jan 2008

Jan 2009

Jan 2010

Jan 2011
NREL/TP-6A20-53024 25

Navajo GS has wet scrubbers, two for each operating unit. 

Engineering and construction began 1994. Around the same 

time as the scrubber installation, ef¿ciency upgrades were 

conducted on the steam turbines to overcome the additional 

operating electrical loads due to the scrubber system and 

the additional pressure loss through Àue gas ductwork. The 

ef¿ciency upgrades maintained the plants original net output 

at 2,250 MW. The wet scrubbers and ef¿ciency upgrades 

cost the owners $420 million. The facility currently is 

operating with a removal ef¿ciency greater than 95%.

1.3.3 Emission Limits for NOx

Table 1-16 shows the peak NOx emissions for each of the 

three units from 2009 through 2011 to date, based on data 

from the plant’s Continuous Emissions Monitoring System. 

The highest emissions happened during 2009, and were 

from Unit 2. 

Table 1-17 summarizes average NOx

 emissions for the 

same years. Unit 1 (the last of the three units to receive 

low-NOx

 burners and SOFA) recorded the highest 

average emission, while Unit 2 and Unit 3 both showed 

a substantial reduction in NOx

 since 2009. By the second 

quarter of 2011, all three reported an average emission rate 

of 0.217 lb/mmBtu or better.

Table 1-16. Maximum Adjusted Nitrogen Oxide Emission Rates, 2009 – 2011 (lb/mmBtu)

Report

Unit 1 Unit 2 Unit 3

Reported Calculated Reported Calculated Reported Calculated

Maximum 0.572 0.572 0.774 0.774 0.578 0.498

Max 2009 0.572 0.572 0.511 0.511 0.578 0.498

Max 2010 0.569 0.569 0.774 0.774 0.465 0.465

Max 2011 0.552 0.552 0.481 0.481 0.478 0.478

Table 1-15. Navajo GS Operation Summary (2010)

Capacity 2,250 MW

Capacity factor 83%

Heat rate 10,085 Btu per kWh

Production cost, 

which includes

Fuel expenses

Non-fuel O&M expenses

$24.45 per MWh

17.80 per MWh

$6.66 per MWh
26 NREL/TP-6A20-53024

Table 1-17. Average Adjusted Nitrogen Oxide Emission Rates, 2009 – 2011 (lb/mmBtu)

Report

Unit 1 Unit 2 Unit 3

Reported Calculated Reported Calculated Reported Calculated

Q1-09 0.386 0.386 0.349 0.349 0.365 -

Q2-09 0.377 0.377 0.364 0.364 0.200 0.200

Q3-09 0.397 0.397 0.352 0.352 0.200 0.200

Q4-09 0.358 0.358 0.308 0.308 0.202 0.202

Q1-10 0.348 0.348 0.269 0.269 0.199 0.199

Q2-10 0.389 0.389 0.217 0.217 0.207 0.207

Q3-10 0.406 0.406 0.219 0.219 0.219 0.219

Q4-10 0.400 0.400 0.213 0.213 0.201 0.201

Q1-11 0.396 0.396 0.212 0.212 0.209 0.209

Q2-11 0.201 0.201 0.217 0.217 0.217 0.217

Maximum 0.406 0.406 0.364 0.364 0.365 0.219

Max 2009 0.397 0.397 0.364 0.364 0.365 0.202

Max 2010 0.406 0.406 0.269 0.269 0.219 0.219

Max 2011 0.396 0.396 0.217 0.217 0.217 0.217

Source: SRP, Emission Reporting Data from Historian, 9S_1b&1c_NGS Unit 1 Emission Data, 9S_1b&1c_NGS Unit 2 

Emission Data, 9S_1b&1c_NGS Unit 3 Emission Data.
NREL/TP-6A20-53024 27

This chapter examines how the rest of the Western 

,nterconnection would respond if Navajo GS were 

to close. Meeting the same overall level of demand 

with a slightly different mix of resources would entail 

measurable costs, and these costs provide a robust 

and meaningful comparison with the cost of BART 

compliance alternatives. 

What follows is an economic analysis of the implications 

of retirement it is not a full reliability analysis. To 

understand the full implications, a reliability study would 

need to analyze the effects of Navajo GS retirement on the 

ability of utilities in the Western Electric Coordinating 

Council (WECC, the Western ,nterconnection’s regional 

reliability organization) to meet planning reserve and 

serve load reliably. The economic analysis performed for 

this study assumes that any reliability problems introduced 

by retirement would not add signi¿cant costs to the 

system, and that the need to conduct a reliability analysis 

would be driven by the basic economics of shutdown. 

,n this respect, this analysis is a “best case” scenario 

regarding retirement.

The rest of the power system would tend to correct itself 

in the event of a Navajo GS retirement. Even though 

Navajo GS is its largest operating coal plant, the Western 

,nterconnection theoretically has enough unused capacity 

throughout the year to make up the loss if the plant 

were to close. Contractual limitations or other business 

considerations may prevent some power trading that 

otherwise would be economically ef¿cient changes in 

transmission path ratings not captured in this economic 

analysis could also hamper some exchanges. Nevertheless, 

it is unlikely that the full capacity of Navajo GS would 

need to be replaced. Capacity expansion is typically 

driven by changes in system-wide factors such as reserve 

margins—the percentage of total available capacity in 

excess of the year’s total demand. The reserve margin for 

the Desert Southwest is currently in excess of 30% (and 

nearly 35% when taking into account anticipated new 

plants), well in excess of the area’s reference reserve margin 

of 13.5%. Without Navajo GS, the area’s reserve margin 

would fall to 22% (27% with anticipated new plants).1

1 The Desert Southwest includes Arizona, New Mexico (excluding a small 

part linked to the Eastern ,nterconnection), and southern Nevada. North 

American Electric Reliability Corporation (NERC), “2011 Summer 

Reliability Assessment,” March 2011.

Eventually, load growth would offset the excess capacity, 

and this would happen sooner if Navajo GS were retired. 

Because investment in one new unit involves hundreds 

of megawatts, millions of dollars, and signi¿cant risk all 

rolled up into a single capital expense, an individual utility 

will plan new capacity based on its own reserve margin, 

its own load growth, and the amount of capacity it is 

already holding in reserve for future electricity demand. 

Many factors affecting a speci¿c expansion decision 

are beyond what this analysis captures. To simplify 

the task and provide an economic reference point, this 

analysis assumes that no additional capacity is necessary 

after Navajo GS retirement, and the costs of retirement 

are incurred exclusively due to the higher cost of the 

replacement energy from existing unused capacity.

As with other chapters in this study, the analysis contained 

in this chapter is a close-up look at one piece of the Navajo 

GS complex case study. The factors accounted for in 

this chapter are limited to the economic operation of the 

regional electric grid. A utility typically would conduct 

a similar analysis for any plant closure, plant retro¿t, or 

construction of a new plant. 

This chapter’s analysis does not account for the 

complicating factors that make Navajo GS unique. ,t 

does not provide a measure of the tribal impacts and 

local economic development effects of retiring the plant, 

neither does it address how possible increases in power 

costs might affect CAP water users. Both of these effects 

require their own analytical approaches, and no attempt 

is made to arti¿cially account for them here. ,nstead, this 

chapter aims to develop a comprehensive understanding 

about traditional utility economic metrics, so that they can 

be accurately considered alongside issues addressed more 

thoroughly in other chapters of this report.

Navajo GS’ utility partners are substantially different 

from the Bureau of Reclamation in ways that affect 

what the ¿ndings of this chapter mean. Most utilities 

serve a diverse customer base with a diverse portfolio of 

generating resources. Capital costs and production costs 

alike are spread among all customers and not assigned 

to a single user. By contrast, Reclamation’s share of 

Navajo GS is virtually the sole source of power for one 

single user, the Central Arizona Project. This sole-source 

2 Regional System Impacts of Retiring Navajo GS
28 NREL/TP-6A20-53024

relationship greatly magni¿es the impacts on CAP of the 

outcomes modeled in this chapter. For this reason, the 

following sections frequently address the consequences for 

Reclamation and CAP differently from outcomes for the 

utility partners.

2.1 Selection of modeling approach

To frame the statutory BART criterion of energy-related 

impacts, NREL posed this question: 

How would grid operators change what they do in the 

event of a Navajo GS retirement?

NREL has used production cost modeling to answer 

this question analytically. Production cost modeling is a 

mainstay of planning in the electric sector, used frequently 

by large utilities, regional reliability organizations, 

and regional transmission organizations. ,t addresses 

with speci¿city many questions that are central to the 

energy impacts of compliance, which the Clean Air Act 

speci¿cally requires states and the EPA to consider in 

making a BART determination.

A production cost model picks the combination of units 

out of the existing generating Àeet that would minimize 

the cost of serving load. The model simulates real-time 

network conditions, including planned operational limits 

on each transmission line, the cost of cold-starting 

a generating unit, limits on how quickly a unit can 

increase or decrease its output, reserve requirements, 

line losses, and other factors that may affect a speci¿c 

unit’s ability to respond to an economic-based instruction 

for dispatching power onto the system. Within these 

operational constraints, the model then dispatches enough 

power from the generation Àeet to match demand at each 

moment over the course of a typical year. The least-cost 

dispatch portfolio accounts for each generating unit’s 

production cost (or more precisely, the cost at the plant of 

producing one additional MW of power), and transmission 

constraints that may limit the deliverability of power from 

units with the lowest production cost. For this study, it is 

assumed that the transmission path ratings do not change 

due to the retirement of Navajo GS.

A production cost model does not take into account 

the capital cost of adding new capacity. ,t takes the 

con¿guration of the power system as it is, neither 

adding new capacity nor retiring old plants even if they 

are unused. Capital costs are assumed to be ¿xed and 

independent of how much or how little the plant actually 

runs throughout the year. The costs coming out of a 

production cost model, therefore, reÀect only a portion of 

what customers ultimately pay through their electric rates. 

Nevertheless, they reÀect the costs that utility operators 

try to minimize when deciding how to run their systems 

day-to-day and hour-to-hour.

While other types of power system modeling exist, NREL 

determined that they are less applicable to the questions 

at hand. For example, capacity expansion models are 

designed to forecast how much new capacity is likely to 

be added and how much is likely to retire under certain 

long-term assumptions. These models are appropriate 

for forecasting long-term changes across the entire 

power system, and for modeling system-wide responses 

to system-wide changes in policy, resource availability, 

climate change, or fuel prices. Capacity expansion 

models are less useful in examining a speci¿c plant 

with peculiar or even unique circumstances, because the 

input assumptions need to be generally (and plausibly) 

applicable to entire categories of generators modeled over 

a long period of time. Consequently, capacity expansion 

models do not have suf¿cient temporal or geographic 

resolution to capture how power system operations would 

respond to a discreet change at a single location, such as 

the retirement of a coal plant as large as Navajo GS.

For example, a capacity expansion model may predict 

the future addition of a certain amount of wind power 

or natural gas capacity, but will usually distribute the 

additional capacity generally without predicting exactly 

where it might be sited. The complex and often litigious 

matters of siting and permitting are simpli¿ed or even 

ignored, because whether the predicted plant actually ends 

up in the next county or the next state has little impact 

on the long-term macro-level phenomena that capacity 

expansion models are designed to examine. 

Plant retirements are similarly heuristic, as a decision to 

permanently close a plant often relies on case-speci¿c 

factors that cannot be captured by a capacity expansion 

model. Local economic impacts, limits to state regulatory 

jurisdiction, management, and other plant-speci¿c 

factors that are not modeled can keep some units on line 

regardless of what a capacity expansion model might 

predict, and vice versa. As long as these unmodeled 

plant-speci¿c factors do not bias the results in only 
NREL/TP-6A20-53024 29

one direction, however, they generally do not detract 

from system-wide conclusions, such as the total amount 

of capacity likely to become less viable under certain 

assumptions about emission regulation.

EPA has used capacity expansion modeling to examine the 

long-term national effects of its regional haze regulations, 

as well as the cross-state air pollution rule, the proposed 

toxics rule, various proposals for addressing climate 

change, and other proposed national policies.2

 ,n some 

runs, the EPA model predicts Navajo GS would be one 

of many coal plants likely to be retired early. Based 

NREL’s own extensive experience with capacity expansion 

modeling, however, less weight is placed on outcomes for 

individual plants when using this type of modeling. ,n any 

case, NREL’s task in this study is different from EPA’s 

task of modeling nationwide policy effects. ,nstead of 

predicting whether and how many generators will retire, 

this task is to measure the potential consequences to the 

rest of the system in the event Navajo GS does retire. 

A reliability analysis would use more detailed AC 

powerÀow models and dynamic models to test reliability 

metrics in the power system. This type of analysis 

was beyond the scope of this economic analysis. AC 

powerÀow analysis would help determine whether the 

retirement would lead to voltage problems, while dynamic 

analysis would help assess the impacts of the retirement on 

serving load during generator and transmission outages. 

Production cost modeling relies on a number of specialized 

terms and concepts. These terms make up the vocabulary 

of understanding the results, so an understanding of what 

they mean is an essential starting point for this chapter’s 

discussion.

Balancing authority (BA) areas. A BA is essentially 

the grid’s unit of central control. The North American 

Electric Reliability Corporation (NERC) de¿nes a BA 

area as the speci¿c collection of generators and load 

whose total metered output and consumption must 

balance moment by moment.3

 ,f demand increases 

by 20 MW, the BA must issue instructions to one or 

more units in its portfolio to ramp up by 20 MW, or 

import it from a neighboring BA with unused reserve. 

2 Link to http://www.epa.gov/visibility/actions.html and http://www.epa.gov/

airmarkt/progsregs/epa-ipm/index.html.

3 The balance is also net of any power transfers into or out of the BA across 

ties with neighboring BAs.

A large utility is often its own BA, although two or 

more utilities can participate in a single BA. Figure 2-1 

shows the approximate areas of the BAs used in this 

analysis several small BAs are analytically combined 

with their surrounding BAs for the sake of clarity. The 

BAs that constitute NERC’s Desert Southwest subregion include SRP, APS, TEP, Nevada Power (on the 

map, NE9P), the ,mperial ,rrigation District (,,D), the 

Western Area Power Administration’s Lower Colorado 

service area (WALC), Public Service Company of 

New Mexico (PNM), and El Paso Electric (EPE).

Nodes. Nodes are geographic points on the system 

where changes can occur that would affect real-time 

costs elsewhere on the system. They are points where 

either a generator connects to the grid, power leaves 

the transmission network to serve load, or multiple 

transmission paths connect or diverge. Figure 2-2 

shows the bus points in the Western ,nterconnection 

that constitute the nodes used in NREL’s analysis.

Locational marginal prices (LMPs). LMPs reÀect 

the immediate cost of producing power at a given 

node. The value of an LMP—expressed in dollars 

per MWh—indicates the cost to the entire system of 

changing generation or demand at that node by one 

megawatt. Generally, two factors can drive an LMP 

higher: the production cost of a particular generator, 

and transmission constraints that limit the ability to 

move low-cost power to a demand point.

For clarity, NREL has aggregated nodal outcomes by BA 

in many instances. Except for the Bureau of Reclamation, 

each Navajo GS partner also operates as a BA, making 

this a convenient and relevant tool for combining 

information. Not only does it comport with how the 

system operates, it also provides a meaningful approach 

to estimating the impact on the areas most likely to be 

affected by a Navajo GS retirement.

An important factor affecting the outcome of a production 

cost analysis is where a plant’s production costs fall 

relative to other generators in the region. All else being 

equal, a plant with a lower cost will be dispatched before 

a plant with a higher cost. A production cost model will 

meet the demand for energy at any given point beginning 

with the units with the lowest cost, and will proceed 

through the stack of available generators, ranked in order 

from lowest to highest cost, until demand is met. 
Energy Analysis 30 nrel.gov/analysis

BCTC

AESO

SPP

PSC

PNM

BPA

WAUW

SCE

APS

PACW

PACE_UT

PACE_WY

NWMT

AVA

EPE

PGE_VLY

TEP

WALC

WACM

PACE_ID

CFE

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PSE

IID

SRP

MAGIC VLY

PGN

SDGE

SMUD

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PSE

LDWP

FAR EAST

TIDC

TPWR

SCL

Reference Map

Balancing Authority Boundaries

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BCTC

AESO

SPP

PSC

PNM

BPA

SCE

APS

PACW

PACE_UT

PACE_WY

NWMT

WAUW

AVA

PGE_VLY

TEP

WALC

EPE

WACM

PACE_ID

CFE

TREAS VLY

NEVP

PSE

IID

SRP

MAGIC VLY

PGN

SDGE

SMUD

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PSE

LDWP

FAR EAST

TIDC

TPWR

SCL

Reference Map

Bus Points

Figure 2-1. Balancing authority areas modeled by NREL Figure 2-2. Bus points included in the model
NREL/TP-6A20-53024 31

Fuel prices are the most important determinant of a 

generator’s production cost. This is especially true 

of natural gas generators in areas where natural gas 

constitutes a large share of the generator Àeet. NREL’s 

base scenario assumes an average natural gas price 

of approximately $6.90 per mmBtu. Because of the 

historical volatility of natural gas prices, however, NREL 

has incorporated into its analysis two sensitivity runs: 

one scenario assuming natural gas prices averaging $13 

per mmBtu, and one assuming prices averaging $4 per 

mmBtu. This range captures most of the pricing points 

for natural gas from the Permian Basin hub since -anuary 

$0 

$4 

$2 

$8 

$6 

$12

$10

$14 

Jan 2008 Jan 2009 Jan 2010 Jan 2011

Data from SNL Financial LC

Figure 2-4. Spot price of natural gas at the Permian Basin Hub, 2008 to date 

A region’s power supply curve depicts 

the generators available within a 

particular region, in the general order 

that the units would be selected by a 

production cost model.

Figure 2-3 shows the power supply 

curve for NERC’s Desert Southwest 

subregion. Each point on the 

curve represents a speci¿c power 

plant a point’s color indicates the 

plant’s energy source. The distance 

between a given plant and the one 

immediately to its left captures 

the plant’s available capacity (in 

megawatts) its value on the vertical 

axis shows the production cost of that 

amount of capacity, in dollars per 

MWh dispatched. The value of the 

plant’s location on the horizontal axis 

represents the total amount of system 

capacity that would be economic 

if the market price were set at that 

plant’s cost of production. 

The production cost of Navajo GS is 

slightly above $20 per MWh. Future 

costs could increase depending on 

the outcome of negotiation over a 

new coal supply contract. The Desert 

Southwest’s summer peak hourly 

demand is around 29,000 MW its 

base load (the lowest demand during 

the year) is between 9,000 and 10,000 

MW.4

 Taking these data points into 

account, a cursory examination of the 

area’s power supply curve suggests that 

Ŷ Among other coal plants in the region, Navajo GS 

has a comparatively low cost of production

Ŷ Navajo GS would be economical most of the time 

and would be used as often as possible, based on 

the plant’s current operational characteristics, and

Ŷ losing Navajo GS would change the dispatch of the 

remaining generators with production costs higher 

than $20.

4 The non-coincident minimum load was 9,211 MW for all BAs in the Desert 

Southwest sub-region.

$0 

$25 

$50 

$75 

$100 

0 10,000 20,000 30,000 40,000 

Production cost 

($/MWh) 

Cumulative capacity (MW) 

Water Renewable Nuclear Coal Gas Base load Summer peak 

Navajo GS 

Figure 2-3. Navajo GS in the power supply curve for the Desert Southwest
32 NREL/TP-6A20-53024

the increase in net generation shown for Nevada Power, 

SRP, and APS indicates additional power from other 

plants in these systems.

Table 2-1 shows the extent to which the Navajo GS 

partners rely on the plant to serve demand. As mentioned 

earlier in this chapter, the utility partners also operate 

as BAs, which distinguishes them from the Bureau of 

Reclamation. Each utility’s share of Navajo GS is one 

of several generation resources that the utility manages 

as a portfolio to meet demand across its entire BA. By 

contrast, the Bureau of Reclamation’s share is earmarked 

for the direct use of one major power user—the Central 

Arizona Project—and therefore was considered in the 

NREL analysis as unavailable to serve other demand. 

Table 2-2 shows how much Navajo GS contributes to 

each BA supply portfolio. This table also shows the 

extent to which other plants within the BA would make 

up the loss, based on the NREL modeling results. What 

is not made up internally would need to come from 

other BAs, either as imported power or (what is more 

likely for the Desert Southwest) by reducing Àows to 

California and retaining more power within the local 

BAs.6

 Together, the utility partners would have to obtain 

a net 7.7 TWh of power from elsewhere in the Western 

,nterconnection, in addition to 4.3 TWh to replace the 

Bureau of Reclamation share. This includes power for the 

CAP system (approximately 2.8 TWh) as well as excess 

power that could be sold (as described in Chapter 4). ,n 

other words, the NREL model suggests that the utility 

partners themselves would economically replace less than 

one-third of what Navajo GS currently provides. Figure 

2-6 shows that most of the balance would come from 

resources in (or committed to) southern California.

Salt River Project would face particular challenges in 

replacing the energy it currently receives from Navajo GS. 

Of all the plant’s utility partners, SRP relies on Navajo 

GS the most. Results from NREL’s modeling suggest that 

other units within the SRP balancing area would be able to 

economically cover only 17% (about 700 GWh) of the loss 

to SRP if Navajo GS were to retire. SRP would need other 

resources to replace 3.1 TWh of what it currently receives 

from Navajo GS.

6 Aside from Navajo GS, three other major base load plants in the Desert 

Southwest—Palo 9erde, Four Corners, and San -uan—had about 15 TWh 

of their 2010 output committed to utilities in California.

2008, as shown in Figure 2-4. Current prices are near 

the low end of the sensitivity range NREL has modeled. 

However, additional demand would tend to push natural 

gas prices slightly higher if a Navajo GS retirement were 

to result in greater utilization of combined cycle gas units 

(as was the case after the retirement of the Mohave coal 

plant in southern Nevada).

Production cost modeling provides a rigorous and 

methodical way of examining in detail what those changes 

might look like. The remaining sections of this chapter 

examine three critical areas. First is where redispatch 

is likely to occur if the electricity currently provided by 

Navajo GS has to come from elsewhere. Second is the 

additional cost associated with the likely redispatch. The 

third examines how the outcomes might affect the Bureau 

of Reclamation differently than the other Navajo GS 

partners who are all BAs.

2.2 Redispatch: What the system would 

use to replace Navajo GS

Annual net generation from Navajo GS has averaged 

17.2 TWh since 2001, and has been as high as 17.7 TWh.5

 

Results from NREL’s modeling predict 17.5 TWh from the 

plant under normal system conditions. This is the amount 

of power that other units on the system would have to 

make up if Navajo GS were to retire. 

Figure 2-5 maps the distribution of annual net generation 

throughout the Western ,nterconnection as modeled 

under normal system conditions. The BAs with the 

largest amounts of net generation generally coincide with 

the areas of largest demand. Production in the Paci¿c 

Northwest also reÀects bulk transfer of hydropower to 

California, which is by far the largest demand center in 

the West. Although Navajo GS is physically situated in 

northern Arizona, its net generation is allocated among its 

owners that operate as BAs: SRP, LADWP, APS, Nevada 

Power, and TEP. 

Figure 2-6 shows where the increase in generation would 

likely occur in the event of a Navajo GS retirement. The 

17.5 TWh that would no longer come from Navajo GS is 

excluded from the data shown in the map. Consequently, 

5 Average excludes 2009 and 2010, when two units shut down temporarily in 

order to install low-NOx burners.
NREL/TP-6A20-53024 33

Table 2-1. Distribution of Navajo GS Production as Modeled in Base Case

Owner Balancing 

authority

Navajo share

(%) (modeled TWh)

U.S. Bureau of Reclamation No 24.3% 4.3

Salt River Project Yes 21.7% 3.8

Los Angeles Department of 

Water and Power Yes 21.2% 3.7

Arizona Public Service Co. Yes 14.0% 2.5

Nevada Power Co. Yes 11.3% 2.0

Tucson Electric Power Co. Yes 7.5% 1.3

Total Navajo production (base case) 17.5

Table 2-2. BA Replacement Needs Resulting from Retiring Navajo GS

Without Navajo

BA receiving Navajo 

GS power

Total net 

generation 

Navajo as 

share of BA 

total 

Change in BA 

generationa

Additional 

replacement 

needed 

TWh TWh % TWh TWh

Salt River Project 26.5 3.8 14% 0.7 3.1

LADWP 31.7 3.7 12% 0.6 3.1

Arizona Public Service 

Co. 30.2 2.5 8% 0.9 1.5

Nevada Power Co. 21.2 2.0 9% 2.9 -0.9

Tucson Electric Power 

Co. 15.2 1.3 9% 0.5 0.8

Total for BAs 124.9 13.2 11% 5.5 7.7 

U.S. Bureau of 

Reclamation 4.3

(a) Net of the 17.5 TWh that would no longer come from Navajo GS
Energy Analysis 34 nrel.gov/analysis

SPP

PSC

PNM

BCTC AESO

BPA

SCE

APS

PACW

PACE_UT

NWMT

PACE_WY

AVA

WAUW

PGE_VLY

TEP

WALC

EPE

WACM

PACE_ID

CFE

TREAS VLY

NEVP

PSE

IID

SRP

PGN

SDGE

BCTC

MAGIC VLY

SMUD

PSE

PGE_BAY

LDWP

FAR EAST

TIDC

TPWR

SCL

September 2011

Department of Energy.

Renewable Energy Laboratory for the

This map was produced by the National

Annual Generation (base case)

40 - 122 TWh15 - 40 TWh0 - 15 TWh

SPP

PSC

PNM

BCTC AESO

BPA

SCE

APS

PACW

PACE_UT

NWMT

PACE_WY

AVA

WAUW

PGE_VLY

TEP

WALC

EPE

WACM

PACE_ID

CFE

TREAS VLY

NEVP

PSE

IID

SRP

PGN

SDGE

BCTC

MAGIC VLY

SMUD

PSE

PGE_BAY

LDWP

FAR EAST

TIDC

TPWR

SCL

Change in generation from other units if NGS retires

October 2011

Department of Energy.

Renewable Energy Laboratory for the

This map was produced by the National

2.5 - 3.0 TWh2.0 - 2.5 TWh1.5 - 2.0 TWh1.0 - 1.5 TWh0.5 - 1.0 TWhNegligible

Figure 2-5. Annual net generation by BA, base case Figure 2-6. Change in net generation without Navajo GS
NREL/TP-6A20-53024 35

LADWP has already announced its intention to divest 

its position in Navajo GS, even though its position would 

be almost as dif¿cult as that of SRP. ,t would also need 

to import about 3.1 TWh of replacement power, which 

the NREL model suggests would most likely come from 

generators within the California ,SO.

By contrast, Nevada Power appears to have suf¿cient 

Àexibility on generators within its BA area to adjust to 

a Navajo GS retirement by relying entirely on internal 

resources. NREL’s modeling results suggest that units in 

the Nevada Power BA area could economically generate 

900 GWh more than what Nevada Power would lose 

from a Navajo GS retirement. This excess is equivalent to 

almost one-third of what SRP would need to obtain, and is 

more than what TEP would need to obtain.

NREL’s modeling results suggest that more than four-

¿fths of the replacement power for Navajo GS would come 

from combined cycle natural gas generators. Table 2-3 

shows the breakdown of replacement generation between 

combined cycle plants and other types of plants. The 

greatest increase is in the Nevada Power BA, and nearly 

all of that increase is on combined cycle units. Combined 

cycle plants in the Nevada Power BA are generally more 

ef¿cient than elsewhere in the ,nterconnection, which is 

why the greatest change in utilization would occur there.

The Western ,nterconnection’s Àeet of combined cycle 

units currently has a capacity factor of 44%.7

 Within 

the Desert Southwest, combined cycle plants have a 

capacity factor of 35%, reÀecting lower utilization 

and proportionally more spare capacity. These ¿gures, 

combined with the results from NREL’s modeling, clearly 

indicate the ability to use existing natural gas units to 

replace power that may be lost due to retiring Navajo GS.

2.3 Production costs: How expensive to 

do without Navajo GS?

Changing dispatch to compensate for the loss of Navajo GS 

would increase total production costs across the Western 

,nterconnection by between 1.6% and 3.1%. This represents 

the additional cost of generating the same amount of power, 

but doing so without Navajo GS. Table 2-4 shows the range 

of modeled changes in total production costs, according to 

the prevailing price of natural gas. The table also shows 

what production costs would be with natural gas prices 

near their historic high of $13 per mmBtu. (Recall the 

discussion earlier in this chapter that these results assume 

no obstacles to economically ef¿cient transactions between 

sellers and buyers of power, and no changes in transmission 

path ratings.)

7 A plant’s capacity factor indicates actual use relative to its theoretical 

potential over a given time period. A plant running at full capacity all the 

time would have a capacity factor of 100%. The capacity factor would 

be 85% if the plant ran at 85% all the time, or if it were shut down for 

maintenance 15% of the time but ran at full capacity the rest of the time.

Table 2-3. Types of Generators Used to Replace Navajo GS

BA

Rank, by total 

additional 

TWh

Additional TWh 

on combined 

cycle gas units

Additional 

TWh on 

other unit 

types

Total 

additional 

TWh

Nevada Power 1 2.88 0.02 2.90

Cal. ISO (SCE) 2 2.37 0.18 2.55

Cal. ISO (SDG&E) 3 2.06 0.03 2.09

Cal. ISO (PG&E 4 1.49 0.03 1.52

APS 5 0.64 0.28 0.92

SRP 0.60 0.05 0.65

LADWP 0.67 -0.10 0.57

TEP 0.00 0.48 0.48

All others 3.77 2.06 5.83

Total 14.5 3.0 17.5

(Navajo BAs in bold italic)
36 NREL/TP-6A20-53024

LMPs would change especially in the vicinity of the plant 

that was removed, and near the plants that run more to 

make up the loss. Recall that the three most important 

factors affecting LMP values are generators’ production 

costs, the level of demand at the system’s load nodes, and 

Àow limits on lines in the transmission network. An LMP 

increases under a certain scenario because less expensive 

power either does not exist or cannot reach that node due 

to line congestion.

LMPs indicate marginal costs (i.e., the value of providing 

one additional megawatt of power or the value of reducing 

load by one megawatt) at speci¿c locations. LMPs and 

total annual production costs may both be expressed as 

dollars per megawatt-hour, but they differ in that the 

latter captures the average cost of all power used, while 

the former reÀects the incremental cost of only the most 

expensive megawatt-hour used and is therefore higher than 

average production costs. LMPs are the basis of power 

prices in organized wholesale markets such as the ones in 

California and Alberta. Elsewhere in WECC outside the 

organized wholesale markets, LMPs are useful indicators 

of the cost of acquiring an additional increment of power. 

The Arizona utilities begin from a favorable position 

with respect to marginal costs relative to the rest of the 

Western ,nterconnection, as illustrated in Figure 2-7. 

LMPs in Arizona are typically from 3% to 4% below the 

,nterconnection average, and are even further below the 

rest of the ,nterconnection when natural gas prices are 

high. ,n comparison, California’s LMPs are generally 10% 

to 13% above the ,nterconnection average due to the fact 

that it has virtually no internal coal capacity and therefore 

relies on natural gas to a greater extent. California’s 

relatively high LMPs push the ,nterconnection average 

higher due to the relatively large amount of load affected. 

The LMP differences between Arizona and California 

provide an economic explanation of why power transfers 

from the Desert Southwest to California are so large. 

High LMPs signal a local demand for lower-cost power, 

either because none is nearby or because transmission 

congestion limits its deliverability. Enabling the power to 

move from low-LMP nodes to the high-LMP nodes would 

result in exchanges that will leave both areas better off: 

for the importing area, lower-cost power for the exporting 

area, more economic output. The Àow of power across the 

Colorado River into California from Arizona, Nevada and 

New Mexico is around 50 TWh during a typical year.8

NREL’s modeling indicates that retiring Navajo GS would 

raise total production costs by 2% to 3% for the Western 

,nterconnection as a whole (see Table 2-5). ,n the scenario 

assuming extremely high natural gas prices, the total 

production cost impact is approximately 5%. As shown in 

Figure 2-8, the Desert Southwest would see most of the 

increase in marginal costs, with LMPs remaining stable 

throughout most of the remainder of the West. LMPs at 

some nodes along the California-Nevada border would 

also increase, but these LMPs are naturally high due to 

local transmission constraints. The amount of load at these 

nodes is small.

The economic fundamentals driving power transactions 

from the Desert Southwest to California would be 

substantially the same in the absence of Navajo GS. 

LMPs in California will still be higher than those in the 

Desert Southwest even without Navajo GS, although the 

difference would be somewhat smaller. This is consistent 

with the redispatch outcomes discussed previously in this 

chapter. While California BAs would make up as much 

8 Western Electricity Coordinating Council (WECC), “2009 Western 

,nterconnection Transmission Path Utilization Study,” -une 24, 2010.

Table 2-4. Interconnection-wide Production Costs ($ millions)

Total cost, $ million per year Total cost per MWh

Natural gas: $4 $6.90 $13 $4 $6.90 $13

Base Case $12,660 $16,251 $23,829 $13.04 $16.74 $24.54

Without Navajo GS $12,857 $16,753 $24,986 $13.24 $17.25 $25.73

Difference $197 $502 $1,157 $0.20 $0.52 $1.19

Difference (%) 1.6% 3.1% 4.9% 1.6% 3.1% 4.9%
NREL/TP-6A20-53024 37

as two-thirds of what would be lost from Navajo GS, 

signi¿cant power Àows westward across the Colorado 

River would continue because the economics would still 

make sense.

Table 2-6 aggregates the nodal results for the ¿ve BAs 

that rely on Navajo GS. These LMP averages represent 

the average costs of all nodes in a BA (weighted by load). 

The LMPs shown for the base case do not reÀect the cost 

of Navajo GS alone, but rather the cost of Navajo GS 

blended with the cost of all other power currently used by 

the utility to serve load. LMPs for the retirement scenario 

indicate what the blended cost of incremental generation 

within the BA would be without Navajo GS.

SRP would experience the largest price impact. With 

Navajo GS, SRP has marginal production costs that are 

lower than those of any other utility partner, including its 

Arizona peers. Retiring Navajo GS would increase SRP’s 

marginal production costs by $2.48 per MWh—the largest 

absolute increase as well as the largest percentage increase 

among all Navajo GS utility partners. Even with that 

increase, however, SRP’s marginal production costs would 

still be lower than those of any other, although by a much 

smaller margin. 

The other two Arizona utility partners, APS and TEP, 

would see their marginal production costs increase by as 

much as 5% if they were to lose their share of Navajo GS. 

As described earlier in this chapter, both rely on Navajo 

GS to a lesser extent than SRP does, and both have a 

greater ability to draw on resources elsewhere in their BAs 

to replace what would be lost if Navajo GS were no longer 

available. This additional measure of internal resource 

Àexibility would partially mitigate the price impact on 

APS and TEP of retiring Navajo GS.

Production costs for LADWP and Nevada Power are 

already higher than the Western ,nterconnection average, 

and retiring Navajo GS would have a proportionately 

smaller impact on them than on their Arizona utility 

partners. This is largely due to the amount of unused 

internal capacity in California and southern Nevada that 

the utilities would use to replace Navajo GS. The smallest 

relative price impact would be on LADWP, which is 

already divesting its position in Navajo GS. LADWP 

currently has the highest internal production cost of any 

Navajo GS partner.

As discussed earlier in this chapter, the NREL model 

indicates that two-thirds of the power needed to replace 

Navajo GS would come from other BAs, with most of that 

amount coming from California. Figure 2-7 shows that 

LMPs in California tend to be relatively high even under 

normal operating conditions. Replacing Navajo GS would 

increase LMPs in Northern California by around 2%, and 

in most of Southern California by around 3% (except for 

,mperial ,rrigation district and SDGE, where the increase 

would be around 6%).

The NREL modeling highlights the following conclusions 

with respect to changes in production costs.

Ŷ The Arizona utilities currently have internal 

power production costs that are less expensive 

than average WECC costs

Ŷ Retiring Navajo GS would increase production 

costs proportionally more for the Arizona utilities 

than for the rest of the West but

Ŷ After retiring Navajo GS, production costs for the 

Arizona utilities would still be lower than for the 

rest of the West, although by a smaller margin.

Table 2-5. Interconnection-wide LMP Averages, Minima and Maxima ($/MWh)

Base case Without Navajo

Natural gas: $4 $6.90 $13 $4 $6.90 $13

Minimum $6.11 $12.36 $29.56 $6.03 $13.22 $33.23

Average (load-weighted) $31.77 $48.84 $84.77 $32.43 $50.13 $88.23

Maximum $64.72 $85.94 $146.35 $74.29 $94.28 $143.67
Energy Analysis 38 nrel.gov/analysis

BCTC AESO

SPP

PSC

PNM

BPA

SCE

APS

PACW

PACE_UT

NWMT

PACE_WY

AVA

WAUW

PGE_VLY

TEP

WALC

EPE

WACM

PACE_ID

CFE

TREAS VLY

NEVP

PSE

IID

SRP

PGN

MAGIC VLY

SDGE

SMUD

PSE

PGE_BAY

LDWP

FAR EAST

TIDC

TPWR

SCL

Base Case LMPs

October 2011

Department of Energy.

Renewable Energy Laboratory for the

This map was produced by the National

$90$50$10

Gas: $6.90 per mmBtu)Figure 2-7. LMP distribution with and without Navajo GS (Natural 

Without Navajo GS Base Case
NREL/TP-6A20-53024 39

BCTC AESO

SPP

PSC

PNM

BPA

SCE

APS

PACW

PACE_UT

NWMT

PACE_WY

AVA

WAUW

PGE_VLY

TEP

WALC

EPE

WACM

PACE_ID

CFE

TREAS VLY

NEVP

PSE

IID

SRP

PGN

MAGIC VLY

SDGE

SMUD

PSE

PGE_BAY

LDWP

FAR EAST

TIDC

TPWR

SCL

This map was produced by the National

Renewable Energy Laboratory for the

Department of Energy.

September 2011

LMP Deltas as % of Base Case LMP

-5%

0%

5%

12% +

Figure 2-8. Change in average annual LMPs when retiring Navajo GS
40 NREL/TP-6A20-53024

2.3.1 Navajo GS retirement relative to changes 

in natural gas prices

To provide a context for the impact of retiring Navajo GS, 

NREL compared LMP changes due to retiring the plant 

with LMP changes due to normal Àuctuations in natural 

gas prices. Figure 2-4 at the beginning of this chapter 

tracks the daily price of natural gas at the Permian Basin 

hub since 2008. Figure 2-9 charts the distribution of daily 

prices over a more recent time horizon. Nearly 95% of 

the time, the price of natural gas was between $3.40 and 

$5.40 per mmBtu. A change from $4 to $5 is therefore 

representative of normal Àuctuations in the price of natural 

gas, at least for the present time.

As shown in Table 2-6, retiring Navajo GS would increase 

LMPs in the owners’ BAs from 3% to 5%, and by 2% 

to 3% for the ,nterconnection as a whole. ,ncreasing the 

price of natural gas from $4 to $5 per mmBtu, on the 

other hand, increases LMPs by 18-19% across the board. 

Table 2-7 shows the detailed impacts by BA, both with and 

without Navajo GS. 

The price outcomes NREL modeled for a theoretical 

Navajo GS retirement mirror how the California wholesale 

market responded to the retirement of the Mohave coal 

plant in 2006. At 1.6 GW, Mohave was smaller than 

Navajo GS, but it dispatched nearly two-thirds of its output 

to California. NREL conducted a statistical analysis of 

daily wholesale prices in Southern California from the 

beginning 2005 to the end of 2007. The results showed 

that while the price of natural gas had a statistically 

Table 2-6. Changes in BAs’ Average LMP Assuming Navajo GS Retirement

BA average LMP ($/MWh)

BA receiving Navajo 

power

With

Navajo GS 

Without 

Navajo GS Change

Salt River Project $47.00 $49.48 $2.48 5.3%

LADWP $51.92 $53.57 $1.65 3.2%

Arizona Public Service Co. $47.50 $49.88 $2.37 5.0%

Nevada Power Co. $50.71 $52.49 $1.77 3.5%

Tucson Electric Power Co. $47.51 $49.82 $2.30 4.8%

WECC average $48.84 $50.13 $1.29 2.6%

signi¿cant effect on wholesale prices, the retirement of 

Mohave did not (see Table 2-8).

Overall, changes in production costs and marginal prices 

that would be caused by retiring Navajo GS would be 

less than the changes caused by day-to-day and monthto-month movements in the price of natural gas. The 

wholesale impact may be evident by tracking LMPs over 

an extended period of time, but would be dif¿cult to 

discern within a short time horizon.

2.4 Impact on Bureau of Reclamation 

and CAP

Up to this point, much of the discussion in this chapter 

has focused on Navajo GS’ utility partners. The effect 

on the Bureau of Reclamation, CAWCD, and entities that 

rely on CAP water, however, would be different due to the 

fact that Reclamation is the only Navajo GS partner that 

is neither a utility nor a BA. Chapter 3 examines in more 

detail consequences of retirement versus other options 

with respect to the impact on CAP. Here, the discussion 

is limited to Reclamation’s cost of replacing power from 

Navajo GS.

The key differences between Reclamation and its utility 

partners are these. 

Ŷ A utility draws on many resources to balance 

load from many points on its system. Reclamation 

relies primarily on one resource (Navajo GS) to 

meet one source of demand (CAP).
NREL/TP-6A20-53024 41

Nevada Power and from generators in Southern California. 

More precisely, less of the 50 TWh of power generated in 

the Desert Southwest would Àow westward to California 

and more would stay in Arizona. This would require more 

generation from California’s own plants. 

The wholesale costs Reclamation would face in replacing 

Navajo GS power would be close to the LMPs in the areas 

where the CAP pumps are located. For load nodes (i.e., 

points of demand where power leaves the network and 

is used) LMPs reÀect the economic value of additional 

power, taking into account all the factors affecting how the 

additional power would be produced and delivered. LMPs 

in the areas where the largest CAP pumps are located 

would range between $33 and $50 per MWh based on the 

price of natural gas. Table 2-7 shows that this price range 

would be rather consistent among APS, SRP and TEP. 

Reclamation would end up in roughly the same economic 

place as the Arizona utilities with respect to the cost 

of replacement power, but it would be coming from a 

different and lower-cost starting point. While its utility 

partners face current costs consistent with the base case 

LMPs shown in Table 2-7, Reclamation’s current power 

costs are tied to the production cost of Navajo GS alone. 

This means that Reclamation’s initial position would be 

33% to 44% below the base case LMPs (again, with LMPs 

varying based on the price of natural gas). 

The bottom line for Reclamation, therefore, is that the 

effective cost of replacement supply could be as much 

as double its current cost. This conclusion is based on 

comparing Navajo GS’ current production cost (around 

$20 per MWh) with what LMPs near the CAP pumps 

would be in the event of a Navajo GS retirement, as shown 

in Table 2-7 for APS, SRP and TEP. This contrasts with 

the much smaller increase in LMPs—between 4% and 

5%—for the Arizona utilities.

The federal government authorized the creation of Navajo 

GS to ensure a low-cost supply of power to pump water 

out of the Colorado River for the Central Arizona Project. 

Retiring Navajo GS would eliminate not only the plant, 

but would also eliminate the operational arrangements 

that made such low-cost power possible. With respect to 

the Bureau of Reclamation and CAP, therefore, replacing 

Navajo GS would involve much more than the ordinary 

changes in production cost that the utility partners would 

experience. 

Ŷ LMPs reÀect a utility’s marginal cost of producing 

power. How the utility schedules and dispatches 

various generators in its portfolio will change 

daily and hourly based on total demand and on 

which units are selected, and this in turn changes 

LMPs and production costs for any given hour. 

LMPs have little bearing on Reclamation’s cost 

of power, however. What matters is Navajo GS’ 

operating cost, which changes little regardless of 

when CAP needs the power.

Ŷ Any change in the cost or availability of one 

generator is dampened by its relative size in the 

utility’s portfolio of generators the larger the 

portfolio, the smaller the impact of one single 

generator on aggregated production costs. For 

Reclamation, any change in the cost or availability 

of Navajo GS transfers entirely to CAP water users.

,f Reclamation no longer had Navajo GS as a resource, it 

would need to turn to the wholesale market for some or 

all of the replacement power. While Reclamation could 

conceivably reallocate some of the power generated from 

the Glen Canyon and Hoover hydroelectric plants, this 

analysis proceeds from the more conservative assumption 

that no such reallocation would occur. Even if Reclamation 

were to draw on its hydroelectric capacity, the reallocation 

in turn would likely require some replacement from the 

wholesale market to ensure Reclamation’s obligations to 

all of its public power customers could be met.

Recall from Table 2-3 that most of the new power generated 

to replace Navajo GS’ 15 TWh would likely come from 

0% 

20%

10%

40%

30%

50%

<$3 $3 to $4 $4 to $5 $5 to $6 >$6

Figure 2-9. Distribution of daily natural gas prices, January 

2010 – September 2011
42 NREL/TP-6A20-53024

Table 2-7. LMP Sensitivities for Natural Gas Price, Navajo GS Retirement

BA Navajo GS 

scenario

Gas at $4/

mmBtu

Gas at $5/

mmBtu

% change due to 

 natural gas

Salt River Project 

Base case $31.08 $36.66 18%

Retire $32.44 $38.46 19%

% change due to 

retirement 4% 5%

LADWP

Base case $34.26 $40.53 18%

Retire $35.28 $41.71 18%

% change due to 

retirement 3% 3%

Arizona Public 

Service Co.

Base case $31.39 $37.05 18%

Retire $32.72 $38.77 18%

% change due to 

retirement 4% 5%

Nevada Power Co.

Base case $32.73 $39.08 19%

Retire $33.75 $40.26 19%

% change due to 

retirement 3% 3%

Tucson Electric 

Power Co.

Base case $31.34 $37.02 18%

Retire $32.64 $38.71 19%

% change due to 

retirement 4% 5%

WECC average

Base case $31.77 $37.74 19%

Retire $32.43 $38.58 19%

% change due to 

retirement 2% 2%

Table 2-8. Regression Analysis of Mohave Retirement and Wholesale Power Prices in California

SP15 price = natural gas price + Mohave + previous day’s SP15 price + intercept

Number of observations: 727 (valid daily values, January 3, 2005 through December 28, 

2007) Goodness of fit (adjusted r2): 0.53

Explanatory variable Coefficient T statistic

Natural gas price

(spot price at El Paso Permian Basin hub) 3.6 7.14 a

Mohave plant 

(binary variable: 1 for operating period, 0 for retirement) -1.6 -1.23

Previous day’s SP15 price

(control for time series effects) 0.56 17.45 a

Intercept 6.5 2.53 a

(a) Signi¿cant at 95% con¿dence level

Sources of data: Energy ,nformation Administration (wholesale market data for California SP15) SNL ,nformation 

(natural gas prices, Mohave net generation and shutdown)
NREL/TP-6A20-53024 43

This chapter summarizes the emission control technologies currently installed at Navajo GS, as well as other 

leading technologies for controlling nitrogen oxide (NOx

) 

emissions. The chapter also discusses complementary 

technologies that can work in conjunction with those designed primarily to control NOx

. 

The Clean Air Act (CAA) has mandated several emission 

control programs at EPA, many benchmarked to requirements for 2064. Some of the CAA programs affecting 

power generation address acid rain, climate change, reduction of air pollutants, and protection of health and ecosystems. The regulations are intended to address sulfur oxides 

(SOx

), NOx, ammonia, particulate matter, and regional 

haze. Future regulations are likely to address mercury and 

air toxics (MATS).

This section discusses how each of the above items has 

been addressed at Navajo GS, or if not, what the major options are for doing so. Navajo GS has already made several 

signi¿cant modi¿cations to integrate emission control 

technologies, among them Àue gas desulfurization (FGD), 

low NOx

 burners (LNB), separated over ¿re air (SOFA), 

and electrostatic precipitators (ESP). Each technology has 

reduced one or more of the pollutants EPA is targeting 

under the authority of the CAA. This section discusses 

technologies being considered by Navajo GS’ stakeholders and the EPA to address regional haze visibility issues 

within Class , areas, including the Grand Canyon. The 

discussion includes technology capabilities, as well as cost 

and impact to Navajo GS and its stakeholders.

EPA proposed the MATS in May 2011 to establish utility 

boiler maximum achievable control technology emissions 

standards for hazardous air pollutants (HAPs).1

 MATS will 

establish emission limits for hydrogen chloride (HCl), mercury (Hg), and other (non-Hg) HAP metals via standards 

for total particulate matter (PM). The proposed MATS rule 

contains separate limits for new or reconstructed units and 

for existing units. ,t also has separate limits for boilers designed to burn coal at low heat values, the threshold being 

8,300 Btu per pound. The emissions standards for units 

with higher heat rates (above 8,300 Btu per pound) are the 

ones expected to apply to Navajo GS’ units, if the rule is 

1 EPA Website, www.epa.gov

3 Control Technologies—Cost of Retrofits 

¿nalized as proposed. EPA released a ¿nal ruling in December 2011, but as of this writing it had not yet appeared 

in the Federal Register.

The Regional Haze Rule is part of the regional haze 

program, implemented under the CAA. As discussed 

elsewhere in this report, the rule was initiated to address 

and improve visibility in federally protected (Class 1) 

national park and wilderness areas. Each state is required 

to develop “goals for improving visibility” under the rule.2

The program provides states guidance on selecting days 

with the worst and best visibility during the year, on the 

effects of relative humidity on visibility, on procedures for 

calculating visibility impairments, and on other related issues. Reduction in power plant NOx

 and SO2 emissions are 

two of the strategic emission reductions intended to help 

achieve the CAA goals by 2064.

The CAA requires EPA to develop rules to implement a 

program of visibility protection, which would require the 

application of best available retro¿t technology (BART) to 

certain facilities. The primary focus of these rules was the 

prevention and remediation of regional haze impacts on 

Class , areas by large emissions sources.

2 EPA Fact Sheet, “The Environmental Protection Agency Releases 

Guidance on ,mplementing ,ts Regional Haze Program”. http://www.epa.

gov/ttn/caaa/t1/fact_sheets/rh_girhp_fs.pdf
44 NREL/TP-6A20-53024

3.1 Technologies Implemented for 

Emission Controls

,n the mid 1990s, Navajo’s owners began the transition to 

clean up the plant’s acid gas emissions by installing wet 

Àue gas desulfurization (FGD) systems on all three units. 

The FGD systems were installed and operational in 1999. 

During the system retro¿t, Navajo also underwent steam 

turbine ef¿ciency upgrades to account for the additional 

auxiliary power required to operate the FGD System and 

maintain a net power generation capacity of 2,250 MW. 

NGS underwent low NOx

 burners and separated over ¿re 

air (LNB/SOFA) retro¿ts starting in 2009, and completing 

in 2011. During the retro¿t the NGS also revised their Title 

9 Operating Permit to reduce the maximum level of NOx

emissions from 0.36 lb/MMBtu to 0.24 lb/MMBtu. The 

LNB/SOFA retro¿ts on Units 3 and 2 were completed in 

2009 and 2010. The retro¿t on Unit 1 was ¿nished in 2011.

Table 3-2: NOx

 Permit Limits and Technology Performance

lb/MMBtu Change from permit 

pre-LNB/SOFA

Change from 

LNB/SOFA

Pre-LNB/SOFA Permit 0.36

LNB/SOFA Permit 0.24 33%

LNB/SOFA/SNCR a Assumed 0.18 - 0.144 50% - 60% 25% - 40%

LNB/SOFA/SCR Estimated 0.08 78% 67%

(a) Assumed reduction of 25% to 40%

Source: ENSR/AECOM, BART Analysis for the Navajo Generating Station Units 1-3, November 2007.

Table 3-1: Nitrogen Oxide Emission Reduction Technologies

Modification technology Post-combustion technology

Low-NOx Burners LNB Selective Non-Catalytic Reduction SNCR

Overfire Air OFA Selective Catalytic Reduction SCR

Sequentially Overfire Air SOFA

Flue Gas Recirculation FGR

3.1.1 NOx Control Technologies

Nitrogen oxide emissions, include NO, and NO2 and is 

identi¿ed as NOx

 emissions or simply NOx, which is being 

called from reduction at federal, state, and local levels. For 

fossil-fuel power plants, there is a variation of technologies 

available to minimize or reduce the NOx

 emissions. These 

can be categorized as modi¿cation techniques, and postcombustion technologies, as identi¿ed in Table 3-1.

Each technology has bene¿ts and limitations for NOx

 controls and are limited to the ultimate reduction of levels of 

NOx

 on coal-¿red power plants.
NREL/TP-6A20-53024 45

3.1.2 Low NOx Burners and Separated 

Over Fire Air

Low- NOx Burners (LNB) are furnace modi¿cations that 

control air-to-fuel ratios to reduce NOx

 formation during 

combustion. This type of control technology represents 

a cost-effective means to reduce NOx

 emissions by 40% 

without chemicals and their potentially negative environmental consequences. LNB installation was completed in 

April 2011 at a cost of approximately $45 million.

Separated Over Fire Air (SOFA) is a method to control 

temperature within the furnace, and complete combustion 

of the fuels without introducing an over abundance of excess 

air. This combustion technique introduces oxygen into the 

system at different elevations or zones of the furnace. By 

controlling the combustion in zones, the temperature and 

quantity of excess air can be controlled. This reduces the 

nitrogen introduced into the system, ultimately reducing the 

quantity of NOx

 produced.

The Title 9 air permit reduced Navajo GS’s NOx

 limits to 

0.24 lb/MMBtu from 0.36 lb/MMBtu. This is a reduction 

of 33%, due to the installation of LNB and SOFA. Table 3-2 

summarizes the permitted limits and anticipated NOx

 limits 

based on different control technologies.

3.1.3 Selective Catalytic Reduction

Selective Catalytic Reduction (SCR) is a method for converting NOx

 into a diatomic nitrogen (N2) and water. The 

process uses a catalyst, and reagent in a speci¿c temperature window to nitrogen oxides. Reagents most commonly 

used include ammonia (anhydrous or aqueous), or urea. The 

catalysts are often manufactured from ceramic materials 

which are embedded with various materials, which can include titanium oxide, and oxides of base metals (vanadium, 

tungsten, zeolites, or various precious metals). Additionally, 

Table 3-3: Selective catalytic reduction in U.S. power plants

Number of installations 71

Average size installed (MW) 466.1

Maximum size installed (MW) 950.0

Minimum size installed (MW) 90.2

Source: SNL Utility Database, www.snl.com

Table 3-4: Plants With Installed SCR Technology (Texas and Western interconnections)

State Plant Net MW State Plant Net MW

TX W A Parish ST 5 734.1 CO Comanche ST 3 820.0

TX W A Parish ST 6 734.1 WY Wygen 3 ST 5 110.0

TX W A Parish ST 7 614.6

TX W A Parish ST 8 654.0

TX J K Spruce ST 2 820.0

Source: SNL Utility Database, www.snl.com

porosity or geometry of the catalyst is a factor. Flue gas 

with higher dust loading requires a larger pore to prevent 

premature plugging however there is a trade-off between 

plugging prevention, total reaction, and operational life 

of equipment. SCR systems in commercial use typically 

reduce NOx

 emissions by 90 percent or more, and thermodynamic calculations indicate that reductions in excess of 

99 percent are possible at 650°F.3

Table 3-3 summarizes the number of SCR installations in 

the United States. As Table 3-4 and Table 3-5 show, 90% 

of them are in the Eastern ,nterconnection. This is nearly 

the same proportion as the distribution of all U.S. coal 

units that are between 90.2 MW and 950 MW in capacity. 

Two sets of SCR cost estimates are in the record with respect to Navajo GS: one by the U.S. National Park Service 

(NPS), and the other by the engineering consulting ¿rm 

3 ,nstitute of Clean Air Companies, selective Catalytic Reduction (SCR) 

Control of NOx Emissions from Fossil Fuel-Fired Electric Power Plants, 

May, 2009.
46 NREL/TP-6A20-53024

Table 3-5: Power Plants With Installed SCR Technology (Eastern Interconnection)

State Plant Net 

MW State Plant Net MW

AL Charles R Lowman ST 2 236.0 NH Merrimack ST 1 113.6

AL Charles R Lowman ST 3 236.0 NH Merrimack ST 2 345.6

AL James H. Miller Jr. ST 1 705.5 NY Kintigh ST 1 655.1

AL James H. Miller Jr. ST 2 705.5 OH J M Stuart ST 1 610.2

AL James H. Miller Jr. ST 3 705.5 OH J M Stuart ST 4 610.2

AL James H. Miller Jr. ST 4 705.5 OH Killen Station ST 2 660.6

AL Colbert ST 5 550.0 OH Conesville ST 4 841.5

FL St Johns River Power ST 1 679.0 OH Miami Fort ST 8 557.7

FL St Johns River Power ST 2 679.0 OH J M Stuart ST 2 610.2

FL Deerhaven ST 2 250.7 OH J M Stuart ST 3 610.2

GA Hammond ST 4 578.0 SC Cope ST1 417.3

IL Marion ST 4 173.0 SC Cross ST 1 590.9

IL Dallman ST 1 90.2 SC Cross ST 2 556.2

IL Dallman ST 2 90.2 SC Winyah ST 3 315.0

IL Dallman ST 3 207.3 SC Winyah ST 4 315.0

IL Dallman ST 4 280.0 TN Bull Run (TN) ST 1 950.0

IN A B Brown ST 1 265.2 TN Kingston ST 1 175.0

IN A B Brown ST 2 265.2 TN Kingston ST 2 175.0

IN Merom ST 1 540.0 TN Kingston ST 3 175.0

IN Merom ST 2 540.0 TN Kingston ST 4 175.0

IN Petersburg ST3 574.3 TN Kingston ST 9 200.0

KY East Bend ST 2 669.3 VA Birchwood Power Fac. ST 1 258.3

KY H L Spurlock ST 1 357.6 VA Chesterfield ST 4 187.5

KY H L Spurlock ST 2 592.1 VA Chesapeake ST4 239.3

KY Elmer Smith ST 1 163.2 WI Weston ST 4 595.0

KY Trimble County ST 2 760.0 WI Elm Rd. Stn. (Oak Cr.) ST 1 615.0

KY D B Wilson ST 1 566.1 WI Elm Rd. Stn. (Oak Cr.) ST 2 615.0

MI Dan E Karn ST 1A 136.0 WI South Oak Creek ST 5 275.0

MO Southwest Power Station 

ST1 194.0 WI South Oak Creek ST 6 275.0

MO New Madrid ST 1 600.0 WI Pleasant Prairie ST 1 616.5

MO New Madrid ST 2 600.0 WI Pleasant Prairie ST 2 616.5

NE Whelan Energy Center 

ST 2 220.0

NE Nebraska City ST 2 738.0

Source: SNL Utility Database, www.snl.com
NREL/TP-6A20-53024 47

Table 3-6: Two estimates for SCR installation at Navajo GS

NGS Unit

Capital Costs Annual O&M Costs

National Park 

Service Sargent & Lundy National Park 

Service Sargent & Lundy

Unit 1 $134,400,638 $151,825,000 $5,071,061 $3,982,000 

Unit 2 $177,394,173 $205,808,000 $6,030,304 $3,982,000 

Unit 3 $153,185,596 $188,250,000 $5,608,740 $3,982,000 

Total $464,980,407 $545,883,000 $16,710,105 $11,946,000 

Table 3-7: Capital Costs of SCR Installations Proposed in the Western Interconnection

Plant Costs Net 

MW

Capital 

cost per 

kw

Reference

Four Corners 4/5 $242,250,000 750 $323 Four Corners 4/5 (BART Analysis)

Boardman (PGE BART) $190,850,000 550 $347 Boardman (PGE BART)

Boardman (ERG) $137,500,000 550 $250 Boardman (ERG BART)

Bridger 1/2/3/4 $166,950,000 530 $315 Bridger 1/2/3/4 (BART Analysis)

Naughton 3 $136,950,000 330 $415 Naughton 3 (BART Analysis)

San Juan GS - Unit 1 $71,740,000 340 $211

EPA [FR Doc. 2011–20682 Filed 

8–19–11; 8:45 am]

San Juan GS - Unit 2 $79,560,000 340 $234

San Juan GS - Unit 3 $88,963,000 497 $179

San Juan GS - Unit 4 $83,655,000 507 $165

Sargent & Lundy (S&L). Both were reviewed for this study. 

NPS’ cost estimate uses the Modi¿ed Cost Manual Approach developed by EPA, and incorporates several inputs 

provided by Navajo GS operating partner SRP.4

 S&L 

developed a construction estimate based on their experience, speci¿c site details provided by SRP, and equipment 

costs provided by suppliers and manufacturers. Construction would require a planned outage, assumed to last eight 

weeks for each unit. The NPS calculations of lost revenues 

are smaller than those of S&L, which may be attributable 

to basing the calculations on a unit capacity of 750 MW as 

compared with its gross capacity of 812 MW.

Table 3-6 compares the overall estimates of capital costs 

and O&M costs. The two estimates employ different assumptions, but both follow comparable methodologies. Because the assumptions differ within reason, this study uses 

both in tandem to establish the high and low bounds of a 

plausible range of future SCR costs speci¿c to Navajo GS. 

Using a plausible range to model future cost recognizes 

4 Worksheets provided by D. Shepherd, National Park Service available at 

www.nrel.gov/navajo.

that actual costs will be affected by conditions that cannot 

be anticipated. For this reason, SCR costs throughout this 

report are modeled as a plausible range. 

To empirically test whether the range bounded by the two 

estimates was indeed plausible, this study compared them 

against cost estimates for SCR retro¿ts proposed elsewhere in the Western ,nterconnection. Recall from Table 

3-5 and Table 3-4 that the use of SCR controls is less widespread in the Western ,nterconnection than in the Eastern 

,nterconnection. The smaller number can magnify the effect of site-speci¿c differences on an overall comparison. 

Capital and operating costs can vary widely depending on 

the type of combustion (wall ¿red, tangentially ¿red, etc.), 

the source of coal being used by the facility, and green¿eld 

installations versus retro¿t installations. 

Table 3-7 compares cost estimates for SCR installations 

planned at a number of facilities in the Western ,nterconnection: the San -uan Generating Station in New Mexico, 

the Boardman Power Plant in Oregon, Naughton Unit 3 
48 NREL/TP-6A20-53024

Interconnection high

Navajo GS:

Sargent & Lundy

Navajo GS:

National Park Service

$500

Cost per kW

$400

$300

$200

$100

$0 SCR capital cost estimates

Interconnection low

Figure 3-1: Estimates of SCR capital costs in the Western 

Interconnection

in Wyoming, and the Four Corners Power Plant in New 

Mexico. Estimated costs (in dollars per kilowatt of net 

generating capacity) range from $165 to $415, with an 

average of $252. The variation in costs can be attributed to 

economies of scale, as well as complexities included in the 

design and construction of each individual retro¿t.

SCR installations at Comanche 3 in Colorado and Wygen 

3 in Wyoming are not include in Table 3-7. Both incorporated SCR controls into the initial design and construction 

of the new units, signi¿cantly reducing cost per kilowatt as 

compared to retro¿tting SCRs to an already existing unit.

Different boiler/furnace designs have limitations to NOx

control technologies. Circulating Àuidized bed boilers 

have high ash loading in the Àue gas and tend to not work 

well with SCR technologies, where other pulverized coal-

¿red boiler designs are amenable to SCR retro¿ts. Navajo 

GS has three units, which are pulverized, tangentially ¿re 

boilers, with very low ash loading in the Àue gas—generally, a well-¿tted candidate for SCR technologies.

Figure 3-1 illustrates how the cost range bounded by the 

S&L and NPS estimates compares with the range of cost 

estimates across the Western ,nterconnection. The range 

of these two estimates—speci¿c to Navajo GS—is entirely within the range for the entire interconnection, and 

is markedly narrower. ,n addition, both are near the same 

quartile of the interconnection range, which would be the 

case if both were reasonable analyses of the same conditions. The comparison, therefore, supports using the S&L 

and NPS estimates as the bounds of a plausible range of 

SCR costs for Navajo GS.

This study, however, does not take either set of estimates 

further than total cost. Both were de¿cient in their respective methodologies for annualizing the total capital costs 

they estimated. Chapter 1 describes in detail the approach 

used in this study to annualize capital costs for each of the 

six Navajo GS owners, and to incorporate the O&M costs 

into the plant’s overall production cost.

3.1.4 Selective Non-Catalytic Reduction

Selective non-catalytic reduction (SNCR) is a post-combustion technology that injects a reagent into the Àue gas, 

where the Àue gas temperature is within a range of 1,700 

oF and 2400 oF.5

 The reagent typically is an urea or ammonia. The temperature range is dependent upon the reagent 

utilized. The SNCR technology depends upon the selective 

NOx

 reduction through the direct contact of ammonia or 

urea droplets, eliminating the need for catalyst. Without 

the need for a catalyst, the capital costs are low in comparison to other post-combustion technologies. The reagent 

injected into the system selectively reacts with NOx

 in the 

presence of oxygen, forming primarily nitrogen and water.

Several reagents have been utilized and tested, however 

ammonia and urea are most widely used for utility scale 

applications.

The reaction occurs in a large temperature window, but as 

the temperature approaches the lower limits, less reaction 

occurs. Ammonia slip begins to promulgate and becomes 

its own source of emission. At higher temperatures, the 

reaction is no longer selective, and the nitrogen intermediates (NH2, HCO, etc.) begin reacting with oxygen to form 

NOx

.The furnace design is also a parameter to recognize 

when incorporating SNCR as a control technology. The 

furnace chamber, as well as the ductwork and heat recover 

sections, all are part of the reaction chamber where NOx

reduction takes place.

SNCR typically have the capability of reducing NOx

 by 25 

percent to 40 percent, depending on the applications. Longterm studies performed by EPR, for a 720 MW tangentially 

¿red boiler (which is similar to Navajo GS) veri¿ed that 

5 Evaluation of An SNCR Trim System on A 720 MW Tangential Design 

Coal-Fired Utility Boiler, EPR,, Palo Alto, CA: 2003. 1008029.
NREL/TP-6A20-53024 49

SNCR could remove on average between 17.8 percent and 

20.6 percent of NOx

 emissions depending upon load. Ammonia slip for this test varied from 4 to 18 ppm.

As Table 3-8 shows, SNCR controls have been installed at 

34 units that, as a group, are smaller than the group on which 

SCR controls exist. Table 3-9 shows that most of these installations have been on the East Coast none is in the Western 

,nterconnection.

Table 3-10 breaks down EPR,’s estimate of capital and O&M 

costs by owner. Total capital cost for all three units would be 

close to $16.5 million. Estimates of operation and maintenance costs are based on EPR,’s study performed on installing SNCR technologies on a 720 MW tangentially ¿red 

power plant.6

3.2 Particulate Matter Reduction and 

Sorbent Injection

Particulates, SO3, mercury, and other toxic emissions can 

be controlled through sorbent injection and ¿lter techniques. Filter techniques include electrostatic precipitators, 

and fabric ¿lter bag houses. Sorbent injection can include 

injecting trona, the raw material for soda ash, limestone, 

or similar material to react with SO2

 and SO3 to produce 

calcium sul¿te and carbon dioxide. Activated carbon in 

some process is injected into the Àuegas to attach to heavy 

metals, including mercury to reduce emission.

3.2.1 Electrostatic Precipitators

Electrostatic precipitators (ESP) are particulate control 

units for removing dust from the Àue gas of large solid fuel 

¿red boilers. The principle operation of an ESP comprises 

six processes: ionization, migration, collection, charge dissipation, particle dislodging, and particle removal.7

The system uses an electrostatic charging system to electrically charge the particles. The charged particles are then 

attracted to a plate, which is oppositely charged much like 

a magnet. The particles are then shaken from the plates 

using vibrations generated by the rapping system, and the 

dust is collected in hoppers at the bottom of the ESP. ESP 

technology can generally collect between 60% and 80% of 

the inlet dust load. 

6 EPR,, Evaluation of an SNCR Trim System on a 720 MW Tangential 

Design Coal-Fired Utility Boiler.

7 Electrostatic Precipitator Knowledge Base, http://www.neundorfer.com/

knowledge_base/electrostatic_precipitators.aspxitp

Navajo GS currently is operating with a hot side ESP. Hot 

side ESPs operate upstream of the air heater and FGD. 

Currently they are obtaining a removal of 90% of PM10 

particulate with the existing ESPs. 

3.2.2 Fabric Filter Baghouse and Sorbent 

Injection

Additions of scrubbers and SCR systems at coal-¿red power plants have signi¿cantly reduced concentrations of the 

pollutants SO2

 and NOx. Unexpected side effects caused 

by the chemical processes in the downstream equipment 

can be the result of additional control equipment. One 

side effect is increased emissions of SO3

 and a resulting 

increase in the opacity of stack emissions—a phenomenon 

sometimes called the “blue plume.” “Blue plume” is visible from the stack of a power plant when SO3

 is converted 

into vapor-phase sulfuric acid (H2

SO4). The “blue plume” 

color and opacity is dependent on the concentration of 

aerosol, size of aerosols, gas temperature, and atmospheric 

conditions. ,n most cases, the plume becomes visible whe 

H2

SO4 concentrations exceed 10 to 20 ppm. 

Components within the Àuegas path of a power plant have 

creates a complex chemical plant, which both increases 

and reduces the potential SO3

 levels being generated and 

made available to convert into H2

SO4. SO3 formation is 

effected by the furnace, SCR, air preheaters, electrostatic 

precipitators, and wet scrubbers. SO3

 formation begins in 

the furnace and is a by-product of combustion of sulfur 

containing fuels. The extent of the reaction depends on the 

quantity of sulfur in the fuel. Coal from the Kayenta mine 

is a bituminous coal with a sulfur content between 0.3 and 

0.5%.8

 Approximately 1% of SO2 contained in the Àuegas 

would be converted to SO3

. As the sulfur containing Àuegas passes the SCR catalyst, the SO2

 is again oxidized, and 

form between 0.5% and 1.5% additional SO3

, doubling the 

quantity of SO3

 in the Àuegas. The air preheater reduces 

the Àuegas temperature, inturn reducing the SO3

 between 

10% and 50%. However, the reduction in temperature also 

increases the risk of H2

SO4 formation at the lower temperatures (<500°F). The ESPs can also reduce the quantity of 

SO3

 levels. This reduction is dependent on the quantity and 

quality of Àyash is the Àuegas, as well as the temperature. 

Reductions can fall in the range of 10% to 50%. Finally, 

the wet scrubber reduces SO3

 levels, typically forming 

8 A Summary of Coal Deposits in the Colorado Plateau: Arizona, Colorado, 

New Mexico, and Utah, Mark A. Kirschbaum and Laura R.H. Biewick, 

Page B3.
50 NREL/TP-6A20-53024

Table 3-9: US Installations of SNCR’s By State

State Plant Net MW State Plant Net MW

FL Crist ST 4 93.7 MS Victor J. Daniel Jr. ST 1 548.3

FL Crist ST 5 93.7 NH Schiller ST 6 50.0

IA Sutherland (IA) ST 3 81.6 NH Schiller ST 4 50.0

IL Marion CFB 1 33.0 NH Schiller ST 7 50.0

IL Corn Products - Illinois ST 

TGO1 22.5 NJ Mercer ST 1 326.4

FL Crist ST 4 93.7 NJ Mercer ST 2 326.4

FL Crist ST 5 93.7 NJ B. L. England ST 1 136.0

IA Sutherland (IA) ST 3 81.6 NJ B. L. England ST 2 163.2

IL Marion CFB 1 33.0 PA Scrubgrass ST GEN1 94.7

IL Corn Products - Illinois ST 

TGO1 22.5 PA P H Glatfelter Co. - Penns ST GEN6 39.1

KY H L Spurlock ST 3 329.4 TN Bowater Newsprint Calhoun 

Oper ST GEN1 19.0

KY H L Spurlock ST 4 329.4 TN Johnsonville (TN) ST 1 125.0

MA Salem Harbor ST 1 81.9 TN Johnsonville (TN) ST 4 125.0

MA Salem Harbor ST 2 82.0 TX Sandow (Alcoa) ST 5 661.5

MA Salem Harbor ST 3 165.7 VA Chesapeake ST1 112.5

MD Warrior Run Cogen ST GEN1 229.0 VA Chesapeake ST2 112.5

MD Luke Mill ST GEN1 35.0 VA Clover ST 1 424.0

MI T B Simon Power Plant ST 

GEN4 21.0 VA Clover ST 2 424.0

MN Clay Boswell ST 4 558.0 WI Manitowoc ST 9 63.4

MO Sikeston ST 1 261.0

Source: SNL Utility Database, www.snl.com

Table 3-10: SNCR Capital, Operation and Maintenance Estimated Costs

Owner Share (%) Share of capital costs Share of operating costs 

SRP 21.7% $3,544,153 $1,276,904

LADWP 21.2% $3,462,491 $1,247,482

APS 14.0% $2,286,550 $823,809

NV Energy 11.3% $1,845,573 $664,932

TEP 7.5% $1,224,938 $441,326

BOR 24.3% $3,968,798 $1,429,897

Total 100.0% $16,332,503 $4,884,351

Table 3-8: Selective non-catalytic reduction in 

U.S. power plants

Number of installations 34

Average size installed (MW) 184.4

Maximum size installed (MW) 661.5

Minimum size installed (MW) 19.0

Source: SNL Utility Database, www.snl.com
NREL/TP-6A20-53024 51

H2SO4 mist, or vapor-phase sulfuric acid. The conversion 

is dependent upon the scrubber design and temperature 

pro¿les through the system. Reduction generally is in 

the range of 30% to 40%. Wet scrubbers are not ef¿cient 

systems for removing H2

SO4 aerosols, of which most will 

exit the stack. The end result is dif¿cult to predict, as the 

con¿guration of every power plant is different.

MATS in the near future will require higher ¿ltration and 

removal of particulate matter. ESPs currently do not have 

the capability of meeting this more stringent particulate 

removal capability. SO3

 formation can be a result of adding 

SCR systems into larger coal ¿red power plants, and sorbent injection of limestone similar materials can be used to 

reduce the SO3

 to current permitted maximum levels. 

Sorbent injection is utilized as a medium to tie-up the SO3

molecules so they can be captured by a fabric ¿lter baghouse. The sorbent is a calcium or salt based substance, 

often limestone or trona. The sorbent is injected into the 

Àue gas stream, and then collected by the baghouse. Sargent & Lundy has developed sorbent injection capital costs 

estimates for Navajo GS. Table 3-11 shows the annualized 

costs for each of Navajo’s three units for a polishing type 

baghouse and sorbent injection installed with the SCR, and 

the baghouse placed between the SCR and wet scrubber. 

,n the event a polishing baghouse and sorbent injection 

system is not effective in minimizeing the SO3

 and H2SO4

formation by the SCR and downstream equipment, a full 

baghouse would be required to be installed. Table 11 provides the costs for SCR, sorbent injection and both types 

of baghouse intallation at Navajo GS.

Table 3-11: Cost for SCR and Polishing Baghouse

SCR with sorbent injection, 

polishing baghouse

SCR with sorbent injection, 

full baghouse

Capital Costs O&M Costs Capital Costs O&M Costs

Unit 1 $154,946,000 $4,257,000 $372,184,000 $4,257,000

Unit 2 $209,324,000 $4,257,000 $410,919,000 $4,257,000

Unit 3 $189,772,000 $4,257,000 $347,869,000 $4,257,000

Total $554,042,000 $12,771,000 $1,130,972,000 $12,771,000
52 NREL/TP-6A20-53024

3.3 Conclusion

Several technologies are available to help address NOx, 

particulate, acid gases, ammonia and other emissions that 

impair visibility. Navajo GS has had spray type FGD systems on each unit since the mid 1990s. Additionally, each 

unit has LNBs and SOFA integrated into its system for 

nitrogen oxide control and reduction.

All units currently are operating under a Title 9 air permit 

that limits NOx

 emissions to less than 0.24 lb/MMBtu, 

more stringent than the 0.36 lb/MMBtu standard the facility had to meet prior to 2009. As of 2011, all three units are 

operating under these new limits. The ¿rst two units that 

had LNBs and SOFA installed currently have maximum 

NOx

 emissions of 0.217 lb/MMBtu.

SCR technologies can potentially reduce NGS emissions 

to between 0.07 and 0.09 lb/MMBtu. Cost estimates developed by S&L and NPS appear reasonable, both in terms of 

their methodologies and assumptions, and in comparison 

with estimates for other proposed SCR installations in 

the Western ,nterconnection. Estimated capital cost for 

SCRs on all three units ranges from $465 million to $546 

million annual O&M costs estimates range from $11.9 

million to $16.7 million.

SNCR would cost less, but would remove less NOx

. SNCR 

technologies have proven to remove between 20% and 

40% of total NOx

, with a higher ammonia slip potential for 

the facility. This study evaluated the potential NOx

 removal at 25% reduction, utilizing EPR,’s ¿ndings for installing 

SNCR on a 720 MW tangentially coal-¿red power plant. 

The capital investment was considerably less, as was the 

operation and maintenance costs. Only ammonia or urea is 

used to control NOx

, and no catalyst would be required to 

be replace annually. Capital costs for SNCR would likely 

total near $16.5 million, with annual O&M around $6 million. NOx

 emissions would be anticipated to be between 

0.18 and 0.14 lb/MMBtu. 

Sorbent inject and baghouse technologies also are potential 

modi¿cations that could supplement SCR. Further analysis 

of the system needs to be completed prior to understanding the need, and often the impacts to sulfuric acid generation and emissions are not fully evaluated until after the 

SCR is installed and the facility is operating. The impact 

to the facility could potentially add $587 million to capital 

costs and $9 million to annual O&M costs.
NREL/TP-6A20-53024 53

This chapter of the report focuses on how increased 

costs associated with the installation of BART emissions 

controls at Navajo GS (or alternatively, a Navajo GS 

shutdown) would impact the Central Arizona Project 

(CAP). Two areas are key: how the costs would affect CAP 

water rates charged by CAWCD and how higher power 

costs would affect CAP repayment obligations of the 

Central Arizona Water Conservation District (CAWCD). 

An increase in the amount CAWCD has to pay for Navajo 

GS power will lead to an increase in the pumping energy 

charge billed to all CAP water users, as Navajo GS 

provides the bulk of the electricity that powers the CAP 

pumping system used to deliver water from the Colorado 

River to Maricopa, Pima, and Pinal counties. ,n addition, 

an increase in CAWCD’s annual payment toward its CAP 

repayment obligation due to the installation of BART 

emissions controls will require CAWCD to increase CAP 

water rates of some customers in order to recover the 

additional expense.

Several agreements anticipate sale of Navajo GS surplus 

power to be a major source of revenue for the Lower 

Colorado River Basin Development Fund (Development 

Fund). ,f the allocation of costs for emission controls 

increases the production costs of Navajo GS power, the 

net revenues from surplus power sales will be reduced, 

resulting in less money Àowing into the Development 

Fund from the sale of Navajo GS surplus power. This 

reduction in revenues may increase the amount of money 

that the CAWCD must contribute toward its annual 

repayment obligation to the federal government for the 

reimbursement of CAP construction costs, and it may 

reduce the ¿nancial capability of the Development Fund to 

meet some commitments to ,ndian tribes negotiated and 

established through the Arizona Water Settlements Act of 

2004 (Settlements Act).

 

4.1 Background to CAP 

,n 1968, Congress passed the Colorado River Basin 

Project Act (Basin Project Act), which authorized the U.S. 

Bureau of Reclamation (Reclamation) to construct the 

CAP. The purpose of the project was to provide Arizona 

with access to the State’s annual 2.8 million acre-feet (AF) 

entitlement of Colorado River water. Completed in 1993, 

the CAP annually delivers 1.5 million AF of Arizona’s 

allocation of Colorado River water to Maricopa, Pima and 

Pinal counties through a series of canals and pumping 

stations. The 336-mile CAP delivery system lifts Colorado 

River water up an elevation of 3,000 feet from Lake 

Havasu to the system’s end near the City of Tucson.

The CAWCD was created in 1971 to assume the 

responsibility for repayment to the federal government of 

the reimbursable costs of CAP construction. ,t is a multicounty water conservation district that includes Maricopa, 

Pima, and Pinal counties. CAWCD operates and maintains 

the CAP and is responsible for the delivery of CAP 

water to customers. CAWCD has authority to levy an ad 

valorem tax of up to 10 cents per $100 assessed valuation 

of property within the District’s service area to fund 

administrative costs and repayment of CAP construction 

costs. The current ad valorem tax rate is set at 6 cents per 

$100 of assessed valuation.

4.1.1 Relationship between CAP and 

Navajo GS

The 1968 Basin Project Act also authorized the Secretary 

of the ,nterior to enter into agreements with non-federal 

entities for the construction of power plants required to 

operate CAP.1

 The U.S. federal government secured 

a 24.3% interest in Navajo GS, which equates to 

approximately 4.3 TWh of power annually to power the 

CAP operations. The CAP uses about 2.8 TWh of Navajo 

GS power annually, which accounts for approximately 

92% of all power used by CAP. The remaining portion of 

the federal share of Navajo GS generation unused by CAP 

pumping operations, called Navajo GS surplus power, 

totals approximately 1.5 TWh annually.

Salt River Project (SRP) is the plant’s managing partner, 

responsible for operations, maintenance, and replacement 

(OM&R). SRP bills the other plant owners for OM&R 

according to each one’s ownership share in Navajo GS. 

Under long-term contracts that expired on September 30, 

2011, SRP billed Reclamation for the annual OM&R costs 

and capital expenditures related to federal government’s 

ownership share of Navajo GS. Reclamation in turn billed 

1 43 U.S.C. 1523 Section 303

4 Central Arizona Project and Navajo Generating Station
54 NREL/TP-6A20-53024

CAWCD for power used for CAP pumping and SRP for 

the share of the costs associated with the use of the federal 

government’s share of Navajo GS power not used for CAP 

pumping.2

 As of October 1, 2011, SRP bills Reclamation 

for the government’s full share of Navajo GS generation. 

Reclamation then bills CAWCD for the OM&R cost 

associated with the power used for CAP pumping. The 

surplus portion of the federal share unused by CAWCD 

is sold through a long-term contract with SRP and on the 

open power market.

4.2 CAP Repayment Obligations and the 

Development Fund

CAWCD is responsible for meeting an annual 

repayment obligation to the federal government for the 

reimbursement of the CAP construction costs, which 

amounts to approximately $55 million a year. CAWCD’s 

annual payment Àows into the Development Fund, which 

is managed by Reclamation.

,n meeting its annual $55 million CAP repayment 

obligation, CAWCD relies on revenues from other sources 

to lower its annual payment into the Development Fund. 

These other sources of revenues, primarily the sale of 

Navajo GS surplus power and other miscellaneous sources, 

are deposited into the Development Fund each year and 

2 These contracts, known as the Four-Party Agreements, will be discussed in 

more detail in a following section.

credited against CAWCD’s annual payment.3 CAWCD’s 

annual payment into the Development Fund is the 

difference between the total $55 million annual repayment 

obligation and the total revenues from Navajo GS surplus 

power sales and net other miscellaneous sources (shown in 

Figure 4-1). 

The funds used by CAWCD to make its annual payment 

into the Development Fund are generated from two 

sources. CAWCD levies ad valorem taxes on real property 

owners within the three-county CAP service area. ,n 

addition, CAWCD assesses capital charges on municipal & 

industrial subcontractors.

4.2.1 Navajo surplus power sales revenues

As indicated above, the revenues generated from sale 

of Navajo GS surplus power are deposited into the 

Development Fund and credited toward the repayment 

obligation of CAP construction costs owed by CAWCD.4

 

The following section describes how the amount of 

revenue from the sale of Navajo GS surplus power has 

been generated in the past, and the future Navajo GS 

surplus power sales arrangement. 

3 Other miscellaneous revenues deposited into the Development Fund come 

from Hoover and Parker-Davis dam surcharges, SO2

 credit sales, and other 

miscellaneous sources. Other miscellaneous revenues typically total $6 -10 

million annually.

4 Section 303 of the Basin Project Act authorized the U.S. Department of 

the ,nterior to sell the remaining Navajo GS power that was unused by 

CAP (projected to be about 1.5 TWh annually) on open power markets and 

deposit revenues received into the Development Fund. Section 107 of the 

Hoover Power Plant Act of 1984 (Hoover Power Act) authorized the use of 

revenues from Navajo GS surplus power sales to aid in the repayment of 

CAP construction costs owed by CAWCD

Development

Fund

NGS Surplus

Power Sales

Revenues

Other Misc.

Revenues CAWCD

Payment

Figure 4-1. Revenue flows into the development fund
NREL/TP-6A20-53024 55

Arrangement prior to September 30, 2011

Following the adoption of the Navajo Power Marketing 

Plan in 1987, SRP agreed to a series of long-term contracts 

for the use of Navajo GS power, including Navajo GS 

surplus power. These contracts, known collectively 

as the Four-Party Agreements, provided a consistent 

amount of Navajo GS surplus power sales revenue Àowing 

into the Development Fund, as SRP agreed to deposit 

$21.75 million annually into the Development Fund as 

a consideration fee for the use of Navajo GS surplus 

power. This $21.75 million payment was deposited into 

the Development Fund and credited towards CAWCD’s 

$55 million annual CAP repayment obligation. Each 

year, other miscellaneous revenues deposited into the 

Development Fund further reduced CAWCD’s annual 

payment. At year’s end, CAWCD was required to make 

a payment into the Development Fund that equaled the 

difference between the other revenue amounts deposited 

in the Development Fund and CAWCD’s $55 million CAP 

repayment obligation. Table 4-1 shows the revenues and 

CAWCD’s payment into the Development Fund for 2009 

and 2010.

Table 4-1 shows that CAWCD’s payment towards its 

annual $55 million CAP repayment obligation was $32 

million in 2009 and $21.3 million in 2010. The yearto-year variation in CAWCD’s payment was largely 

dependent on amount of other miscellaneous revenues 

Àowing into the Development Fund.

Arrangement after September 30, 2011

All Four-Party Agreements expired on September 30, 

2011. After October 1, 2011, the value of the Navajo GS 

surplus sales revenues will be determined by two sources 

of revenue. SRP has signed an agreement to receive 

220,000 MWh of Navajo GS surplus power for an annual 

payment of $25 million.5

 

5 SRP is responsible for paying the production costs associated with their 

220,000 MWh of NGS surplus power in addition to the value of the SRP 

The remaining Navajo GS surplus power (estimated to be 

1.28 TWh annually) will be sold in accordance with the 

2007 plan adopted by Reclamation. The Western Area 

Power Administration (on behalf of Reclamation) will 

market the remainder of Navajo GS surplus power and 

deposit revenues from the sales into the Development 

Fund. These revenues will also be credited against 

CAWCD’s annual CAP repayment obligation. However, 

the amount of revenues generated from the sales of the 

remainder of Navajo GS surplus power will be highly 

variable and largely dependent on the market price for 

power at the time of the sale and Navajo GS power 

production costs. 

NREL used a “backcasting” analysis to test how the 

post Four-Party Agreement revenue arrangement may 

impact the Development Fund. For the purposes of the 

backcasting analysis and deriving estimates throughout 

this chapter, NREL conservatively selected a Navajo GS 

power production cost of $30 per MWh.6

 

Table 4-2 shows what the net values of Navajo GS surplus 

power would have been if the post Four-Party Agreement 

contract ($25 million).

6 The applicable production cost of Navajo GS power was not supplied to 

NREL by the parties. Two sources of information exist, but they yield 

different answers. Annual data provided in various federal ¿lings for 

Navajo indicated total production costs (coal costs and O&M costs) of 

$23.90 per MWh and $24.45 per MWh for 2009 and 2010, respectively. 

Data from CAWCD’s annual ¿nancial statement reÀecting what the district 

paid for power give a somewhat higher estimate: $32.14 per MWh and 

$32.27 per MWh for 2009 and 2010, respectively. NREL was not able to 

determine, within the timeframe of this study, whether the amount charged 

to CAWCD included costs other than fuel and O&M, and if so, what those 

costs were. For the purposes of the backcasting exercise and deriving 

estimates throughout this chapter, NREL conservatively selected a proxy 

value toward the higher end of this range to represent Navajo’s production 

costs: $30 per MWh.

 These results are sensitive to the actual production cost of Navajo power. 

Costs close to those reÀected in federal ¿lings would have resulted in net 

gains for both years.

Table 4-1. Actual Revenues into the Development Fund, 2009 and 2010

Source of Revenue 2009 2010

SRP consideration fee for Navajo GS power ($ M) $21.8 $21.8

Net other miscellaneous revenues ($ M) $1.2 $11.9

CAWCD payment to meet $55M repayment obligation ($ M) $32.0 $21.3
56 NREL/TP-6A20-53024

revenue structure had been in place in 2009 and 2010, 

assuming Navajo GS power production costs were $30 per 

MWh. The analysis also uses wholesale power market 

prices, which averaged $27 per MWh in 2009 and $30 per 

MWh in 2010.7

Table 4-2 shows that under the post Four-Party Agreement 

revenue arrangement that the value of the SRP contract 

would have been $25 million in 2009 and 2010. ,f 

wholesale power market prices averaged $27 per MWh 

in 2009 and $30 per MWh in 2010, the net value of the 

remaining Navajo GS surplus power would be a net loss of 

$2.7 million in 2009 and $0 million in 2010.

Under the post Four-Party Agreement arrangement, these 

revenues from Navajo GS surplus power sales would Àow 

7 These results are sensitive to the actual production cost of Navajo power. 

Costs close to those reÀected in federal ¿lings would have resulted in net 

gains for both years.

Table 4-2. Net Values of Navajo GS Surplus Power Sales Revenues into the Development Fund, 

Backcast Based on the Post Four-Party Agreement Revenue Arrangement (in $ million)

2009 2010

SRP contract (220,000 MWh of Navajo GS surplus power)

Value of SRP contract 

$25.0 $25.0

Net value of remaining Navajo GS surplus power in power markets

A. Total federal share of Navajo GS power generation

B. “Hoover B” power used for CAP pumping

C. CAP pumping power requirements

D. SRP contract for Navajo GS power

E. Remainder of Navajo GS surplus power 

 (A + B – C – D)

1. Value of remaining Navajo GS surplus at market prices

2. Production cost of remaining Navajo surplus at $30/MWh 

3.9 TWh

0.2 TWh

3.0 TWh

0.2 TWh

0.9 TWh

$24.3

$27.0

4.0 TWh

0.2 TWh

3.0 TWh

0.2 TWh

1.0 TWh

$29.8

$29.8

Net value of remaining Navajo GS surplus power ($2.7) 0

Sources: U.S. Energy ,nformation Administration, Forms 923 and 906 (for net generation) Central Arizona Project Annual 

Report, 2010 (for pumping energy) CAWCD, Financial statements and Other Financial ,nformation, 2010, p. 35 (for Hoover B 

power purchases) SNL ,nformation (for wholesale power prices at CA,SO SP-15 hub)

into the Development Fund and would be credited toward 

CAWCD’s $55 million annual CAP repayment obligation. 

Table 4-3 shows the revenue Àows into the Development 

Fund under a backcast scenario for 2009 and 2010 based 

on the post Four-Party Agreement arrangement. 

Table 4-3 shows that the post Four-Party Agreements 

revenue arrangement would have decreased CAWCD’s 

payment, from $32 million to $31.5 million in 2009, and 

from $21.3 million to $18.1 million in 2010. The Navajo 

GS surplus power sales revenue in 2009 would have 

likely have been a net loss if CAWCD had to pay the cost 

of that power at the rates indicated in its 2010 ¿nancial 

statements. However, if the market prices for power had 

been higher, CAWCD’s payment into the Development 

Fund could have been smaller than what it actually was in 

2009 and 2010.

Note that the amount of remaining Navajo GS surplus 

power available for sale on power markets in 2009 (0.9 
NREL/TP-6A20-53024 57

emissions controls or a Navajo GS shutdown should not 

impact the Development Fund’s ability to meet this ¿rst 

cascade of payment priorities. The list and order of the ¿rst 

cascade of payment priorities is shown in Appendix A. 

The Settlements Act established a second cascade of 

Development Fund payment priorities (shown in Appendix 

B). This second cascade will only receive Development 

Fund revenues if the annual Navajo GS surplus power 

sales revenues and other miscellaneous revenues exceed 

CAWCD’s annual CAP repayment obligation of $55M. 

Table 4-4 shows a hypothetical scenario where the second 

cascade of priority payments would receive Development 

Fund revenue.

Table 4-4. Scenario in which $10 million is Available for 

Second Cascade of Payment Priorities ($ M)

Source of Revenue

Net value of SRP contract for 220, 000 MWh 

of Navajo GS surplus power $25.0

Net value of remaining Navajo GS surplus 

power

$30.0

Net other miscellaneous revenues $10.0

CAWCD payment to meet $55M repayment 0.0

Excess revenue for second cascade of 

priority payments $10.0

Table 4-4 illustrates that if, hypothetically, the net value 

from the market sale of the remaining Navajo GS surplus 

power sales were $30 million annually, the total amount 

TWh) and 2010 (1 TWh) was less than the 1.28 TWh 

anticipated by CAWCD going forward. This is attributable 

to planned outages during 2009 and 2010 for the 

installation of low-NOx

 burners. The following analysis 

in this report assumes that remaining Navajo GS surplus 

power available for sale on the power markets will be 1.28 

TWh per year.

4.2.2 Use of Development Fund revenues

,n 2004, the Settlements Act altered how the Development 

Fund was structured and how the Fund revenues were 

to be used. The Àows of revenue into the Fund did 

not change revenues deposited into the fund still were 

credited against CAWCD’s annual payment toward 

meeting its $55 million repayment obligation. However, 

the Settlements Act authorized the revenues to be made 

available to fund the delivery of CAP water to ,ndian 

tribes and to fund Arizona ,ndian water settlements. 

Reclamation was tasked to manage the Development 

Fund and disperse the revenues to meet Settlements Act 

obligations to the tribes. Reclamation did not disperse 

Development Fund revenues to meet Settlements Act 

obligations until after -anuary 1, 2010.8

 

The Settlements Act set the priorities for how the 

Development Funds revenues are to be directed in meeting 

federal obligations under ,ndian water settlements. The 

Settlements Act established two groups of Development 

Fund payments, each arranged as cascading priorities. 

The ¿rst cascade of payment priorities for ,ndian water 

settlements under the Settlements Act is funded by 

CAWCD’s annual $55 million CAP repayment obligation. 

As long as CAWCD continues to meet its $55 million 

annual CAP repayment obligation, additional costs 

associated with the installation of Navajo GS BART 

8 See Section 107(b) of the Arizona Water Settlements Act.

Table 4-3. Revenues into the Development Fund in 2009 and 2010, Backcast Analysis Based on the 

Post Four-Party Agreement arrangement ($ M)

Source of Revenue 2009 2010

Net value of SRP contract $25 $25.0

Net value of remaining Navajo GS surplus power in power markets ($2.7) $0

Net other miscellaneous revenues $1.2 $11.9

CAWCD payment to meet $55M repayment obligation $31.5 $18.1
58 NREL/TP-6A20-53024

of revenues Àowing into the Development Fund for that 

year would be $65 million, which would exceed CAWCD’s 

$55 million CAP repayment obligation by $10 million. 

Such a scenario would mean that CAWCD would not 

be required to make a payment into the Development 

Fund in that year, as the $55 million annual repayment 

obligation would be completely met by revenues from the 

Navajo GS surplus power sales, SRP contract, and other 

miscellaneous revenues. ,t would also mean $10 million 

excess revenue would Àow into the second cascade of 

payment priorities. 

Even in the absence of the installation of BART emissions 

controls at Navajo GS, the second cascade of priorities 

under the Settlements Act will only receive Development 

Fund revenues when market power prices are high. For 

the net value of the remaining Navajo GS surplus power 

sales to be $30 million (as shown in Table 4-4), Navajo 

GS surplus power would have to be sold at an average 

market price of $53 per MWh, assuming $30 per MWh 

production costs for Navajo GS.9

 Since 2008 when 

wholesale power prices were unusually high due to high 

natural gas prices, the only time the Southern California 

market has sustained prices above $53 was during the ¿rst 

quarter of 2010 (based on a 30-day moving average of dayahead on-peak prices at the CA,SO SP-15 hub).

4.3 Navajo GS and CAP Water Rates

Navajo GS supplies the bulk of the power required for the 

CAP system, which moves water from the Colorado River 

to Maricopa, Pima, and Pinal counties. The CAP system 

delivers water to a range of municipal and industrial 

(M&,), tribal (federal), and agricultural customers. Figure 

4-2 shows the amount that each sector received of the total 

1.5 million AF of CAP water delivered in 2010.

4.3.1 Water Rates

Several cost components drive the CAP water rates 

charged to customers. Table 4-5 shows the current and 

projected costs associated with these component costs.10 

The cost of Navajo GS power directly impacts the CAP 

pumping energy charge rate component. 

The rate components apply to different sectors and uses, 

resulting in different CAP water rates structures charged 

9 ,f actual production costs were closer to $24, wholesale prices would need 

to be $47.

10 Central Arizona Project, Final 2011/2012 Rate Schedule Update, -une 2, 

2011.

M&I Subcontract

399,773

M&I Excess

464,441

Agriculture

400,684

Federal SubcontractOff Reservation

236,891

Federal SubcontractOn Reservation

95,928

Figure 4-2. Distribution of CAP water deliveries in 

2010 (acre-feet)

Table 4-5. Projected Costs of CAP Water by 

Component ($/AF)

2011 2012 2013 2014 2015 2016

Capital 

Charges 15 15 15 10 5

Fixed 

OM&R 69 73 76 78 81 83

Pumping 

Energy 53 49 50 51 56 58

to each sector. Table 4-6 shows the CAP water delivery 

rates for the different categories of users and uses, projected to 2016.

M&I water rates

CAP water rates for M&, users vary (shown in Table 4-6). 

Users of subcontract water pay both the ¿xed OM&R and 

pumping energy charges, which is $122 per AF in 2011. 

Non-subcontract and recharge CAP water costs include an 

additional capital charge per AF, resulting in a water rate 

of $137 in 2011.11 

11 Non-subcontract M&, users do not have long-term subcontracts in place for 

CAP water.
NREL/TP-6A20-53024 59

Federal water rates

CAP water rates for federal deliveries (primarily ,ndian 

water allocations) of CAP water include both delivery 

charge rate components – ¿xed OM&R and pumping 

energy charges. However, the Settlements Act authorized 

the use of Development Fund revenues to pay for the 

¿xed OM&R cost for most ,ndian tribes receiving CAP 

water deliveries. Therefore, as long as Development Fund 

revenues are available, the tribes will pay only the energy 

pumping charge for CAP water ($53 in 2011) rather than 

both the energy pumping charge and ¿xed OM&R costs 

shown in Table 4-6.

Agriculture water rates

As shown in Table 4-6, agricultural users pay a reduced 

rate for delivery of CAP water. Under the Settlements 

Act, non-,ndian agricultural users of CAP water gave up 

their rights to priority CAP water in order to be relieved of 

debt incurred during the construction of CAP distribution 

systems in irrigation districts. The Settlements Act 

granted irrigation districts access to CAP water for a water 

service charge equal to the energy pumping charge until 

the end of 2030.12 

4.4 Rate Impact Scenarios: Base case, SCR 

Installation, SCR plus Baghouse plus Sorbent Injection Installation, Shutdown

This section examines the impact that SCR installation, 

SCR plus baghouse plus sorbent injection installation or 

Navajo GS shutdown would have on CAWCD’s repayment 

obligation into the Development Fund and on water rates 

paid by CAP customers. First, the section establishes a 

business as usual scenario to establish a base case that 

12 The Colorado River Documents 2008, Chapter 5, p 5-15.

can be compared with the SCR installation, SCR plus 

baghouse installation, and Navajo GS shutdown scenarios.

These assumptions are made with respect to how the cost 

of any BART upgrade would be calculated and passed on 

to CAP water users.

Ŷ Reclamation—and ultimately CAWCD and CAP 

water users—would only be responsible for 

24.3% of the total upgrade costs, consistent with 

Reclamation’s share of Navajo GS. They would 

not be responsible for the other 75.7%, which the 

other utility partners would pay for using their 

normal rate base ¿nancing mechanisms.

Ŷ The capital costs associated with Reclamation’s 

share of the BART upgrades would be amortized 

over 20 years, at a rate of 5% using the 

bonding authority of CAWCD. This is a default 

assumption, made necessary by the uncertainty 

over how Reclamation would pay for its share of 

the upgrade cost. Reclamation currently has no 

cost recovery mechanism comparable to the rate 

base approach that its utility partners would use. 

The further assumption is that Congressional 

action would be required to add the federal 

government’s share of BART upgrades to the 

mechanisms currently used to recover other 

capital costs relating to Navajo GS, and that such 

action should not be the basis of analysis unless 

and until passed by Congress.

Ŷ CAWCD’s demand for pumping power is inelastic

that is, the cost of power does not affect the 

amount of power the district takes from Navajo 

GS to operate the CAP pumps. 

Table 4-6. CAP Water Delivery Rates ($/AF)

2011 2012 2013 2014 2015 2016

M& I

Long-term Subcontract

Non-Subcontract

Recharge

Interstate Recharge

122

137

137

167

122

137

137

163

126

141

141

164

129

139

139

162

137

142

142

166

141

141

141

167

Federal (Tribes) 122 122 126 129 137 141

Agricultural 53 49 50 51 56 58
60 NREL/TP-6A20-53024

Ŷ We also assume that demand for CAP water 

by M&,, agricultural, and tribal users will be 

inelastic. Although high prices for CAP water may 

prompt some water users to seek other available 

water sources, there is no easy way to quantify 

such a curtailment in CAP water demand. 

Therefore, the analysis in this section assumes that 

CAP water demand will remain ¿xed, regardless 

of price.

Ŷ Changes in the cost of Navajo GS power due to 

BART or other emission control retro¿ts would 

be added to the pumping power charges from 

Reclamation to CAWCD, resulting in an increase 

in the pumping energy charge assessed to CAP 

water users by CAWCD.

Ŷ Annualized capital costs of BART controls would 

be applied to CAP pumping power only. 9ariable 

production costs would be applied to pumping 

power and excess power.

Ŷ Any increase in the production cost of Navajo GS 

power would decrease the net value of the Navajo 

GS surplus power and result in an increase in 

CAWCD’s annual payment towards its annual 

CAP repayment obligation. The analysis assumes 

that CAWCD would have to recover this increase 

in its annual payment by assessing a “CAP 

repayment recovery charge” on all M&, CAP 

water deliveries, rather than through an increase 

in the ad valorem tax.13 

Ŷ For each scenario, current power market 

conditions are used in calculating the net value of 

the Navajo GS surplus power, using the average 

power market price between 2009 and 2011 - 

$27.25 per MWh.14 Under this power market 

scenario, the production costs of Navajo GS power 

($30 per MWh) would actually be higher than the 

market price for the remaining Navajo GS surplus 

power, resulting in a negative net value. Rather 

than generate surplus power that would be sold at 

a loss, the assumption is that plant operators would 

ramp Navajo GS down and only generate the 

power required for CAP annual pumping needs 

13 The CAP repayment recovery charge would not be assessed on agricultural 

or Federal CAP water deliveries.

14 Average market price for day ahead power sold in the California ,SO at 

the SP15 hub from April 2009 through October 2011. Average takes into 

account on-peak and off-peak prices, assuming 11% of excess is sold as 

peak power and 89% as off-peak. This on-peak/off-peak ratio reÀects the 

makeup of the remaining NGS surplus power. Prices sourced through SNL 

power markets data. Assumes 1,280,000 MWh surplus available for the 

market.

(2.8 TWh) and enough surplus power to meet the 

annual obligations of the SRP contract (220,000 

MWh). The net value of the Navajo GS surplus 

power would be equal only to the net value of the 

SRP contract for surplus power.

4.4.1 Base Case Scenario

The base case scenario assumes that Navajo GS continues 

to operate without being required to install additional 

BART emissions controls. The pumping energy charge 

to CAP water users would remain the same as 2011 rates 

(shown in Table 4-5). The base case scenario establishes 

the baseline annual payment made by CAWCD toward its 

CAP repayment obligation. 

To project the amount of CAWCD’s annual payment into the 

Development Fund, the net value of the Navajo GS surplus 

power sales under a 2011 base case scenario was calculated. 

Table 4-7 shows what the net value of Navajo GS surplus 

power sales would be in 2011 using the average power 

market price for power between 2009 and 2011, along with 

Navajo GS power production costs of $30 per MWh. 

Table 4-7 shows that the net value of the Navajo GS 

surplus power under SRP contract would be $18.4 million 

in 2011, while the net value of the remaining Navajo GS 

surplus power would be a loss of $3.5 million in 2011 

using a market price of $27.25 per MWh. The negative 

net value of the remaining Navajo GS surplus power 

underscores how sensitive these revenues will be to market 

conditions. Again, the assumption is that Reclamation 

would avoid selling power at a loss (i.e., below its cost of 

production) and would instead curtail generation. CAWCD 

would receive no credit toward its annual CAP repayment 

obligation from the sale of the remaining Navajo GS 

surplus power.

Table 4-8 shows the revenue Àows into the Development 

Fund under the 2011 base case scenario, where the net 

value of the remaining Navajo GS surplus power sales 

would be zero.

Table 4-8 shows that under the 2011 base case scenario, 

CAWCD’s annual payment toward its $55 million CAP 

repayment obligation would be $20 million. Under this 

base case scenario, other miscellaneous revenues are set at 

$10 million, which is consistent with CAWCD’s ¿nancial 

projections.
NREL/TP-6A20-53024 61

Table 4-7. Net Value of Navajo GS Surplus Power Under a 2011 Base Case Scenario ($ M)

Net value of SRP contract (220,000 MWh of Navajo GS surplus power)

Value of SRP contract $25.0

Net value of remaining 1.28 TWh Navajo GS surplus power in power markets

Value of remaining surplus power at a market price of $27.25/MWh $34.9

Total production cost of Navajo NS power at $30/MWh $38.4

Net value of remaining Navajo GS surplus power -$3.5

Table 4-8. Revenues into the Development Fund Under the 2011 Base Case Scenario

Source of Revenue (millions)

Net value of SRP contract for 220,000 MWh of Navajo GS surplus power $25.0

Net value of remaining Navajo GS surplus power $0.0

Other miscellaneous revenues $10.0

CAWCD payment to meet $55M CAP repayment obligation $20.0

Table 4-9. Impact of SCR Installation on CAWCD’s Navajo GS Power Costs

low high

Federal share of total SCR capital cost $113.0 M $132.6M

Annual 20 year capitalized costs at 5% interest $9.1 M $10.6 M

Capital cost added to CAWCD’s Navajo GS power costs (per MWh)

(based on 2.8 TWh of annual CAP pumping energy use) a

$3.25/

MWh

$3.79/

MWh

Federal share of annual SCR O&M costs $2.9 M $4.1 M

O&M cost added to cost of federal share of Navajo GS power (per MWh) 

(based on 4.25 TWh annual federal share of Navajo GS power)b

$0.68/

MWh

$0.96/

MWh

Capital and O&M cost added to CAWCD’s power costs (per MWh) $3.93/

MWh

$4.75/

MWh

Total increase in CAWCD’s annual power costs 

(based on 2.8 TWh annual CAP pumping power use) $11.0 M $13.3 M

(a) SCR capital costs are assigned only to the annual power use of CAWCD, not to the entire federal share of Navajo GS power. 

All of the capital costs would be paid annually through a ¿xed amount of Navajo GS power used by CAWCD.

(b) SCR O&M costs are assigned to the entire federal share of Navajo GS power. The O&M costs would according to the 

amount of Navajo GS power generated each year.
62 NREL/TP-6A20-53024

4.4.2 SCR Installation Scenario

The costs associated with capital and annual O&M of 

SCR emission controls at the Navajo GS would increase 

the cost of Navajo GS power. The cost estimates of 

installing SCR technology at Navajo GS vary. As Chapter 

5 explains in further detail, this report uses two cost 

estimates to establish a plausible cost range of installing 

SCR technology at Navajo GS. Table 4-9 shows the impact 

of SCR capital and O&M costs on CAWCD’s Navajo GS 

power costs.

Table 4-9 indicates that SCR capital and O&M costs will 

result in an increase in CAWCD’s Navajo GS power costs 

by between $3.93 per MWh and $4.75 per MWh. ,f base 

case Navajo GS power costs are $30 per MWh, these 

results suggest that adding SCRs will affect the cost of 

Navajo GS pumping power by up to 16%. Such an increase 

would add as much as $13.1 million to CAWCD’s annual 

power costs each year.

Impact of SCR installation on CAP water rates

An increase in CAWCD’s Navajo GS power costs due 

to SCR installation would impact CAP water rates by 

increasing the pumping energy charge for CAP water 

users. Table 4-10 shows how the SCR installation would 

impact CAP pumping energy charge.

Table 4-10 shows that under a low cost SCR scenario the 

total increase in CAWCD’s annual power costs ($11.0 

million) would result in approximately a $7 per AF in the 

pumping energy charge for CAP water customers. Under 

a high cost SCR scenario, the total increase in CAWCD’s 

annual power costs ($13.3 million) would result in 

approximately a $9 per AF increase in the pumping energy 

charge for CAP water customers. 

Table 4-11 shows the impact of CAP pumping energy 

charges on 2011 base case CAP water rate components.

The increase in pumping energy charge would apply to 

all sectors and uses of CAP water. Table 4-12 shows how 

increases in the pumping energy charge would impact 

each sector of users under the low cost SCR installation 

scenario.

As shown in Table 4-12, a $7 per AF increase in the 

pumping energy charge will result in ,ndian tribes and 

agricultural CAP water customers experiencing the largest 

proportional increase in CAP water rates (a 13% increase 

over base water rates). The M&, CAP water users will 

also see substantial increases in CAP water rates (a 4 to 

6% increase over base water rates).

As shown in Table 4-13, an $8 per AF increase in the 

pumping energy charge will result in ,ndian tribes and 

agricultural CAP water customers experiencing the largest 

proportional increase in CAP water rates (a 16% increase 

over base water rates), while M&, CAP water users will 

also see substantial increases in CAP water rates (a 5% to 

7% increase over base water rates).

Impact of SCR installation on Development 

Fund revenues

Table 4-8 shows that under the 2011 base case scenario, 

CAWCD’s annual payment toward its $55 million CAP 

repayment obligation would be $20 million. Neither the 

low nor high cost SCR installation scenario would alter 

the value of the Navajo GS surplus power, resulting in no 

change in CAWCD’s annual payment from the 2011 base 

case under the SCR installation scenarios.

Table 4-10. Increase in the CAP Pumping Energy Charge under the SCR Installation Scenario

low high

Increase in CAP pumping energy charge

Total increase in CAWCD’s annual power costs $11.0 M $13.3 M

Total water deliveries in 2011 (in AF) $1.55 M $1.55 M

Increase in CAP pumping energy charge per AF $7.10/AF $8.58/AF
NREL/TP-6A20-53024 63

Table 4-11. Changes in CAP Water Rate Components Under Low and High Cost SCR Installation 

Scenarios

Water rate components ($ per AF) Base Rate Low High

CAP system capital charge 15 15 15

Fixed OM&R for CAP system charge 69 69 69

Pumping energy charge 53 60 62

Table 4-12. Increase in CAP Water Rates Under the Low Cost SCR Installation Scenario

Sectors Base Rate Low SCR 

Rate % Increase

M & I users ($ per AF)

Long-term Subcontract

Non-Subcontract

Recharge

AWBA Interstate Recharge

122

137

137

167

122

144

144

174

6%

5%

5%

4%

Federal/Indian users ($ per AF) 53 60 13%

Agricultural users ($ per AF) 53 60 13%

Table 4-13. Increases in the Pumping Energy Charge Under the High Cost SCR Installation Scenario

Sectors Base Rate Low SCR 

Rate % Increase

M & I users ($ per AF)

Long-term Subcontract

Non-Subcontract

Recharge

AWBA Interstate Recharge

122

137

137

167

131

146

146

176

7%

6%

6%

5%

Federal/Indian users ($ per AF) 53 62 16%

Agricultural users ($ per AF) 53 62 16%
64 NREL/TP-6A20-53024

4.4.3 SCR plus Baghouse & Sorbent Injection 

Installation Scenario

The installation of SCR plus baghouse & sorbent injection 

(BH&S,) emissions controls at the Navajo GS would result 

in an increase in the cost of Navajo GS power. The cost 

estimates of installing SCR plus BH&S, at Navajo GS 

used in this report uses are described in Chapter 3. Table 

4-14 shows the impact of SCR plus BH&S, installation and 

O&M cost on Navajo GS power costs.

Table 4-14 indicates that SCR plus BH&S, capital and 

annual O&M costs would add between $8.61 per MWh 

and $9.43 per MWh to CAWCD’s power costs. This would 

increase CAWCD’s annual power costs by as much as 

$26.4 million. 

Impact of SCR plus baghouse & sorbent injection installation on CAP water rates

An increase in Navajo GS power costs due to SCR plus 

BH&S, installation will impact CAP water rates by 

increasing the pumping energy charge for CAP water 

users. Table 4-15 shows the impact of SCR plus BH&S,

installation on the CAP pumping energy charge.

Table 4-14. Impact of SCR plus Baghouse & Sorbent Injection Installation on CAWCD’s Navajo GS 

Power Costs

Impact of SCR Plus Baghouse & Sorbent Injection Installation

Federal share of BH&SI capital cost

Annual 20 year capitalized costs at 5% interest

Capital cost added to CAWCD’s Navajo GS power costs (per MWh)

(based on 2.8 TWh of annual CAP pumping energy use)

$145.0 M

$11.6 M

$4.14/MWh

Federal share of annual BH&SI O&M costs

O&M cost added to the cost of the federal share of Navajo GS power (per MWh) 

(based on 4.25 TWh annual federal share of Navajo GS power)

$2.3 M

$0.54/MWh

Additional capital and O&M cost of CAWCD’s power costs for BH&SI installation (per MWh) $4.68/MWh

Additional capital and O&M cost of CAWCD’s power costs for SCR plus BH&SI installation (per 

MWh)

$8.61/MWh 

to 

$9.43/MWh

Total increase in CAWCD’s annual CAP pumping energy costs 

(based on 2.8 TWh annual CAP Navajo NG power use)

$24.1 M 

to 

$26.4 M

Table 4-15 shows that under a low cost SCR plus BH&S,

scenario the total increase in CAWCD’s annual power 

costs ($24.1 million) would result in a $16 per AF increase 

in the pumping energy charge for CAP water customers. 

Under a high cost SCR plus BH&S, scenario, the total 

increase in CAWCD’s annual power costs ($26.4 million) 

would result in a $17 per AF increase in the pumping 

energy charge for CAP water customers. 

Table 4-16 shows the impact of the increased Navajo GS 

power costs from SCR plus BH&S, installation on 2011 

CAP water rate components.

An increase in the pumping energy charge would apply to 

all sectors and uses. Table 4-17 shows how an increase in 

the pumping energy and charges under the low cost SCR 

plus BH&S, installation scenario would impact CAP water 

rates.

As shown in Table 4-17, a $16 per AF increase in the 

pumping energy charge will result in ,ndian tribes and 

agricultural CAP water customers experiencing the largest 

proportional increase in CAP water rates (a 29% increase 
NREL/TP-6A20-53024 65

over base water rates), while M&, CAP water users will 

also see substantial increases in CAP water rates (a 11 to 

14% increase over base water rates).

Table 4-18 shows how increases in the pumping energy 

charge would impact CAP water rates under the high cost 

SCR plus BH&S, installation scenario.

As shown in Table 4-18, a $17 per AF increase in the 

pumping energy charge will result in ,ndian tribes and 

agricultural CAP water customers experiencing the largest 

proportional increase in CAP water rates (a 32% increase 

Table 4-15. Increases in the CAP Pumping Energy Charge under the SCR plus Baghouse & Sorbent 

Injection Installation Scenario

Low High

Increase in CAP pumping energy charge

Total increase in CAWCD’s annual power costs $24.1 M $26.4 M

Total water deliveries in 2011 (in AF) 1.55 M 1.55 M

Increase in CAP pumping energy charge per AF $15.55/AF $17.03/AF

Table 4-16. Increase in CAP Water Rate Components Under the SCR plus Baghouse & Sorbent 

Injection Scenario ($/AF)

Water rate components ($ per AF) Base Rate Low High

CAP system capital charge 15 15 15

Fixed OM&R for CAP system charge 69 69 69

Pumping energy charge 53 69 70

Table 4-17. Increase in CAP Water Rates under the Low Cost SCR plus Baghouse & Sorbent Injection 

Installation Scenario

Sectors Base Rate Low SCR 

Rate % Increase

M & I users ($ per AF)

Long-term Subcontract

Non-Subcontract

Recharge

AWBA Interstate Recharge

122

137

137

167

138

153

153

183

13%

11%

11%

9%

Federal/Indian users ($ per AF) 53 69 29%

Agricultural users ($ per AF) 53 69 29%

over base water rates), M&, CAP water users will also 

see substantial increases in CAP water rates (a 10 to 14% 

increase over base water rates).

Impact of SCR plus baghouse & sorbent injection 

installation on Development Fund revenues

Table 4-8 shows that under the 2011 base case scenario, 

CAWCD’s annual payment toward its $55 million CAP 

repayment obligation would be $20 million. Neither the 

low nor high cost SCR plus BH&S, installation scenario 

would alter the value of the Navajo GS surplus power, 

resulting in no change in CAWCD’s annual payment from 

the 2011 base case under the SCR installation scenarios.
66 NREL/TP-6A20-53024

4.4.4 Navajo GS Shutdown Scenario

,n the event of a Navajo GS shutdown, CAWCD will 

have to purchase replacement power to operate the CAP 

system pumps. NREL modeled the cost of purchasing 

power on the open power markets in the event of a Navajo 

GS shutdown, developing a low price and high price for 

power. Chapter 2 explains the methodology behind these 

estimates. Under the low price scenario, the market price 

for power would be $32.44 per MWh.15 Under a high 

price scenario, the market price for power would be $49.48 

per MWh. Table 4-19 shows how a Navajo GS shutdown 

would impact CAP pumping power costs under low and 

high power price scenarios.

Under a low market price scenario, Table 4-19 shows that 

CAWCD would see its CAP pumping power costs increase 

by $6.8 million, an 8% increase over the cost of using 

Navajo GS power (at $30 per MWh). ,f CAWCD purchased 

replacement power under a high market power price 

scenario, the increase in CAP pumping power costs would 

be $54.5 million, a 64% increase over the cost of using 

Navajo GS power.16

15 The low power market price ($32.44) used in the shutdown scenario is 

higher than market power price used to determine the net value of Navajo 

GS surplus revenue in the base case, SCR, and SCR plus BH&S, scenarios 

($27.25) because the Navajo GS shutdown scenario involves the purchase 

of replacement power for CAP pumping, which would include the purchase 

of off-peak and on-peak power. The Navajo GS surplus power sold under 

the other scenarios would be primarily off-peak power, which has a lower 

market price than on-peak power.

16 The $6.8 million increase in CAWCD pumping energy cost is derived by 

multiplying the $2.43 per MWh by the 2,800,000 MWh of Navajo GS power 

used by CAP each year. The $54.5 million increase in CAWCD pumping 

energy cost is derived by multiplying the $19.46 per MWh by the 2,800,000 

MWh of Navajo GS power used by CAP each year.

Table 4-18. Increase in CAP Water Rates Under the High Cost SCR plus Baghouse & Sorbent 

Injection Installation Scenario

Sectors Base Rate Low SCR 

Rate % Increase

M & I users ($ per AF)

Long-term Subcontract

Non-Subcontract

Recharge

AWBA Interstate Recharge

122

137

137

167

139

154

154

184

14%

12%

12%

10%

Federal/Indian users ($ per AF) 53 70 32%

Agricultural users ($ per AF) 53 70 32%

Impact of Navajo GS shutdown on CAP water rates

An increase in CAWCD power costs due to the purchase 

of replacement market power would impact CAP water 

rates by increasing the pumping energy charge for CAP 

water users. ,n addition, CAWCD will likely have to 

recover a signi¿cant increase in the annual payment 

toward its CAP repayment obligation, as there would no 

longer be any revenue Àowing into the Development Fund 

from the sale of Navajo GS surplus power. Table 4-20 

shows the impact of a Navajo GS shutdown scenario on 

the CAP pumping energy charge and CAP repayment 

recovery charge.

Table 4-20 shows that under a low power market price 

Navajo GS shutdown scenario the total increase in 

CAWCD’s CAP pumping energy costs ($6.8 million) 

would result in a $4 per AF in the pumping energy charge 

for CAP water customers. Under a high power market 

price scenario, the total increase in CAWCD’s CAP 

pumping energy costs ($54.5 million) would result in a $35 

per AF increase in the pumping energy charge for CAP 

water customers. 

Table 4-20 also shows that the CAP repayment recovery 

charge associated with Navajo GS shutdown would be 

$29 per AF assessed to M&, CAP water customers. This 

signi¿cant charge reÀects the loss of all revenues Àowing 

into the Development Fund from the sale of Navajo GS 

surplus power through the SRP contract.

Table 4-21 shows the impact of the increased Navajo GS 

power costs on 2011 CAP water rate components.

As indicated previously, CAP water rate components 

apply to different sectors and uses, resulting in differing 
NREL/TP-6A20-53024 67

CAP water rates for each sector. Table 4-22 shows how 

an increase in the pumping energy charge and CAP 

repayment recovery charge due to a Navajo GS shutdown 

would impact each sector of users under low power market 

price conditions.

As shown in Table 4-22, M&, CAP water customer would 

experience a greater proportional increase in CAP water 

rates than would ,ndian tribes and agricultural under low 

power market price conditions. The large increase in M&,

CAP water rates is due to the CAP repayment recovery 

charge, which would likely be required to recover CAWCD’s 

increased payment into Development Fund due to the loss of 

Navajo GS surplus power sales revenues.

Table 4-23 shows CAP water rate impacts from a Navajo GS 

shutdown scenario under high power market conditions.

As shown in Table 4-23 ,ndian and Agricultural CAP 

Table 4-19. Impact of a Navajo GS Shutdown Scenario on CAP Pumping Power Costs

Low power

price 

High power

price

Cost of Navajo GS power $30.00/MWh $30.00/MWh

Market price for power $32.44/MWh $49.48/MWh

Increase in costs over Navajo GS power costs $2.43/MWh $19.46/MWh

Total increase in CAP power costs over Navajo GS18 $6.8 M $54.5 M

% increase in CAP power costs over Navajo GS 8% 64%

Table 4-20. Increases in the CAP Pumping Energy Charge and CAP Repayment Recovery Charge 

Under the Navajo GS Shutdown Scenario

Low Power 

Price 

High Power 

Price

Increase in CAP pumping energy charge

Total increase in annual CAP pumping energy costs $6.8 M $54.5 M

Total water deliveries in 2011 (in AF) 1.55 M 1.55 M

Increase in CAP pumping energy charge per AF $4.39AF $35.16/AF

CAP repayment recovery charge

Base case CAWCD payment to meet $55M CAP repayment obligation $20.0 M $20.0 M

Shutdown CAWCD payment to meet $55M CAP repayment obligation $45.0 M $45.0 M

Increase in CAWCD payment to meet $55M CAP repayment obligation $25.0 M $25.0 M

Total 2011 M&I CAP water deliveries (in AF) 0.86 M 0.86 M

CAP repayment recovery charge to recover increase in payment per AF $28.94/AF $28.94/AF

water users would experience the greatest proportional 

increase (66%) in water rates due to a Navajo GS shutdown 

under high power market price conditions. M&, CAP water 

users would also experience a substantial increase (38 to 

52%) in CAP water rates. Replacing Navajo GS power 

required for CAP pumps with market power under high 

price conditions would dramatically increase water rates. 

Impact of SCR installation on Development Fund 

revenues

Under the Navajo GS shutdown scenario shown in Table 

4-20, CAWCD’s annual payment into the Development 

Fund would be $45 million to compensate for the loss of 

revenues from the sale of Navajo GS surplus power. This 

$45 million annual payment would be $25 million greater 

than the $20 million annual payment made under the base 

case scenario. 
68 NREL/TP-6A20-53024

Table 4-21. Increase in CAP Water Rate Components Under the Navajo GS Shutdown Scenario 

($/AF)

Water rate components Base Rate Low power 

price rate

High power 

price rate

Capital charge 15 15 15

Fixed OM&R 69 69 69

Pumping energy charge 53 57 88

CAP repayment recovery charge - 29 29

Table 4-22. Increase in CAP Water Rates Under the Navajo GS Shutdown Scenario (Low Power 

Price)

Sectors Base Rate Low power 

price rate % Increase

M & I users ($ per AF)

Long-term Subcontract

Non-Subcontract

Recharge

AWBA Interstate Recharge

122

137

137

167

155

170

170

200

27%

24%

24%

20%

Federal/Indian users ($ per AF) 53 57 8%

Agricultural users ($ per AF) 53 57 8%

Table 4-23. Increase in CAP Water Rates Under the Navajo GS Shutdown Scenario (High Power 

Price)

Sectors Base Rate Low power 

price rate % Increase

M & I users ($ per AF)

Long-term Subcontract

Non-Subcontract

Recharge

AWBA Interstate Recharge

122

137

137

167

186

201

201

231

52%

47%

47%

38%

Federal/Indian users ($ per AF) 53 88 66%

Agricultural users ($ per AF) 53 88 66%

4.5 Summary

This chapter of the report examined the potential impacts 

of the installation of BART emissions controls at Navajo 

GS or a Navajo GS shutdown on Development Fund 

revenues and CAP water rates. The analysis looked at 

four separate Navajo GS scenarios – base case, SCR 

installation, SCR plus BH&S, installation, and Navajo GS 

shutdown. 

4.5.1 Impacts on CAP water rates

An increase in Navajo GS power costs will affect the 

water rates that CAWCD charges CAP water users. The 

installation of Navajo GS BART emission controls or a 

Navajo GS shutdown would lead to an increase in the 

pumping energy charges billed to all CAP water users. 

,t could also require CAWCD to establish a mechanism 

to recover additional payments made toward its CAP 
NREL/TP-6A20-53024 69

repayment obligation due to lost Navajo GS surplus power 

sales revenues. 

Under the scenario analysis, M&, users will bear the 

cost of the increase in the CAP pumping energy charge, 

as well as the payment of the CAP repayment recovery 

charge. ,ndian and agricultural users will only pay the 

increase in the CAP pumping energy charge. Table 4-24 

summarizes the impacts of SCR installation, SCR plus 

baghouse installation, and Navajo GS shutdown on CAP 

water rates, showing both projected CAP water rates under 

each scenario. Table 4-25 shows the percentage increase 

in water rates over 2011 base rates.

Table 4-24 shows that under a SCR installation scenario 

all CAP water customers will see rates increase by $7 to 

9 per AF. Under a SCR plus BH&S, installation scenario, 

all CAP water customers will pay an additional $16 to 17 

per AF. ,n the event of a Navajo GS shutdown scenario, 

the price of replacement power will dictate CAP water rate 

increase. Under a low market power price scenario, M&,

users would see CAP water rates increase by $33 per AF, 

while ,ndian and agricultural users will see rate increases 

of $4 per AF. A high market power price scenario would 

result in M&, water rate increases of $64 per AF, while 

,ndian and agricultural CAP customers would see water 

rates increase by $35 per AF. 

As shown in Table 4-25, ,ndian and agricultural CAP 

water users would generally experience a greater 

proportional increases in CAP water rates than M&,

customers, except under a Navajo GS shutdown scenario 

where low cost replacement power is available on the open 

power markets. 

4.5.2 Development Fund impacts

As illustrated in previous sections of this chapter, SCR 

installations or a Navajo GS shutdown would impact 

Development Fund revenues credited toward CAWCD’s 

annual $55 million CAP repayment obligation. Any 

increase Navajo GS power costs would result in less revenue 

generated through the sale of Navajo GS surplus power 

on the open market, reducing the amount credited against 

CAWCD’s annual payment into the Development Fund.

The chapter examined the impact of three scenarios on 

CAWCD’s annual payment. Under the SCR and SCR plus 

BH&S, installation scenarios, CAWCD’s annual payment 

would remain $20 million. A Navajo GS shutdown would 

result in a situation where the Development Fund would 

no longer receive revenues from the SRP contract, leaving 

CAWCD with an annual payment of $45 million, which 

is substantially higher than CAWCD’s 2009 payment and 

base case annual payment.

Development Fund disbursement obligations to Arizona 

,ndian tribes established under Settlements Act should 

remain largely unaffected by SCR and SCR plus BH&S,

installation at Navajo GS or a Navajo GS shutdown. As 

long as CAWCD continues to meet its $55 million annual 

CAP repayment obligation, additional costs associated 

with the installation of Navajo GS BART emissions 

Table 4-24. Increase in CAP Water Rates Under Various Navajo GS Scenarios ($/AF)

Navajo GS shutdown

Base 

Rate

SCR 

rate

SCR plus 

BH&SI 

rate

Low 

power 

price rate

High 

power 

price rate

M & I users ($ per AF)

Long-term Subcontract

Non-Subcontract

Recharge

AWBA Interstate Recharge

122

137

137

167

129-131

144-146

144-146

174-1476

138-139

153-154

153-154

183-184

155

170

170

200

186

201

201

231

Federal/Indian users ($ per AF) 53 60-62 69-70 57 88

Agricultural users ($ per AF) 53 60-62 69-70 57 88
70 NREL/TP-6A20-53024

controls or a Navajo GS shutdown should not impact 

the Development Fund’s ability to meet the ¿rst cascade 

of payment priorities. The increase cost of Navajo GS 

power would decrease the likelihood that Navajo GS 

surplus power sales would contribute enough revenue 

to completely offset and exceed CAWCD’s $55 million 

annual CAP repayment obligation and provide funds for 

the second cascade of payment priorities. However, even 

in the absence of the installation of BART emissions 

controls at Navajo GS, the second cascade of priorities 

under the Settlements Act will only receive Development 

Fund revenues when market power prices are substantially 

higher than current power market prices. 

Table 4-25. Percentage Increase in CAP Water Rates Under Various Navajo GS Scenarios ($/AF)

Navajo GS shutdown

Base 

Rate SCR rate

SCR plus 

BH&SI 

rate

Low 

power 

price rate

High 

power 

price rate

M & I users ($ per AF)

Long-term Subcontract

Non-Subcontract

Recharge

AWBA Interstate Recharge

--

--

--

--

6%-7%

5%-6%

5%-6%

4%-5%

13%-14%

11%-12%

11%-12%

9%-10%

27%

24%

24%

20%

52%

47%

47%

38%

Federal/Indian users ($ per AF) -- 13%-16% 29%-32% 8% 66%

Agricultural users ($ per AF) -- 13%-16% 29%-32% 8% 66%

Fixed operation, maintenance and replacement (OM&R) charges associated with

the delivery of CAP water to Indian tribes

Gila River Indian Community Water OM&R Trust Fund

Gila River Indian Community to rehabilitate the

existing San Carlos Irrigation Project

1) New Mexico Unit Fund, 2) CAP water distribution systems for the Gila River

Indian Community, San Carlos Apache Tribe, and Tohono O'odham Nation, 

3) Rehabilitiation of the San Carlos Irrigation Project, and 

4) Future Indian Water Settlement Subaccount

Payment of the costs of constructing CAP distribution systems for the

Yavapai Apache, Pasqua Yaqui and Tonto Apache tribes and the

Sif Oidak District of the Tohono O’odham Nation

Fixed operation, maintenance and replacement (OM&R) charges associated with

the delivery of CAP water to Indian tribes

Final year's payment on CAP repayment obligation

U.S. Treasury General Fund to reimburse fixed OM&R costs for CAP Indian

deliveries and Indian water rights settlement costs previously paid

from the Development Fund. 

U.S. Treasury General Fund to 9(d) debt made non-reimbursable

under Settlements Act 

U.S. Treasury General Fund

Appendix A: First Cascade of the Settlements Act Payment 

Priorities

Appendix B: Second Cascade of the Settlements Act Payment 

Priorities
NREL/TP-6A20-53024 71

This chapter summarizes the state of the science with 

respect to the impacts of the Navajo Generating Station 

(Navajo GS) on visibility in several national parks and 

wilderness areas designated for visibility protection. 

,t begins with a brief discussion of the statutory and 

regulatory basis for visibility protection of these lands 

under the Clean Air Act (CAA), and the regulatory basis 

for applicability of the regional haze BART requirements 

to Navajo GS, then examines the modeling and monitoring 

used by parties to the proceeding.

5.1 Regulatory Framework

Under the 1977 CAA amendments, Congress mandated 

the Prevention of Signi¿cant Deterioration of Air 

Quality (PSD) construction permitting program for 

stationary emissions sources. The purpose was to prevent 

degradation of air quality in Class ,, Class ,,, and Class 

,,, areas. These area designations apply only where the 

air quality is better than the pollutant concentration limits 

established under the National Ambient Air Quality 

Standards (NAAQS).

There have been no Class ,,, areas designated to date, 

and therefore, except for NAAQS nonattainment areas 

(established on a pollutant-by-pollutant basis), the nation 

is divided into only Class ,, and Class , areas. The Class 

, areas are certain national parks and wilderness areas of 

a certain size as de¿ned within the CAA (“mandatory” 

Class , areas), plus any areas specially redesignated as 

Class , after the 1977 CAA amendments. 

,n addition to other types of protections required under 

the CAA, mandatory Class , areas nationwide generally 

have been designated for special visibility protection. The 

only exceptions are the Rainbow Lake Wilderness Area 

in Wisconsin and the Bradwell Bay Wilderness Area in 

Florida (Code of Federal Regulations, 40 CFR 81, Subpart 

D).

Navajo GS is located approximately 5 miles southeast of 

the Glen Canyon Dam, which created Lake Powell, as 

shown in Figure 5-1. Navajo GS is located within 300 

kilometers (km) of eleven (11) Class , national parks and 

wilderness areas. As Figure 5-1 shows, Class , areas 

surround the power plant in all four quadrants of the 

compass. Thus, it is important to consider the Navajo 

GS’s potential visibility impacts on not only the Grand 

Canyon National Park, which is the nearest and most 

prominent Class , area, but on all these Class , areas.

The CAA requires EPA to develop rules to implement a 

program of visibility protection, which would require the 

application of Best Available Retro¿t Technology (BART) 

to certain facilities. The primary focus of these rules was 

the prevention and remediation of regional haze impacts 

on Class , areas by large emissions sources.

On -uly 6, 2005, the EPA published ¿nal amendments 

to its 1999 regional haze rules in the Federal Register, 

including 40 CFR 51, Appendix <, thus ¿nalizing 

guidance for BART determinations (70 FR 39104-39172). 

The regional haze rules establish guidelines that States 

may follow in setting BART emissions limits on emission 

sources that are:

1. BART-eligible, based on their having begun operation 

after August 8, 1962, and being “in existence” before 

August 8, 1977, which includes sources that had 

received a construction permit by the latter date

2. Sources that “may reasonably be anticipated to cause 

or contribute” to visibility impairment in any Class ,

area.

Under the EPA’s BART guidelines, air quality modeling 

is used to determine whether a given source is potentially 

causing or contributing to visibility impairment in any 

Class , area. The CALMET/CALPUFF modeling system 

is air quality modeling software, recommended by EPA1

, 

which is often used to make the assessments of visibility 

impacts for BART-subject facilities. Generally, EPA’s 

BART rules state that any BART-eligible source, as 

de¿ned above, should be subjected to a full BART control 

technology analysis to determine appropriate emissions 

controls, if the modeled visibility impact at any Class ,

area exceeds a threshold of 0.5 deciviews (dv).

A deciview is a unit or metric for haziness that was 

developed to provide a measure of visibility, such that a 

given change in deciviews would have an approximately 

1 The ¿nal BART Guidelines expressly identify and endorse CALPUFF as 

an appropriate (but not necessarily exclusive) modeling tool for assessing 

source impacts on visibility. See 70 Fed. Reg. at 39,122.

5 Assessment of Visibility Science
72 NREL/TP-6A20-53024

This map was produced by the National

Renewable Energy Laboratory for the

Department of Energy.

October 2011

^_

0 200 100 Kilometers

PSD Class I Areas within 300 km of the Navajo Generating Station

Arizona

^_ Navajo Generating Station

NPS Class I Areas

USFS Class I Areas

Utah

Nevada

Colorado

New Mexico

Arches

National Park

Bryce Canyon

National Park

Canyonlands

National Park

Grand Canyon

National Park

Mazatzal

Wilderness

Mesa Verde

National Park

Petrified Forest

National Park

Pine Mountain

Wilderness

Sycamore Canyon

Wilderness

Zion

National Park

Capitol Reef

National Park

Lake

Powell

Figure 5-1. Navajo GS location relative to PSD Class I areas within 300 km
NREL/TP-6A20-53024 73

equivalent human perceptibility, whether one was 

observing a vista on a hazy day or a clear day. The 

deciview value is proportional to the natural logarithm 

of atmospheric light extinction (bext), where the light 

extinction is expressed as the inverse of a million meters 

(Mm-1). The deciview value is calculated as follows:

dv 10
ln(bext/10) 

 

Because metrics like deciviews and atmospheric light 

extinction are dif¿cult to conceptualize, Figure 5-2 shows 

the relationship between light extinction, deciviews, and 

visual range.2

 9isual range is a more familiar metric to the 

general public, as it is commonly used to describe weather 

conditions involving reduced visibility during precipitation 

events, dust storms, or fog. Also, it is worth noting 

that theoretically, in an unpolluted atmosphere at high 

elevation, light extinction can drop to less than 10 Mm-1, 

making the dv value drop below zero, as can be seen from 

Figure 5-2. At the elevation of the Colorado plateau, the 

best possible visual range (horizontally) is approximately 

400 km, corresponding to a value of zero dv or 10 Mm1. Such optimum visibility occurs when light is scattered 

only by air molecules, known as Raleigh scattering. 

The human perceptibility of a given change in visibility 

measured in deciviews is a matter of some debate. The 

EPA, in its Regional Haze Regulations and Guidelines 

for BART, cites a 1991 report from the National Acid 

Deposition Assessment Program, which stated that 

a 5% change in light extinction, corresponding to an 

approximate 0.5 dv change in visibility, was approximately 

at the threshold of human perception.3

 However, in the 

2 Malm, William C., 1999. ,ntroduction to 9isibility, Air Resources 

Division, National Park Service, Cooperative ,nstitute for Research in the 

Atmosphere (C,RA), NPS 9isibility Program, Colorado State University, 

Fort Collins, CO 80523.

3 EPA 2005, Final Rule, Regional Haze Regulations and Guidelines for Best 

Available Retro¿t Technology (BART) Determinations. See 70 Fed. Reg. at 

39,119.

same discussion, EPA summarizes comments on the 

proposed Regional Haze rule, one of which cites a more 

recent study that found a much higher threshold for the 

difference in dv for human perceptibility, with a minimum 

value of between 1.5 and 2 dv.4

 The latter study also 

found that a deciview was not a consistent measure of 

human perceptibility under a range of natural visibility 

conditions and observer-vista distances, but rather, gave 

consistent results only for observing objects with the same 

colorfulness and that were located at a distance of from 

one-quarter to one-half the observed visual range on a 

given day.

Despite some possible shortcomings in the deciview 

metric, EPA and state agencies use it in applying regional 

haze regulations to emissions sources. This report uses 

deciviews as a relative (not absolute) modeled measure 

of the potential visibility impacts of various emissions 

control scenarios for the Navajo GS. 

 

5.1.1 Applicability of BART to the Navajo GS

The regional haze BART regulations apply to Navajo GS 

because the facility meets the two quali¿cations listed in 

the rules. First, 

the facility is 

BART-eligible 

because it was 

in existence on 

August 7, 1977 

and had not been 

in operation 

for more than 

15 years prior to that date. Second, dispersion modeling 

performed in 2007 predicted that the facility’s emissions 

at the time would have a visibility impact of more than 0.5 

deciviews at one or more Class , areas.5

 Based on these 

two factors, the facility was required to perform a BART 

analysis and to thereby propose a BART emissions control 

strategy to EPA.

4 Henry, R.C., 2002. -ust-Noticeable Differences in Atmospheric Haze, 

-ournal of the Air & Waste Management Association, 52:1238–1243, 

October.

5 ENSR/AECOM 2007. BART Analysis for the Navajo Generating Station 

Units 1 – 3, November.

Figure 5-2. Relationship between atmospheric light extinction, deciviews, and visual range

Extinction (Mm 10 -1)

Deciview (dv)

Visual Range (km)

20 30 40 50 70 100 200 300 400 500 700 1000

0 7 11 14 16 19 23 30 34 37 39 42 46

400 200 130 100 80 60 40 20 13 10 8 6 4
74 NREL/TP-6A20-53024

For most power plants in the United States, the regulatory 

agency with direct oversight on BART matters is the state 

air quality regulatory agency. However, because Navajo 

GS is on Native American land (within the Navajo Nation), 

the jurisdiction for the BART determination rests with the 

EPA in this case EPA Region 9 has jurisdiction.

 

5.2 Emissions and Visibility Trends for 

Southwestern States

This section summarizes sulfur dioxide (SO2) and nitrogen 

oxides (NOx

) emissions trends in the southwestern states 

of New Mexico, Colorado, Utah, Arizona, and Nevada, 

and the Paci¿c Coast state of California over the past 

decade. This section also provides emissions data for 

the past 15 years for Navajo GS and for the Mohave 

Generating Station (MGS), a coal-¿red plant near the 

Arizona-Nevada border in Laughlin, Nevada, that ceased 

operation in 2005. MGS, which was about 70 % of the size 

of Navajo GS in terms of operating capacity, was located 

approximately 50 miles southwest of the western end of 

the Grand Canyon.

This section also summarizes visibility trends based on 

data collected at various Class , areas in the region, as 

contained in the ,MPRO9E (,nteragency Monitoring of 

Protected 9isual Environments) database maintained at 

Colorado State University.6

 The purpose of these data 

summaries is to help provide the reader an understanding 

of progress made to date in reducing emissions of visible 

pollutants in the region.

5.2.1 Regional Emissions Trends

New Mexico, Colorado, Utah, Arizona, Nevada, and 

California were selected for this summary because 

emissions from both industrial facilities and urban areas 

in this region are most likely to have an effect on visibility 

in the Class , areas that are within 300 km of Navajo GS, 

as depicted in Figure 5-1. Emissions sources in northern 

Mexico may also have effects on visibility in the region, 

but reliable emissions data from Mexico were unavailable 

for this study.

The National Emissions ,nventory (NE,) is a 

comprehensive and detailed estimate of air emissions 

prepared every three years by the EPA. Table 5-1 is a 

6 http://vista.cira.colostate.edu/improve/

summary of annual SO2 and NOx emissions from the NE,

database7

 for 2002, 2005, and 2008, for each of the states 

listed above, plus added emissions from the two large 

coal-¿red power plants within the Navajo Nation Navajo 

GS and the Four Corners Power Plant (FCPP). The Table 

5-1 state-by-state totals do not include emissions from 

other tribal land sources. Therefore, the totals in Table 

5-1 for Arizona include the NE, totals plus the added 

Navajo GS emissions from the EPA’s Clean Air Markets 

Division (CAMD) database.8

 The totals in Table 5-1 for 

New Mexico include the NE, totals plus the Four Corners 

Power Plant (located west of Farmington, New Mexico) 

emissions from the CAMD database. 

While the data in Table 5-1 show only slight decreases in 

total SO2

 and NOx emissions from the several states listed 

from 2002 to 2005, there were much more signi¿cant 

decreases in total emissions between 2005 and 2008. The 

relatively large percentage drop in SO2

 emissions was 

largely a function of much lower diesel fuel sulfur limits 

imposed by EPA for on-road and non-road engines in 

2007. The signi¿cant decrease in NOx

 emissions from 

2005 to 2008 was largely due to tighter tailpipe emissions 

standards for new on-road and non-road vehicle engines. 

5.2.2 Power Plant Emissions Trends

Regionally, the emissions of SO2 and NOx have been 

trending downward. There have also been signi¿cant 

reductions, however, in emissions from large power plants 

(MGS and Navajo GS) near Grand Canyon National Park 

(GCNP). These speci¿c reductions have been studied for 

their visibility impacts on GCNP and other Class , areas 

in the region, and these studies are discussed in Section 

5.4.

Figures 5-3 and 5-4 show the trends in annual SO2

 and 

NOx

 emissions from Navajo GS and MGS over the 14 

years from 1997 through 2010. This period was selected 

because it stretches back to just before the ¿rst SO2

scrubber retro¿ts began on the three units at Navajo 

GS. As shown on these charts, there are no emissions 

from MGS after 2005 because that plant was shut down 

permanently late that year.

7 http://www.epa.gov/ttn/chief/eiinformation.html

8 http://camddataandmaps.epa.gov/gdm/index.cfm
NREL/TP-6A20-53024 75

As shown in Figure 5-3, Navajo GS and MGS together 

were emitting more than 100,000 tons/year of SO2

 in 1997. 

The scrubber installations on the three Navajo GS units 

took place between 1997 and 2000, decreasing the plant’s 

SO2

 emissions by more than 90%. The shutdown of MGS 

at the end of 2005 reduced the region’s SO2

 emissions by 

more than 40,000 tons/year, on average. Consequently, 

total SO2

 emissions of the coal-¿red power plants nearest 

GCNP are now less than 5% of what they were in 1997, 

or roughly 5,000 tons per year from Navajo GS. This 

reduction was expected to yield signi¿cant improvement 

in visibility metrics at GCNP and other regional Class ,

areas because ¿ne sulfate particles formed from SO2

 were 

expected to be the primary contributor to regional haze in 

the area.9

 

As a result of the emissions decreases, SO2

 emissions from 

Navajo GS are unlikely to be a focus for current BART 

9 Grand Canyon 9isibility Transport Commission, Recommendations for 

,mproving Western 9istas, -un10, 1996

Table 5-1. SO2 and NOx Emissions Trends from 2002-2008 in Southwestern United States

SO2 Annual Emissions (tons per year)

State 2002 2005 2008

California 171,943 223,312 47,979

Nevada 66,640 72,398 16,814

Arizona 113,762 93,653 87,860

Utah 51,970 52,496 30,437

New Mexico 111,562 60,092 34,250

Colorado 118,419 80,052 67,394

Totals 634,296 582,003 284,734

NOx Annual Emissions (tons per year)

State 2002 2005 2008

California 1,295,794 1,419,014 1,076,603

Nevada 121,713 132,998 83,930

Arizona 377,460 334,958 273,777

Utah 203,787 187,030 166,129

New Mexico 312,488 279,142 183,473

Colorado 319,555 257,536 248,144

Totals 2,630,797 2,610,678 2,032,056

Source: National Emissions ,nventory

proceeding. To date, the primary focus has been on NOx

emissions.

The NOx

 emissions trends from MGS and Navajo GS are 

shown in Figure 5-4. The Navajo GS NOx

 emissions had 

been averaging approximately 35,000 tons/year through 

2008, but then began dropping each subsequent year as 

low-NOx

 burners (LNB) and separated over¿re air (SOFA) 

technology was installed, one unit per year, in 2009, 2010, 

and 2011. The Unit 1 LNB/SOFA retro¿t was the last to 

be completed, earlier in 2011. The emission rates achieved 

on Units 2 and 3 in the ¿rst half of 2011 suggest that the 

Navajo GS units with operating LNB/SOFA systems 

will emit slightly more than 0.21 lb/MMBtu.10 This rate 

would result in annual plant-total NOx

 emissions, based 

on historical plant usage, in the neighborhood of 20,000 

tons/year. This implementation of LNB/SOFA technology 

should yield approximately a 42% reduction (a decrease of 

10 http://camddataandmaps.epa.gov/gdm/index.cfm
76 NREL/TP-6A20-53024

Ŷ How rapidly will nitrate particles 

form with increasing downwind 

distance"

Ŷ How much conversion to ¿ne 

particulate nitrate will occur by the 

time emissions are transported over 

Class , areas in the Southwest"

The focus of power plant emissions 

controls already installed in the 

western United States has primarily 

been on SO2

 emissions, which 

produce sulfate particles. SO2

 has 

been the initial focus because sulfate 

has a larger impact on regional 

haze compared to nitrate. ,n the 

southwestern states in particular, 

sulfate is an even greater concern 

compared to nitrate, because SO2

tends to form sulfate more readily 

at higher temperatures. Sulfate 

formation appears to still be 

dominant over nitrate formation 

in winter months, but just not as 

dominant as during the summer 

(see discussion and chart in Section 

5.4). Thus, for example, measured 

nitrate levels tend to be greater in 

the northern states, and greater 

in general in winter (or late fall 

through early spring) months as 

compared to summer months. ,n 

the southwestern region potentially 

affected by emissions from Navajo 

GS, the winter months are expected 

to be of greatest concern for nitrate 

formation.

5.3 Modeling Studies of Navajo GS 

Visibility Impacts

5.3.1 CALPUFF Model

Multiple visibility modeling studies have been conducted 

for Navajo GS since 2007, in response to requirements of 

the Regional Haze rule. These multiple studies include 

approximately 15,000 tons) in NOx

 emissions compared to 

historical Navajo GS emissions.

Some of the region-wide NOx

 emissions, whether from 

power plants, other industrial sources, or mobile sources, 

will eventually form nitrate particles as the emissions 

are transported downwind. These ¿ne nitrate particles 

contribute to regional haze. Two of the most signi¿cant 

questions regarding Navajo GS NOx

 emissions are: 

50000

40000

30000

20000

10000

0.0

70000

60000

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

Tons

Mohave S02 Navajo S02

Figure 5-3. SO2 emission trends for large power plants in the vicinity of the GCNP

35000

30000

25000

20000

15000

10000

5000

0.0

45000

40000

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

Tons

Mohave NOx Navajo NOx

Figure 5-4. NOx emission trends for large power plants in the vicinity of the GCNP
NREL/TP-6A20-53024 77

two by consultants for the Salt River Project (SRP) that 

are summarized in this section11,

12, and a modeling study 

by the EPA referenced in its advance notice of proposed 

rulemaking (ANPR) regarding BART for both Navajo GS 

and the Four Corners Power Plant.13 All of the Navajo 

GS studies discussed here used the CALPUFF modeling 

system, although the CALPUFF model versions differ and 

the input data differ somewhat in each study.

The CALPUFF model is considered by EPA to be a 

screening tool for visibility assessment. The model is not 

designed to account for a myriad of possible atmospheric 

chemical and photochemical reactions of pollutants, 

natural atmospheric gases, and particles, but rather deals 

with relatively simple chemical reactions that transform 

SO2

 and NOx to ¿ne sulfate and nitrate particles. How 

accurately CALPUFF handles the sulfate and nitrate 

transformations has been questioned, but as a recognized 

screening method, EPA considers CALPUFF to be 

an appropriate tool for comparing alternative control 

strategies on a single-source basis.14

11 ENSR/AECOM 2007. BART Analysis for the Navajo Generating Station 

Units 1 – 3, November.

12 SRP 2011. 9isibility Modeling Using Upgraded CALPUFF Model, 

Submitted for Consideration in Developing Best Available Retro¿t 

Technology Proposal for Navajo Generating Station, February.

13 EPA 2009. Assessment of Anticipated 9isibility ,mprovements at 

Surrounding Class , Areas and Cost Effectiveness of Best Available Retro¿t 

Technology for Four Corners Power Plant and Navajo Generating Station: 

Advanced Notice of Proposed Rulemaking, 74 Fed. Reg. 44313

14 EPA 2005, Final Rule, Regional Haze Regulations and Guidelines for Best 

Available Retro¿t Technology (BART) Determinations. See 70 Fed. Reg. at 

39,123.

5.3.2 Navajo GS Modeling Studies

The Navajo GS emission control technology scenarios 

modeled for visibility impacts included installation of 

LNB/SOFA technology and selective catalytic reduction 

(SCR) technology together with LNB/SOFA. Because the 

Navajo GS plant owners have recently voluntarily installed 

LNB/SOFA on all three Navajo GS units in 2009, 2010, 

and 2011, the focus of this assessment is on the potential 

improvement in visibility to be gained by installation of 

SCR vs. the current LNB/SOFA system. With respect to 

the existing SO2

 control, the wet scrubbers on Navajo GS 

are essentially doing the best technologically feasible level 

of control at this time, removing up to 95% of SO2

 and 

emitting less than 0.06 lb/MMBtu at the outlet. Direct 

particulate matter emissions are also effectively controlled 

with electrostatic precipitators and the wet scrubbers.

Table 5-2 provides a summary of some of the key 

modeling differences between two SRP studies and 

EPA’s study that formed the basis for its August 28, 2009 

ANPR. Note that for the 2011 SRP study, CALPUFF 

9ersion 6.4 was used. However, EPA does not consider 

CALPUFF 9ersion 6.4 to be an appropriate tool for BART 

determination at this time. Although SRP contends that 

the newer version performs better than CALPUFF 9ersion 

5.8, EPA said as recently as August 2011 that the newer 

CALPUFF version has not been adequately tested and 

subjected to public review and comment.15

15 EPA 2011. Approval and Promulgation of ,mplementation Plans New 

Mexico Federal ,mplementation Plan for ,nterstate Transport of Pollution 

Affecting 9isibility and Best Available Retro¿t Technology Determination, 

76 FR 52388.

Table 5-2. Comparison of Modeling Procedures for SRP and EPA Visibility Studies on Navajo GS

Modeling Procedure SRP 2007 EPA 2009 SRP 2011

CALPUFF Version No. 5.8 5.8 6.4

Background Ammonia (NH3, ppb) 0.2-1.0a 0.7-1.3 (1.0-1.5)b CMAQ est.c

Direct SO4 Emissions (lb/hr) 13.02 11.25 13.02

(a) 9aried monthly from 0.2 in winter to 1.0 summer. The SRP 2007 study added to these background NH3 values to account 

for estimated NH3 slip associated with SCR option.

(b) 9aried monthly from 0.7 in late winter to 1.3 in -une, except that at Mesa 9erde, higher values were used, ranging monthly 

from 1.0 to 1.5 ppm.

(c) The modeled NH3 concentrations predicted by the CMAQ model were used. The NPS has commented that the CMAQ 

NH3 predictions are at the lower end of the range of limited measurements in western states, which could result in 

underestimation of ammonium nitrate formation.16

16 Memorandum from Pat Brewer, NPS, to David Hurlbut, NREL, September 19, 2011.
78 NREL/TP-6A20-53024

Tables 5-3, 5-4, and 5-5 present a summary of the 

CALPUFF modeling results for the three studies listed 

in Table 5-2 and discussed above. Table 5-3 provides 

the CALPUFF model results at the eleven Class , areas 

within 300 km of Navajo GS, calculated in deciviews, 

for the original baseline conditions (prior to LNB/SOFA 

installation) and for operation with LNB/SOFA in place 

with an emission rate for each unit equivalent to 0.24 lb/

MMBtu. As discussed previously, reported data for the 

¿rst half of 2011 indicate that Units 2 and 3, which were 

retro¿tted in 2009 and 2010, were actually emitting NOx

 at 

approximately 10% below this modeled level, between 0.21 

and 0.22 lb/MMBtu. Note that Table 5-3 does not provide 

results for the SRP 2011 CALPUFF version 6.4 study, 

because that report did not provide baseline or LNB/SOFA 

results.

Table 5-4 shows the CALPUFF results for Navajo GS 

operating with SCR technology for NOx

 emissions control. 

Table 5-4 does not include results for the SRP 2011 

CALPUFF 9ersion 6.4 study, because that report did not 

provide SCR results, but rather, provided only the resulting 

differences between LNB/SOFA as shown in Table 5-5.

Table 5-5 shows the predicted incremental improvement in 

visibility between the LBN/SOFA operation at an assumed 

NOx

 emission rate equivalent to 0.24 lb/MMBtu, and the 

SCR-controlled emission rates assumed to be equal to 0.08 

lb/MMBtu for each study. 

While there were other differences between the studies, 

such as modeling grid spacing, the major differences in 

the results in Table 5-5 are likely due primarily to the 

different background ammonia concentrations, and in the 

case of the CALPUFF 9ersion 6.4 results, a signi¿cant 

change in the way the model algorithms convert NOx

 to 

nitrate. ,n addition, SRP’s analyses (both the 2007 and 

2011 studies) attempt to account for ammonia slip from 

the SCR process, as well as additional sulfuric acid mist 

(H2SO4) produced by the SCR catalyst. SRP assumed 

a slightly larger amount of H2SO4 emissions compared 

to EPA’s study. Combined with the revised CALPUFF 

6.4 treatment of nitrate, which signi¿cantly reduces its 

rate of production in the plumes, the adverse effects 

of the additional H2SO4 results in the prediction of a 

slight degradation for visibility in some Class , areas 

listed. Between background ammonia and the handling 

of H2SO4, the former appears to account for much of the 

difference between SRP and EPA in their model results. 

To summarize, comparing LNB/SOFA vs. addition of SCR 

to all units at Navajo GS, the maximum improvement at 

any Class , area estimated by SRP in both its 2007 study 

Table 5-3. CALPUFF Results for Original Navajo GS Baseline and for LNB/SOFA Operation

Navajo GSP: Baseline Impact

(dv)

Navajo GS: LNB/SOFA Impact 

(dv)

Class 1 Area SRP 2007 EPA 2009 SRP 2007 EPA 2009

Arches 2.05 3.25 1.51 2.08

Bryce Canyon 2.00 3.66 1.58 2.44

Canyonlands 2.47 4.37 1.96 2.98

Capitol Reef 2.68 5.48 2.31 4.08

Grand Canyon 2.56 5.41 2.29 4.35

Mazatzal 0.71 1.16 0.47 0.73

Mesa Verde 1.42 2.24 1.04 1.33

Petrified Forest 1.52 2.62 1.14 1.54

Pine Mountain 0.66 1.08 0.46 0.64

Sycamore Canyon 1.31 1.96 0.92 1.28

Zion 1.83 3.73 1.47 2.65
NREL/TP-6A20-53024 79

Table 5-4. CALPUFF Results for Navajo GS with SCR Operation

Navajo GS Plant: SCR Impact

(dv)

Class 1 Area SRP 2007 EPA 2009

Arches 0.99 0.89

Bryce Canyon 1.23 1.10

Canyonlands 1.35 1.25

Capitol Reef 1.89 2.04

Grand Canyon 2.29 2.46

Mazatzal 0.38 0.37

Mesa Verde 0.58 0.52

Petrified Forest 0.76 0.66

Pine Mountain 0.34 0.32

Sycamore Canyon 0.63 0.59

Zion 1.10 1.05

Table 5-5. CALPUFF Results for Navajo GS, SCR Improvement over LNB/SOFA

Navajo GS Plant: SCR Improvement over 

LNB/SOFA (Δdv)

Class 1 Area SRP 2007 EPA 2009 SRP 2011

Arches 0.52 1.19 0.23

Bryce Canyon 0.35 1.34 0.15

Canyonlands 0.61 1.73 0.30

Capitol Reef 0.42 2.04 0.57

Grand Canyon 0.00 1.89 0.01

Mazatzal 0.09 0.36 -0.04

Mesa Verde 0.46 0.81 0.08

Petrified Forest 0.38 0.88 0.07

Pine Mountain 0.12 0.32 -0.04

Sycamore Canyon 0.29 0.69 0.04

Zion 0.37 1.60 -0.02
80 NREL/TP-6A20-53024

and its 2011 study are slightly more than a half deciview, 

with either zero improvement or a very slight degradation 

predicted at some Class , areas modeled. EPA’s 2009 

results, in contrast, show visibility improvement as high 

as approximately 2 deciviews for some Class , areas if 

SCR is installed on all units at Navajo GS. However, 

EPA recognizes that CALPUFF may overestimate 

nitrate formation. A study of the degree of possible 

overestimation indicated that using NH3 background 

concentrations even in the 0.5 to 1.0 ppb range (EPA used 

an even higher range for its 2009 modeling) can result in 

overestimation of nitrate impacts by a factor of 2 to 4.17 

Whether one accepts EPA’s ANPR statement that a 

change of approximately one deciview is the threshold 

for a perceptible change, or the observational ¿eld study 

referenced in EPA’s Regional Haze rule which found a 

threshold of just under two deciviews is the minimum 

perceptibility threshold, the results summarized here 

reÀect contrasting ¿ndings. SRP’s ¿nding in each of its 

two studies is that the installation of SCR will not yield a 

perceptible improvement in visibility at the listed Class ,

areas. EPA’s ¿nding is that installation of SCR will result 

in a perceptible improvement in visibility at multiple Class 

, areas. 

As mentioned above, background ammonia concentrations 

are a critical factor in predicting ammonia nitrate 

formation. The assumed ammonia concentrations input 

to SRP’s and EPA’s analyses differed signi¿cantly, as 

summarized in Table 5-2, and are likely responsible for 

the majority of the differences between the SRP and EPA 

model results. The high nitrate episodes measured at 

,MPRO9E sites in the Colorado Plateau are cold season, 

rather than warm season events. Similarly, the high nitrate 

episodes modeled for the Class , areas in the region are 

cold season, rather than warm season events. Therefore, it 

is most crucial to get the ammonia concentrations correct 

in the cool months, as that is when both modeling and 

monitoring indicate that there can be relatively high nitrate 

days.

Limited studies have been done to date to measure 

17 Scire et. al. 2003. Evaluation of the CALPUFF Model in Predicting 

Concentration, 9isibility and Deposition at Class , Areas in Wyoming. 

Presented at the AWMA Specialty Conference: Guideline on Air Quality 

Models: The Path Forward. Mystic, Connecticut, Oct. 23-24, 2003. 

ambient air ammonia concentrations in the Four Corners 

region. One of these studies was done by SRP in 2010 

to help support CALPUFF modeling studies for Navajo 

GS.18 That study measured average wintertime ammonia 

concentrations ranging from 0.63 to to 0.22 ppb at two 

sites approximately 100 km south and north Navajo GS, 

respectively. A prior study (Dec. 2006 – Dec. 2007) 

measured ammonia at several sites, including one in 

Oklahoma, two sites in southwest Colorado (one at Mesa 

9erde) and three sites in northwest New Mexico.19 The 

most rural and least agricultural of these sites was Mesa 

9erde, where ammonia averaged 0.2 ppb, with lower 

values in the winter and higher in the summer. Sites 

nearer urban areas such as Farmington, New Mexico and 

nearer sources of emissions averaged around 1 ppb, again 

with lower values on the colder months and higher values 

generally during the warm months of the year.

The studies summarized above indicate that in more 

remote areas of the southwest, especially during winter 

months, there is much less ammonia available in the 

atmosphere. The ammonia ranges used by EPA’s 

modeling, ranging from 0.7 ppb to 1 ppb in the winter 

months, depending on modeled Class , area, are much 

higher than measured in the above studies. For example, 

winter month ammonia measured at Mesa 9erde was in 

the 0.1 to 0.2 ppb range. As pointed out in the referenced 

SRP ammonia study, use of EPA’s higher ammonia values 

produces modeled ammonium nitrate concentrations 

an order of magnitude higher than measured values for 

many cases. On the other hand, use of the SRP ammonia 

background values in CALPUFF produces a much better 

comparison between modeled and measured values. 

5.4 Monitoring and Related Studies at 

Regional Class I Areas

While the preceding summaries of modeling analyses 

disagree over whether further NOx

 emissions controls 

at Navajo GS would yield a perceptible improvement 

in visibility, there have also been some published 

18 Salt River Project, September 2010. Measurements of Ambient 

Background Ammonia on the Colorado Plateau and 9isibility Modeling 

,mplications.

19 Sather, et. al., 2008. Baseline Ambient Gaseous Ammonia Concentrations 

in the Four Corners Area and Eastern Oklahoma, USA. -ournal of 

Environmantal Monitorin, ¿rst published on the web 25th September 2008 
NREL/TP-6A20-53024 81

observational studies that have attempted to discern 

whether prior emission reductions from power plant 

retro¿ts in the area have resulted in perceptible changes in 

visibility or related metrics. ,n addition, visibility-related 

parameters have been monitored at several regional Class 

, areas as part of the ,MPRO9E program, for which a 

nationwide database is maintained by Colorado State 

University.20 The following sections present some of these 

data, with a focus on nitrate observations and trends, in 

relation to emissions changes that have been occurring at 

power plants in the area and region-wide.

5.4.1 Papers Examining Visibility Improvements from Emission Reductions 

Two published studies have sought to determine whether 

emission reductions at power plants near the Grand 

Canyon have resulted in any perceptible or any measurable 

changes in visibility or in visibility-related parameters. 

These studies include those on the effects of shutting 

down MGS at the end of 2005, and the effects of installing 

scrubbers from 1997 through 1999 for acid gas/SO2

 control 

at Navajo GS. 

To help in understanding these studies regarding the 

effects of MGS and Navajo GS emissions, it is helpful 

to understand general meteorological patterns in the 

region. Figure 5-5 provides an annual wind rose for 

Flagstaff based on data available online21 for the years 

1982-1990 (nine years), as well as seasonal wind roses 

for the same period. Flagstaff is in north-central 

Arizona, approximately 100 miles south of Navajo GS 

and approximately 150 miles east of MGS. The ground 

elevation at Flagstaff is similar to that of Navajo GS. The 

near-surface winds represented here for Flagstaff are 

not necessarily representative of plume-level transport 

winds for Navajo GS (which will typically be well above 

ground level), especially given the channeling effects 

of interspersed mountain ranges, valleys and canyons. 

However, these wind data at least show that the wind 

patterns in the region can have strongly predominant 

directions, and that the predominant directions can vary 

signi¿cantly with season. 

20 CSU 2011: http://vista.cira.colostate.edu/improve/

21 Data from http://www.webmet.com. The data were plotted with WRPLOT 

9iew software available at the same web site as provided by Lakes 

Environmental Software.

The bars on the wind rose charts in Figure 5-5 indicate the 

frequency as speed of winds from a particular direction. 

These wind data show that on an annual average basis, 

winds in the Flagstaff area are most often from the 

northeast or southwest. On a seasonal basis, winds 

from the southwest are more predominant in spring, 

summer, and fall, but in the winter months, winds from 

the northeast are somewhat more frequent than southwest 

winds. 

With respect to the late 1990s scrubber retro¿ts at Navajo 

GS, a study by Green et. al. was performed in 2005 to 

evaluate particulate sulfur and visibility levels in the 

Grand Canyon, before and after the scrubber retro¿ts.22 

The study found that installation of the scrubbers, which 

reduced Navajo GS SO2

 emissions by more than 90%, 

produced a measurable reduction in both particulate 

sulfate levels and in light extinction in GCNP, especially 

during the winter months when plume transport conditions 

favor movement of the Navajo GS plumes over and often 

through the canyon. The study also indicated that the 

more extreme, high sulfate events in GCNP decreased 

markedly from before the scrubber retro¿ts.

A second study more recently (2010) examined the effects 

of the shutdown of the MGS (located ~50 miles southwest 

of the west end of GCNP) at the end of 2005.23 This study 

found a slight reduction in sulfate concentrations, in the 

range of 0.1 to 0.32 micrograms per cubic meter (μg/m3) 

in the summer at monitoring sites in GCNP. The study 

authors stated this range was approximately 3% -10% of 

summer sulfate concentrations. For nitrates, the authors 

found that summer nitrate concentrations fell by 0.12 μg/

m3 at ,ndian Gardens (approximately halfway down the 

canyon) and at Hance Camp on the South Rim. However, 

the study also found no improvement in visibility 

measured in deciviews or light extinction. The authors 

speculated that this lack of improvement may have been 

caused by natural or other variations in other aerosols, 

which could have masked any improvement that might 

have been expected due to the slight sulfate reduction and 

nitrate reductions.

22 Green, et. al. 2005. The Effects of Scrubber ,nstallation at the Navajo 

Generating Station on Particulate Sulfur and 9isibility Levels in the Grand 

Canyon. -ournal of the Air and Waste Management Association, 9ol. 55, p. 

1675, November.

23 Terhorst and Berkman 2010. Effect of Coal-Fired Power Generation on 

9isibility in a Nearby National Park. Atmospheric Environment, 9ol. 44 

(p. 2524-2531).
82 NREL/TP-6A20-53024

NORTH

SOUTH

WEST EAST

8%

12%

16%

20%

Station #03103 - Flagstaff Pulliam Airport

(1982-1990)

WIND SPEED 

(m/s)

 >= 11.1

 8.8 - 11.1

 5.7- 8.8

 3.6 - 5.7

 2.1 - 3.6

 0.5 - 2.1

Calms: 3.76%

Source: http://www.webmet.com/

WRPLOT View - Lakes Environmental Softare

NORTH

SOUTH

WEST EAST

5%

10%

15%

20%

25%

NORTH

SOUTH

WEST EAST

6%

9%

12%

15%

Winter

(December, January, February)

Summer

(June, July, August)

Fall

(September, October, November)

Spring

(March, April, May)

NORTH

SOUTH

WEST EAST

4%

8%

12%

16%

20%

NORTH

SOUTH

WEST EAST

6%

9%

12%

15%

Figure 5-5. Annual and seasonal wind roses for Flagstaff, Arizona
NREL/TP-6A20-53024 83

Finally, the second study authors also pointed out 

that CALPUFF simulations had predicted marked 

improvement in visibility at GCNP if MGS had been 

retro¿tted with SO2

 control, and because their study 

showed no visibility improvement, even with a total 

shutdown of MGS, their conclusions called into question 

the usefulness of CALPUFF for Regional Haze regulatory 

purposes. One should understand that this critique refers 

to earlier versions of CALPUFF, including 9ersion 5.8 

which is being used by EPA as its basis for BART analysis, 

and not necessarily the most recent 9ersion 6.4, which 

attempts to improve CALPUFF’s handling of chemical 

conversion processes.

,n addition to the two studies based on measurements/

monitoring, a recent modeling study by Carlton et al. 

used the Community Multiscale Air Quality (CMAQv4.7) 

model to assess the extent to which anthropogenic air 

pollutant emissions may contribute to formation of 

secondary organic aerosol (SOA).24 Anthropogenic 

emissions may help to create oxidants that convert 

both natural and human emissions of volatile organic 

compounds (9OCs) to particulate matter in the form of 

SOA. CMAQ is a much more sophisticated model than 

CALPUFF CMAQ accounts for transport over long 

distances and numerous chemical reactions that can 

produce particulate matter such as sulfates, nitrates, and 

SOA.

For the cited CMAQ modeling study, the modeling domain 

included the entire lower 48 states, southern Canada, 

and most of Mexico. This modeling study predicted that 

elimination of all controllable anthropogenic emissions 

in the domain could eliminate 50% or more of the SOA 

over much of the eastern United States. (Nearly all 

anthropogenic emissions were placed in the category 

of “controllable” for the study.) However, in northern 

Arizona and southern Utah, the model predicted that 

elimination of all controllable emissions would accomplish 

only a 10% - 20% reduction in SOA. Thus, in addition 

to reducing nitrate particle formation, CMAQ indicates 

that controlling NOx

 and other pollutants may help to 

substantially reduce SOA in the eastern United States. 

However, in the Colorado Plateau region, the potential for 

NOx

 emission reductions to accomplish SOA reduction in 

addition to possible nitrate particle reduction seems to be 

very limited, according to this modeling study. 

24 Carlton et al. 2010. To What Extent Can Biogenic SOA be Controlled"

Environmental Science & Technology, 9ol. 44, p. 3376-3380.

5.5 Visibility Monitoring Metrics and 

Regional Trends 

Navajo GS already has the best available SO2 emissions 

control. At question in the current BART proceeding is the 

extent to which further NOx

 control would lead to further 

visibility improvement. The answer may lie, at least in 

part, in the correlation between two pieces of information: 

the emissions decrease due to the closure of MGS, and 

the substantial region-wide NOx

 emissions decreases as 

summarized in Table 5-1. Between 2002 and 2008, the 

region-wide NOx

 emissions, as summarized in Table 5-1, 

decreased by nearly 600,000 tons/year, or approximately 

23% from the 2002 value. Nearly all of this decrease took 

place from 2006 through 2008. 

Tighter EPA emission standards for new on-road and nonroad engines took effect during this period. ,n addition, 

some power plant retro¿ts (e.g., low NOx

 burners) were 

in place by 2008. Recessionary pressures and slower 

economic activity may also have reduced NOx

 emissions 

for 2008. After 2008, the on-road and non-road emission 

sector emissions, which make up a large fraction of the 

inventory, are expected to continue to drop substantially 

due to continued Àeet replacement with newer on-road and 

non-road vehicles in 2009 and 2010.

Whatever the causes, NOx

 emissions in the region from 

the 2006-2010 period are on the order of 23% lower than 

NOx

 emissions in 2002. Based on the slight change from 

2002 to 2005, the 2002 data are probably representative 

of the 2001 to 2005 period. Given this signi¿cant drop 

in NOx

 emissions between the ¿rst half and last half of 

the past decade, the nitrate measurements from several 

of the Class , areas in the region around Navajo GS were 

analyzed to see if there were similar decreases in nitrate 

concentrations.

The data in Table 5-6 show the calculated ammonium 

nitrate concentrations available from ,MPRO9E sites 

in the region for the ¿rst half and the last half of the 

past decade. One caveat is that the 2010 data were only 

available through October 2010. Because winter nitrate 

values tend to be much higher in the summer, this may 

have biased the 2006-2010 averages slightly on the low 

side. Also, the Meadview site only had data starting in 

February 2003, so the 2001-2005 average for that site 

represents most of 2003, plus 2004 and 2005. 
84 NREL/TP-6A20-53024

This analysis presumes that a 5-year period is long 

enough to establish a reasonable nitrate average, and that 

this parameter is not signi¿cantly affected by climate or 

precipitation cycles, such as El Nino/La Nina that have 

a typical cycle length on the order of 5 years. Based on 

this presumption, the nitrate concentrations values do 

exhibit a slight downward trend. Because measured nitrate 

concentrations in the region appear to have dropped by 

around 12%, this is presumably in response to a drop 

in NOx

 emissions in the region, which are likely around 

23% lower for 2006-2010 compared to 2001-2005 based 

on the data in Table 5-1. However, because formation of 

nitrate aerosol is dependent on a complex, non-linear, set 

of atmospheric conditions and pollutant concentrations, it 

should not be anticipated that a linear rollback of emissions 

would have a linear effect on concentrations.

While there appears to be a decrease in nitrate 

concentrations along with the decrease in regional NOx

emissions, the nitrate decrease at these sites averages 

about half the magnitude on a percentage basis. This 

could imply that much of the nitrate is transported in from 

outside the region, or is from natural sources. ,t could also 

be that because the relationship between NOx

 emissions 

and nitrate is nonlinear due to complex atmospheric 

chemical reactions or deposition of nitrogen compounds. 

One nonlinear effect is the competition in the atmosphere 

for the chemicals (such as ammonia) that help to form 

ammonium nitrate. 

The preference for sulfate formation over nitrate is evident 

all year, and is especially exaggerated in the summer as 

shown in Figure 5-6, which shows the annual pro¿le of 

monthly average sulfate and nitrate concentrations, as 

well as the ratio of sulfate to nitrate, for ,ndian Gardens, 

based on more than 20 years of data. This dominance of 

sulfate is even more remarkable given the much larger 

NOx

 emissions compared to SO2 emissions in the region 

as shown in Table 5-1. ,n coal-¿red power plant plumes, 

even with the best possible scrubbing, there is still a 

fair amount of SO2

 and sulfate present relative to the 

amount of ammonia in the atmosphere. Whatever the 

mechanisms, reductions in atmospheric loadings of NOx

 in 

the southwest United States do not seem to correspond to 

equal reductions in nitrate loadings at most of the Class ,

,MPRO9E sites in the Navajo GS region.

To gain an additional, longer-term perspective on nitrate 

concentration trends at the regional ,MPRO9E monitoring 

locations, the annual averages for the period of record are 

plotted in Figures 5-7 through 5-12 for all the sites listed in 

Table 5-6, except Meadview, which has limited long-term 

data. Also shown on these ¿gures are the annual averages 

of ¿ne particulate matter concentration (PM2.5) and 

sulfate concentration, calculated as ammonium sulfate. 

While there are some perceptible downward trends in 

sulfate and PM2.5 at several sites, the nitrate concentrations 

have been relatively constant over the period of record. 

One important concept to emphasize in looking at these 

Table 5-6. Ammonium Nitrate Concentration Trends

Class 1 Area/Location 2001-2005 Avg.

(μg/m3)

2006-2010d Avg.

(μg/m3) 

Percent 

Reduction

Bryce Canyon 0.270 0.237 12.2

Canyonlands 0.274 0.247 9.9

Grand Canyon/Hance Camp a 0.212 0.219 -2.9

Grand Canyon/Indian Gardens b 0.238 0.209 12.2

Grand Canyon/Meadview c 0.281 0.248 12.1

Mesa Verde 0.236 0.192 18.4

Petrified Forest 0.288 0.226 21.6

Summation & Avg. Percent 1.799 1.577 11.9

(a) Hance Camp is on the canyon rim, near the east end of the wide portion of GCNP.

(b) ,ndian Gardens is about half way down the south canyon wall, near the east end of the wide portion of GCNP.

(c) Meadview is in the far western portion of GCNP. Meadview data for 2001-2005 begin in February 2003.

(d) The 2010 data include only measurements through October.
NREL/TP-6A20-53024 85

charts is that ammonium sulfate and 

ammonium nitrate are assumed, 

for visibility impact purposes, 

to have the same effect per mass 

concentration amount. Thus, despite 

the fact that anthropogenic SO2

emissions in the region have dropped 

far below those of NOx

 (see Table 

5-1), the ¿ne sulfate particles still 

represent, on average, around three or 

more times the amount of visibility 

degradation as nitrate particles, on an 

annual average basis. 

5.6 Control 

Technology Options and 

Cost/Benefit Analysis

Navajo GS is already using the best 

available control for reduction of 

SO2

, the pollutant with the largest 

potential impact on visibility. The 

other major regulated pollutants that 

can signi¿cantly impact visibility are 

particulate matter and NOx

. 

5.6.1 

Future Air Quality Regulatory 

Impact on Navajo GS

,n addition to the pending Regional 

Haze/BART determination for 

Navajo GS, there are other programs 

and rules that could eventually force 

emissions reductions at Navajo GS 

that may help to further mitigate 

any potential contributions to 

regional haze. One recently-issued 

rule is the mercury and air toxics 

standards (MATS) rule. Depending 

on current performance of Navajo 

GS in comparison to the ¿nal 

limits for existing coal boilers in 

the MATS rule, the plant may need 

additional emissions control to attain 

compliance within three years of 

the date of ¿nal rule publication in 

1.0

0.5

0.0 0

10

9

8

7

6

5

4

3

2

1

2.0

1.5

January

February

March

April

May

June

July

August

September

October

November

December

Concentration (ug/m3

)

Ratio of Sulfate to Nitrate

Sulfate: Nitrate Ammonium Sulfate

Year

Indian Gardens - Monthly Averages

(1989-2010)

Ammonium Nitrate

Figure 5-6. Annual profile of sulfate, nitrate and sulfate:nitrate ratio for Indian 

Gardens

3.0

2.5

2.0

1.5

1.0

.5

0.0

5.0

4.5

4.0

3.5

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

Concentration (ug/m3

)

PM2.5 Aerosol Ammonium Sulfate

Year

Bryce Canyon

Ammonium Nitrate

Figure 5-7. PM2.5, sulfate and nitrate annual average trends for Bryce Canyon
86 NREL/TP-6A20-53024

3.0

2.5

2.0

1.5

1.0

.5

0.0

5.0

4.5

4.0

3.5

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

Concentration (ug/m3

)

PM2.5 Aerosol Ammonium Sulfate

Year

Canyonlands

Ammonium Nitrate

Figure 5-8. PM2.5,sulfate and nitrate annual average trends for Canyonlands

3.0

2.5

2.0

1.5

1.0

.5

0.0

5.0

4.5

4.0

3.5

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

Concentration (ug/m3

)

PM2.5 Aerosol Ammonium Sulfate

Year

Hance Camp

Ammonium Nitrate

Figure 5-9. PM2.5, sulfate and nitrate annual averagetrends for GCNP/Hance Camp
NREL/TP-6A20-53024 87

3.0

2.5

2.0

1.5

1.0

.5

0.0

5.0

4.5

4.0

3.5

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

Concentration (ug/m3

)

PM2.5 Aerosol Ammonium Sulfate

Year

Indian Gardens

Ammonium Nitrate

Figure 5-10. PM2.5, sulfate and nitrate annual average trends for GCNP/Indian 

Gardens

3.0

2.5

2.0

1.5

1.0

.5

0.0

5.0

4.5

4.0

3.5

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

Concentration (ug/m3

)

PM2.5 Aerosol Ammonium Sulfate

Year

Mesa Verde

Ammonium Nitrate

Figure 5-11. PM2.5, sulfate and nitrateannual average trends for Mesa Verde
88 NREL/TP-6A20-53024

the Federal Register.25 The rule was signed in December 

2011 and will likely be published in -anuary 2012. On this 

timeline, any retro¿ts to attain compliance would need to 

be in place by -anuary 2016.

Another proposed rule that could affect Navajo GS, but has 

recently been put off until 2013 or later, is a new National 

Ambient Air Quality Standard (NAAQS) for ozone. ,f 

a tighter ozone NAAQS is eventually enacted, it would 

likely affect most major sources of NOx

 in the nation, 

possibly requiring many of them to install the best possible 

NOx

 emissions control. This requirement could take the 

form of a second version of the Cross State Air Pollution 

Rule (CSAPR) that was recently issued26 and that applies 

to larger (> 25 MW) utility units in generally the eastern 

half of the lower 48 states. CSAPR regulates only the 

principal precursor emissions of ¿ne particulate matter 

25 EPA, May 3, 2011. National Emission Standards for Hazardous Air 

Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating 

Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, 

,ndustrial-Commercial-,nstitutional, and Small ,ndustrial-Commercial-

,nstitutional Steam Generating Units Proposed Rule. 76 FR 24976.

26 EPA, Aug. 8, 2011. Federal ,mplementation Plans: ,nterstate Transport of 

Fine Particulate Matter and Ozone and Correction of S,P Approvals Final 

Rule. 76 FR 48208.

and ozone, namely SO2 and NOx

emissions. However, a federal court 

stayed CSAPR on December 30, 2011 

in response to legal challenges, so its 

implementation will be delayed. 

The MATS rule could require 

the Navajo GS owners to install 

additional particulate matter 

control, perhaps baghouses, as well 

as mercury control in the form of 

sorbent injection (possibly activated 

carbon). However, it is expected that 

any change in PM emissions by these 

controls would have a negligible 

impact on visibility in Class , areas.

,f a “CSAPR2” rule was 

implemented in response to a 

new ozone standard, it is possible 

that Navajo GS would need to 

install more aggressive NOx

emission controls. However, 

given the expected rule timing 

and implementation timeframes, 

implementation of an Navajo GS retro¿t, if required for 

such a rule, is likely 8-10 years away. Obviously, if such 

controls were implemented, they would also decrease the 

potential for Navajo GS impacts on visibility. 

 

5.6.2 Cost/Benefit Analysis

For the purposes of evaluating whether costs for a 

prospective control technology are justi¿ed for a given 

facility, a commonly used metric is the annualized cost 

of the control divided by the visibility improvement to 

be gained, in units of dollars per deciview ($/dv). The 

annualized cost of control is calculated as the sum of the 

annualized initial capital cost for design, equipment, and 

installation, plus the annual operation and maintenance 

(O&M) cost.

Most of the focus of studies for NOx

 control on Navajo GS 

to date has been on SCR technology. Chapter 4 discussed 

selective non-catalytic reduction (SNCR) as another 

potential NOx

 reduction technology, with much lower total 

3.0

2.5

2.0

1.5

1.0

.5

0.0

5.0

4.5

4.0

3.5

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

Concentration (ug/m3

)

PM2.5 Aerosol Ammonium Sulfate

Year

Petrified Forest

Ammonium Nitrate

Figure 5-12. PM2.5, sulfate and nitrate annual average trends for Petrified Forest
NREL/TP-6A20-53024 89

various NOx emission control options for the coal-¿red 

Units 2 and 3 of the Apache Generating Station (Apache 

GS), each rated at 195 MW.27 The control options include 

various LNB, SNCR, and SCR technologies. The S,P 

concludes that the BART should be LNB with over¿re air 

(OFA) for each unit. The calculated $/yr/dv values were 

$2 million to $2.5 million for these units, as compared to 

$9-$10 million for each unit with SCR included.

,n Nevada, the coal-¿red 557-MW Reid Gardner Station 

north of Las 9egas includes three BART-subject units 

(1, 2, and 3) rated at 100 MW each. Nevada’s S,P 

analysis28 included $/dv values for several NOx

 control 

options, including LNB/OFA, rotating opposed-¿re 

air (ROFA) with Rotamix, and LNB/OFA plus SCR 

(shown in Table 5-8). The NOx

 emission limits originally 

proposed by EPA29 to be approved for BART on these 

units are slightly higher than the current performance of 

the recently installed LNB/SOFA units on Navajo GS. 

However, after consideration of public comments on 

its rule proposal regarding Nevada’s S,P, EPA recently 

¿nalized approval of the S,P as proposed with the 

exception of the Reid Gardner BART limits for NOx

. EPA 

has decided to take more time to review the supporting 

information for NOx

 and will take action in the future on 

this portion of Nevada’s S,P.30

Table 5-8 compares the BART controls proposed for 

Apache and Reid Gardner with current NOx

 controls 

at Navajo GS  all calculated $/dv values are based on 

CALPUFF 5.8 or earlier model versions. For the Reid 

Gardner Station, the EPA’s original proposed BART 

determination (now withdrawn) was in agreement 

with Nevada’s S,P proposal, consisting of a low-NOx

combustion/SNCR technique (ROFA w/Rotamix) that 

results in a three-unit average emission limit of 0.23 lb/

MMBtu. Recent (2011) data from Units 2 and 3 at Navajo 

GS with recently installed LNB/OFA in operation are 

showing average NOx

 emissions between 0.21 and 0.22 lb/

MMBtu.

27 Arizona State ,mplementation Plan – Regional Haze Under Section 308 of 

the Federal Regional Haze Rule, -anuary 2011

28 Nevada Division of Environmental Protection, Nevada Regional Haze S,P 

(October 2009), Appendix B Support Documents (BART Analysis for 

Reid Gardner Station Unit 1, BART Analysis for Reid Gardner Station Unit 

2, BART Analysis for Reid Gardner Station Unit 3).

29 EPA, -une 22, 2011. Approval and Promulgation of Air Quality 

,mplementation Plans State of Nevada Regional Haze State 

,mplementation Plan. 76 FR 36450.

30 See EPA rulemaking (not yet published in Federal Register) at http://www.

epa.gov/region9/air/actions/nv.htmlhaze

annualized costs compared to SCR, but also signi¿cantly 

lower NOx

 removal rates. ,n this chapter, the analysis of 

cost and bene¿ts focuses on SCR. 

EPA provides a range of estimated site-speci¿c annualized 

costs for installation and operation of an SCR system 

on Navajo GS. This range is from two estimates, one by 

SRP, and the other by the NPS. According to the EPA’s 

ANPR for Navajo GS, the annualized cost estimates were 

approximately $71.7 million as estimated by Sargent 

& Lundy for SRP, and approximately $67.6 million as 

estimated by the NPS. (Note that the annualized SCR 

costs used throughout the remainder of this report are 

different from those calculated by Sargent & Lundy and 

NPS and used in their cost/bene¿t ratios.) 

Using this range of estimated annualized costs, a range 

of cost/bene¿t ratios can be calculated as shown in Table 

5-7. These data are based on the modeled visibility (dv) 

improvements listed in Table 5-5 of this section, the 

annualized costs estimated by SRP as cited in the EPA’s 

ANPR, and the NPS-estimated annualized costs as cited in 

the EPA’s ANPR. Note that SRP updated its cost estimate 

for an SCR retro¿t in 2010 and submitted it to EPA, but the 

earlier SRP cost is used here to provide a more consistent 

measure of how the updated CALPUFF 9ersion 6.4 model 

(SRP 2011) affected the cost/bene¿t metric, expressed in 

million dollars per year per deciview (M$/yr/dv). 

Given that the SRP and EPA/NPS estimates of capital 

costs and operating costs are relatively close, the 

differences between the SRP-based $/yr/dv values and 

the EPA-based $/yr/dv values are largely a function of 

the different modeling results. SRP’s 2011 cost/bene¿t 

ratios are large, even when compared to those calculated 

for other facilities. However, these ratios were calculated 

using a signi¿cantly different modeling procedure 

(CALPUFF 6.4 and different ammonia inputs) than that 

used by many other states and EPA. This difference in 

methodology is crucial factor when comparing the cost/

bene¿t values derived with CALPUFF 6.4 and CALPUFF 

5.8. EPA is reviewing CALPUFF 6.4 but has not endorsed 

its use as a regulatory standard. CALPUFF 5.8 is 

currently EPA’s accepted model, despite inconsistencies 

between its predicted visibility improvements and actual 

measurements (discussed previously in this chapter).

Arizona’s Regional Haze State ,mplementation Plan (S,P), 

submitted to EPA in 2011, examines the cost/bene¿t of 
90 NREL/TP-6A20-53024

,nstallation of SCR technology on Navajo GS would 

result in a calculated cost/bene¿t ratio larger than those 

calculated for BART controls proposed for other units 

in the region. ,t remains to be seen whether EPA will 

approve the more modest levels of NOx

 control proposed 

by the states on Reid Gardner and Apache GS. However, 

even if EPA determines that these other facilities should 

install SCR, the cost/bene¿t values for Navajo GS based 

on EPA modeling/analysis for Navajo would be higher 

than for SCR installation on the other facilities. 

5.7 Summary of Key Points

Following are some of the key points regarding visibility 

science with respect to Navajo GS impacts and the 

prospective visibility emission control costs to bene¿t 

comparison.

Ŷ SO2

 emissions in the Southwestern United States 

as a whole have dropped by more than a factor of 

two in the past decade, due in part to SO2

 scrubber 

retro¿ts and shutdowns at coal-¿red power plants, 

Table 5-7. Navajo GS Cost/Benefit Analysis Ranges for SCR Based on SRP and EPA/NPS Analyses

Annualized Cost (millions)=>

Navajo GS Plant: SCR Cost/Benefit over 

LNB/SOFA (M$/yr/dv)

71.7 67.6 71.7

Class 1 Area SRP 2007 EPA 2009 SRP 2011a

Arches 138 57 312

Bryce Canyon 205 50 478

Canyonlands 118 39 239

Capitol Reef 171 33 126

Grand Canyon NA 36 7170

Mazatzal 797 188 NA

Mesa Verde 156 83 896

Petrified Forest 189 77 1024

Pine Mountain 598 211 NA

Sycamore Canyon 247 98 1793

Zion 194 42 NA

(a) Uses same cost basis as the SRP 2007 column, but recalculates the cost/bene¿t metric based on SRP’s 2011 visibility 

impact modeling results using the CALPUFF 9ersion 6.4 model.

but primarily due to fuel sulfur reductions for 

transportation fuels. This appears to be correlated 

with observed drops in sulfate concentrations and 

improved visibility at Class , areas in the region. 

However, the measured sulfate reductions in the 

Class , areas are much smaller than the percentage 

SO2

 emissions decreases from the region as a 

whole.

Ŷ While NOx

 emissions in the Southwest as of 2008 

were nearly an order of magnitude higher than 

SO2

 emissions, sulfate particles were still three 

to ¿ve or more times (depending on monitoring 

site and time of year) as large a factor as nitrate 

particles in calculated visibility impacts, based on 

annual averages of ,MPRO9E measurements. ,t 

appears that under most conditions, sulfate is the 

preferred mate for any free ammonia, whether in 

the background atmosphere or in emission source 

plumes. Even under cold weather conditions 

in this region, sulfate is usually dominant over 

nitrate, although the sulfate-to-nitrate ratio is 

smaller in the cold months.
NREL/TP-6A20-53024 91

Table 5-8. Visibility Cost/Benefit Comparisons

Facility & Unit(s) NOx

Control

Modeled 

NOx

Emission 

Rate (lb/

MMBtu)

Cost/

Benefit 

(M$/yr/

dv) a

Proposed 

as BART

Prospective 

NOx

 Limit 

(lb/MMBtu)

Reid Gardner #1 ROFA w/

Rotamix 0.16 2.45 by EPA 0.20

Reid Gardner #2 ROFA w/

Rotamix 0.16 2.38 by EPA 0.20

Reid Gardner #3 ROFA w/

Rotamix 0.20 2.68 by EPA 0.28

Reid Gardner #1-3 Avg. ROFA w/

Rotamix 0.23

Reid Gardner #1 LNB/OFA + 

SCR 0.07 7.73 No NA

Reid Gardner #2 LNB/OFA + 

SCR 0.07 7.44 No NA

Reid Gardner #3 LNB/OFA + 

SCR 0.07 8.29 No NA

Apache Gen. Station #2 LNB/OFA 0.31 2.00 by ADEQ 0.31

Apache Gen. Station #3 LNB/OFA 0.31 2.59 by ADEQ 0.31

Apache Gen. Station #2 LNB/OFA + 

SCR 0.07 9.03 No NA

Apache Gen. Station #3 LNB/OFA + 

SCR 0.07 9.58 No NA

Navajo Gen. Station (all 

units) LNB/OFA 0.24 1.16 ? ?

Navajo Gen. Station (all 

units)

LNB/OFA + 

SCR 0.08 33.00 ? ?

(a) Based on the maximum 98th percentile deciview impact in a Class , area.
92 NREL/TP-6A20-53024

Ŷ Measurements speci¿c to this region indicate that 

actual visibility impacts may not be as great as 

those estimated by CALPUFF 5.8 as applied by 

EPA. The data and other studies summarized here 

are inconsistent and inconclusive as to whether 

current levels of NOx

 emissions from Navajo GS 

(especially with recent LNB/SOFA in operation) 

by themselves impact visibility. Therefore, 

the overall effect of removing approximately 

two-thirds of the current NOx

 emissions by 

installing SCR in addition to LNB/SOFA remains 

uncertain, based on the current state of modeling 

atmospheric chemical processes. ,nstalling 

SCR controls might not create any perceptible 

improvement in visibility not installing them 

might postpone addressing a contributing element 

to regional haze

Ŷ The largest source of differences in visibility 

impact modeling performed by SRP and EPA 

is the background ammonia concentration, 

especially in the critical winter period when 

nitrates tend to be a more signi¿cant factor 

in visibility impairment. SRP used winter 

background ammonia concentrations that were 

several times lower than used in EPA’s modeling. 

The SRP winter values correspond with data from 

rural monitoring sites at Mesa 9erde (considered 

a Four Corners area regional background site) in 

southwest Colorado, Halls Crossing in southern 

Utah, and Navajo Lake in northwest New Mexico. 

EPA’s ammonia background values correspond 

more closely with data collected in more urban or 

agriculturally developed areas near Farmington 

that are impacted by local ammonia sources. 

,f the model input ammonia values are too 

high compared to actual background ammonia 

concentrations that are mixed into the power plant 

plumes as they travel downwind of a source, the 

modeling process can signi¿cantly overestimate 

nitrate particle formation, thus overestimating 

visibility impact of the plumes. 

Ŷ Navajo GS emissions have recently dropped by 

more than 40%, and region-wide NOx

 emissions 

are on a signi¿cant downward trend that should 

continue for several years (due especially to 

mobile source engine emissions standards). 

,t would therefore be prudent, whether or not 

Navajo GS is ¿tted with SCR during the current 

round of NOx

 reductions, to take a similar look 

at regional ,MPRO9E monitor results in a few 

years. NOx

 and SO2 compete for ammonia, so 

observing actual improvements as both continue 

to decline signi¿cantly in the region should help 

to understand whether further controlling NOx

emissions from Navajo GS or other sources 

are likely to provide any signi¿cant visibility 

improvement. 
NREL/TP-6A20-53024 93

This chapter examines how the Navajo GS, the Peabody 

Western Kayenta coal mine, and the Central Arizona 

Project (CAP) impact Arizona’s ,ndian tribes, their people, 

and homelands. The power plant is on Navajo land, while 

the coal mine is on land within the boundaries of both the 

Navajo and Hopi ,ndian Reservations. The CAP, which 

depends on electricity from the Navajo plant to operate its 

water distribution infrastructure, delivers water to nine 

tribes in Arizona.

The EPA’s ¿nal BART determination will have diverse 

impacts on Arizona’s tribes. 1

This chapter separately 

examines two categories of effects: those related to power 

generation, and those affecting the cost of delivering the 

water that tribes depend on for domestic and agricultural 

use. For the Hopi Tribe and Navajo Nation in northeast 

Arizona, a power plant shutdown would impact areas 

such as local employment, tribal revenues, and public 

health. For the tribes that receive CAP water, any change 

to the status quo is likely to increase costs for CAP water 

rates. While changes to water rates are addressed fully in 

Chapter 4, this chapter will describe more fully the tribes’ 

use of the CAP water.

6.1 Tribes and Power Generation

Early plant retirement is the only BART scenario that 

would seriously harm the economies of the Navajo 

Nation and the Hopi Tribe, the two tribes engaged in 

various aspects of coal mining and power production. 

As discussed in the previous chapters, Navajo GS would 

continue to run at nearly the same level of production if 

SCRs or any other control technology were installed. The 

plant’s capital costs would be higher, but its production 

costs would increase by a modest 3% to 4%. The plant 

would still have lower operating costs than most other 

generators in the Desert Southwest, and would require 

the same amount of coal and at least the same number of 

employees to run.

Also recall from Chapters 2 and 3 that the likely power 

1 EPA’s policies for framing the considerations of decisions that could 

affect ,ndian tribes were set forth in 1984 and re-af¿rmed in 2009. “EPA 

Policy for the Administration of Environmental Programs on ,ndian 

Reservations,” available at http://www.epa.gov/tribalportal/pdf/indianpolicy-84.pdf (last visited on December 27, 2011).

replacement costs resulting from shutdown are likely to be 

higher than the capital cost and additional production cost 

of adding emission controls.2

 Those analyses suggest that 

the basic economics (apart from uncertainties discussed 

elsewhere in this report) would not favor retirement. Even 

with baghouses added to the plausible cost range of SCRs, 

the additional cost would still in all likelihood be less than 

the cost of replacing Navajo GS with spare capacity on 

existing generators elsewhere in the region. 

The tribes have already experienced plant and mine 

closures. The Mohave Generating Station in southeastern 

Nevada closed at the end of 2005, due largely to the cost 

of retro¿tting the power plant with SO2 scrubbers. At 

that time, all the coal for Mohave came from the Black 

Mesa Mine, one of two mines at the Black Mesa Mining 

Complex. The company used water from the Navajo 

Aquifer (N Aquifer) to slurry the coal to the power plant in 

Laughlin, Nevada, some 273 miles away. When Mohave 

closed, nearly a third of the Hopi’s operating budget—then 

$21.5 million—was eliminated.

The 2005-2006 Navajo Nation strategic plan anticipated 

that the loss of mining jobs caused by the closure of the 

Mohave Power Plant would have a severe impact on the 

regional economy, including less revenue for the tribal 

government and the services it provided. The plan noted 

that levying a tribal income tax and developing gaming 

revenues were both being considered to replace the lost 

revenues. Since that time, the Navajo Nation has opened 

two tribal casinos in New Mexico and has broken ground 

on a third one that will be outside Flagstaff, Arizona.

6.1.1 Employment and Economic 

Conditions

Nearly 1,000 people are employed at Navajo GS and the 

Kayenta coal mine with the majority being American 

,ndians (450 at the power plant and 400 at the mine). Wages 

and bene¿ts for all Native employees are $52 million at the 

plant and $46.8 million at the Kayenta Mine.3

2 Recall that these analyses hold all other factors constant, and do not factor 

in uncertainties due to investment recovery timelines, changes in future 

plant ownership, renegotiating the site lease with Navajo Nation, and 

changes in transmission path ratings.

3 ,nformation supplied by Salt River Project and Peabody Energy. The 

companies do not collect information about the particular tribal af¿liations 

of any individual employee.

6 Impacts on American Indian Tribes in Arizona
94 NREL/TP-6A20-53024

^_

^_

!(

!(

!(

!(

!(

!(

!(

!(

!(

!(

!(

!(

!(!(

0 100 50 Kilometers

Navajo Generating Station Tribe Map

This map was produced by the National

Renewable Energy Laboratory for the

Department of Energy.

November 2011

Arizona

Utah

Nevada

Mexico

Hopi

Tribe

Tohono O'odham

Nation

White Mountain Apache

Indian Tribe

Phoenix

Kayenta

Coal Mine

Gila River

Indian Community

Navajo

Generating

Station

Navajo

Nation

California

San Carlos

Apache Tribe

Tucson

Grand Canyon

National Park

Tribe Land

Metro Area

Central Arizona Project Canal

!( Pumping Station

(size indicates relative

annual energy use)

Ak-Chin

Indian Community

Ft. McDowell

Yavapai Nation

Pascua Yaqui

Tribe

Salt River

Pima-Maricopa

Indian Community

Tohono O'odham

Nation

Navajo

Nation

Tohono O'odham

Nation

Tonto Apache

Tribe

Yavapai-Apache Tribe

Yavapai-Prescott (Camp Verde)

Indian Tribe

Figure 6-1. Navajo generating station tribe map
NREL/TP-6A20-53024 95

Table 6-1. Poverty Rates on Navajo and Hopi Reservations, 2005-2009a

Poverty Rate,

All People

Poverty Rate, Under 

18

Average Annual 

Income

Navajo Reservation 37.4% 44.1% $35,926

Hopi Reservation 34.9% 44.0% $38,062

Arizona 14.7% 20.8% $67,331

(a) U.S. Census, 2005-2009 American Community Survey. 

http://www.census.gov/acs/www/data_documentation/2009_5yr_data/

The power plant’s 450 full-time Native American 

preference employees represent 83% of its workforce, and 

include both hourly and salaried positions. Eighty-three 

of the Navajo-preference positions are in management or 

professional roles. The average hourly wage at the plant, 

around $35.00 per hour4

, is twice Coconino County’s 

average wage.5

The Kayenta Mine, which is operated by Peabody Western 

Coal Company (PWCC), employs 400 Native Americans 

among its total workforce of 425. Native Americans 

make up 79% of the managers, supervisors, and of¿cials. 

Annual wages and bene¿ts are around $46.8 million, or 

about $117,000 per employee on average. 

Although the wages and bene¿ts from the mine are high, 

2000 Census data show that only 0.7% of the Hopi tribal 

members are employed in the mining industry. The 

numbers are slightly higher for the Navajo Nation—2.7%. 

However, these ¿gures are much higher in some areas 

directly surrounding the mine area, such as in the Navajo 

Nation’s Chilchinbito, Dennehotso, Shonto, and ,nscription 

House areas, ranging from 11.7% to 18.4%.6

Both the Navajo Nation and the Hopi Tribe have 

communities living in extreme poverty. The U.S. Census 

Bureau’s American Community Data show that 37% 

of the Navajo Nation’s population lives in poverty. The 

statistics are similar for the Hopi Tribe. ,n the years 2005-

2009, 35% of Hopi people were in poverty. Within both 

tribes, 54% of related children under 18 lived below the 

poverty level. The proportion of the population living 

4 Hourly wage interpolated from Table D-12, Of¿ce of Surface Mining, 

“Kayenta Mine Permit Renewal Environmental Assessment.” August 2011.

5 Bureau of Labor Statistics, “Quarterly Census of Employment and Wages.” 

2010 data. http://www.bls.gov/cew. Last visited November 18, 2011.

6 U.S. Census Bureau 2000 (SF3, QT-P24 and SF3, QT –P30). The 2010 

Census data is not yet available at this level of analysis.

below the poverty level in both tribes is more than twice 

that of Arizona as a whole, while the average annual 

income on the reservations was nearly half that of the state 

population. 

Census data indicate that both tribal populations have 

high dependency ratios, in that the proportion of the 

non-working population to the working population is 

higher than for the rest of the State of Arizona.7

 This trend 

generally indicates more people relying on wages as well 

as on government and community support services. ,n 

interviews, Peabody of¿cials said that each mining job 

typically supports large and extended families.

6.1.2 Leases, royalties, and other payments

The royalties and bonus payments from the Kayenta 

Mine consistently provide one of the largest sources of 

revenue for both the Hopi Tribe and Navajo Nation. Table 

6-2 summarizes some of the bene¿ts paid to the tribes. 

According to a recent strategic development plan for 

the Navajo Nation, mining-related revenues—including 

the Kayenta Mine and other mining activity on the 

reservation—have provided more than 55% of the tribe’s 

operating expenses in recent years.8

 The Hopi have said 

that more than 80% of their 2009 budget was funded by 

mining revenue.9

7 The dependency ratio is calculated by dividing the non-working population 

(0-14 years and over 65 years) by the working population and multiplying 

by 100. 

8 Navajo Nation Division of Economic Development.“2009-2010 Economic 

Development Strategy.” Available at http://www.navajobusiness.com/pdf/

CEDS/CED_NN_Final_09_10.pdf. Last visited November 18, 2011.

9 Leroy Shingoitewa, Testimony to U.S. House of Representatives, 

Water and Power Subcommittee and ,ndian and Alaska Native Affairs 

Subcommittee, -oint Oversight Hearing on “Protecting Long Term Tribal 

Energy -obs and Keeping Arizona Water and Power Costs Affordable: 

The Current and Future Role of the Navajo Generating Station, May 

24, 2011. Available at http://naturalresources.house.gov/UploadedFiles/

ShingoitewaTestimony05.24.11.pdf. Last visited November 18, 2011.
96 NREL/TP-6A20-53024

Overall, PWCC pays about $50 million/year to the two 

tribes, and since 1987 has paid a total of nearly $1.3 billion 

to the tribes. ,n 2010, the total tribal payments for coal 

royalties were $34.4 million and the coal bonuses for 

the two tribes totaled $5 million. Bonuses are ¿xed and 

currently triggered and paid when the ¿rst ton is mined 

for the given year. Royalties are based on the volume of 

production. Table 6-3 and Table 6-4 show how the sums 

have been allocated to each tribe based on their interest in 

the mining operations.

Peabody has a lease from the tribes to use water from 

the N Aquifer, paying $943.48 an acre-foot for its use. 

The total payment for the mine’s 2010 water usage—

approximately $1.1 million—was split equally between 

the two tribes. The amount of revenue from water sales 

Table 6-2. Tribal Benefits Paid by PWCC ($ Millions) a

Annual Average 

Payments Total Payments (1987-2010)

Coal Royalties $34.7 $988.10

Coal Bonuses b $6.4 $64.2

Water Fees $3.2 $73.0

NTUA Revenue c $6.3 $151.5

Total $50.6 $1,276.80

(a) Of¿ce of Surface Mining. “Kayenta Mine Permit (A=-0001D) Renewal Environmental Assessment.” August 2011. 

Available at http://www.wrcc.osmre.gov/Current_,nitiatives/Kayenta_Mine/Renewal.shtm. Last visited November 16, 2011. 

Appendix F Charts F-7, F-8, and F-10.

(b) Peabody began paying coal bonuses in 1998. Total includes a $24 million bonus in 2006 after lease extension

(c) The Navajo Tribal Utility Authority is a business enterprise of the Navajo Nation. Total payments include 2010 estimated 

payment of $9.9 million

Table 6-4. Navajo Nation Revenue from Kayenta Mine Operations ($ Millions) a

Annual Average Total Payments (1987-2010)

Coal Royalties $24.4 $562.1

Coal Bonus Payments $4.5 $19.6

Water Fees $1.6 $36.5

NTUA Revenue $6.7 $153.8

Total $37.2 $772.0

(a) This table represents the Navajo Nation’s share of the totals from Table 6-2.

Table 6-3. Hopi Tribal Revenue from Kayenta Mine Operations ($ Millions) a

Annual Average Total Payments (1987-2010)

Coal Royalties $10.2 $235.3

Coal Bonus Payments $2.2 $19.6

Water Fees $1.6 $36.5

Total $14.0 $291.40

(a) This table represents the Hopi Tribe’s share of the totals from Table 6-2.
NREL/TP-6A20-53024 97

has decreased signi¿cantly, nearly 75%, since the closing 

of the Black Mesa Mining operation in 2005 and the 

subsequent termination of coal slurry operations. 

The Kayenta Mine also pays the Navajo Tribal Utility 

Authority (NTUA) for electricity use at the mine and 

related operations. These payments average about $6.3 

million a year, although payments have shown a steady 

increase. ,n 2010, Peabody estimates it paid NTUA $9.9 

million. On average, Peabody’s payments make up 

approximately 15% of the NTUA’s revenue from electricity 

sales and around 10% of its overall revenue.10

The mine also pays state property taxes, providing a major 

source of revenue for Navajo County and the Kayenta 

Uni¿ed School District. Property tax revenues in 2010 

were about $1.6 million, $1.2 million of which went to the 

school district. 

From 1988 through 2010, the Hopi Tribe received a total 

of $3,876,000 in scholarship funds through the coal lease 

agreements. The annual amount in 2010 was $173,000 with 

the amount set to escalate each year. For that same time 

period, the Navajo have received a total of $4,422,000 in 

scholarship funds through the coal lease agreements. Both 

Peabody and the power plant fund these scholarships.

Peabody of¿cials say the company provides other 

local area bene¿ts such as resident land use payments

assistance with grazing management programs and 

education road maintenance and improvements water 

supply assistance free public coal to area residents an 

annual health fair, a 24-hour emergency health care 

facility and ambulance service and emergency assistance 

with roads, coal, and water. 

6.1.3 Public health concerns 

Several stakeholders and individuals expressed concerns 

over how the mine and the power plant affect public 

health. The lack of epidemiological studies speci¿c to the 

population living on the Hopi and Navajo Reservations 

means that conclusions about public health impacts near 

the Navajo Plant and Kayenta Mine must instead be drawn 

from personal experiences and more general studies. 

10 Of¿ce of Surface Mining. “Kayenta Mine Permit (A=-0001D) Renewal 

Environmental Assessment.” August 2011. Available at http://www.wrcc.

osmre.gov/Current_,nitiatives/Kayenta_Mine/Renewal.shtm. Last visited 

November 16, 2011. Appendix F-10.

The following is a compilation and description of the 

information available. 

Although the scope of the current EPA proceeding is 

visibility, Navajo GS owners are analyzing the economic 

impacts of visibility, toxics, and other potential regulations 

as an aggregation of risk (see Chapter 1). The business 

decisions resulting from all these regulatory outcomes will 

have some impact on the health of tribal populations living 

near Navajo GS or the mine.

Power plant emissions have long been a key priority for 

EPA monitoring, regulation, and enforcement, because of 

their potentially serious public health effects.11 Uncontrolled 

releases of mercury from power plants damage children’s 

developing brains, affecting memory, attention, language, 

and ¿ne motor and visual spatial skills. Mercury and other 

toxics also pollute lakes, streams, and ¿sh. Other metals 

such as arsenic, chromium, and nickel can cause cancer.

On March 16, 2011, EPA proposed mercury and air 

toxics standards, applicable to new and existing power 

plants using coal and fuel oil. The standards aim to 

reduce emissions of metals, including mercury, arsenic, 

chromium, and nickel acid gases, including hydrogen 

chloride and hydrogen Àuoride and particulate matter. 

EPA published its ¿nal rule in December 2011. For 

coal-¿red units, such as the Navajo plant, the proposed 

standards would establish numerical limits for mercury, 

acid gases, and particulate matter.

A related concern raised by non-governmental 

organizations (NGOs) with regard to the Navajo plant is 

the disposal of coal combustion residuals (CCRs) such 

as coal ash. The Sierra Club, for example, cited studies 

that concluded waste from coal plants carries into the 

environment 100 times more radiation than a nuclear 

power plant producing the same amount of energy.12

,n -une 2010, the EPA proposed a draft rule on disposing 

of CCRs. The EPA noted that the environmental concerns 

over coal ash pertain to “pollution from impoundment 

11 Environmental Protection Agency. “Mercury and Air Toxics Standards 

(MATS).” http://www.epa.gov/airquality/powerplanttoxics/. Last visited 

November 18, 2011.

12 Hvistendahl, Mara. “Coal Ash is More Radioactive than Nuclear 

Waste.” Scienti¿c American, Dec. 17, 2007. Available at: http://www.

scienti¿camerican.com/article.cfm"id coal-ash-is-more-radioactive-thannuclear-waste. Last visited November 16, 2011.
98 NREL/TP-6A20-53024

and land¿lls leaching into ground water and structural 

failures of impoundments.”13 The proposed rule does not 

address the recycling of coal ash into building materials, 

such as concrete used in commercial and infrastructure 

applications. ,n the proposed rule, the EPA stated “there is 

wide acceptance of the use of CCRs in encapsulated uses, 

such as wallboard, concrete, and bricks because the CCRs 

are bound into products. The Agency believes that such 

bene¿cial uses of CCRs offer signi¿cant environmental 

bene¿ts.” 14

On the Navajo Reservation, coal ash is recycled into 

concrete to pave streets and is used in construction of 

facilities in the form of FlexCrete.15 The Navajo Housing 

Authority has used the FlexCrete bricks to build homes on 

the Navajo reservation.16 The Navajo FlexCrete plant is 3 

miles from the power plant, and the company estimates 

that approximately 21 tons of coal ash is recycled into 

every house built with their product. 17

6.1.4 Groundwater Issues

Several NGOs who met with NREL expressed concern 

about the mine and the power plant contaminating 

groundwater, depleting natural springs, and the impacts 

of coal ash and the mercury and particulates it contains 

impacting the health of residents on both the Navajo and 

Hopi reservations. Navajo Nation of¿cials, on the other 

hand, cite a USGS study commissioned by the Of¿ce of 

Surface Mining (OSM) that refuted concerns that the 

mining operations are pumping water from the N Aquifer 

to the detriment of the land or natural springs. 

OSM recently released a draft Environmental Assessment 

(EA) and Finding of No Signi¿cant ,mpact for the 5-year 

13 Environmental Protection Agency. “Coal Combustion Residuals - Proposed 

Rule.” http://www.epa.gov/wastes/nonhaz/industrial/special/fossil/ccr-rule/

index.htm. Last visited November 16, 2011.

14 Environmental Policy Agency. “Hazardous and Solid Waste Management 

System ,denti¿cation and Listing of Special Wastes Disposal of Coal 

Combustion Residuals From Electric Utilities Proposed Rule.” 75 Fed. Reg. 

35128, 35154 (-une 21, 2010).

15 See http://www.navajoÀexcrete.biz/

16 Thompson, -onathan. “Ashes to Houses.” High Country News. November 

20, 2007. Available at: http://www.hcn.org/articles/17384. Last visited 

November 16, 2011.

17 Navajo FlexCrete Building Systems, ,nc. Promotional presentation. 

Available at http://www.navajoÀexcrete.biz/presentations. Last visited 

November 16, 2011.

renewal of the Kayenta Mine.18 A signi¿cant portion 

of this document addressed ground and surface water 

impacts. However, multiple NGOs provided public 

comments on the EA that question these assessments and 

the OSM’s ¿nding for the mine permit renewal.19

Black Mesa Water Coalition, Diné C.A.R.E., To Nizhoni 

Ani, Center for Biological Diversity, and Sierra Club 

argue the EA does not properly analyze depletion to the 

N Aquifer or the diminution in water quality to water 

impoundments at the mine. An updated comment to 

the EA provides a third-party analysis critical of the 

hydrological studies that support the EA’s FONS,.

20 OSM 

collected public comments on the EA through November 

3, 2011. They have not issued a Record of Decision 

regarding the permit renewal.

6.1.5 Hopi Tribe

The Hopi Tribe is located 250 miles northeast of Phoenix. 

Most of the tribe’s area is completely surrounded by 

the Navajo Nation reservation. Hopi ,ndian trust lands 

include the Moenkopi District reservation near Tuba City, 

and its Ranch Lands area between Flagstaff, Winslow and 

Holbrook. There are approximately 7,000 Hopi people 

living on the 1.5–million-acre reservation, far fewer than 

the Navajo population. The terrain is high desert, dotted 

with pinion, juniper, and sagebrush. 

The Hopi Tribe is party to joint mining leases along with 

the Navajo Nation for some of the coal in the Black Mesa 

Mine Complex. The Hopi receive about $13 million 

annually from the Kayenta Mine operations in coal 

royalties and bonus payments. However, the Hopi Tribe 

does not receive any revenues from the operations of the 

Navajo plant. The revenues contribute to supporting its 

government functions, directly impacting nearly every 

aspect of Hopi life, including the education of Hopi young 

people health and social service programs governmental 

18 Of¿ce of Surface Mining. “Kayenta Mine Permit (A=-0001D) Renewal 

Environmental Assessment.” August 2011. Available at http://www.wrcc.

osmre.gov/Current_,nitiatives/Kayenta_Mine/Renewal.shtm. Last visited 

November 16, 2011.

19 Letter from Brad A. Bartlett, Energy Minerals Law Center to Richard 

Holbrook, Of¿ce of Surface Mining, -une 4, 2010. Available at: www.nrel.

gov/ngs.

20 Daniel Higgins, “Comments on Peabody Western Coal Company’s Permit 

Renewable for the Kayenta Coal Mine: Review of 2008 Cumulative 

Hydrologic ,mpact Assessment, 2010 Probable Hydrologic Consequences, 

2011 Environmental Assessment, and Peabody Groundwater Model.” 

October 2011. Not peer reviewed. Available at: www.nrel.gov/ngs.
NREL/TP-6A20-53024 99

infrastructure and many other essential tribal programs.21

Hopi leaders initially were concerned that closing the 

Navajo plant would have severe and immediate economic 

impacts on the tribe, including increasing unemployment, 

severe curtailment of social programs, slowing of capital 

advancements, weakened tribal government infrastructure 

programs, and other indirect economic losses.22 More 

recently, however, the leadership changed to a position 

of neutrality based on information that the future of 

the Lower Colorado River adjudication settlement—a 

water rights lawsuit that the Hopi have participated in for 

more than 10 years—is directly related to the continued 

operability of the Navajo plant. ,n a -uly 25, 2011, letter 

to U.S. Secretary of ,nterior Ken Salazar, Hopi Chairman 

Leroy Shingoitewa said the tribe intends to remain 

neutral on the power plant issue until they are able to 

understand the relationship between the plant and the river 

adjudication.23

21 Chairman Shingoitewa, personal communication.

22 Hopi Chairman Leroy Shingoitewa testi¿ed to Congress on May 24, 

2011,that “...implementation of the BART decision would undermine the 

Hopi Tribe’s ability to maintain its homeland.” Testimony to U.S. House of 

Representatives’ Water and Power Subcommittee and ,ndian and Alaska 

Native Affairs Subcommittee, -oint Oversight Hearing on “Protecting Long 

Term Tribal Energy -obs and keeping Arizona Water and Power Costs 

Affordable: The Current and Future Role of the Navajo Generating Station, 

May 24, 2011.

23 Letter from Chairman Leroy Shingoitewa to Secretary Ken Salazar. -uly 

25, 2011. Available at www.nrel.gov/ngs.

$100.0

$80.0

$60.0

$40.0

$20.0

$0.0

$140.0

$120.0

2002 2003 2004 2005

Kayenta Mine Revenues

General Fund Budget

$126.6

$126.6

$117.2

$117.2

$121.0

$121.0

$124.0

$124.0

$30.0

$30.0

$29.3

$29.3

$30.5

$30.5

$34.2

$34.2

Figure 6-2. Navajo Nation, Kayenta Mine revenues and general fund budget 2002-

2005 ($ millions)

The remoteness of the reservation 

creates many challenges and 

limits opportunities for economic 

development. A total of 26% of the 

employed workforce is in the public 

administration sector, heightening 

the potential impact of a signi¿cant 

decrease in the revenues from the 

mine. ,n terms of other energy 

development, the Hopi Tribe is one 

of the few tribes with an established 

and dedicated Renewable Energy 

Of¿ce, and NREL resource 

assessments show large amounts of 

high-quality solar resource areas 

across the Hopi Reservation.24

NGOs, such as the Black Mesa 

Water Coalition, have issued reports 

on the potential for renewable energy development on 

Hopi lands, including the Black Mesa Mining complex.25

6.1.6 Navajo Nation

The Navajo Nation is located 260 miles northeast of 

Phoenix. ,t is the largest tribal nation in the United 

States, both in population and landmass. The population 

is approximately 300,000. The reservation covers more 

than 27,000 square miles in 13 counties of Arizona, New 

Mexico, and Utah. 

Historically, mining has been an important stream of 

income for the Navajo Nation. Navajo Nation President 

Ben Shelly said that the power plant is, therefore, “an 

essential component of the Navajo Nation’s economy 

and our energy portfolio, and must remain viable, for the 

sake of the Nation and our People, for years to come.”26

As Figure 6-2 demonstrates, historically, a signi¿cant 

portion of the Navajo Nation’s annual budget comes from 

revenues related to the Kayenta Mine.27 ,ncluding other 

mining operations, such as the now-closed Black Mesa 

24 National Renewable Energy Laboratory. “Solar Prospector.” http://maps.

nrel.gov/prospector

25 Black Mesa Water Coalition. “Solar Potential on Black Mesa.” February 

2011. Available at: www.nrel.gov/ngs.

26 Navajo Nation Division of Economic Development.“2009-2010 Economic 

Development Strategy.” Available at http://www.navajobusiness.com/pdf/

CEDS/CED_NN_Final_09_10.pdf. Last visited November 18, 2011.

27 Navajo Nation 2005–2006 Comprehensive Economic Development 

Strategy of the Navajo Nation, page 13 (total Budget amounts) Kayenta 

Mine Renewal EA, Appendix F (Kayenta Mine Revenues).
100 NREL/TP-6A20-53024

and Pittsburgh & Midway mines, the Navajo Nation has 

recently depended on mining revenues for upwards of 50% 

of its annual budget.

The Navajo Nation receives an average of $37.2 million 

per year from PWCC from the Kayenta mine, and total 

payments since 1987 have been $772 million. Because 

the power plant is on reservation lands, the Navajo Nation 

receives additional leasing income. ,n 2009, the Navajo 

Nation received site lease payments from the power plant 

site in the amount of $600,000, and air permit fees in the 

amount of $400,000.28 Negotiations for a new site lease 

are currently taking place the current lease is set to expire 

in 2019. Currently, the rights-of-way used by the railway 

to deliver coal to the plant are not assessed any fees, and 

such fees will be part of the new lease when it is ¿nalized, 

according to Navajo of¿cials.

NTUA, an enterprise of the Navajo Nation, provides 

electricity, natural gas, water, wastewater treatment, and 

solar energy to residents and businesses of the Navajo 

Nation, and provides service to limited areas of the Hopi 

Reservation. The NTUA purchases electrical power from 

sources off the reservation and distributes it to homes 

across northeastern Arizona, northwestern New Mexico, 

and southeastern Utah. The Kayenta Mine is a major user 

of power provided by NTUA, with the value of power 

purchases amounting to just under $10 million in 2010. 

Two 69-kilovolt (k9) feeder lines serve the mines. Under 

an agreement with NTUA, Peabody operates the substation 

that serves the mine. Arizona Public Service provides 

electrical service to other parts of the Hopi Reservation.

Neither the tribe’s strategic development plan nor any 

other document reviewed for this study contained an 

economic transition plan for when the Navajo power 

plant closes. Several efforts aim to promote economic 

diversi¿cation, but none are explicitly linked to a transition 

plan. ,n -uly of 2009, for example, the Navajo Nation 

Council passed legislation establishing a Navajo Green 

Economy Commission, a ¿ve-person commission that 

will seek funding to help foster a green economy for the 

Navajo Nation. However, funding for the commission was 

not included in this year’s Navajo Nation appropriations. 

28 Comments of the Central Arizona Water Conservation District on 

the Environmental Protection Agency’s Advanced Notice of Proposed 

Rulemaking Regarding Best Available Retro¿t Technology for Nitrogen 

Oxide Emissions at the Navajo Generating Station, Docket Number 

EPA-R09-OAR-2009-0598, Oct. 28, 2011. Table , – Bene¿ts to the Navajo 

Nation, page 5.

The commission is charged with overseeing the approval 

of small-scale green projects, such as wool mills, farmers 

markets, and home weatherization. The Council also voted 

to create a Navajo Green Economy Fund that creates an 

account for receiving federal, state, local, and private 

funds to make these green projects possible. 

The Navajo Nation is pursuing several renewable energy 

projects through the NTUA: 

Ŷ Boquillas Wind Project: SRP announced in -uly 

2011 that it had selected the NTUA and Edison 

Mission Energy to build and operate the 85-MW 

Boquillas wind project in Coconino County, Ariz. 

SRP anticipates purchasing 100% of the output 

from the wind project under a 25-year power 

purchase agreement.29

Ŷ Gray Mountain Wind Farm (Cameron, 

Arizona): Potential to produce up to 500 MW

likely the best wind site on the Navajo Nation. 

An independent power producer (,PP) is working 

with the local community and potential developers 

to realize this project. NTUA and the ,PP have 

secured the interconnection queue position to 

transmit power from this proposed wind farm. 

This project is in early pre-development stages.

Ŷ Black Mesa Wind Farm (Kayenta, Arizona): 

Potential to generate up to 60 MW preliminary 

wind data warrants a formal wind study at two 

sites on Black Mesa. NTUA is exploring the 

feasibility of development and the project is in the 

early pre-development stage. 

Ŷ NTUA Chevron Mine Solar Project (Window 

Rock, Arizona): This project will build out an 

existing 60-MW solar farm. NTUA is working on 

this development with Sun Carrier. 

Ŷ Paragon Ranch Solar Project (Paragon, New 

Mexico): This project has potential to build out 

to more than 200 MW. The Navajo-Hopi Land 

Commission is working with TetraTech on the 

feasibility studies. 

Ŷ Gray Mountain Solar Project (Cameron/Gray 

Mountain, Arizona): This project has potential to 

build out to 40 MW. 

29 SRP, news release, -uly 28, 2011.
NREL/TP-6A20-53024 101

Ŷ To’hajiilee Solar Farm (Tohajiilee, NM): 

Project developers entered into an agreement with 

SunPower and began negotiations on the power 

purchase agreement (PPA) and ¿nancing. 

Ŷ Iyanbito Solar Farm (Iyanbito, NM): Project 

developers are working with the community to 

establish a 20-MW solar farm. Project is early predevelopment stages.

Ŷ NTUA Chevron Biomass Facility (Window 

Rock, AZ): Project developers are looking to 

build a 20-MW biomass facility. NTUA has 

already purchased the lands and is working on a 

PPA.

The Navajo Nation is also involved in potential new 

fossil fuel plants that could be sited on its land. Two—a 

combined cycle natural gas plant augmented with 

concentrating solar power, and a generator powered 

by waste heat from a proposed coal gasi¿cation and 

liquefaction plant—are in early pre-development. The 

Desert Rock Energy Project, a 1,500-MW coal-¿red power 

plant that would be owned and operated by the Navajo 

Nation, initially gained the required EPA permits it needed 

during the Bush Administration. Those permits have since 

been rescinded and the project remains on the drawing 

board. 30

6.2 Tribes with CAP water allocations

Nine tribes (including three districts of the Tohono 

O’odham Nation) have CAP water contracts. Early federal 

acts include the Ak-Chin Settlement of 1984 and the 

Southern Arizona Water Rights Settlement Act of 1982 

(SAWRSA). More recently, the Arizona Water Settlement 

Act of 2004 (AWSA) settled claims for the Gila River 

,ndian Community (GR,C) and amended the SAWRSA 

to provide additional CAP water needed to implement the 

1984 agreement. 

The Navajo Nation and the Hopi Tribe—the two tribes 

most affected by operations at the power plant and the 

coal mine—are also in the midst of water rights settlement 

negotiations for the CAP and other water allocations to 

meet the needs of the tribes’ citizens. 

A signi¿cant increase in the cost of power from the power 

30 http://navajotimes.com/news/2010/0410/040810desertrock.php

plant can affect key provisions of these agreements to the 

detriment of the tribes. The consequences are magni¿ed 

by the fact that several of the settlements include language 

that waives the tribes’ claim to future water aside 

from those speci¿ed in the settlement. Many of these 

settlements anticipate a role for the Lower Colorado River 

Basin Development Fund in meeting the terms of the 

agreement.

The tribal water issues that stand to be affected by the 

BART rule can be traced back to U.S.-,ndian treaty law. 

The United States government established reservations 

for tribes throughout the country as permanent homelands 

where tribal populations could live undisturbed, in 

exchange for the lands they gave up. Over time, the courts 

established the doctrine of federally reserved water rights, 

known as the Winters Doctrine.31 The courts held that, 

along with the reservations of land, the tribes also required 

reservations of water to sustain the people and their lands

the Winters Doctrine holds that the treaties between the 

tribes and the United States implied corollary rights to 

such natural resources.32 This legal principle is also carried 

through for reservations created through executive order or 

by Congressional acts. These federally reserved water rights 

have been the subject of litigation, negotiations, and, in 

some cases, water rights settlements. 

Access to water was critical to the development of many 

non-,ndian communities in Arizona, which was the 

justi¿cation for developing CAP. As Chapter 4 explains 

in further detail, the Colorado River Basin Project Act 

(CRBPA) of 1968 established the Development Fund as 

part of the overall CAP plan to hold (among other monies) 

revenues from selling excess power from the federal 

government’s share of the Navajo plant, and payments 

made each year by CAWCD toward CAP debt obligations. 

The Hoover Power Plant Act of 1984 authorized applying 

revenues from excess power sales toward CAWCD’s CAP 

repayment obligations. The AWSA further amended the 

CRBPA in 2004. Under these most recent changes, revenues 

in excess of what is needed to fund CAP repayment is 

earmarked for offsetting the cost of delivering CAP water to 

tribes, for the construction and rehabilitation of distribution 

systems to deliver CAP water to tribes, and for payment for 

an ,ndian water rights settlement yet to be reached. 

The 2004 amendment established statutory priorities for 

31 Winters v. U. S., 207 U.S. 564, 28 S. Ct. 207 (1908).

32 207 U.S. at 577, 28 S. Ct. at 212.
102 NREL/TP-6A20-53024

the use of monies from the Development Fundbeyond 

those credited toward CAP repayment. These cascading 

priorities start with payments toward the tribes’ 

operations, maintenance and replacement (OM&R) 

charges for water delivery. Rehabilitating irrigation 

systems and building new water distribution systems are 

among the priorities. Once CAP repayment is completed 

in 2043, all Development Fund payments will go toward 

these and other designated statutory obligations. 

Less revenue Àowing into the Development Fund would 

mean less money available for improving tribal water 

infrastructure. Chapter 4 explains the Àow of money 

in and out of the Development Fund and how higher 

power costs from the Navajo GS might affect the amount 

of funds available. Tribal CAP projects previously 

funded from appropriations are now funded from the 

Development Fund, pursuant to the AWSA. Several of 

the tribes have started or have proposed infrastructure 

projects through the Development Fund.

A more direct potential impact is on tribal agriculture 

because of higher irrigation costs. Arizona’s arid 

climate allows little if any dry farming nearly all of 

the state’s harvested cropland is irrigated.33 Farm pro¿t 

margins are tight statewide only 22% of all farms in 

Arizona reported any net gain in 2007.34 Tribes with 

entitlements to CAP water receive assistance through 

the Development Fund for a portion of their irrigation 

delivery charges—the fund pays the tribes’ OM&R 

charges, leaving the tribes responsible only for the 

variable pumping charges.

The pumping charge, however, is where any increase in 

electricity cost would be recovered. ,n other words, if 

BART-related upgrades at the Navajo plant translated 

into higher electricity costs for running the CAP water 

pumps, CAWCD could recover the additional cost 

through the variable pumping charge assessed to all 

users, including the tribes.

GR,C is the largest CAP water customer. A study 

commissioned by the tribe concluded that future 

increases in CAP water costs—increases that would 

33 U.S. Department of Agriculture, “Census of Agriculture,” 2007. Data 

tables for Arizona show 832,406 acres of harvested cropland, of which 

823,468 acres were irrigated.

34 U.S. Department of Agriculture, “Census of Agriculture,” 2007.

occur without any BART-related changes at the Navajo 

plant—would continue to erode farm operating margins 

for the tribe. Assuming that the federal government’s 

share of capital costs would be recovered entirely 

through higher pumping charges, GR,C estimates that 

adding SCR technology at the Navajo plant would reduce 

the tribe’s net farm income by around 2% in 2015, and 

by 3.3% in 2020. The tribe’s study estimates that the 

additional cost of baghouses along with SCR would 

increase the impact on net farm income by a factor of 

two.35

6.2.1 Impacts on specific tribes

The foregoing discusses the potential impacts that would 

be common to all tribes using CAP water. Each tribe has 

particular needs and circumstances, however, so there 

would also be individual impacts that would affect water 

deliveries and infrastructure development, depending 

upon the terms of each tribal settlement. 

Ak-Chin Indian Community

The Ak-Chin Tribe has a CAP allocation of up to 85,000 

acre-feet (a.f.) per year if available.36 This includes 

a lease of up to 10,000 a.f. annually to Del Webb 

Corporation for a development north of Phoenix called 

Anthem.37 Whatever portion of water the Ak-Chin ,ndian 

Community doesn’t use is available for delivery to the 

San Carlos Apache Tribe to ful¿ll obligations made to 

them.

Ft. McDowell Yavapai Nation 

The tribe has an allocation of 18,233 a.f. and is currently 

leasing 4,300 a.f. of their allocation to the City of 

Phoenix. The tribe is currently entering into annual 

leases for all but 250 a.f. of the balance.38 Full cost of 

delivery for the leased water is paid by Phoenix. 

Gila River Indian Community

,n testimony to Congress, GR,C of¿cials described the 

importance of upholding the terms of the Community’s 

water settlement based on the trust obligations of the 

35 Harvey Economics, transmittal letter and exhibits of draft ¿ndings, 

November 16, 2011.

36 An acre-foot is the amount of water needed to ¿ll an acre with water 1 foot 

deep and is generally abbreviated as a.f. An acre-foot is typically the water 

needed to ful¿ll the needs of a ¿ve-member family for 1 year.

37 http://www.onlineatanthem.com/

38 U.S. Bureau of Reclamation, personal communication to NREL.
NREL/TP-6A20-53024 103

United States. The tribe has a vision of returning to a 

traditional lifestyle of farming that enhances the status 

of its culture, economy, and health, and is developing a 

2,400-mile irrigation canal system to deliver agricultural, 

municipal, industrial, riparian repair, and recreational 

water to the reservation. The Community says it believes 

that increased CAP water costs will put those community 

goals in jeopardy.39

The GR,C has a CAP allocation of 311,800 a.f., which 

represents about 23% of the total annual CAP supply. The 

Community is the largest CAP customer in Arizona.40

The GR,C is leasing a portion of its allocation, taking 

direct delivery of some of its water on the reservation 

and recharging groundwater at a water savings facility. 

The Arizona Water Settlement Act of 2004 provides for 

GR,C to lease or exchange any of its CAP water for offreservation use within 10 Arizona counties. Several lease 

agreements have been reached with cities in the Phoenix 

area totaling 41,000 a.f. Phelps Dodge has leased another 

12,000 a.f. with an option to lease another 10,000 a.f. in the 

future. The City of Chandler has an agreement to provide 

11,200 a.f. of reclaimed water to GR,C in exchange for 

8,970 a.f. of CAP water. Mesa will provide 29,400 a.f. 

of reclaimed water to GR,C in exchange for 23,530 CAP 

water. 

,n addition, the AWSA provides monies from the 

Development Fund to construct a GR,C water distribution 

system, as well as for rehabilitation of the San Carlos 

,rrigation Project. Full cost of the leased water is paid by 

lessees. 

GR,C currently pays for the variable energy costs of their 

CAP water, although the AWSA established a trust fund 

that the tribe can elect to use for this purpose. The tribe’s 

¿xed OM&R costs are paid by the Development Fund.

The tribes that constitute GR,C are historically farming 

tribes, currently irrigating 35,600 acres to grow a variety 

of crops, including alfalfa, vegetables, melons, small 

grains, and cotton. GR,C has plans to farm 77,000 

acres by 2030 and is planning a total investment of $645 

39 Manual testimony to Congress, May 24, 2011

40 Manuel, -oseph, Gila River ,ndian Community Lieutenant Governor 

testimony to U.S. House of Representatives Subcommittee on Water and 

Power and Subcommittee on ,ndian and Alaskan Native Affairs, -oint 

Subcommittee Oversight Hearing on “Protecting Long-Term Tribal Energy 

-obs and keeping Arizona Water and Power Costs Affordable: The Current 

and Future Role of the Navajo Generating Station, May 24, 2011

million dollars. Gross operating margins are currently 

about $113 an acre an analysis conducted for GR,C 

forecasts that the additional cost of SCRs will reduce 

margins by 3% in 2020, and by 8.5% in 2030.41

Cumulative employment losses could be 1,218 people, and 

it is estimated that total personal income loss would be 

$1billion if the power plant were to close.42

Hopi Tribe

The Hopi Tribe does not have a CAP water allocation. 

,n 2010 and 2011, the tribe purchased 2,000 a.f. of 

excess CAP water from CAWCD through the Access to 

Excess program. Excess water available in 2012 will be 

distributed based on CAWCD’s Access to Excess policies.

Pascua Yaqui Tribe

The tribe has a contract with the Department of the 

,nterior, dated Dec. 11, 1980, for the delivery of 500 a.f. 

of CAP water. The Pascua Yaqui take delivery of their 

full allocation via an exchange with the City of Tucson. 

The tribe’s full water right is the subject of a current 

adjudication the Pascua Yaqui are currently claiming a 

water right of 3,520 a.f. per year. This amount is subject to 

change during the adjudication, and the updated amount 

is con¿dential at this time.43 ,n 2012, CAP water rates 

are set at $122 per a.f. with $73 per a.f. in ¿xed OM&R 

paid from the LCRBDF and the variable pumping energy 

component, $49 per a.f., will be paid by the tribe. The 

Pascua Yaqui also pay a fee of $15.17 per a.f. to the City of 

Tucson for storing the tribe’s water. 

Salt River Pima-Maricopa Indian Community 

(SRPMIC)

The SRPM,C settlement entitles the Community to 

122,400 a.f. annually from different sources. The CAP 

allocation is 13,300 a.f. and the full allocation is leased to 

Phoenix-area cities. The full cost of delivery is paid by the 

lessees.

San Carlos Apache Tribe

The tribe’s CAP allocation is variable, ranging from 

45,565 a.f. to 60,665 a.f. annually. The City of Scottsdale 

leases 12,500 a.f. from the tribe, while Phelps Dodge 

leases another 14,000 a.f. for its Morenci Mine. Some 

41 Harvey Economics, transmittal letter and exhibits of draft ¿ndings, 

November 16, 2011

42 ,bid.

43 Yucupicio, Peter, Pascua Yaqui Chairman letter to Cynthia Hoeft, Bureau 

of Reclamation, September 23, 2011
104 NREL/TP-6A20-53024

of the tribe’s allocation comes from the unused portion 

of the Ak-Chin allocation. The San Carlos Apache Tribe 

is working with the Bureau of Reclamation to get water 

delivered to the reservation. The AWSA provides funding 

to build a water system suf¿cient to deliver 12,700 a.f. of 

CAP water. 

Tohono O’odham Nation

The Nation has two separate entitlements of CAP water 

to meet the needs of distinct areas of the reservation. The 

largest entitlement is for 66,000 a.f., which the Nation may 

use for any purpose, anywhere in the CAP service area 

(Maricopa, Pinal, and Pima Counties). A smaller 8,000 

a.f. allocation is solely for agricultural purposes in the Sif 

Odak District. There is no existing authority for the Nation 

to exchange or lease this allocation of water. The Tohono 

O’odham have not been able to use this water because 

no delivery or distribution system has been constructed. 

Planning studies are underway for construction of such a 

system that would allow the Nation to develop agricultural 

endeavors in this district.

As part of the AWSA agreement, the Nation also agreed 

to limit groundwater withdrawals from two districts on its 

reservation, the San Xavier Reservation and the eastern 

Schuk Toak District. Groundwater is the sole source of 

domestic water on the reservation. There are no plans to 

use CAP water for domestic uses because a water treatment 

plant would have to be built and operated to allow the 

Tohono O’odham to use the water. 

,n its water settlements to date, the Nation has released 

its superior claims to other waters, including surface and 

groundwater, in exchange for CAP water. The settlements 

also created two separate sources for paying the higher 

delivery costs associated with CAP water. The ¿xed 

OM&R components of delivering water for both allocations 

are paid from the LCRBDF. The energy pumping charges 

for the 66,000 a.f. allocation are to be paid from a 

Cooperative Fund ¿rst established by the 1982 SAWRSA 

and reauthorized in the 2004 AWSA. The Cooperative 

Fund is also slated to be used as a backup ¿nancing 

mechanism for ¿xed OM&R charges. However, only the 

interest accrued in the Cooperative Fund may be used to pay 

the charges. ,n addition, the settlements clarify that if the 

two sources, the LCRBDF and the Cooperative Fund, are 

no longer available, the Nation is responsible for paying all 

the delivery charges of CAP water to ful¿ll the settlement 

allocations.44

44 Norris, Ned, Tohono-O’odham Chairman letter to David Peterson, NREL, 

October 5, 2011

Tonto Apache Tribe

The tribe has an allocation and a CAP contract for 128 a.f. 

but has not reached a water rights settlement. However, the 

Tonto Apache are currently not using their water and there 

is no existing authority for them to exchange or lease the 

water. The tribe is remote and has not been able to receive 

its CAP water directly because of the lack of infrastructure. 

Most likely, the tribe’s ability to use its CAP allocation will 

depend on ¿nding exchange partners.

Yavapai-Apache Tribe (Camp Verde)

The tribe has a contract with the Department of the ,nterior, 

dated Dec. 11, 1980, for the delivery of 1,200 a.f. of water to 

the reservation and currently relies on the 9erde River and 

groundwater to sustain its homelands. The tribe’s full water 

rights have not been quanti¿ed and are part of an ongoing 

adjudication.45 The Yavapai-Apache claim a right to 6,848 

a.f. from various sources in the 9erde River watershed as 

well as in stream Àow rights, but this amount is subject to 

change as the adjudication proceeds. Like the Tonto Apache 

Tribe, the Yavapai-Apachi Tribe is remote, has not been 

able to receive its CAP water directly because of the lack 

of infrastructure, and will likely need exchange partners in 

order to use its CAP allocation.

Yavapai-Prescott Indian Tribe

The Yavapai-Prescott ,ndian Tribe Water Rights Settlement 

Act of 1994 provides 500 a.f. for the Yavapai-Prescott 

,ndian Tribe. The tribe has now assigned this water to 

the City of Scottsdale. The water is subject to the original 

,ndian CAP priority.

White Mountain Apache Indian Tribe

The White Mountain Apache Tribe entered into an 

agreement in -anuary 2009, that became law in December 

2010. Under the agreement, the tribe is entitled to 23,782 

a.f. of CAP water per year, all of which has been leased 

under the terms of the settlement. A portion of the leased 

water has a non-,ndian agriculture delivery priority. The 

tribe is also entitled to 1,218 acre-feet acquired from an 

irrigation project, which is being ¿rmed to M&, priority by 

the United States and the State of Arizona. The tribe is not 

responsible for any water service charges for the tribal CAP 

water, even if it is leased. Fixed OM&R costs are paid from 

the LCRBDF as long as funds are available. 

45 David Kwail, Yavapai-Apache Chairman letter to Cynthia Hoeft, Bureau of 

Reclamation, Sept. 21, 2011
NREL/TP-6A20-53024 105

This chapter discusses the Navajo GS plant’s employment 

impacts and broader economic inÀuence in Apache, 

Coconino, and Navajo counties. ,t describes at a regional 

level the economic and employment relationships between 

the plant, the Peabody Western Kayenta Mine, and the 

communities nearest to them. The ¿rst part of the analysis 

applies a jobs and economic development impact tool 

developed by NREL. The chapter then analyzes economic 

trends to estimate the role that the Navajo plant and the 

Kayenta Mine play in the local economy

The previous chapter examined job and other impacts 

speci¿c to Arizona tribal populations. By contrast, this 

chapter provides an economic overview of the threecounty area using data available from the U.S. Bureau of 

Labor Statistics and other traditional sources.

7.1 Estimation of primary and secondary 

effects related to Navajo GS

Modeling of employment and economic impacts was 

conducted with the suite of NREL input-output models 

known as the -obs and Economic Development ,mpacts 

(-ED,) models. This analysis uses the -ED, module for 

coal power plants.1

 

-ED, model results for new plants are displayed in two 

different time periods: construction and operations. This 

particular analysis is different, in that it aims to estimate 

the economic footprint of an existing plant. Operationsperiod results are long term, for the life of the project, and 

are reported as annual jobs and economic activity, which 

continue to accrue throughout the operating life of the 

facility.

Total economic impacts include on-site labor and 

professional services as well as jobs and economic activity 

that result from spending in supporting industries (e.g., 

construction material and component suppliers, analysts 

and attorneys who assess project feasibility and negotiate 

1 NREL’s -ED, models are publicly available spreadsheet tools that apply 

state-speci¿c ,MPLAN multiplier data. This analysis relied on year 

2009 data for the three-county region under consideration (i.e., Apache, 

Coconino, and Navajo Counties). The -ED, analysis tools were developed 

by NREL in conjunction with MRG & Associates. For more information on 

the -ED, tools, see http://www.nrel.gov/analysis/jedi/.

contract agreements, banks ¿nancing the projects, and 

equipment manufacturers) and by local government, 

from project related property and sales tax revenues. 

Total impacts also include induced effects that are driven 

by reinvestment and spending of earnings by direct 

and indirect bene¿ciaries. ,nduced impacts are often 

associated with increased business at local restaurants, 

hotels, and retail establishments but also include child 

care providers and any other entity affected by increased 

economic activity and spending occurring at the ¿rst two 

tiers.

Payments to tribal governments are a special category 

of economic bene¿t particular to Navajo GS. As -ED, is 

designed as a more general model of economic impact, 

it does not speci¿cally account for these payments. 

Therefore, the total economic impact would include those 

modeled by -ED,, plus the payments described in Chapter 

6, plus the induced impacts associated with the tribal 

payments.

7.1.1 Methodology and inputs

This analysis includes the results of modeled data on the 

operational impacts associated with a facility comparable 

to NGS. ,n the case of coal about 70% of total operations 

costs (including fuel) were estimated to be sourced from 

the three-county area of interest. Operations costs are 

estimated at $35/kW ¿xed, $3.65/MWh variable, and fuel 

costs at $1.70/mmbtu. These modeling inputs allowed the 

results to approximate the on-site employment reported by 

NGS as well as Peabody Energy (for the Kayenta Mine) to 

within 10%. 

-ED, results are not intended to be a precise forecast

they are an estimate of potential activity resulting from a 

speci¿c set of projects and modeling inputs. ,n addition, 

-ED, results presuppose that projects are ¿nancially 

viable and can be justi¿ed independent of their economic 

development value. Results generated by the -ED, models 

are gross (not net) results. They do not consider potential 

increases or decreases in electricity rates resulting from 

investments in new infrastructure, nor do they consider 

whether the respective projects displace economic activity 

elsewhere. -ED, model categories and default information 

are based on real-world projects. NREL analysts perform 

interviews with project owners, developers, engineering 

7 Economic and Employment Impacts
106 NREL/TP-6A20-53024

and design ¿rms, construction ¿rms, and others to align 

model inputs and the corresponding results with reality, as 

closely as possible. Of course, individual projects will have 

varying results depending on a wide variety of factors 

including project location and topography, available local 

labor, available local goods and services, and commodity 

prices at the time of construction. Results presented here 

are in 2010 dollars.

7.1.2 Results

The modeled results for on-site employment (450 persons) 

calibrates lower than actual employment as reported 

by plant operator SRP (around 540). -ED, estimated 

the additional employment effects at 2,025 jobs. This 

includes employment in the supply chain serving Navajo 

GS (including the Kayenta mine’s 400 employees) as well 

as indirect employment. Table 7-1 shows the jobs and 

earnings associated with on-going operation of Navajo GS, 

as modeled in -ED,.

Beyond the employment effects, the total economic output 

associated with Navajo GS operations is $511 million 

annually. This includes the sum value of all goods and 

services associated with operating the facility through its 

various stages of production.

A handful of factors could alter the impacts noted Table 

7-1, most notably the degree to which the Navajo GS 

operations rely on local labor, goods, and services. ,n 

addition, the model does not work at a level of detail 

suf¿cient to estimate the jobs that would accrue to native 

Hopi or Navajo populations or to even potentially to others 

residing within this three-county area. While it is possible 

that the type of local business activity supported by these 

projects could be provided by the native populations it 

is also possible that local labor and services anticipated 

in this effort could be provided by other parties in the 

counties or potentially even by labor and service providers 

from outside the region entirely. This is of particular 

importance as the analysis of the existing economic 

impact of NGS and the Kayenta Mine suggests that the 

potential closing is likely to disproportionately affect the 

native Hopi and Navajo populations.

7.2 Economic and employment profile of 

the three-county region

This analysis uses published data from a variety of 

sources. The 2000 and 2010 United States Census are 

used for population and ethnicity data.2

 The U.S. Bureau 

of Labor Statistics (BLS) provides unemployment data 

by county, and discloses wage and employment data by 

county and industry when there are enough employers to 

meet disclosure guidelines.3

 ,n addition to data served by 

U.S. government agencies, this analysis uses reservationlevel unemployment data received from the Navajo 

Nation,4

 and wage and payment data received directly 

from SRP, the Navajo plant operator, and Peabody Energy, 

operator of the Kayenta Mine.5

Unfortunately, data are often aggregated at a level that 

prevents a clear analysis of local effects of a potential 

shutdown of the Navajo plant. For example, the U.S. 

government provides county-level data on employment 

and wages, but this data is limited in its ability to reÀect 

tribal concerns. The Hopi Reservation is located within 

two counties, and the Navajo Reservation is located 

in three Arizona counties as well as in the States of 

New Mexico and Utah. Additionally, the BLS and the 

Tribes have a different methodology for calculating 

unemployment. The BLS only considers someone 

unemployed if they do not have a job, are available to 

work, and have actively looked for a job in the last four 

weeks. The B,A de¿nition, on the other hand, counts 

people as unemployed who would like a job but have 

stopped looking for one. According to the B,A, “[t]he 

difference in calculation generally leads to the Tribes 

2 U.S. Census Bureau, Census 2000 Gateway, http://www.census.gov/main/

www/cen2000.html U.S. Census Bureau, 2010 Census, http://2010.census.

gov/2010census.

3 Bureau of Labor Statistics, Databases, Tables & Calculators by Subject, 

http://bls.gov/data/.

4 Navajo Nation Department of -ustice, email correspondence, October 4, 

2011. www.nrel.gov/navajo

5 Navajo Nation, email correspondence, September 24, 2011 and October 11, 

2011.

Table 7-1. Estimated On-site and Regional 

Employment Effect of Navajo GS

Full-time 

employment

Annual 

earnings

On-site 450 $29,250,000

Rest of region 

(direct, indirect, and 

induced employment

2,025 $103,500,000
NREL/TP-6A20-53024 107

reporting signi¿cantly higher unemployment rates than 

those reported by BLS for counties and states in proximity 

to the reservations.”6

 This analysis acknowledges and 

explains the limitations in the available data. 

7.2.1 Current Economic Conditions

The Navajo Generating Station is located in Coconino 

County, and the Kayenta Mine is located in Navajo 

County, Arizona. While shutting down the Navajo plant 

may affect other parts of Arizona or surrounding states, 

local communities would likely feel the most direct 

impact, especially the Navajo and Hopi Reservations. The 

Navajo Nation is located in Apache, Coconino, and Navajo 

Counties and crosses state borders into New Mexico and 

Utah, and the Hopi Reservation is located in Coconino and 

Navajo Counties. 

Data from the 2000 and 2010 United States Census 

provides a picture of how the local population has changed 

over the last decade (see Table 7-2). The data show total 

population growing in all three counties with Coconino 

County experiencing the highest growth rate (with 15% 

growth over the decade). When the data are subdivided 

by ethnic groups, the trend in population growth becomes 

more nuanced. Navajo County gained less than 100 

people classi¿ed as American ,ndian and Alaskan 

Native (A,AN), and Apache County lost over 800 people 

classi¿ed as A,AN. ,n fact, while the Hopi Reservation 

saw an increase in population of 5%, the Navajo Nation 

experienced a 4% loss in population. As a whole, the 

6 Bureau of ,ndian Affairs, Department of the ,nterior, 2005 American ,ndian 

Population and Labor Force Report, 2005, p. viii.

census data suggests that while the population of the three 

counties is growing, the share of A,AN people has grown 

at a slower rate.

Data from the BLS and the Navajo Nation suggest 

differences in the average unemployment rate for Apache, 

Coconino, and Navajo Counties, and for the Navajo 

Reservation.7

 Due to the methodological differences 

between the data sets explained previously, however, a 

direct comparison between the numbers is problematic. 

While the unemployment rate for the three counties is 

slightly higher than the U.S. national unemployment 

rate, it has closely followed movements in the national 

unemployment rate. Biennial unemployment data 

provided by the Navajo Nation show that unemployment 

on the reservation has averaged around 50% for the 

last twenty years. Other than a short-term dip in 1998, 

trends in the unemployment rate for Navajo paralleled the 

gradual improvement seen in the county and national data 

up to 2007. Navajo data for 2008 and later were not yet 

available as of this writing.

The BLS provides industry-level employment and wage 

information using the 2002 North American ,ndustry 

Classi¿cation System (NA,CS) and an internal system 

of 11 aggregate sectors referred to as “super sectors.”8

 

County-level employment and wage data are not 

consistently available in all industries in all three counties 

7 Detailed employment data for the Hopi Reservation were not available for 

this analysis.

8 Bureau of Labor and Statistics, Overview of BLS Wage Data by Area and 

Occupation, http://bls.gov/bls/blswage.htm.

Table 7-2. Population and Ethnicity by County and Tribe

County Tribal Lands

Population Coconino Navajo Apache Hopi Tribe Navajo Nation

2000

 AIAN 33,161 46,532 53,375 6,470 174,847

 Total 116,318 97,468 69,423 6,836 181,269

2010

 AIAN 36,714 46,611 52,514 6,857 167,031

 Total 134,421 107,449 71,518 7,185 173,667
108 NREL/TP-6A20-53024

of interest,9 so this analysis utilizes 

“Natural resources and mining” 

(BLS sector 1101) as an estimator of 

the relative importance of the local 

mining industry. 

Total employment in the three 

counties increased for most of the last 

decade, though it has declined since 

2007, likely due to the lingering U.S. 

recession (Table 7-3). ,n contrast, 

the number of natural resources and 

mining employees steadily declined 

over the entire time period a 15% 

drop from 2005 to 2006 coincided 

with the closure of the Mohave coal 

plant in southern Nevada, which 

relied on the Kayenta Mine for 

fuel. Average annual pay for those 

employees increased by 12% over the 

decade, however, seemingly immune 

to the stagnating average wages for 

all industries. Furthermore, Navajo 

provided an average wage estimate of 

$50.54 per hour (including bene¿ts) 

for Navajo employees. Given the 

data provided by the Navajo Nation 

and BLS data on mining industry 

wages, these jobs provide above 

average wages and bene¿ts to their 

employees.

Total product data are not available 

for the Navajo plant and the Kayenta 

Mine, so to assess the diversity of 

the local economy, this analysis uses 

total income data provided by the 

BLS.10 At an aggregate level, the 

BLS categorizes data from “goodsproducing” and “service-providing” 

industries with both the Navajo plant 

and the Kayenta Mine categorized as 

goods-producing companies. While 

9 This is due to disclosure rules that ensure 

aggregate statistics cannot be used to ascertain 

wage and employment data for individual 

companies.

10 The U.S. Department of Commerce does not 

publish production data at the county level.

50.0

40.0

30.0

20.0

10.0

0.0

70.0

60.0

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

Unemployment Rate

(%)

National Three County Navajo Nation

Figure 7-1. Unemployment rates of U.S., Navajo Nation, and Coconino, Apache, and 

Navajo Counties, AZ, 1990-2010.

1500

1000

500

0

2500

2000

2001

2003

2005

2007

2009

Total Wages

($000,000 2010)

Services Natural Resources and Minding All Other Goods

Figure 7-2. Total wages, by Sector, Apache, Coconino, and Navajo Counties, AZ, 

2001-2010.
NREL/TP-6A20-53024 109

total wages for goods-producing companies had a slight 

peak in 2007, over the past decade the service-providing 

sector increased to nearly 80% of the economy of the 

three counties (Figure 7-2). More speci¿cally, the natural 

resources and mining industry provided 2.5% of total income in 2001, but by the end of the decade, that percentage 

had dropped to 1.6% (Figure 7-2). These statistics suggest 

that the economy of the three counties is largely based 

around services, and that the natural resources and mining 

industries only modestly contribute to aggregate income.

While a direct accounting of the taxes paid by Navajo 

was not made available for this analysis, Peabody Energy 

provided state and local taxes paid by the Kayenta Mine. 

,n 2010, the mine paid $17 million in state sales taxes 

and $1.6 million in Navajo County property tax. According to Peabody Energy estimates, around $1.2 million of 

their property tax payment went to the Kayenta Uni¿ed 

School District located in Navajo County. State and local 

tax revenue would certainly be reduced in the event of an 

Navajo shutdown. Additionally, according to the Navajo 

Nation’s 2009-2010 Comprehensive Economic DevelopTable 7-3. Apache, Coconino, and Navajo County Employment and Wages by Industry

Employees Total Wages 

($K 2010)

Average Annual Pay 

($ 2010)

All 

Industries

Natural 

Resources 

and 

Mining

All 

Industries

Natural 

Resources 

and Mining

All 

Industries

Natural 

Resources 

and 

Mining

2001 94,501 1,402 3,001,621 74,281 31,763 52,982

2002 96,063 1,436 3,122,043 74,830 32,500 52,110

2003 97,092 1,334 3,220,679 68,894 33,171 51,645

2004 99,385 1,277 3,308,374 71,494 33,288 55,986

2005 103,513 1,299 3,535,847 70,906 34,158 54,585

2006 106,463 1,130 3,645,247 61,190 34,240 54,150

2007 108,249 1,093 3,833,831 58,158 35,417 53,209

2008 106,684 1,140 3,741,142 57,359 35,068 50,315

2009 102,512 1,018 3,696,133 56,855 36,056 55,849

2010 101,088 986 3,619,227 58,378 35,803 59,207

ment Strategy, the Nation notes that payments from three 

mines on Navajo land (the Peabody Mine, Pittsburgh and 

Midway Mine, and the Navajo Mine) account for more 

than $60 million in revenue, roughly 60% of the Nation’s 

2008 General Fund budget.11 

11 Navajo Nation, 2009-2010 Comprehensive Economic Development 

Strategy, 2008, p.16.
110 NREL/TP-6A20-53024
NREL/TP-6A20-53024 111

Conclusions

The foregoing chapters of this study support several 

conclusions relating to factors that EPA will consider 

in its BART determination. Nevertheless, this study 

makes no recommendation about what the BART 

determination should be for Navajo GS, and none of the 

conclusions that follow should be construed as implying a 

recommendation. 

Cost of compliance

Ŷ The basic costs of installing SCRs at Navajo 

GS would likely be less than the basic costs of 

shutting it down and replacing it with power from 

unused capacity elsewhere in the West.

The plausible range of additional annual cost resulting 

from SCR installation is between $57 million and $70 

million per year. This includes capital costs (amortizing 

each owner’s share over 20 years using each partners’ 

cost of capital as its discount rate) and production costs 

(calculated based on Navajo GS’ historical production 

levels). ,t does not include other unknown costs that may 

be related to additional control technologies, such as 

changes in plant ownership, changes in ownership shares, 

costs relating to the negotiation of the Navajo GS site 

lease, the cost of coal from the Kayenta mine, or other 

factors.

By comparison, if Navajo GS were retired and the same 

amount of power came from the least-cost redispatch 

of existing units, total production costs throughout the 

Western ,nterconnection would likely increase $197 

million to $502 million. As explained in Chapter 2, these 

estimates represent an economically optimal outcome 

that accounts for known, quanti¿able constraints, with 

natural gas prices de¿ning the plausible range of total 

replacement costs. Unknown factors could introduce 

inef¿ciencies that would generally increase actual costs. 

For example, existing power contracts may bind a utility 

to an agreement that is less than optimal, while unplanned 

changes in transmission line ratings could limit the Àow 

of power across paths that would otherwise be preferred 

economically. Therefore, the replacement costs represent 

best-case scenarios. 

The economic balance does not change when adding the 

cost of baghouses and sorbent injection, which might not 

address visibility issues but might be required as a result 

of future EPA emission rules. The annual retro¿t costs 

(with capital costs recovered over 20 years) would be 

double that of SCR alone, but even so, the annual cost is 

still about $67 million per year below replacement costs 

under the most optimistic natural gas price scenario.

Ŷ The cost burden of additional retro¿ts would 

probably fall more heavily on CAP water users 

than it would on customers of any of the ¿ve 

utilities that own shares of Navajo GS. Replacing 

the plant would likely result in an even greater 

impact disparity.

The capital costs and additional production costs of SCR 

controls at Navajo GS would likely increase the retail rates 

of each utility partner by 0.2% to 0.6%. With baghouses 

and sorbent injection, and capital recovery accelerated to 

10 years, the impact on retail rates would be about triple. 

Each Navajo GS utility partner would add its share 

of retro¿t capital costs to its net utility plant (the total 

value of all capital assets minus depreciation). This base 

aggregates all of the utility’s capital assets, and the total 

revenue required each year to service the equity and debt 

that ¿nance these assets make up the base rates paid by all 

of the utility’s retail customers. For example, the additional 

capital cost of SCR control technology at Navajo GS 

would increase by 1.4% to 1.7% SRP’s net utility plant 

(the total value of all capital assets minus depreciation). 

Applied across all its electricity sales, the impact on SRP’s 

retail rates would be around 0.04 cents per kilowatt-hour. 

The Bureau of Reclamation is not an electric utility and 

therefore lacks a comparable rate structure for recovering 

capital costs. ,n fact, this study found considerable 

uncertainty regarding how the federal government’s share 

of new capital costs might be recovered. Lacking clearer 

guidance for the purpose of analysis, this study’s default 

assumption was that public-sector revenue bonds or a 

similar instrument would ¿nance Reclamation’s share 

of capital costs, with the revenue requirement added to 
112 NREL/TP-6A20-53024

water rates charged by CAWCD. Assuming an interest 

rate of 5% and a 20-year term, the debt service would add 

0.32 cents to 0.38 cents per kilowatt-hour to the cost of 

pumping water—ten times the per-kilowatt-hour impact 

that the utility partners’ electric customers would see.

Ŷ SCR retro¿ts will affect the water rates that 

CAWCD charges CAP water users by 5% to 16%.

The installation of BART emission controls at Navajo 

GS could require CAWCD to recover additional revenues 

to apply towards the federal government’s share of the 

new capital costs. Federal appropriations toward this 

obligation would mitigate the impact on CAP water users, 

but as of this writing no appropriation has been proposed. 

The revenue tools available to CAWCD include water 

rates, revenue bonds, and an ad valorem tax.

An increase in production costs could result in lost Navajo 

GS surplus power sales revenues, which would increase 

the amount CAWCD would need to pay into the Lower 

Colorado River Basin Development Fund toward its CAP 

repayment obligation. This could also require additional 

revenues from water rates.

Ŷ Even in the absence of the installation of BART 

emissions controls at Navajo GS, the second 

cascade of priorities under the Arizona Water 

Settlements Act would only receive Development 

Fund revenues when market power prices are 

substantially higher than they are today.

Revenues from excess power sales on the open market are 

neither stable nor predictable regardless of how BART 

capital costs may be recovered. Beginning in October 

2011, Reclamation and CAWCD implemented a strategy 

to rely more on the regional power market to dispose of 

excess power. The increase in Navajo GS production costs 

due to BART retro¿ts would in all likelihood be lost in the 

larger and more erratic Àuctuations of wholesale power 

prices. Currently, wholesale prices are relatively depressed 

due to low natural gas prices and to lower electricity 

demand resulting from the recession. Therefore, with or 

without BART costs in the equation, Reclamation and 

CAWCD will still need to deal with the likelihood of lower 

revenues into the development fund and the potential 

impact on CAP water rates.

Energy impacts of compliance

Ŷ Installing SCRs would, in all likelihood, cause 

little change in the amount of energy provided by 

Navajo GS.

The additional operating and maintenance costs associated 

with SCR retro¿ts would likely increase production costs 

at Navajo GS by between $0.73 and $1.02 per megawatthour, or between 3% and 4%. ,t is unlikely that a change 

of this magnitude would signi¿cantly change how much 

power Navajo GS would produce, as it would still be one 

of the lowest-cost resources in the Desert Southwest with 

respect to production costs. 

Ŷ Shutdown would tend to reduce power exports 

from the Desert Southwest to Southern California, 

and would tend to increase electricity production 

from combined cycle gas units in Southern 

California.

A large amount of power currently Àows from generators 

in Arizona, New Mexico and Nevada to Southern 

California. When Navajo GS is removed from the West’s 

regional generation Àeet in simulations based production 

costs, changes in the cost of local power (as reÀected 

in LMPs) create an economic incentive to reduce the 

commercial Àow of power westward across the Colorado 

River. The tendency is for more generated power to stay 

in Arizona, and more generation to come from combined 

cycle gas turbines located in California. Contract 

delivery obligations might restrict this tendency, but the 

consequences would be to increase replacement costs even 

more.

Remaining useful life of Navajo GS

Ŷ While BART retro¿ts would be unlikely to force 

retirement of Navajo GS for economic reasons, the 

plant nevertheless might be halfway through its 

operating life.

Navajo GS will have been in service 45 years when its 

site lease with Navajo Nation expires in 2019. While 45 

years was a typical useful lifespan for smaller coal plants 

in the U.S. built prior to Navajo GS, larger coal plants 

built around the time of Navajo GS and later appear to 
NREL/TP-6A20-53024 113

be lasting longer. Survival analyses conducted by NREL 

and others indicate that relatively fewer units of Navajo 

GS’ generation are retiring early, and the ones that remain 

continue to sustain high capacity factors. Statistical 

analysis point to a normal operating life of 65 to 70 years. 

The utility partners’ capital investments in Navajo GS 

(including retro¿ts to date, but excluding future retro¿ts) 

are on track to be fully depreciated no later than 2026, 

when the plant will have had more than 50 years in 

service. 

Degree of improvement in visibility

Ŷ The body of research to date is inconclusive as 

to whether removing approximately two-thirds of 

the current NOx emissions from Navajo GS would 

lead to any perceptible improvement in visibility 

at the Grand Canyon and other areas of concern. 

Evidence suggests that NOx emissions from Navajo 

GS are a likely incremental contributor to haze at the 

Grand Canyon. Whether the incremental contribution is 

signi¿cant or even perceptible is a matter of debate among 

experts in the ¿eld of visibility science. Resolving these 

questions requires expertise in atmospheric chemistry and 

air transport modeling, not power sector expertise.

Monitoring and other evidence suggests NOx is a weaker 

contributor than SO2, which has already declined 95% at 

Navajo GS since the installation of scrubbers in 2000. 

Impacts on Indian tribes

Ŷ For agricultural users and Indian tribes, water 

rates from CAP would likely increase between 

13% and 16%. Baghouses and sorbent injection 

would roughly double the impact on water rates. 

A signi¿cant increase in the cost of power from Navajo 

GS could affect settlements with some ,ndian tribes who 

surrendered future water right claims in exchange for 

low-cost access to CAP water and other bene¿ts. While 

this study estimates the magnitude of potential water rate 

increases, a more detailed examination of what they mean 

for tribal water settlements (for example, determining the 

threshold at which a rate increase would be materially 

signi¿cant) would require a legal analysis that was beyond 

the scope of this study. 

A signi¿cant area of concern for CAP water-using tribes 

relates to the potential for sales of surplus Navajo GS 

power to exceed the $55 million annual CAP repayment 

obligation. ,n cases where annual revenue into the fund 

exceed $55 million, the “second cascade” of funding 

disbursements would kick-in, with initial funds in the 

second cascade going to reduce the ¿xed operations, 

maintenance and replacement charges associated with 

the delivery of CAP water to ,ndian tribes. Under a 

new agreement related to the sales of surplus Navajo 

generation, approximately 1 TWh of primarily off-peak 

power would be up for sale on the general wholesale power 

market, making this portion of excess power revenue more 

directly subject to market prices. Current power prices 

are not high enough to support Àows into second-cascade 

disbursements, nor have they been since 2008. Two factors 

could mitigate against higher power prices in the future: 

success of energy ef¿ciency programs in Arizona and 

other Southwest states, and additional natural gas supplies 

resulting from the development of shale gas. 

Ŷ Early plant retirement is the only BART scenario 

likely to result in serious harm to the economies of 

the Navajo Nation and the Hopi Tribe. 

Navajo GS would likely run at nearly the same level of 

production as it is currently if SCR controls were installed. 

Most of the capital costs would be recovered through the 

owner utilities’ rate base, but production costs would only 

increase by between 3% and 4%. 

Similarly, many of the environmental impacts of 

compliance other than air quality (which primarily affect 

the Hopi and Navajo living close to the plant and to the 

Kayenta mine) would not change signi¿cantly if the plant 

had to install additional NOx controls but ran at close to its 

normal production level. 
114 NREL/TP-6A20-53024

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