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National Renewable Energy Laboratory 15013 Denver West Parkway 

Golden, CO 80401 

303-275-3000 • www.nrel.gov 

Beyond Renewable Portfolio 

Standards: 

An Assessment of Regional 

Supply and Demand 

Conditions Affecting the 

Future of Renewable Energy in 

the West 

David J. Hurlbut, Joyce McLaren, and 

Rachel Gelman 

National Renewable Energy Laboratory 

Prepared under Task No. AROE.2000 

NREL is a national laboratory of the U.S. Department of Energy 

Office of Energy Efficiency & Renewable Energy 

Operated by the Alliance for Sustainable Energy, LLC 

This report is available at no cost from the National Renewable Energy 

Laboratory (NREL) at www.nrel.gov/publications. 

Technical Report 

NREL/TP-6A20-57830 

August 2013 

Contract No. DE-AC36-08GO28308 
Cover Photos: (left to right) photo by Pat Corkery, NREL 16416, photo from SunEdison, NREL 17423, photo by Pat Corkery, NREL 

16560, photo by Dennis Schroeder, NREL 17613, photo by Dean Armstrong, NREL 17436, photo by Pat Corkery, NREL 17721.

NOTICE 

This report was prepared as an account of work sponsored by an agency of the United States government. 

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express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of 

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Acknowledgments 

The genesis of this report was a 2010 conference in Tempe, Arizona, titled “Cooperation 

Among States in the Western Interconnection on Electric Resource Planning and 

Priorities.” The conference was funded with grant from the U.S. Department of Energy 

(DOE) to the Western Governors’ Association (WGA) and was organized by regulatory 

commissioners from five southwest states: Kris Mayes, then chair of the Arizona 

Corporation Commission; Jim Tarpey, commissioner with the Colorado Public Utilities 

Commission; Rebecca Wagner, commissioner with the Nevada Public Utilities 

Commission; Dian Gruenich, then commissioner with the California Public Utilities 

Commission; and Jason Marks, then commissioner with the New Mexico Public 

Regulation Commission. This report expands an analytical framework presented at that 

conference by the National Renewable Energy Laboratory (NREL), based on recently 

completed work for the Western Renewable Energy Zone Initiative. The authors are 

grateful to these commissioners for their early encouragement. 

The authors would especially like to thank Doug Larson, Tom Carr, Steve Ellenbecker, 

Jennifer Gardner, and Victoria Ravenscroft of the Western Interstate Energy Board 

(WIEB). Regional planning for transmission and renewable energy in the Western 

Interconnection has advanced tremendously since the 2010 Tempe conference, and 

WIEB staff have been at the forefront of these activities. The guidance they provided for 

this report was invaluable in keeping the analysis relevant. 

NREL experts Lori Bird, and Marissa Hummon provided valuable contributions in 

developing the methodologies used in this report. We are also grateful to Pete Larson and 

Andrew Mills of Lawrence Berkeley National Laboratory for their insights and advice. 

We are especially grateful to NREL geothermal expert Chad Augustine for his assistance 

in refining the geothermal estimation methodology used in this study so that it takes into 

account the newest insights about engineered geothermal systems. 

Finally, we also thank DOE’s Office of Electricity Delivery and Energy Reliability, 

which has overseen the interconnection-wide planning work funded through the 

American Recovery and Reinvestment Act. In addition to providing Recovery Act 

funding for the 2010 conference, the office has also supported assistance by the National 

Renewable Energy Laboratory (NREL) and other national laboratories to the entities 

(including WGA) that were awarded Recovery Act funding to conduct interconnectionwide planning; this study is part of that support. We especially thank Larry Mansueti and 

David Meyer for their guidance and support. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) iii 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

List of Acronyms 

ACC	 Arizona Corporation Commission 

ACEEE	 America Council for an Energy-Efficient 

Economy 

APS	 Arizona Public Service Company 

BA	 balancing authority 

CCGT	 combined cycle natural gas turbine 

CSP	 concentrating solar power 

DG	 distributed generation 

DNI	 direct normal insolation 

DOE	 U.S. Department of Energy 

EERS	 energy efficiency resource standard 

EGS	 enhanced geothermal systems 

EPE	 El Paso Electric Company 

IOU	 investor-owned utility 

IRP	 integrated resource plan 

ISO	 independent system operator 

ITC	 investment tax credit 

GDP	 gross domestic product 

GW	 gigawatt 

GWh	 gigawatt-hour 

LADWP	 Los Angeles Department of Water and 

Power 

LBNL	 Lawrence Berkeley National Laboratory 

MPR	 market price referrent 

MW	 megawatt 

MWh	 megawatt-hour 

NERC	 North American Electric Reliability 

Corporation 

NPC	 Nevada Power Company 

NREL	 National Renewable Energy Laboratory 

OATT	 open access transmission tariff 

PG&E	 Pacific Gas & Electric Company 

PNM	 Public Service Company of New Mexico 

PRC	 New Mexico Public Regulation Commission 

PSCO	 Public Service Company of Colorado 

PTC	 production tax credit 

PUC	 public utilities commission 

PV	 photovoltaic 

QRA	 qualified resource area 

REC	 renewable energy certificate/renewable 

energy credit 

Recovery Act	 American Recovery and Reinvestment Act 

of 2009 

RES	 renewable energy standard 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) iv 

at www.nrel.gov/publications. 
 

 

 

RETI California Renewable Energy Transmission 

Initiative 

RPS renewable portfolio standard 

RRS renewable resource standard 

SDG&E San Diego Gas & Electric Company 

SMUD Sacramento Municipal Utility District 

SPPC Sierra Pacific Power Company 

SPSC State/Provincial Steering Committee 

SRP Salt River Project 

TEP Tucson Electric Power Company 

TWh terawatt-hour 

WGA Western Governors’ Association 

WREZ Western Renewable Energy Zones 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) v 

at www.nrel.gov/publications. 
 

 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications. 

vi 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Executive Summary 

Several Western states have renewable portfolio standard (RPS) requirements that have 

driven significant expansion of wind, solar, and geothermal power. This study examines 

the renewable energy resources likely to remain undeveloped in the West by the time all 

these requirements have culminated in 2025. Development beyond that point will likely 

depend on the best of these remaining resources—where they are located, what it takes to 

get them to market, and how cost effectively they fit into a diverse portfolio of electric 

generation technologies. 

While the bulk of this study concerns future renewable energy supply, its aim is to reduce 

some of the present uncertainty that complicates long-term planning. These findings 

about the renewable resources likely to be available in 2025 can inform today’s 

discussions about policies targeting future development—policies that might be different 

from the RPS model. Many important factors outside the scope of this study are likely to 

affect what those policies are. The aim here is not to recommend a path, but to assess the 

supply conditions that—with many other factors—might affect future state policies and 

utility business decisions. 

So far, most western utilities have relied primarily on renewable resources located close 

to the customers being served. This appears to be enough to keep most states on track to 

meet their final RPS requirements. What happens next depends on several factors that are 

difficult to predict at this point in time. These factors include trends in the supply and 

price of natural gas, greenhouse gas and other environmental regulations, changing 

consumer preferences, technological breakthroughs, and future public policies and 

regulations. Changes in any one of these factors could make future renewable energy 

options more or less attractive. 

Nevertheless, it is possible to characterize the stock of renewable resources likely to 

remain undeveloped after RPS requirements are met, and to do so with a reasonably high 

degree of confidence. That is the purpose of this report. While the study does not by itself 

answer questions about where future energy supplies should come from, it does reduce 

some of the uncertainty about one type of alternative: utility-scale renewables developed 

for a regional market. 

This study divides the timeline of renewable energy development into two periods: the 

time covered by state RPS policies as they exist today, and what may be termed “next 

generation” renewable energy policies. In the West, the last state RPS culminates in 

2025, so the analysis uses 2025 as a transition point, as illustrated in Figure ES-1. Nextgeneration policies may be simple extensions of existing RPS mandates, or innovative 

tools specifically designed to address new conditions in the electric sector. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) vii 

at www.nrel.gov/publications. 
 

 

 

 

 $-

0

 Resource options 

energy supply 

Cost of renewable 

in order of cost 

($/MWh) RPS-related 

demand in 2025 

Cumulative amount of developed renewable energy resources (TWh per year) 

RPS demand Post-RPS demand 

time 

Figure ES-1. Conceptual renewable energy supply curve 

Best-Value Propositions for Post-2025 Regional Renewables 

“Value proposition” means there is reasoned justification for believing that a 

corresponding investment in infrastructure would be responsive to a foreseeable demand 

if it were built. The stronger the potential value, the more likely it would be that 

renewable resource developers would compete for that future opportunity. In some cases, 

realizing a value proposition could depend on regional cooperation for new transmission. 

A number of corridors with positive value propositions stand out. They generally cluster 

around two destination markets: California and the Southwest; and the Pacific Northwest. 

Most involve deliveries of wind power, but in some circumstances solar and geothermal 

power may offer targeted opportunities for value. 

Wyoming and New Mexico could be areas of robust competition among wind projects 

aiming to serve California and the Southwest. Both states are likely to have large 

amounts of untapped, developable, prime-quality wind potential after 2025. Wyoming’s 

surplus will probably have the advantage of somewhat higher productivity per dollar of 

capital invested in generation capacity; New Mexico’s will have the advantage of being 

somewhat closer to the California and Arizona markets. 

Montana and Wyoming could emerge as attractive areas for wind developers competing 

to meet demand in the Pacific Northwest. The challenge for Montana wind power appears 

to be the cost of transmission through the rugged forests that dominate the western part of 

the state. 

Wyoming wind power could also be a low-cost option for Utah. This could complement 

Utah’s own diverse portfolio of in-state resources. 

Colorado is a major demand center in the Rocky Mountain West and will likely have a 

surplus of prime-quality wind potential in 2025. However, the results suggests that 

especially high transmission costs could be a formidable economic obstacle to future 

renewable energy trading between Colorado and its Rocky Mountain neighbors. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) viii 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

California, Arizona, and Nevada are likely to have surpluses of prime-quality solar 

resources. None is likely to have a strong comparative advantage within the three-state 

market, unless environmental or other siting challenges limit in-state development. Of the 

three, California is the most economically attractive destination market, as indicated by 

the competitive benchmark used in this study. Development of utility-scale solar will 

probably continue to be driven by local needs rather than export potential. 

New geothermal development could trend toward Idaho by 2025. Much of Nevada’s 

known geothermal resource potential has already been developed, but to date very little 

of Idaho’s has. Geothermal power from Idaho could be competitive in California as well 

as in the Pacific Northwest, but the quantity is relatively small. Reaching California, 

Oregon, and Washington may depend on access to unused capacity on existing 

transmission lines, or on being part of a multi-resource portfolio carried across new lines. 

Surplus Prime-Quality Resources in 2025 

The analysis begins with a detailed state-by-state examination of renewable energy 

demand and supply projected out to 2025. The purpose of the state analyses is to forecast 

where the largest surpluses of the most productive renewable resources are likely to be 

after all current RPS policies in the West culminate. Table ES-1 summarizes the findings. 

Table ES-1: Major Findings about Surplus Resources in 2025 

The western states together will need between 127 TWh and 149 TWh of renewable 

energy annually in 2025 to meet targets stipulated by current state laws. California 

accounts for nearly 60% of this RPS-related demand. 

Renewable energy projects either existing or under construction in the western 

United States as of 2012 can supply an estimated 86 TWh. 

Colorado, Montana, Nevada, and New Mexico each has within its borders more 

untapped prime-quality renewable resources than it needs to meet the balance of its 

forecasted requirement for 2025. 

Wyoming and Idaho have no RPS requirement, but they provide renewable energy 

to other states and have large undeveloped supplies of prime-quality renewable 

resources. 

Arizona has sufficient high-quality solar resources to meet the balance of its 

forecasted requirement for 2025. It has a limited amount of non-solar resources, 

none of which is likely to be competitive outside the state. 

California, Oregon, Utah, and Washington have already developed most (if not all) of 

their easily developable prime-quality in-state renewable resources. Their less 

productive renewable resources could be sufficient to meet the balance of their 

forecasted 2025 requirements, but the cost is likely to be higher than the cost of 

renewable power developed prior to 2012. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) ix 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In this analysis, “prime-quality renewable resources” means: wind areas with estimated 

annual capacity factors of 40% or better; solar areas with direct normal insolation of 7.5 

kWh/m2

/day or better; and all discovered geothermal resources. 

Renewable Resource Screening and Analytical Assumptions 

This report relies on updates to the wide-area renewable energy resource assessment 

conducted under the Western Renewable Energy Zone (WREZ) Initiative for the Western 

Governors’ Association. The purpose of the WREZ assessment was to locate the West’s 

most productive utility-scale renewable energy resource areas—zones where installed 

generation would produce the most electricity for each dollar invested.1 The assessment 

took into account the quality of natural factors, such as windiness and annual sunshine, as 

well as limiting factors, such as national parks, wilderness areas, and terrain that was too 

rugged for development.2 Prime-quality renewable resources are a subset of the screened 

WREZ resources. 

Four assumptions guide forecasts of the prime resources likely to remain untapped by 

2025: 

•	 Utilities will prefer using in-state prime resources to meet their RPS requirements 

•	 Prime out-of-state resources will not be preferred unless there are no more prime 

in-state resources 

•	 Only surplus prime resources will have a meaningful place in a regional post2025 market 

•	 Utilities will prefer a diversity of resource types in their RPS compliance 

portfolios. 

These assumptions are consistent with feedback from utility planners and regulators 

obtained as part of the WREZ Initiative. 

While the WREZ analysis is the most comprehensive renewable energy assessment 

conducted for the western United States to date, there are some shortcomings that have a 

potential effect on the assumptions underlying this analysis. Resources that might be 

good enough for local use but are unlikely to be competitive in a regional market were 

not screened and quantified with the same rigor as were higher quality resources because 

they were outside the scope of the WREZ analysis. Unique characteristics and a short 

interconnection distance could make an isolated non-WREZ site unusually productive, 

even if there was no evidence of systematic quality across the larger area. A large number 

of such undetected areas could result in underestimating the nearby supplies capable of 

1 The strict technical meaning of the term “productive,” as used throughout this report, is a generator’s 

annual capacity factor—the unit’s actual electricity production expressed as a percentage of the electricity 

that the equipment would produce if it were running at its full rated capacity all the time.

2 Mountains and other steep terrain (e.g. , greater than 20% slope for wind power) were considered too 

difficult to develop and were excluded. Lack of nearby transmission was not a criterion for exclusion, as 

the purpose of the WREZ analysis was to help inform planning for new transmission. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) x 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

meeting post-2025 demand economically. It could also lead to underestimating the prime 

resources likely to remain undeveloped by 2025. 

Another caveat is that small-scale renewable DG is outside the scope of this particular 

study. This does not diminish the importance of DG as a long-term resource. Rather, it 

recognizes that DG and utility-scale renewables face different issues of comparable 

complexity and are best analyzed on their own merits separately. DG and the 

development of utility-scale prime renewable resources are not mutually exclusive; 

nevertheless, aggressive state DG policies could reduce demand for new utility-scale 

generation resources of any type, which in turn could reduce demand for prime 

renewables developed regionally. 

Competitiveness of Future Surpluses in Destination Markets 

The study then moves from the state resource analyses to examine the value of delivering 

the region’s best surplus resources to the West’s largest demand centers. The test for 

competitiveness is the difference between the delivered cost of the best 1,000 GWh of 

prime renewable resources likely to remain undeveloped in 2025 and a cost benchmark 

for the destination market. The benchmark is based on the projected future cost of a new 

combined-cycle natural gas turbine (CCGT) built in the destination market, with natural 

gas in 2025 at a nominal price of between $7.50/mmBtu and $8.43/mmBtu. In the case of 

wind and solar power, we adjust the benchmark to account for how well electrical 

production from the renewable resource matches load in the destination market hour to 

hour. 

The study does not make an assumption about future federal or state renewable energy 

policies past their current expiration or target dates. Cost estimates do not include the 

production tax credit (PTC) or the investment tax credit (ITC). One aim of this analysis is 

to provide a baseline picture of the renewable energy market in 2025 before adding in the 

effect of future policies, whatever they might be. A plausible baseline can provide 

important input for designing future state and federal policies. 

Drawing on earlier work, this study assumes the following cost changes from 2012 to 

2025:3 

•	 Wind power: All-in costs will decrease 19% on a constant-dollar basis and will 

increase 9% in nominal dollars 

3 Wind power cost estimates are based on: Lantz, E.; Wiser, R.; Hand, M. IEA Wind Task 26: The Past and 

Future Cost of Wind Energy. NREL/TP-6A20-53510. Golden, CO: National Renewable Energy 

Laboratory, May 2012. Cost estimates for solar and geothermal power are based on: Augustine, C.; Bain, 

R.; Chapman, J.; Denholm, P.; Drury, E.; Hall, D.G.; Lantz, E.; Margolis, R.; Thresher, R.; Sandor, D.; 

Bishop, N.A.; Brown, S.R.; Cada, G.F.; Felker, F.; Fernandez, S.J.; Goodrich, A.C.; Hagerman, G.; Heath, 

G.; O’Neil, S.; Paquette, J.; Tegen, S.; Young, K. Renewable Electricity Futures Study Volume 2: 

Renewable Electricity Generation and Storage Technologies. NREL/TP-6A20-52409-2. Golden, CO: 

National Renewable Energy Laboratory, 2012. CCGT and natural gas costs are based on the California 

Public Utility Commission’s Market Price Referrent, Resolution E-4442. Public Utilities Commission of 

the State of California (Dec. 1, 2011). Section 3 of this report discusses in further detail the approach for 

estimating future costs. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xi 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

•	 Solar power: All-in costs will decrease 35% on a constant-dollar basis and will 

decrease 5% in nominal dollars 

•	 Geothermal power: All-in costs will decrease 9% on a constant-dollar basis and 

will increase 19% in nominal dollars 

•	 CCGT (benchmark value): All-in costs will remain unchanged on a constantdollar basis and will increase 29% in nominal dollars; the nominal price of natural 

gas for electric generation will range from $7.50 per mmBtu to $8.40 per mmBtu 

at major trading hubs in 2025. 

As explained below, the study applies a sensitivity analysis to test the robustness of its 

conclusions if future costs differ from these estimates. 

Significant technological breakthroughs or other developments could have implications 

for the assumptions about renewable resource availability and effective per-megawatthour cost. For wind power, technological breakthroughs in turbines designed for 

moderate wind speeds could improve the productivity of sites that are less productive 

using current technologies. This could reduce the cost differential between remote primequality wind resources and local wind resources of moderate quality. Much of this 

improvement has already taken place and is captured in the cost estimates used for this 

study, but additional improvements are possible. 

Estimates for geothermal power account for advancements in engineered geothermal 

systems (EGS). Pilot projects suggest that including an EGS component in new 

infrastructure at sites with known geothermal potential could increase productivity by 

25% and could reduce total costs (on a per-megawatt-hour basis) by 2%.4 In this study, 

these adjustments to quantity and cost are applied to known geothermal potential that had 

not yet been developed as of 2013. 

Excluded from the analysis is a large amount of geothermal potential currently 

categorized as “undiscovered.” Its existence is inferred from statistical models of the 

spatial correlation of geologic factors that are indicative of geothermal systems, but its 

specific location is unknown. If more undiscovered resources can be located, the amount 

of developable geothermal potential incorporated into long-term regional planning could 

increase. Predicting the quantity is infeasible at this point because of insufficient data and 

the lack of a sound forecasting methodology. For the purposes of this study, we assume 

that the unknown increase in discovered geothermal resources will mostly offset the 

unknown decrease in future geothermal potential that may be due to some sites with 

known potential not being developed. 

The analysis assumes that the shape of hourly load profiles in destination markets will not 

change appreciably between 2012 and 2025. The valuation methodology gives greater 

economic weight to power delivered on peak, and this adds to the value of solar power. If 

actual profiles were to trend flatter—that is, future midday load peaks are less 

pronounced than they are today—solar resources would have a smaller time-of-delivery 

4 “Nevada Deploys First U.S. Commercial, Grid-Connected Enhanced Geothermal System,” Washington, 

D.C.: U.S. Department of Energy, April 12, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xii 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

value adder. Similarly, one case study indicates that solar power’s capacity value (i.e., the 

value of its ability to deliver power at peak times) diminishes at higher penetration rates, 

although the trend is significantly less for concentrating solar power with thermal 

storage.5 

We include a new approach to estimating future transmission and integration costs, 

noting, however, that future transmission costs and grid integration costs are difficult to 

forecast with precision. This study tests whether the difference between current delivered 

cost and the benchmark is large enough to accommodate a hypothetical doubling of 

current transmission costs.6 Figure ES-2 illustrates the “two times tariff” approach. A 

renewable energy zone is treated as having a high potential for value in 2025 if its busbar 

cost plus double the current transmission charges is less than the benchmark in the 

destination market.7 

By basing the methodology on current tariff rates rather than generic cost-per-mile line 

costs, the analysis accounts for how transmission costs can vary from one area to another. 

A transmission line of the same size is generally more expensive to build if the route 

includes mountains and forests, as compared to a route across plains. Juxtaposing 

estimates from this new approach with more conventional estimates can provide an 

additional data point for understanding the uncertainty surrounding future transmission 

costs. In most cases the “two times tariff” approach results in delivered cost estimates 

that are higher than those suggested by costs of new transmission projects that have been 

proposed along the same resource-to-market path, indicating that the methodology is 

appropriately conservative.8 

5 Mills, A. and Wiser, R. “Changes in the Economic Value of Variable Generation at High Penetration 

Levels: A Pilot Case Study of California.” LBNL-5445E. Lawrence Berkeley National Laboratory: 

Berkeley, CA, 2012.

6 We also escalate the doubled rates by 2% annually to account for inflation. Effectively, this methodology 

estimates that transmission costs will increase faster over the next 12 years than they did over the past 12 

years, and that the nominal cost of transmission in 2025 will be 59% higher than what historical trends 

would suggest.

7 “Busbar cost” refers to a technology’s annualized capital costs plus its annual operating costs, excluding 

transmission and other costs involved in moving the power from where it is generated to where it is used. 

“Delivered cost” is the combination of busbar costs, transmission costs, and any grid integration costs that 

might be assessed. 8 See Section 3 for a detailed comparison of this methodology with the projected costs of publicly 

announced major transmission projects in the West. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xiii 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

Figure ES-2. Cost benchmarking methodology 

Table ES-2. Highest-Value Regional Resource Paths Ranked by Index Score 

High value 

potential 

Busbar cost 

Busbar cost 

Current 

transmission 

cost x 2 

Current 

transmission 

cost x 2 

Wind resource 

Solar resource 

Geothermal resource 

a An index score less than 1.0 indicates a resource with a delivered cost that is still below the 

relevant state benchmark even if current transmission costs are doubled. The formula for 

calculating the score is: 

resource busbar cost + 2 × ∑ current transmission charges index score = state delivered cost benchmark 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xiv 

at www.nrel.gov/publications. 

High potential 

for value— 

index score <1 

Moderate or 

low potential 

for value— 

index score >1 

Index 

Scorea 

Wyoming wind to Nevada 0.79 

Wyoming wind to Utah 0.84 

New Mexico wind to Arizona 0.94 

Wyoming wind to Arizona 0.95 

Moderate 

value 

potential 

Wyoming wind to California 0.97 

Wyoming wind to Washington 1.04 

Wyoming wind to Oregon 1.04 

New Mexico wind to California 1.06 

Nevada solar to California 1.07 

Idaho geothermal to California 1.11 

Montana wind to Nevada 1.12 

Arizona solar to California 1.13 

Montana wind to Utah 1.17 

Montana wind to Oregon 1.18 

Montana wind to Washington 1.19 

Benchmark for 

testing delivered 

cost in destination 

market 
 

 

 

 

 

 

 

 

 

 

 

 

Table ES-1 ranks the 15 resource-to-market combinations that scored highest in the 

evaluation methodology used in this study: 

•	 Wyoming wind power delivered to Utah, California, Nevada, Oregon, 

Washington, and Arizona
 

•	 Solar power from Nevada and Arizona delivered to California 

•	 New Mexico wind power delivered to California, Arizona, and Utah 

•	 Wind power from Montana delivered to Oregon, Washington, and Utah 

•	 Geothermal power from Idaho to California. 

These resource paths have the highest likelihood of being reasonably competitive with 

natural gas generation in 2025 even if current transmission costs were to double. 

Cost Sensitivities 

Long-term trends in capital costs are difficult to predict, so this study included a 

sensitivity analysis to test how a 10% change in a technology’s assumed 2025 cost would 

affect its relative competitiveness as estimated in this study. 

The most pronounced cost sensitivity was for utility-scale solar power from Nevada and 

Arizona delivered to California. If costs were to fall 10% below the base-case 

assumptions used in this analysis, solar power from Nevada and Arizona would be close 

to parity with CCGT in California. The two resource paths would rank third and fourth 

among the potential paths with the greatest likelihood for value in a post-2025 West. A 

cost decrease would also favor California’s own solar resources, however, so the net 

impact on imports would probably be related to siting constraints. 

Results for wind power did not change significantly under different cost assumptions. 

Wyoming wind delivered to Utah and California remained below or close to parity with 

natural gas. Other wind resource paths were slightly less competitive. 

Paths for geothermal power were sensitive to cost changes. The reduced-cost scenario 

brought Idaho geothermal to within 10% of competitiveness with natural gas in 

California. Higher costs, on the other hand, could put geothermal power 30% to 85% 

above the forecasted cost of a new CCGT in 2025. 

Future Competitiveness 

Results from this study suggest that geothermal power will likely remain more costly on 

an all-in, per-MWh basis than equivalent CCGT or other renewable power options in the 

West out to 2025, barring a significant breakthrough in current technology cost or 

performance. For wind and solar built in ideal locations, the gap could become small. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xv 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table ES-3. Competitiveness Indicators for Regionally Developed Renewables in 2025 

Difference From Projected Cost of CCGT 

(%) ($/MWh) 

Geothermal 

Idaho to California, Northwest; $15–$42 higher Nevada to California; Imperial Valley 

to Arizona
 

Solar $1–$31 higher Nevada and Arizona to California 

Wind 

Wyoming and New Mexico to 

California and Arizona; Montana and Parity to $16 higher 

Wyoming to Oregon, Washington,

and California
 

12%–35% higher 

1%–19% higher 

Parity to 13% higher 

Note: Competitiveness is measured as the difference between the levelized delivered cost of an 

unsubsidized renewable resource and the levelized cost of a locally sited CCGT, with both values projected 

to 2025. Values shown here are averages derived from the resource paths indicated. Upper bounds of the 

ranges shown are calculated after increasing assumed busbar costs by 10%; lower bounds assume busbar 

costs that are 10% lower. Delivered costs use double current transmission tariff charges to proxy 

transmission and integration costs in 2025. 

Table ES-2 frames the results of the sensitivity analysis in the context of a renewable 

resource’s competitiveness, which is defined and measured here as the difference 

between the resource’s levelized delivered cost without subsidy and the levelized cost of 

a CCGT built in 2025 in the destination market. 

Competitiveness was calculated for the following resource paths: 

•	 Geothermal power: Idaho to California, Oregon, and Washington; Nevada to 

California; California (Salton Sea) to Arizona 

•	 Solar power: Nevada and Arizona to California 

•	 Wind power: Wyoming and New Mexico to California and Arizona; Montana and 

Wyoming to Oregon and Washington; Montana to California. 

Figure ES-3 compares the relative economic competitiveness in California of six 

renewable resource options, as estimated in this analysis. For each option shown on the 

chart, empirical evidence exists suggesting that large surpluses will be available in 2025. 

Most are likely to be close to the cost of a new CCGT, even if their busbar costs turn out 

to be 10% higher than the baseline estimates used in this analysis. The results suggest 

that, once the state achieves its current RPS goal in 2020, looking regionally for 

additional renewable energy supplies could provide California with reasonable diversity 

at reasonable cost. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xvi 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

Benchmark is the projected all-in cost of a new CCGT plant built in 2025, as calculated by the California 

Public Utilities Commission (PUC) for its 2011 market price referent. Busbar costs for wind and solar are 

adjusted to account for coincidence with California load. Out-of-state delivery costs are approximated 

using the “two times tariff” methodology mentioned in this summary and detailed in Section 3. 

Transmission costs within California are assumed to be the same for all resources and are not represented. 

Figure ES-3. Cost of resources projected to be available in bulk to California after 2025 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xvii 

at www.nrel.gov/publications. 
 

 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xviii 

at www.nrel.gov/publications. 
 

 

 

 

Table of Contents 

Best-Value Propositions for Post-2025 Regional Renewables ........................................................... viii
 

Surplus Prime-Quality Resources in 2025.............................................................................................ix
 

Renewable Resource Screening and Analytical Assumptions................................................................x
 

Competitiveness of Future Surpluses in Destination Markets ...............................................................xi
 

Cost Sensitivities...................................................................................................................................xv
 

Future Competitiveness ........................................................................................................................xv
 

1
 Introduction ...........................................................................................................................................1
 

1.1 Regional Framework .....................................................................................................................2
 

1.2 WREZ Phase 1 and Phase 2: Locating the Best Resources...........................................................3
 

1.2.1 Prime Renewable Resources .............................................................................................5
 

1.3 WREZ Phase 3...............................................................................................................................6
 

1.4 Major Assumptions........................................................................................................................7
 

1.5 Renewable Energy Credits...........................................................................................................10
 

1.6 Report Structure...........................................................................................................................10
 

2 State Assessments of Renewable Energy Supply and RPS-Related Demand .............................12
 

2.1 Arizona ........................................................................................................................................14
 

2.1.1 State Highlights...............................................................................................................14
 

2.1.2 Demand ...........................................................................................................................15
 

2.1.3 Supply..............................................................................................................................18
 

2.1.4 Conclusion.......................................................................................................................21
 

2.2 California .....................................................................................................................................22
 

2.2.1 State Highlights...............................................................................................................22
 

2.2.2 Demand ...........................................................................................................................23
 

2.2.3 Supply..............................................................................................................................27
 

2.2.4 Conclusion.......................................................................................................................34
 

2.3 Colorado ......................................................................................................................................35
 

2.3.1 State Highlights...............................................................................................................35
 

2.3.2 Demand ...........................................................................................................................36
 

2.3.3 Supply..............................................................................................................................39
 

2.3.4 Conclusion.......................................................................................................................41
 

2.4 Idaho ............................................................................................................................................42
 

2.4.1 State Highlights...............................................................................................................42
 

2.4.2 Demand ...........................................................................................................................43
 

2.4.3 Supply..............................................................................................................................46
 

2.4.4 Conclusion.......................................................................................................................47
 

2.5 Montana .......................................................................................................................................48
 

2.5.1 State Highlights...............................................................................................................48
 

2.5.2 Demand ...........................................................................................................................49
 

2.5.3 Supply..............................................................................................................................52
 

2.5.4 Conclusion.......................................................................................................................53
 

2.6 Nevada .........................................................................................................................................54
 

2.6.1 State Highlights...............................................................................................................54
 

2.6.2 Demand ...........................................................................................................................55
 

2.6.3 Supply..............................................................................................................................58
 

2.6.4 Conclusion.......................................................................................................................60
 

2.7 New Mexico and El Paso, Texas.................................................................................................61
 

2.7.1 State Highlights...............................................................................................................61
 

2.7.2 Demand ...........................................................................................................................62
 

2.7.3 Supply..............................................................................................................................65
 

National Renewable Energy Laboratory (NREL) 

This report is available at no cost from the 

xix
 at www.nrel.gov/publications.
 
 

 

 

 

2.7.4 Conclusion.......................................................................................................................67
 

2.7.5 El Paso, Texas .................................................................................................................68
 

2.8 Oregon .........................................................................................................................................69
 

2.8.1 State Highlights...............................................................................................................69
 

2.8.2 Demand ...........................................................................................................................70
 

2.8.3 Supply..............................................................................................................................73
 

2.8.4 Conclusion.......................................................................................................................74
 

2.9 Utah..............................................................................................................................................75
 

2.9.1 State Highlights...............................................................................................................75
 

2.9.2 Demand ...........................................................................................................................76
 

2.9.3 Supply..............................................................................................................................79
 

2.9.4 Conclusion.......................................................................................................................80
 

2.11 Washington..................................................................................................................................81
 

2.11.1 State Highlights ..............................................................................................................81
 

2.11.2 Demand...........................................................................................................................82
 

2.11.3 Supply.............................................................................................................................85
 

2.11.4 Conclusion ......................................................................................................................86
 

2.12 Wyoming .....................................................................................................................................87
 

2.12.1 State Highlights ..............................................................................................................87
 

2.12.2 Demand...........................................................................................................................88
 

2.12.3 Supply.............................................................................................................................91
 

2.12.4 Conclusion ......................................................................................................................92
 

2.13 Regional Summary ......................................................................................................................93
 

2.13.1 Highlights .......................................................................................................................93
 

3 Post-2025 Value Propositions............................................................................................................94
 

3.1 Methodology................................................................................................................................95
 

3.1.1 Estimating Busbar Costs..................................................................................................98
 

3.1.2 Estimating Transmission Costs .....................................................................................100
 

3.1.3 Uncertainties Affecting Future Transmission Costs......................................................104
 

3.1.4 Integration Costs............................................................................................................105
 

3.1.5 Ranking the Source-to-Sink Resource Paths.................................................................106
 

3.2 The Top Value Propositions......................................................................................................106
 

3.2.2 Wyoming Wind .............................................................................................................109
 

3.2.4 New Mexico Wind ........................................................................................................111
 

3.2.6 Nevada Solar .................................................................................................................113
 

3.2.8 Montana Wind...............................................................................................................114
 

3.2.9 Other Regional Surpluses..............................................................................................115
 

4 Conclusion and Next Steps..............................................................................................................123
 

Appendix: Regionalism Past and Present ............................................................................................124
 

The Advent of Regional Baseload Gigaplants....................................................................................125
 

Parallels Between Past with Present ...................................................................................................128
 

Differences..........................................................................................................................................130
 

Conclusion ..........................................................................................................................................132
 

References ...............................................................................................................................................133
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xx 

at www.nrel.gov/publications. 
 

 

 

List of Figures 

Figure ES-1. Conceptual renewable energy supply curve......................................................................... viii
 

Figure ES-2. Cost benchmarking methodology .........................................................................................xiv
 

Figure ES-3. Cost of resources projected to be available in bulk to California after 2025 ...................... xvii
 

Figure 1-1. Conceptual renewable energy supply curve ...............................................................................2
 

Figure 1-2. Map of renewable energy zone hubs identified in WREZ Phase I .............................................4
 

Figure 1-3. Characteristics of future renewable energy supply balances......................................................9
 

Figure 2-1. Arizona's renewable energy supply and demand......................................................................14
 

Figure 2-2. Arizona's residential electricity use per capita (2010)..............................................................16
 

Figure 2-3. Arizona's nonresidential electricity use per dollar of GDP (2010)...........................................16
 

Figure 2-4. Arizona's historical and projected electricity efficiencies ........................................................17
 

Figure 2-5. Arizona's Current Electricity Supply ........................................................................................19
 

Figure 2-6. California’s renewable energy supply and demand..................................................................22
 

Figure 2-7. California’s residential electricity use per capita (2010)..........................................................24
 

Figure 2-8. California’s nonresidential electricity use per dollar of GDP (2010).......................................24
 

Figure 2-9. California’s historical and projected electricity efficiencies ....................................................25
 

Figure 2-10. California’s current electricity supply ....................................................................................27
 

Figure 2-11. Renewable resource potential in California............................................................................32
 

Figure 2-12. Developed resources in California (existing, under construction)..........................................32
 

Figure 2-13. Colorado’s renewable energy supply and demand .................................................................35
 

Figure 2-14. Colorado’s residential electricity use per capita (2010) .........................................................37
 

Figure 2-15. Colorado’s nonresidential electricity use per dollar of GDP (2010) ......................................37
 

Figure 2-16. Colorado’s historical and projected electricity efficiencies....................................................38
 

Figure 2-17. Colorado’s current electricity supply......................................................................................39
 

Figure 2-18. Idaho’s renewable energy supply and demand .......................................................................42
 

Figure 2-19. Idaho’s residential electricity use per capita (2010)...............................................................44
 

Figure 2-20. Idaho’s nonresidential electricity use per dollar of GDP (2010)............................................44
 

Figure 2-21. Idaho’s historical and projected electricity efficiencies..........................................................45
 

Figure 2-22. Idaho’s current electricity supply ...........................................................................................46
 

Figure 2-23. Montana’s renewable energy supply and demand..................................................................48
 

Figure 2-24. Montana’s residential electricity use per capita (2010)..........................................................50
 

Figure 2-25. Montana’s nonresidential electricity use per dollar of GDP (2010) .......................................50
 

Figure 2-26. Montana’s historical and projected electricity efficiencies ....................................................51
 

Figure 2-27. Montana’s current electricity supply ......................................................................................52
 

Figure 2-28. Nevada's renewable energy supply and demand.....................................................................54
 

Figure 2-29. Nevada’s residential electricity use per capita (2010)............................................................56
 

Figure 2-30. Nevada’s nonresidential electricity use per dollar of GDP (2010).........................................56
 

Figure 2-31. Nevada’s historical and projected electricity efficiencies ......................................................57
 

Figure 2-32. Nevada’s current electricity supply ........................................................................................59
 

Figure 2-33. New Mexico's renewable energy supply and demand ............................................................61
 

Figure 2-34. New Mexico’s residential electricity use per capita (2010)....................................................63
 

Figure 2-35. New Mexico’s nonresidential electricity use per dollar of GDP (2010).................................63
 

Figure 2-36. New Mexico’s historical and projected electricity efficiencies..............................................64
 

Figure 2-37. New Mexico’s current electricity supply................................................................................66
 

Figure 2-38. Oregon’s renewable energy supply and demand ....................................................................69
 

Figure 2-39. Oregon’s residential electricity use per capita (2010) ............................................................71
 

Figure 2-40. Oregon’s nonresidential electricity use per dollar of GDP (2010) .........................................71
 

Figure 2-41. Oregon’s historical and projected electricity efficiencies.......................................................72
 

Figure 2-42. Oregon’s current electricity supply.........................................................................................73
 

Figure 2-43. Utah’s renewable energy supply and demand ........................................................................75
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xxi 

at www.nrel.gov/publications. 
 

 

 

 

 

Figure 2-44. Utah’s residential electricity use per capita (2010).................................................................77
 

Figure 2-45. Utah’s nonresidential electricity use per dollar of GDP (2010) .............................................77
 

Figure 2-46. Utah’s historical and projected electricity efficiencies...........................................................78
 

Figure 2-47. Utah’s current electricity supply.............................................................................................79
 

Figure 2-48. Washington’s renewable energy supply and demand.............................................................81
 

Figure 2-49. Washington’s residential electricity use per capita (2010).....................................................83
 

Figure 2-50. Washington’s nonresidential electricity use per dollar of GDP (2010)..................................83
 

Figure 2-51. Washington’s historical and projected electricity efficiencies ...............................................84
 

Figure 2-52. Washington’s current electricity supply .................................................................................86
 

Figure 2-53. Wyoming’s renewable energy supply and demand ................................................................87
 

Figure 2-54. Wyoming’s residential electricity use per capita (2010) ........................................................89
 

Figure 2-55. Wyoming’s nonresidential electricity use per dollar of GDP (2010) .....................................89
 

Figure 2-56. Wyoming’s historical and projected electricity efficiencies...................................................90
 

Figure 2-57. Wyoming’s current electricity supply.....................................................................................91
 

Figure 3-1. Illustration of cost benchmarking methodology .......................................................................95
 

Figure 3-2. Projected supply cost of Wyoming wind power ($/MWh at the busbar)................................109
 

Figure 3-3. Projected supply cost of New Mexico wind power ($/MWh at the busbar)...........................111
 

Figure 3-4. Projected supply cost of Nevada solar power ($/MWh at the busbar)....................................113
 

Figure 3-5. Projected supply cost of Montana wind power ($/MWh at the busbar) .................................114
 

Figure 3-6. Cost of resources projected to be available in bulk to California after 2025..........................118
 

Figure A-1. Implied exports and imports among western regions based on generation 

and consumption...................................................................................................................125
 

Figure A-2. U.S. coal units from 1940 to 2000, by nameplate capacity and year online, with units
 

Figure A-3. Direction of historical commercial flows of power from major baseload plants in the 

built in the Western Interconnection larger than 500 MW...................................................126
 

Western Interconnection (those with units 500 MW or larger)............................................127
 

Figure A-4. Geothermal, wind, solar share of generation in WECC (U.S. only)......................................129
 

Figure A-5. Recovery of capital costs through a utility’s rate base...........................................................131
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xxii 

at www.nrel.gov/publications. 
 

 

 

List of Tables 

Table ES-1: Major Findings about Surplus Resources in 2025....................................................................ix
 

Table ES-2. Highest-Value Regional Resource Paths Ranked by Index Score .........................................xiv
 

Table ES-3. Competitiveness Indicators for Regionally Developed Renewables in 2025.........................xvi
 

Table 2-1. Comparison of California Capacity Identified in WREZ and RETI Analyses (MW) ...............29
 

Table 2-2. California Resources Estimated to be Available for Future Development ................................33
 

Table 2-3. El Paso Electric in Texas and New Mexico ...............................................................................68
 

Table 3-1. Adjustments Applied to the MPR Fixed-Cost Component........................................................97
 

Table 3-2. Adjustments Applied to the MPR Variable-Cost Component ...................................................97
 

Table 3-3. State Cost Benchmarks ..............................................................................................................98
 

Table 3-4. Current Tariff Rates for Long-Term Firm Point-to-Point Transmission Service ....................101
 

Table 3-5. Tariffs Used for Indicative Source-to-Sink Transmission Charges.........................................102
 

Table 3-6. “Tariff Times Two” Values Used in Scoring Resource Paths ($/MWh) .................................102
 

Table 3-7. Highest-Value Source-to-Sink Resource Paths Ranked by Index Score .................................108
 

Table 3-8. Full List of Resource Path Scores ............................................................................................116
 

Table 3-9. Competitiveness Indicators for Regionally Developed Renewables in 2025 ..........................117
 

Table 3-10. Scores After Decreasing Solar Busbar Costs by 10%............................................................120
 

Table 3-11. Scores After Increasing Solar Busbar Costs by 10%.............................................................120
 

Table 3-12. Scores After Decreasing Wind Busbar Costs by 10% ...........................................................121
 

Table 3-13. Scores After Increasing Wind Busbar Costs by 10%.............................................................121
 

Table 3-14. Scores After Decreasing Geothermal Busbar Costs by 10% .................................................122
 

Table 3-15. Scores After Increasing Geothermal Busbar Costs by 10%...................................................122
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xxiii 

at www.nrel.gov/publications. 
 

 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) xxiv 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

1 Introduction 

This study assesses the outlook for further renewable energy development in the West 

once states have met their renewable portfolio standard (RPS) requirements. While it is 

too early to predict what future policies and market factors will drive post-2025 demand 

for utility-scale renewables, it is possible to forecast what the supply picture will look 

like once current RPS targets have been achieved. The aim of this study is to assemble an 

empirical picture of that future supply to help inform discussions about policies targeting 

future renewable energy development. 

Most western states appear to be on track to meet their final RPS requirements, relying 

primarily on renewable resources located relatively close to the customers being served. 

If by 2025 the least-expensive local resources are already in use, then developing the next 

tier of low-cost renewable resources could require new approaches. These could include 

developing large-scale regional projects farther from the customers being served, 

pursuing strategies to increase the value of small-scale distributed generation (DG), or 

finding innovative ways to expand into harder-to-develop and less-productive local 

resource areas. None of these approaches precludes the others. Balancing them into a 

coherent portfolio of strategies will depend in part on how state policy makers and utility 

planners weigh the present uncertainties of each. 

The focus of this study is regional large-scale renewable resource development, 

comparable to what occurred in the 1970s with the development of large central-station 

coal and nuclear plants. A significant amount of power flows across state borders today 

because of these regional baseload plants, with California as the largest destination 

market. This earlier regionalism relied on emerging technologies whose ability to achieve 

economies of scale depended on locational factors that were often far from the customers 

being served—factors not unlike those affecting large-scale renewable energy 

development today. 

Small-scale renewable DG is outside the scope of this particular study. This does not 

diminish the importance of DG as a long-term resource. Rather, it recognizes that DG and 

utility-scale renewables face different issues of comparable complexity and are best 

analyzed on their own merits separately. Similarly, local development constraints tend to 

be shaped by local circumstances, requiring individualized analytical approaches rather 

than a systematic regional approach. 

The analytical aim is to forecast the characteristics of the best utility-scale renewable 

resources in the West that are likely to remain undeveloped by 2025. The analysis begins 

by examining how deeply each state has gone—and could go—into its own stock of 

renewable resources to meet its RPS mandate. What might appear in this analysis as a 

supply shortfall does not necessarily mean an RPS is in jeopardy. Rather, it suggests that 

additional prime-quality renewable resources available for new development locally may 

be systematically scarce at the point that the state achieves its RPS goal. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 1 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 $-

0

 Resource options 

energy supply 

Cost of renewable 

in order of cost 

($/MWh) RPS-related 

demand in 2025 

Cumulative amount of developed renewable energy resources (TWh per year) 

RPS demand Post-RPS demand 

time 

Figure 1-1. Conceptual renewable energy supply curve 

Figure 1-1 conceptually illustrates how this analysis proceeds. RPS mandates are the 

primary drivers for in-state renewable energy demand to date. Demand tends to take the 

least-expensive developable options first. If anything on the low-cost end of the supply 

curve is not developed, it is likely because of site-specific issues capable of preventing 

future development as well. Generally, what remains in-state after satisfying RPS 

demand tends to be more expensive than the resources already developed. 

1.1 Regional Framework 

Regionalism is challenging, even when it makes economic sense. Despite some limited 

precedent for regionalism in the West, the regulatory institutions that have shaped 

electricity policy and decisions are largely state and local. There are few institutions 

within which states can engage in collaborative decision making because federalism sets 

boundaries on the ability of states to act in concert over matters involving interstate 

commerce.9 Generally, local projects are easier to do even if they cost more. 

The American Recovery and Reinvestment Act of 2009 recognized this challenge by 

setting aside $80 million “for the purpose of facilitating the development of regional 

transmission plans.”10 Regional energy planning has been a conversation among western 

states for several years under the aegis of the Western Governors’ Association (WGA) as 

well as in other venues.11 The Recovery Act tasked the U.S. Department of Energy 

(DOE) with providing technical assistance to entities such as WGA so that their dialogue 

could be informed by updated data and state-of-the-art analysis. This study is one of the 

many activities funded by DOE under this section of the Recovery Act. 

9 Kundis Craig, R. “Constitutional Contours for the Design and Implementation of Multistate Renewable
 

Energy Programs and Projects,” University of Colorado Law Review, (81:3), 2010; pp. 771.
 10 American Recovery and Reinvestment Act of 2009, Title IV. H.R. 1. 110th Congress (Feb. 16, 2009).
 11 See, for example, Clean and Diversified Energy Initiative, Western Governors’ Association, 2006; 10-

Year Energy Vision: Goals and Objectives, Western Governors’ Association, 2013.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 2 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

This analysis focuses on the U.S. portion of the Western Interconnection, which has 86% 

of the region’s supply of generation and 87% of its demand.12 Although British 

Columbia, Alberta, and northern Baja California are also part of the western grid, this 

report assumes that movement toward regionalism will depend on whether U.S. states can 

reach consensus on moving forward. The analysis assumes further that if a U.S. 

consensus were to happen, there would be few barriers to participation by developers 

operating in the Canadian western provinces or Baja California. Focusing this analysis on 

the U.S. portion is also consistent with the purposes of the Recovery Act. 

Many technical issues of interest primarily to utility planners and engineers are outside 

the scope of this analysis and are addressed elsewhere.13 Nevertheless, the regional value 

propositions identified in this analysis could be important inputs to deciding which 

technical issues should be addressed first. Operational changes, such as a regional energy 

imbalance market and sharing reserves across several balancing authority (BA) areas, 

would also require some institutional framework; how easily and quickly those 

institutional changes come about could rest on the strength of policy support from states. 

1.2 WREZ Phase 1 and Phase 2: Locating the Best Resources 

This study builds on a number of preceding related efforts. In 2007, WGA asked DOE for 

federal support to identify renewable energy zones in the Western Interconnection. The 

Western Renewable Energy Zone (WREZ) initiative contemplated several phases, the 

first of which was a cross-sectional assessment of renewable resources throughout the 

West. Phase 1 was conducted for WGA by the National Renewable Energy Laboratory 

(NREL), under the guidance of a steering committee comprising state and provincial 

energy officials and with input from a diverse group of stakeholders.14 Phase 2, 

conducted by Lawrence Berkeley National Laboratory (LBNL), was a transmission 

analysis linking the Phase 1 resource hubs with the interconnection’s largest demand 

centers. The centerpiece of that work was a tool that stakeholders can use to compare 

scenarios for delivering renewable resources from selected zones to selected load centers. 

12 2011 Power Supply Assessment. Salt Lake City, UT: Western Electricity Coordinating Council (WECC),
 

Nov, 17, 2011.

13 For a comprehensive overview of the technical issues currently under discussion among utility planners
 

in the West, see: Meeting Renewable Energy Targets in the West at Least Cost: The Integration Challenge.
 

Denver, CO: Western Governors’ Association, June 2012.
 

www.westgov.org/wieb/meetings/crepcsprg2012/briefing/WGAivg.pdf. 14 Western Renewable Energy Zones – Phase 1 Report. Denver, CO: Western Governors’ Association, 

June 2009. http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/WREZ_Report.pdf. For the 

technical analysis behind this report, see: Pletka, R.; Finn, J. Western Renewable Energy Zones, Phase 1: 

QRA Identification Technical Report. NREL/SR-6A2-46877. Golden, CO: National Renewable Energy 

Laboratory, October 2009. www.nrel.gov/docs/fy10osti/46877.pdf. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 3 

at www.nrel.gov/publications. 
 

 

 

 

 

 

Figure 1-2. Map of renewable energy zone hubs identified in WREZ Phase I15 

15 Western Renewable Energy Zones – Phase 1 Report. Denver, CO: Western Governors’ Association, 

June 2009. http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/WREZ_Report.pdf. Original 

Black & Veatch published map updated by NREL with wind speed data at 80-meter and 100-meter hub 

height developed by AWS Truepower LLC. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 4 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The map in Figure 1-2 summarizes the work of WREZ Phase 1. The resource areas 

shown on the map are those that remained after several levels of screening. Resource 

screens eliminated areas with little wind and little sunshine during a typical year. Landuse screens eliminated national parks and other protected areas, as well as areas where 

the terrain would make the cost of development prohibitively expensive or otherwise 

impractical. The remaining areas represent the highest concentrations of the most 

productive wind, solar, and geothermal resources—qualified resource areas (QRAs). 

1.2.1 Prime Renewable Resources 

This study uses updates to the screened resources from the Phase 1 analysis to locate and 

estimate export-quality renewable potential. While the WREZ Phase 1 analysis was a 

highly selective screening of renewable resource potential across the Western 

Interconnection, this analysis uses an even more rarified subset of WREZ resources. 

These prime resources include: 

•	 All identified geothermal potential16 

•	 Solar resources that passed WREZ screening and have direct normal insolation 

(DNI) of at least 7.5 kWh per square meter per day 

•	 Wind resources that passed WREZ screening and have estimated annual capacity 

factors of at least 40%. 

The criteria for prime wind resources used in this study incorporate recently updated 

wind speed data at 80- and 100-meter hub heights based on new mesoscale modeling by 

AWS Truepower. The original WREZ Phase 1 study relied on large cross-sectional 

mesoscale wind speed simulations that covered the entire Western Interconnection. The 

old dataset estimated wind speeds at a height of 50 meters, with annual characteristics 

represented as wind speed “classes.” The WREZ Phase 1 analysis estimated that wind 

areas Class 5 or higher had average annual capacity factors of 35% or higher. The best 

areas at 80 meters largely coincide with the best areas at 50 meters, but the capacity 

factors are generally higher. In some WREZ areas where the wind speed regimes were 

slower, productivity was estimated based on Class 3 wind turbines at a hub height of 100 

meters. 

For this analysis, prime wind resources are those with an average annual capacity factor 

of 40% or better at a hub height of 80 meters. 

Estimates for geothermal power have been updated to account for recent advancements in 

engineered geothermal systems (EGS). Pilot projects suggest that including an EGS 

component in new infrastructure at sites with known geothermal potential could increase 

productivity by 25% and could reduce total costs (on a per-megawatt-hour basis) by 

16 Unlike wind and solar, where surface measurements enable the estimation of detailed output gradients, 

geothermal’s first-order distinction is between “discovered” potential (sites where some exploration has 

taken place and where data indicates potential) and “undiscovered” potential (resources thought to exist 

across a general area based on interpolation between measurement points but whose precise location is 

unknown). The amount of undiscovered potential estimated in WREZ Phase 1 is about five times the 

amount of discovered potential. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 5 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2%.17 In this study, these adjustments to quantity and cost are applied to known 

geothermal potential that had not yet been developed as of 2013. We still exclude from 

the analysis a large amount of geothermal potential currently categorized as 

“undiscovered” (its existence is inferred from statistical models of the spatial correlation 

of geologic factors that are indicative of geothermal systems, but its specific location is 

unknown). For the purposes of this study, we assume that the unknown increase in 

discovered geothermal resources will mostly offset the unknown decrease in future 

geothermal potential that may be due to some sites with currently known potential not 

being developed. 

1.3 WREZ Phase 3 

The third phase of the WREZ work, conducted by the Regulatory Assistance Project, 

involved interviews with utility resource planners, state utility commissioners, and 

Canadian provincial energy ministries.18 The aim was to assess current views about the 

prospects for regional coordination on strategies to develop renewable resources in the 

QRAs identified in Phase 1. 

Many of the Phase 3 findings are pertinent to questions that are addressed in this report:

19 

•	 Nearly all utilities believe the cost of generation from renewable resources will 

continue to trend downwards, both for DG and utility-scale generation. They also 

believe utility-scale generation will continue to be less costly than customer-sited 

DG. 

•	 Diversifying the types of renewable resources acquired is an increasingly 

important driver for utility resource selection, particularly with increasing levels 

of variable energy resources and related integration concerns. 

•	 Utilities are focused on developing renewable resources in or close to their service 

areas. Among the reasons is that resources close to load may not require new 

high-voltage transmission and, therefore, are easier to develop in a more 

incremental manner. Even where transmission capacity is available, the 

economics of distant, higher-quality resources may be diminished by pancaking 

of charges—purchasing transmission service separately from each provider whose 

lines the power crosses to reach loads.20 In-state resources also are a more 

obvious nexus with state public interest standards for siting and cost recovery, 

reducing development timelines, and risk for utilities. 

17 “Nevada Deploys First U.S. Commercial, Grid-Connected Enhanced Geothermal System,” Washington, 

D.C.: U.S. Department of Energy, April 12, 2013.

18 Renewable Resources and Transmission in the West: Interviews on the Western Renewable Energy Zone 

Initiative. Denver, CO: Western Governors’ Association, March 2012. 

http://www.westgov.org/wieb/meetings/crepcfall2011/briefing/10-18-11WREZes.pdf. 19 For a full listing of all the findings and recommendations, see WREZ Phase 3, executive summary. 20 “Rate pancaking” is a common term in electricity regulation. The term is used throughout this report to 

refer to the accumulation of transmission charges between the point of generation and the point of delivery 

to end-use customers. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 6 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

•	 Utilities are less interested in resources from WREZ hubs unless transmission to 

the hub already exists or there is a high degree of certainty for the timely 

completion of transmission to the hub. 

•	 Two-thirds of the utilities interviewed say state policies or regulations impede 

development of interstate transmission. Key areas of concern are local siting 

processes, inconsistent siting standards across borders, and cost recovery risk. 

Public utilities commissions (PUCs) and provincial energy ministries cited the 

following hurdles: demonstration for a given state that a line is needed and will 

serve the public interest, lack of eminent domain authority, multiple 

uncoordinated approvals required by various levels of government, and cost 

recovery processes. 

•	 Some utilities believe cooperation is required to develop resources in distant 

WREZ hubs and associated transmission. 

•	 Most utilities said the institutional structure in place in the West is adequate, or 

can be adapted, to successfully develop transmission to WREZ hubs. However, 

some utilities believe institutional and legislative changes are needed, including 

regional coordination of market functions and a clear long-term signal on 

environmental priorities. 

Overall, the WREZ Phase 3 findings suggest that the potential benefit of long-distance 

renewables is tempered by uncertainties and that existing rules and practices do not 

address these uncertainties very well. Collaboration makes sense to many, but the 

solutions coming out of such discussions could require institutional innovation beyond 

what current state policies and regulations typically contemplate. RPS mandates are the 

basis of current renewable energy procurement; because this demand is not strictly pricesensitive, projects that are easy and quick have a comparative advantage over less-costly 

projects that require more time and entail more regulatory uncertainty. 

This study is intended to continue the discussion by evaluating what the market for 

renewable power might look like if present obstacles and uncertainties were addressed. 

Institutional innovation is most likely to succeed when it aligns with the most favorable 

economic forces. The question posed here is: Assuming RPS mandates no longer drive 

renewable energy expansion, which regional transactions would make the most economic 

sense, where would they be, and how would they compare with other options for new 

generation? 

1.4 Major Assumptions 

Four common-sense assumptions guide forecasts of the prime resources likely to remain 

untapped by 2025. 

•	 Utilities in a state will prefer using in-state prime resources whenever possible to 

meet their RPS requirements. 

•	 Prime out-of-state resources will not be preferred unless there are no more prime 

in-state resources. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 7 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

•	 Only surplus prime resources will have a meaningful place in a regional post2025 market. 

•	 Utilities will prefer a diversity of resource types in their RPS compliance 

portfolios. 

These assumptions are consistent with feedback from utility planners and regulators 

obtained as part of the WREZ Initiative. Exceptions might occur, but we assume here that 

the exceptions are neither frequent nor systematic. 

We assume more generally that any post-2025 renewable energy market that evolves in 

the West will have two interdependent drivers: state policies and utility business 

decisions. For utility-scale renewables in a post-2025 market, achieving economies of 

scale could require multiparty deals and capital investments spanning several states, 

similar to the expansion of coal baseload plants in the 1970s. The related business risks 

are different than what they were in the 1970s, however, and the ability of utilities to 

address them may depend on whether state decision makers can find consensus on 

coordinated goals and policies. This study presumes throughout that coordinated state 

policies would result in clearer market signals to guide utility business decisions. 

Figure 1-3 illustrates the supply and demand framework used in this study. The approach 

is based on the economics of trade: discrete political entities—in this case, states—are 

similar in their pursuit of economic wellbeing but begin with different resource 

endowments. If some states have more of a desired good than they need and other states 

have less than they need, there should be room for exchanges that would leave most 

states better off and no state worse off. 

The renewable resources available to a state include those within its own jurisdiction and 

those available from other states. Demand will tend to absorb the prime supply first 

because the per-megawatt-hour cost is more attractive. Over time, however, meeting 

additional demand will require developing resources of lower quality that will tend to 

cost more. 

The first chart in Figure 1-3 illustrates how the regional supply pool forms. If a state’s 

own demand for renewable power is small relative to its own supply of prime resources, 

then the state loses nothing by making its surplus available for export. In-state demand 

uses the most productive and least-cost in-state resources, and the surplus made available 

for export is potentially more productive and lower in cost than the undeveloped 

resources in a prospective importing state. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 8 

at www.nrel.gov/publications. 
 

 

 

 

 

 

Existing Supply 

Already producing power or are under 

construction. Some existing supply may 

not be prime quality. 

Unused Prime Renewable Resources 

Prime quality renewable resource 

potential inside a renewable energy zone 

that has not yet been developed 

Other Renewable Resources 

•	 Unused potential within a renewable 

energy zone that is not prime quality 

•	 Isolated areas that would be 

counted as prime quality had they 

been located in a renewable energy 

zone 

Future Surplus of Prime Renewable Resources (Ability to Export) 

Future Shortage of Prime Renewable Resources (Potential for

Import)
 

Figure 1-3. Characteristics of future renewable energy supply balances 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 9 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

The second chart shows the economic drivers for importing. The example state’s prime 

resources are enough to meet the early increments of renewable energy demand. Later, as 

demand continues to grow, economic competition arises between the state’s remaining 

undeveloped resources and imported resources that are more productive and easier to 

develop. The critical juncture is when the cost of the next in-state project is greater than 

the cost of the best imports, taking into account transmission costs. Past that point, 

foregoing imports in favor of less-productive in-state capacity would result in higher 

costs to the state’s retail electric customers. 

1.5 Renewable Energy Credits 

Some states allow utilities to use unbundled renewable energy credits (RECs) to meet 

part of an RPS requirement. Unbundled RECs allow a utility to count towards its RPS 

compliance the energy produced by a remote renewable energy facility even if the energy 

is not delivered to the utility’s customers. They are a way of bridging an apparent 

shortfall between what a utility needs for RPS compliance and the renewable resources 

physically available for delivery to customers. 

We assume here that unbundled RECs will be used less often after 2025. By then, current 

RPS requirements will have culminated and, consequently, RPS compliance is unlikely to 

be a significant driver for procuring additional renewable energy supplies. The factors 

most likely to drive renewable energy procurement after 2025—switching to clean 

energy sources, replacing old capacity, responding to consumer preferences—generally 

involve energy delivery. 

1.6 Report Structure 

This report begins by looking at each state individually to estimate its RPS-related 

demand and to forecast how much of the state’s best resources are likely to remain. The 

aim is to see whether a state is a likely importer or exporter in 2025. Total electricity 

demand projected forward to 2025 is the basis for estimating in-state demand for 

renewable power, based on the state’s current RPS requirements. The updated WREZ 

Phase 1 analysis provides a carefully screened approximation of the plausible availability 

of in-state utility-scale resources. 

Next, the study combines the salient attributes of each state into a trade picture of the 

West as a whole, conceptually erasing state borders and examining aggregated supply 

and demand as though it were contained in one market. We describe an approach for 

combining the busbar cost of remote renewable resources with plausible proxy values for 

transmission cost so that the delivered cost of imported renewable resources can be 

compared with the cost of the in-state resources that, after 2025, are likely to 

be undeveloped. 

The analytical synthesis results in a number of value propositions for interstate flows of 

renewable power. “Value proposition” means there is reasoned justification for believing 

that a corresponding investment in infrastructure would be responsive to a foreseeable 

demand if it were built. The stronger the potential value, the more likely it would be that 

renewable resource developers would compete for that future opportunity. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 10 

at www.nrel.gov/publications. 
 

 

This report concludes with a brief look at the historical precedent for regionalism in the 

electricity sector. Cross-state collaboration occurred in the 1970s and 1980s with respect 

to large baseload plants. The analysis looks at the similarities and differences between 

that earlier round of regionalism and current factors affecting large-scale deployment of 

renewable power. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 11 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2 State Assessments of Renewable Energy 

Supply and RPS-Related Demand 

This section describes the supply of undeveloped renewable resources that each state in 

the West is likely to have in 2025. First, the analysis derives a plausible range of 

renewable energy each state is likely to need in 2025 to satisfy RPS targets as they exist 

in law today. It then identifies the resources that have been developed to date and 

compares the balance of RPS-related demand with the best remaining resources. 

Renewable energy projects that already exist and are producing power are generally 

assumed to apply to the RPS in the state where the development occurs. Where 

ownership or contract information is known, however, project output is assigned to the 

states identified in the agreements. The same approach is applied to projects under 

construction, except that annual energy production is estimated. 

For the purpose of estimating resource availability, the analysis assumes that all 

renewable energy development—whether for in-state use or for export to other states— 

may be subtracted from the pool of resources estimated to exist in the renewable energy 

zones identified in the WREZ activities described in Section 1. While some projects 

might in fact be outside a zone, the assumption is that these exceptions are not numerous 

enough to systematically compromise the usefulness of using the WREZ analysis to 

quantify developable resources. The operational assumption is that the best WREZ 

resources are used first. 

The state laws setting RPS requirements express their targets as a percentage of retail 

sales. Several factors can influence future electricity sales, and these uncertainties are 

accounted for by expressing future demand as a plausible range rather than a single 

number. Two methodologies define each state’s plausible range. One is the methodology 

used by the State/Provincial Steering Committee (SPSC) to forecast future load for the 

purposes of long-term regional planning.21 The other is a method developed for this study 

based on mathematical extenstions of historical trends. 

The SPSC begins with load projections for BA areas provided by utilities themselves. 

The SPSC, with support from LBNL, reviewed and adjusted the utility load projections to 

ensure consistency with state energy efficiency requirements. Load is not the same as 

electricity sold to retail customers, however. Because most RPS requirements are based 

on retail sales rather than load, we reduce the load projections by 10% to generally 

account for line losses, wholesale power transactions, and other loads that are not retail 

sales and, therefore, do not represent an RPS requirement.22 

21 The SPSC operates under the aegis of the WGA and comprises representatives of governors, premiers,
 

and public utility commissioners. The SPSC’s role is to provide state input into regional transmission
 

planning and related analytical efforts affecting the Western Interconnection. 22 The load forecasts approved by the SPSC are for 2020. We project those forecasts to 2025 by applying
 

compound annual growth rates used by the Western Electricity Coordinating Council in its long-term
 

planning analyses.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 12 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

Calculations from historical trends starts with dividing retail sales into two components: 

residential and nonresidential (primarily commercial and industrial retail sales). The next 

step is to calculate historical efficiencies in each of the two sectors. The indicator for 

residential efficiency is residential sales per resident, expressed as annual megawatthours sold per capita. For nonresidential efficiency, the indicator is nonresidential 

kilowatt-hours sold per dollar of state gross domestic product (GDP). 

Energy Information Administration data on state electricity sales and U.S. Census Bureau 

data on state population are combined to calculate each state’s annual per-capita 

residential electricity sales from 1990 through 2010. A linear trend applied to the 

historical observations provides each state’s projected per-capita residential electricity 

sales for 2025. The projected sales per capita is then multiplied by the Census Bureau’s 

2025 population projection, resulting in projected residential sales for 2025. 

Nonresidential efficiency trends are nonlinear, requiring a different forecasting 

methodology. State GDP data combined with nonresidential sales establish each state’s 

annual electricity intensity (nonresidential megawatt-hours sold per dollar of GDP). For 

most states, electricity intensity has fallen since 1998, presumably due to improvements 

in energy efficiency. An exponential decay function applied to the historical data ensures 

that the predicted trend does not fall below 0 MWh per dollar of GDP and is used to 

forecast efficiency in the nonresidential sector in 2025. (The recession years 2008 

through 2011 are excluded from the trend estimation.) Each state’s projected GDP for 

2025 is based on the state’s historical GDP growth from 1998 through 2007, applied 

forward from 2011 actual GDP. The product—projected nonresidential sales per dollar of 

GDP times projected GDP—yields projected nonresidential sales for 2025. 

Finally, combining the two calculations for retail sales—one obtained from SPSC 

projections, the other from historical trends of residential and nonresidential sales— 

provides the inputs to current RPS requirements as they are expressed in law today. The 

plausible range of what a state is likely to need in 2025 to satisfy RPS requirements is 

bounded by these two values. 

In theory, the calculations based on historical data should be higher than the calculations 

based on the extended SPSC estimates. In some cases, however, the historical data yield 

lower estimates. This is due to low estimates for nonresidential electricity sales, arising 

from unusually steep declines in megawatt-hours per dollar of state GDP between 1998 

and 2007, the period used to establish the trends. Three factors can accelerate the 

observed efficiency gains: unusually strong energy efficiency improvements; sectoral 

changes away from electricity-intensive activities, such as mining, and toward those that 

are less electricity intensive, such as services; and changes in commodity prices that 

increase the cash value of a sector’s output relative to the rest of the economy. The 

analysis does not control for these effects. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 13 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

2.1 Arizona 

2.1.1 State Highlights 

• Arizona will need between 7.9 TWh and 8.5 TWh of renewable energy in 2025 to meet 

targets stipulated by current state rules. 

• Renewable electricity projects existing or under development as of 2012 can supply 

3.2 TWh annually. 

• Prime, export-quality solar resources that have not yet been developed could provide 

at least 2.7 TWh annually. The state has an additional 44 TWh of non-prime solar, 

biomass, and wind resources that could meet in-state demand. 

Arizona has sufficient renewable resources—mostly solar—to meet its 2025 

requirements. As of 2011, Arizona ranked last among all western states in renewables as 

a share of total generation, but new solar projects coming online will significantly 

increase that share. Arizona could expand and diversify its renewable energy portfolio by 

importing base-load geothermal and low-cost wind power (which it currently does in 

small amounts) and by further developing its in-state biomass and wind resources. 

Diversification could reduce costs, improve operations, and facilitate additional exports 

of prime-quality solar power. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. Arizona also has an estimated 41.9 TWh of developable solar 

potential in areas with DNI between 7.25 and 7.50. 

Figure 2-1. Arizona's renewable energy supply and demand23 

23 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 14 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.1.2 Demand 

Arizona’s renewable energy standard (RES) requires investor-owned utilities (IOUs) and 

cooperatives that have the majority of their customers in Arizona to meet 15% of their 

retail electric sales through eligible renewable technologies by 2025 and thereafter.24 The 

RES includes interim goals that increase gradually each year until 2025. Starting in 2012, 

30% of the required renewable energy must come from distributed renewable resources, 

with half of that amount from residential distributed systems and the other half from 

nonresidential, non-utility applications. Half of the DG must come from residential 

applications. Extra credit multipliers are awarded for certain technologies, in-state solar 

installations, and for facilities using products manufactured in Arizona. 

Utilities can also earn renewable energy certificates (RECs) for investments in, or 

incentives provided to, in-state solar manufacturing plants, based on the capacity of 

panels manufactured by the facilities. Those RECs are applied to the main RPS tier—the 

segment not reserved for distributed systems—and cannot account for more than 20% of 

the annual requirement. Energy efficiency does not count toward the RES. Energy 

produced by eligible renewable energy systems must be deliverable to the state. 

Salt River Project (SRP), the state’s largest utility, is not subject to the RES because it is 

a public power utility. Nevertheless, SRP’s governing board has approved its own 

renewable energy target of 20% by 2020 (including hydro).25 

The RES requirement is calculated as percentages of sales. The amount of renewable 

energy needed to meet the requirement is sensitive to total electricity demand and, 

similarly, to the success of energy efficiency programs. The level of energy intensity, 

GDP, population growth, and energy efficiency all affect total electricity demand. 

2.1.2.1 Residential Consumption Trends 

On average, Arizona residents used 5.06 MWh per person in 2010 (see Figure 2-2). 

Historical trends suggest that the residential consumption rate will reach 6.22 MWh per 

person in 2025, which would be the highest in the region (see Figure 2-4). 

The U.S. Census Bureau projects a 33% increase in Arizona’s population between 2011 

and 2025, which also the highest rate in the region. This would put Arizona’s population 

at 9.5 million, making it the second-most populous state in the West, after California. 

Combining the projected trend in per-capital residential use with projected population 

growth suggests a total demand of 59 TWh in the Arizona residential sector for 2025, 

excluding the effect of new energy efficiency measures. 

24 The RES was enacted by the Arizona Corporation Commission through its regulatory rulemaking 

authority, unlike requirements in most other states that were enacted by statute. The Arizona attorney
 

general certified the constitutionality of the rule in 2007.

25 To learn more about SRP’s goal for renewable energy, see:
 

http://www.srpnet.com/environment/renewable.aspx.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 15 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-2. Arizona's residential electricity use per capita (2010)26 

Figure 2-3. Arizona's nonresidential electricity use per dollar of GDP (2010)27 

26 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 27 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “Regional Economic Accounts.” U.S. Bureau of
 

Economic Analysis, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 16 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

Figure 2-4. Arizona's historical and projected electricity efficiencies28 

2.1.2.2 Nonresidential Consumption Trends 

Arizona’s electricity intensity (nonresidential electricity use per dollar of GDP) is typical 

for the region. In 2010, the state used 0.16 kWh per dollar of GDP (see Figure 2-3). As 

with other states, Arizona’s electricity intensity in the nonresidential sector has declined 

significantly in recent decades (see Figure 2-4), indicating greater electricity efficiency in 

the output of goods and services. The state is expected to continue improving between 

2011 and 2025. 

2.1.2.3 Energy Efficiency Measures 

In 2009, the Arizona Corporation Commission (ACC) adopted an Energy Efficiency 

Resource Standard (EERS). Beginning in 2010, Arizona IOUs and cooperatives were 

required to save 1.25% of their previous year’s retail electricity sales. The requirement 

increases to 2% beginning in 2014. Funding for utility-led efficiency programs is 

collected through customer rates. 

Under the EERS, the state as a whole needs to achieve a total of 22% savings from 

efficiency by 2020, including a 2% reduction in peak demand from demand response 

activities.29 Based on historical trends, Arizona electricity demand will reach 85 TWh in 

2019, which would imply a required savings of 17 TWh in 2020. 

28 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012; “Regional Economic Accounts.” U.S. Bureau of Economic Analysis, June 2012. 29 “State Energy Efficiency Policy Database.” American Council for an Energy-Efficient Economy
 

(ACEEE), 2013. Accessed Oct. 16, 2012: http://www.aceee.org/sector/state-policy/arizona.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 17 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Arizona spent $126 million on electric energy efficiency in 2011, about 1.74% of retail 

revenues. The ACEEE estimates that 710 GWh of new electricity savings were achieved 

in 2010, amounting to 0.98% of retail sales.30 

2.1.2.4 Plausible Range of Demand for Renewables 

Historical trends in population, GDP, and per-unit electricity consumption suggest that 

retail sales could rise 24% from 2011 to 2025, reaching a projected total of 96 TWh by 

2025. The SPSC’s extended demand forecast suggests 2025 retail sales of 90 TWh, 

taking into account energy efficiency improvements consistent with state requirements. 

These two forecasts establish a plausible range for future retail electricity sales. Applying 

current RES requirements to these two retail sales forecasts suggests that the demand for 

renewable energy related to the RES will most likely be between 7.9 TWh and 8.5 TWh 

in 2025. 

The size of the market for voluntary purchase of renewable energy also increases demand 

for renewable generation beyond that stimulated by state RES policy. In 2009, Arizona 

electric customers in all sectors voluntarily purchased over 104,000 MWh of renewable 

energy.31 Estimates indicate a 45% growth in voluntary demand across the West between 

2009 and 2015.32 

There are 3.2 TWh of renewable energy serving in-state loads. This suggests that Arizona 

will need 4.7 TWh to 5.3 TWh more renewable energy to meet RES requirements 

in 2025. 

2.1.3 Supply 

The ACC oversees the state’s two IOUs, Arizona Public Service Company (APS) and 

Tucson Electric Power Company (TEP). APS provides power to about 1 million of the 

state’s customers (about 43%) in 11 different counties. TEP serves about 375,000 

customers (about 16%) in southern Arizona. SRP is a large public power utility, serving 

the densely populated Phoenix area, and provides power to about 40% of the state’s 

customers. Thirteen cooperative, municipal, and rural electric companies serve the 

remaining 1% of customers in the state. 

Arizona is the third-largest producer of electricity in the West, behind California and 

Washington. Unlike California, Arizona is a net electricity exporter. Power exported to 

neighboring states from Arizona’s two largest power plants—the Palo Verde nuclear 

station and the coal-fired Navajo Generating Station—account for nearly 20% of the 

electricity generated in Arizona. In-state electricity generation is fueled mainly by coal 

(38%), natural gas (26%), and nuclear (28%). Traditional hydroelectricity (constructed 

prior to 2000) supplies 7% of the electricity (see Figure 2-5). 

30 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE),
 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf.
 31 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 32 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. An Examination of the Regional Supply and 

Demand Balance for Renewable Electricity in the United States through 2015. NREL/TP-6A2-45041.
 

Golden, CO: National Renewable Energy Laboratory, 2009. http://www.nrel.gov/docs/fy10osti/45041.pdf.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 18 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. 

Figure 2-5. Arizona's Current Electricity Supply33 

There are plans to close three coal units that APS owns at the Four Corners generating 

plant in New Mexico. APS owns 15% of the two newer units at Four Corners, and in 

2012 it received state and federal approval to buy Southern California Edison’s (SCE) 

48% share of the two units. 

2.1.3.1 Existing Renewable Energy Supply 

Together, renewable energy technologies produced about 1.5% of Arizona’s electricity. 

In-state facilities are currently capable of producing over 1.6 TWh per year. The majority 

of renewable energy generation produced in Arizona is from solar (1 TWh per year). 

About 46% of the electricity generated from renewable energy sources in Arizona, 

including 77% of its solar production, is exported out of the state. 

A number of solar projects are under construction in Arizona, including the 250-MW 

concentrating solar power Solana Generating Station and the 125-MW Arlington Valley 

Solar Energy Project II. Numerous solar plants between 10 MW and 25 MW are also 

under construction throughout the state. 

Both major Arizona utilities were in compliance with RPS requirements in 2011. The 

APS utility-scale renewables portfolio has recently shifted from mostly wind to a 

majority of solar. The company added nearly 60 MW of utility-scale solar in 2011 alone, 

including the Paloma (17 MW), Cotton Center (17 MW), and Hyder I (11 MW), as well 

as contracts for power from the Ajo (4.5 MW) and Prescott (10 MW) projects. APS’s 

largest renewable facility is soon to be the 280-MW Solana concentrating solar power 

(CSP) plant, currently under construction by developer Abengoa.34,35 

33 SNL Energy, extracted Dec. 10, 2012.
 34 2011 Renewable Energy Standard Compliance Report (Table 1). Phoenix, AZ: Arizona Public Service
 

(APS), March 30, 2012.
 

http://www.azcc.gov/Divisions/Utilities/Electric/REST%20PLANS/2012/APS2011RESComplianceReport.
 

pdf.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 19 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The utility-scale renewable energy for TEP comes mainly from the 50-MW Macho 

Springs wind farm in New Mexico, a landfill gas facility in Tucson, and photovoltaic 

(PV) facilities at Springerville and the University of Arizona Tech Park. Additional solar 

capacity that will supply TEP with generation by 2012 are under construction, the largest 

of which are two 25-MW PV facilities by developers NRG Energy and FRV Tucson.36 

2.1.3.2 Planned Renewable Energy Supply 

Solar energy capacity is likely to continue growing within Arizona. Over the next few 

years, TEP plans to add a 35-MW PV facility to its portfolio, as well as several smallerscale solar projects.37 APS plans to increase renewable energy capacity through the 

Arizona Sun program as well as third-party solar PPAs. According to the company’s own 

calculations, it will need more than 3.4 TWh of renewables by 2015 to meet 

requirements, and as of the end of 2011, it had about 32% of this. In 2011, solar capacity 

made up 22% of the utility’s renewable capacity, but this is expected to increase to 57% 

as expected projects come online. In addition, while the majority of the APS renewable 

capacity is currently third-party owned, anticipated utility-owned projects could bring a 

more equal ownership balance over the near term.38 

In addition to utility-scale projects, there is continuing interest in utility-led incentive 

programs for customer-side solar development and the development of central solar 

facilities by private companies in Arizona.39 

Transmission lines already approved would enable solar energy exports to the southern 

California market as well as geothermal imports from the Imperial Valley. Arizona 

utilities have already expressed interest in importing geothermal resources from the 

Imperial Valley. In March 2012, for example, the new 50-MW Featherstone geothermal 

plant in California began delivering power to customers in the Phoenix area.40 Lines in 

the planning stages would also enable low-cost wind power imports from New Mexico. 

35 TEP’s actual DG production fell short of the 69,990-MWh requirement, but the utility reported
 

compliance in this category based on annualized production calculations that account for projects that came 

online late in the year.

36 Tucson Electric Power 2011 REST Compliance Report (Table 2.1). Phoenix, AZ: Tucson Electric Power
 

Company, 2012.
 

http://www.azcc.gov/Divisions/Utilities/Electric/REST%20PLANS/2012/TEP2011Restplan.pdf.
 37 Tucson Electric Power 2011 REST Compliance Report. Phoenix, AZ: Tucson Electric Power Company,
 

2012. http://www.azcc.gov/Divisions/Utilities/Electric/REST%20PLANS/2012/TEP2011Restplan.pdf.
 38 2011 Renewable Energy Standard Compliance Report (Table 1). Phoenix, AZ: Arizona Public Service
 

(APS), March 30, 2012.
 

http://www.azcc.gov/Divisions/Utilities/Electric/REST%20PLANS/2012/APS2011RESComplianceReport.
 

pdf.
 39 "Arizona Approves Tucson Electric's Community Solar Program" (July 30, 2010), "Salt River Project
 

Proposes to Accelerate Renewables, Efficiency Standard" (April 19, 2011), "Solar Reserve Receives
 

Certificates for Ariz. Power Plant, Transmission Line" (December 15, 2010). SNL NewsWire. SNL Energy.
 40 “After Startup of $400M Geothermal Plant, EnergySource Looks to New Projects at Salton Sea.” SNL
 

NewsWire. SNL Energy, May 25, 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 20 

at www.nrel.gov/publications. 
 

 

 

2.1.3.3 Undeveloped Renewable Energy Supply 

Arizona’s renewable energy zones have an estimated 2.7 TWh of unused prime solar 

resources and another 41.9 TWh with DNI between 7.25 kWh and 7.50 kWh per square 

meter per day, bordering the threshold used in this analysis for delineating prime 

resources. This unused prime and borderline prime solar potential has an energy 

equivalent almost equal to the combined annual generation of the Palo Verde nuclear 

plant and the Navajo coal plant, the state’s two largest thermal generating stations. The 

state also has an estimated 2.2 TWh of biomass resources (which can provide base-load 

power) and some undeveloped in-state wind resources. 

2.1.4 Conclusion 

Arizona has sufficient resources within its renewable energy zones to meet expected 

demand under the RES in 2025. Importing lower-cost wind and baseload geothermal to 

complement its high-quality solar resources would diversify Arizona’s renewable 

portfolio and improve grid operations. The extent to which Arizona diversifies will 

determine how much prime quality solar will be available to meet post-2025 demand or 

to export to neighboring states. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 21 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

2.2 California 

2.2.1 State Highlights 

• California will need between 74.5 TWh and 91.2 TWh of renewable energy in 2025 to 

meet targets stipulated by current state law. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 40.3 TWh. 

• California could be close to full utilization of its in-state developable non-solar 

renewable resources and prime solar resources by 2025, if not sooner. About 25.5 

TWh of non-prime solar remain, as well as small quantities of untapped geothermal 

potential. 

California’s remaining options for easily developable in-state utility-scale renewables 

could be limited by 2025. Wind, geothermal, biomass, and small hydro projects under 

contract (either existing or under construction) are about equal to the total developable 

potential estimated for each of these technologies in California’s renewable energy zones. 

The remaining potential is almost all solar, and whether the quantity will be sufficient to 

meet state RPS requirements in 2025 will depend on the pace of load growth. California 

currently imports wind and solar power and a small amount of biomass and hydro power. 

It exports some geothermal power and a small amount of wind power, but 98% of the 

renewable power generated in California remains in-state. Cost-effectively meeting post2025 demand for renewable power will likely depend on California’s ability to import 

wind and geothermal power, especially if that demand is cost-sensitive. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-6. California’s renewable energy supply and demand41 

41 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 22 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.2.2 Demand 

California demand for renewable energy is currently driven primarily by the state’s RPS, 

which requires all utilities within the state to meet 33% of their retail sales with 

renewable resources by the end of 2020.42 The magnitude of this target, combined with 

the state’s high overall electricity demand, means that California will represent 58% to 

59% of the region’s total RPS-related renewable energy demand by 2025, amounting to 

between 74.5 TWh and 78.2 TWh. 

California’s RPS was originally established in 2002 and most recently updated by Senate 

Bill X1-2, enacted in April 2011. The current law requires all utilities (IOU and publicly 

owned) to derive 33% of retail sales from renewable energy by 2020. There are interim 

requirements of 20% by the end of 2013 and 25% by the end of 2016. The new RPS rules 

establish three categories of resources and the percentage each can contribute to the total 

requirement.43 

1.	 Eligible renewable energy resource electricity products that: 

A. Have a first point of interconnection with a California BA, have a first 

point of interconnection with distribution facilities used to serve end users 

within a California BA area, or are scheduled from the eligible renewable 

energy resource into a California BA without substituting electricity from 

another source 

B. Have an agreement to dynamically transfer electricity to a California BA 

(not less than 75% of procurements credited toward compliance by 2020) 

2.	 Firmed and shaped eligible renewable energy resource electricity products 

providing incremental electricity and scheduled into a California BA
 

3.	 Eligible renewable energy resource electricity products, or any fraction of the 

electricity generated, including unbundled renewable energy credits, that do not 

qualify under categories (1) or (2) (not more than 10% of procurements credited 

toward compliance by 2020). 

The RPS requirement is calculated as percentages of sales. Consequently, the amount of 

renewable energy needed to meet the requirement is sensitive to total electricity demand 

and, similarly, to the success of energy efficiency programs. The level of energy 

intensity, GDP, population growth, and energy efficiency all affect total electricity 

demand. 

42 California Public Resources Code Sec. 25740 et seq. and California Public Utilities Code Sec. 399.11 et
 

seq.

43 California Public Utilities Code Sec. 399.16.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 23 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-7. California’s residential electricity use per capita (2010)44 

Figure 2-8. California’s nonresidential electricity use per dollar of GDP (2010)45 

44 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012. 45 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “Regional Economic Accounts.” U.S. Bureau of
 

Economic Analysis, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 24 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-9. California’s historical and projected electricity efficiencies46 

2.2.2.1 Residential Consumption 

The U.S. Census Bureau projects a 16% increase in California’s population between 2010 

and 2025. This would put the state’s population at 44.3 million. Despite its rank as the 

most populous state in the region, California’s residential electricity use per person is the 

lowest in the region. On average, California residents used 2.34 MWh per person in 2010 

(see Figure 2-7). Historical trends indicate that this will increase 12% by 2025, with 

consumption reaching 2.65 MWh per person by 2025 (see Figure 2-9). 

2.2.2.2 Nonresidential Consumption 

California’s energy intensity (the nonresidential energy use per dollar of GDP) is the 

lowest in the region. In 2010, the state used slightly less than 0.10 kWh per dollar of GDP 

(see Figure 2-8). As with other states, California’s electricity intensity in the 

nonresidential sector has declined significantly in recent decades (see Figure 2-9), 

indicating increasing electricity efficiency in the output of goods and services. The state 

is expected to reduce nonresidential energy intensity even further between 2010 and 

2025. 

46 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012. 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau, 

October 2012; “Regional Economic Accounts.” U.S. Bureau of Economic Analysis, June 2012. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 25 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.2.2.3 Energy Efficiency and Customer-Sited Renewables 

Greater energy efficiency and demand-side management curbs electricity demand 

growth, which also reduces demand for renewable energy under the state RPS. California 

has a long history of energy efficiency programs offered through the utilities, and these 

have significantly limited per-capita demand growth of the state. The PUC has actively 

promoted utility efficiency through such measures as decoupling utility profits from sales 

and valuing efficiency as a resource in integrated resource planning processes. Today’s 

utility-led efficiency programs are funded through a public benefits charge on customer 

electricity bills as well as through cost recovery through rate cases brought by IOUs 

before the PUC. California’s IOU budgets for energy efficiency in 2011 totaled $1.2 

billion, amounting to 3.35% of statewide utility revenues. Energy-saving targets 

established by the California PUC call for an 8.5% savings between 2012 and 2020. 

Already the state has made significant progress. The ACEEE estimates that efficiency 

programs in 2010 achieved a net incremental savings of 4.6 TWh.47 

Incentive programs that encourage customer-sited renewable energy projects also have 

the effect of decreasing the total electrical load, and these projects serve to reduce the 

amount of renewable energy the utility must supply to comply with the RPS. California 

offers numerous loans, rebates, grants, tax incentives, feed-in tariffs, and performancebased incentives that stimulate customer-sited renewable energy projects. The California 

Solar Initiative provides performance-based rebates on solar systems to customers of the 

state IOUs. All utilities within the state are also required to offer a feed-in tariff rate for 

renewable energy systems up to 3 MW. The Self-Generation Incentive Program offers a 

maximum of 60% rebate for co-generation projects.48 

2.2.2.4 Plausible Range of Demand for Renewables 

Historical trends in population, GDP, and per-unit electricity consumption suggest that 

retail sales could rise 8% from 2011 to 2025, reaching a projected total of 280 TWh by 

2025. Particularly strong energy efficiency gains between 2000 and 2007 accelerate the 

future reductions predicted for nonresidential energy efficiency, which in turn reduces the 

forecast for nonresidential sales. The SPSC’s extended demand forecast suggests 2025 

retail sales of 291 TWh, taking into account energy efficiency improvements consistent 

with state requirements. These two forecasts establish a plausible range for future retail 

electricity sales. Applying current RES requirements to these two retail sales forecasts 

suggests that the demand for renewable energy related to the RPS will most likely be 

between 74.5 TWh and 78.2 TWh in 2025.49 

The voluntary market also increases demand for renewable energy because voluntary 

sales do not count toward the RPS requirement. In 2009, electric customers in California 

47 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE),
 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf.
 48 For details on these and other California incentive programs for renewable energy, see the Database of
 

State Incentives for Renewables and Efficiency (DSIRE) at http://www.dsireusa.org/.
 49 This RPS-related renewable energy demand estimate adjusts for the approximately 13 TWh of
 

Department of Water Resources electricity demand, which is not included in RPS requirement calculations.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 26 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

voluntarily purchased more than 0.8 TWh of renewable energy.50 This is the largest 

voluntary demand market in the region. Estimates indicate a 45% growth in voluntary 

demand across the West between 2009 and 2015, which means that California’s 

voluntary market could exceed 1 TWh by 2015.51 

2.2.3 Supply 

California’s five largest utilities serve 91% of the state’s retail electricity customers.52 

Three of these—Pacific Gas and Electric (PG&E), SCE, and San Diego Gas and Electric 

(SDG&E)—are IOUs. The Los Angeles Department of Water and Power (LADWP) and 

the Sacramento Municipal Utility District (SMUD) are the state’s two large publicly 

owned utilities. A small percentage of California customers buy electricity from 

independent electric service providers (ESPs) rather than a utility. As of November 2012, 

20 ESPs are registered with the California PUC to sell to direct-access customers.53 

Note: 2% of California’s geothermal generation and 1% of California’s wind generation go to other states 

as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. 

Figure 2-10. California’s current electricity supply54 

50 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 51 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009.

52 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 53 All California customers were first given the choice to select an electric service provider in 1998 when
 

the direct-access provisions were enacted according to the state’s electricity restructuring bill, AB1890.
 

The California PUC suspended the direct access program beginning September 20, 2001, as a result of the
 

2000-2001 electricity crisis. In October 2006, retail customers who had previously signed up to receive
 

direct access were allowed to do so again, and in October 2009, the direct-access program was opened for
 

new nonresidential retail customers, pursuant to Senate Bill 695. However, yearly enrollment in the
 

program is capped. See http://docs.cpuc.ca.gov/Published/esp_lists/esp_udc.htm and 

http://www.cpuc.ca.gov/PUC/energy/Retail+Electric+Markets+and+Finance/ for more information.
 54 SNL Energy, extracted Dec. 10, 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 27 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

California’s electricity fuel mix has been shifting away from coal for decades. Only 1% 

of California’s in-state generation came from coal in 2011. Imports from coal, nuclear, 

and other fuel sources accounted for 25% of the state’s consumption.55 In-state natural 

gas plants provided 32% of consumption, while hydro and nuclear provided 15% and 

13%, respectively.56 

Since 2006, California law (SB1368) has restricted utilities from constructing, investing 

in, or contracting to purchase electricity from baseload power plants that fail to meet 

specified greenhouse gas emissions standards, regardless of whether the plant is located 

within California. Since the passage of SB1368, California utilities have been divesting 

their stakes in large coal plants. SCE and LADWP reduced their percentage of coal-fired 

generation with the closure of the Mohave coal-fired plant in Nevada in 2009. LADWP is 

now divesting its interest in the Navajo plant in Arizona, while SCE is selling its stake in 

the Four Corners plant in New Mexico.57 

2.2.3.1 Existing Renewable Energy Supply 

Together, renewable energy technologies produced about 14% of California’s in-state 

generated electricity. Existing in-state facilities are capable of producing about 26.5 TWh 

per year.58 The state has net imports of renewable energy; renewable generation allocated 

to California loads (combined with in-state existing plants and those under construction) 

in 2010 totaled 51.4 TWh. The majority of existing in-state renewable energy generation 

is from wind (10.4 TWh per year), geothermal (13.4 TWh per year), and solar (2.3 TWh 

per year). 

2.2.3.2 California’s Renewable Energy Transmission Initiative 

California’s Renewable Energy Transmission Initiative (RETI) conducted its own 

renewable energy assessment from 2008 to 2010, concurrent with but separate from the 

WGA’s West-wide WREZ assessment.

59 The RETI assessment was more detailed than 

the WREZ assessment with respect to California resources, but the results shared some 

measure of congruity. Black & Veatch was the technical consultant for both assessments. 

Much of the RETI resource assessment work has been carried through to the Desert 

Renewable Energy Conservation Plan (DRECP), a multistakeholder California planning 

effort to “provide effective protection and conservation of desert ecosystems while 

allowing for the appropriate development of renewable energy projects.”60 

55 Consumption, as defined here, is in-state generation plus net imports.
 56 “California Electrical Energy Generation.” The California Energy Consumption, 2013.
 

http://energyalmanac.ca.gov/electricity/electricity_generation.html.
 57 http://www.snl.com/interactivex/article.aspx?id=12208347&KLPT=6;
 

http://www.snl.com/interactivex/article.aspx?id=12012961&KLPT=6.
 58 California is a net importer of electricity generated from a variety of renewable technologies.
 59 http://www.energy.ca.gov/reti/ 60 http://www.drecp.org/
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 28 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 2-1. Comparison of California Capacity Identified in WREZ and RETI Analyses (MW)61 

Biomass Geothermal Solar b Wind 

Southern California 

RETI zonesa 

Tehachapi, Kramer, Fairmont, 

Imperial North-A, San Diego 

South 

DRECP 

Range across 6 Alternatives 

WREZ zones 

West, Central, Northeast, East, 

South 

136 

n/a 

175 

1,434 

n/a 

1,394 

16,069 

8,457 to 

14,304 

15,180 

6,041 

802 to 

6,649 

4,786 

Northern California 

RETI zonesa 

(no corresponding WREZ zones) 

Solano, Round Mountain-A 

-- 384 -- 894 

a Zones with better-than-median environmental scores and better-than-median economic scores. 

b WREZ area and capacity estimates are based on requirements for CSP; most sites that can accommodate 

CSP can also accommodate PV 

The RETI analysis identified potential renewable energy development areas and grouped 

them into zones, as was done in the WREZ analysis. For each zone, development areas 

were screened for suitability. The remaining resource areas underwent a technical 

analysis to estimate the capacity they could accommodate (in megawatts), the energy 

potential (gigawatt-hours per year), and the cost of developing each area (levelized 

dollars per megawatt-hour). Next, the resource areas were vetted through an open 

stakeholder process to characterize the relative environmental impact of development. 

The outcome was a pair of scores for each zone—one for economics and one for 

environmental impact. 

Here, the comparison of RETI zones and WREZ zones in California focuses on the RETI 

zones where economic and environmental scores were better than the median. This sets 

aside zones where development would tend to be more expensive or pose greater risk to 

environmentally sensitive areas. 

All of the WREZ zones in California are located in the southern part of the state, and the 

highest-scoring RETI zones in southern California have an aggregate profile similar to 

that of the WREZ zones. The most plentiful resource is solar, followed by wind (mostly 

in the Tehachapi area), and geothermal around the Salton Sea. Table 2-1 compares the 

two sets of zones by the total capacity identified for biomass, geothermal, solar, and 

61 Renewable Energy Transmission Initiative, RETI Phase 2B Final Report. San Francisco, CA: Black & 

Veatch, May 2010. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 29 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

wind potential. It also shows estimates of developable wind and solar power in 6 DRECP 

planning scenarios that were published in December 2012.62 

Two better-than-median RETI zones are located in northern California. One is primarily 

geothermal, the other is primarily wind. Both are relatively small, which is one reason 

their resources were not represented in the WREZ assessment. 

RETI and WREZ used different screening processes and different assumptions so the 

specific identified resources do not match site to site. Nevertheless, the overall quantities 

are reasonably close despite the different approaches. This suggests that either total is a 

reasonable approximation of California’s most cost-effective developable renewable 

resources, for purposes that are geographically broad and do not require site-specific 

assessment. This study uses the California WREZ estimates for two reasons. First, it 

maintains methodological consistency with other western states. Second, the WREZ 

resources are broken down in such a way that enables cost and quantity updates applied 

to resources in other states. 

2.2.3.3 Planned Renewable Energy Supply 

California’s IOUs plan for future renewable energy needs through their long-term 

procurement plans. Public utilities and independent power producers plan other facilities. 

California Energy Commission data indicate that 19 TWh/year of new renewable energy 

generation is in some stage of planning. While some of these projects might not happen, 

historical data indicates that 79% of all generation from planned projects seeking 

contracts has been successfully delivered. The majority (53%) of failed generation has 

been solar thermal technology; however, solar thermal projects are large, and these 

contracts were no more likely to fail than other technologies in terms of number of 

contracts. 

California currently has over 3.2 GW of solar capacity under construction (both CSP and 

utility-scale PV).63 More than 1 GW of wind and 53 MW of biomass projects are under 

construction as well. 

2.2.3.4 Undeveloped Renewable Energy Supply 

The state’s renewable energy zones have an estimated 10 TWh of developable solar 

resources that have not yet been tapped. Solar projects to date, however, exceed the 

amount of developable prime and borderline prime resources estimated to exist within 

California’s zones.64 This suggests that California’s remaining solar resource areas tend 

have less solar exposure than what has already been developed and might be 

less productive. 

Future opportunities for renewables other than solar appear to be getting tighter. About 

half of the geothermal potential identified in southern California was developed as of 

62 “Primary Features of DRECP Alternatives.” California Energy Commission, Dec. 21, 2012.
 63 SNL Energy, extracted Dec. 10, 2012.
 64 This is likely because resources outside of WREZ and some lower-quality resources have been
 

developed. As used in this study, prime solar areas have a DNI of 7.5 kWh per square meter per day.
 

Borderline prime resources have a DNI between 7.25 kWh and 7.50 kWh per square meter per day.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 30 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

2012, and what was planned as of early 2013 amounted to an additional 17%. Existing 

wind development exceeds what was estimated to be in a renewable energy zone, 

indicating that developers are already looking at areas where the potential is less 

concentrated and possibly lower in productivity. Data for biomass also suggest future 

development will be outside a renewable energy zone. Most of the identified potential for 

small hydro was outside a zone, and as of 2012 about 10% of it had been developed. 

In short, while individual project opportunities might exist based on the conditions 

affecting particular sites, systematic indicators suggest that California overall could be 

approaching supply constraints if restricted to in-state resources. At some point, options 

for new in-state renewable energy development might be dominated by areas that are less 

productive or more environmentally sensitive. 

Figure 2-11 shows the supply curves for the screened solar and non-solar resources 

identified within California’s renewable energy zones. They indicate the total estimated 

generating potential, ordered by the estimated cost of delivered power from these 

resources. The supply curves identify more than 21 TWh per year of generating potential 

from non-solar renewables. Total developable solar areas have the potential to provide 

between 41 TWh and 55 TWh, depending on the technology employed. 

Figure 2-12 shows the resources that have already been developed, also ordered by the 

estimated cost of their development.65 Nearly 59 TWh of solar and non-solar renewable 

energy generation has been developed in California, at costs that have typically ranged 

from $54/MWh to $133/MWh.66 Costs for wind, geothermal, and biomass generation are 

generally lower, with generation from solar technologies generally higher. 

65 While project-specific contract prices are confidential, SCE, PG&E, and SDG&E report average contract
 

prices according to technology and project size. Here, we use these averages as proxy prices and apply
 

them to projects according to their size. 66 Renewables Portfolio Standard Quarterly Report: 4th Quarter. California Public Utilities Commission,
 

2011.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 31 

at www.nrel.gov/publications. 
32 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications. 

Screened resource areas estimated to exist in renewable energy zones. Costs are based on technical 

estimates. Curves are for all resource potential regardless of whether developed or undeveloped. 

Chart for solar potential indicates cost curves for different solar technologies as they apply to the same 

screened resource areas. Solar development to date amounts to about 20,000 GWh per year for solar and 

thermal technologies combined. 

Figure 2-11. Renewable resource potential in California 

Costs approximations are based on aggregated contract information compiled by the California PUC for 

projects approved for RPS compliance. 

Figure 2-12. Developed resources in California (existing, under construction) 

 

$0

$50

$100

$150

$200

0 10,000 20,000 30,000

Cost

($/MWh)

Cumulative GWh per year

Biomass

Geothermal

Wind

0 20,000 40,000 60,000

Cumulative GWh per year

Thermal (dry-cooled)

Thermal (wet-cooled)

Thermal (dry-cooled, storage)

Thermal (wet-cooled, storage)

PV (fixed)

PV (tracking)

 $-

 $50

 $100

 $150

 $200

 $250

 - 20,000 40,000 60,000 80,000

Cost

($/MWh)

Cumulative GWh per year

wind

geothermal

solar PV

solar thermal

other
 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 2-2. California Resources Estimated to be Available for Future Development67 

WREZ potential 

Developed resources

(existing, under 

construction) 

In zone, 

GWh/year 

Outside zones, 

GWh/year GWh/year $/MWh 

Wind 8,895 about 10,691a 13,000 $70 

Geothermal 11,074 undiscoveredb 13,379 $94 

Biomass 1,080 4,840 4,309 $74 

Hydro 8 10,669 to 

12,078c 942 $70 

Solar (in-zone) 40,762 to 54,602d 

PV under contract 16,301 $174 

Thermal under 

contract 10,924 $155 

a Neither the WREZ study nor this study estimated the breakdown of non-zone resources by capacity 

factor. For this table, the energy profiles of California’s in-zone and out-of-zone wind resources are 

assumed to be relatively proportional. The WREZ study estimated in-zone wind capacity at 6,042 MW 

and non-zone capacity at 7,262 MW.

b “Undiscovered” conventional geothermal resources are those whose existence somewhere in a general 

area is implied by interpolation between measurement points but whose precise location is unknown. 

All identified geothermal resources were assigned to the nearest zone, leaving no identified potential 

outside of a zone. Undiscovered renewable resources were not assigned to a zone. c The WREZ study identified 2,298 MW of small hydro potential in California outside of renewable 

energy zones. Capacity factors for most hydro projects examined in the WREZ analysis ranged from 

53% to 60%. 

d Potential varies based on the type of solar technology applied. If all potential is developed with fixed 

PV, the estimated energy potential is 40,762 GWh per year. If all potential is developed with wet-cooled 

solar thermal with storage, the estimated energy potential is 54,602 GWh per year. 

Table 2-2 summarizes the resources identified in the WREZ analysis. The first two data 

columns show the identified resource potential after screening out areas that are off-limits 

to development or are difficult to develop economically due to physical characteristics of 

the terrain. Screened resources that are part of a geographic concentration are assigned to 

a zone; the second column shows isolated resources that may be developable but are not 

part of a renewable energy zone. 

The last two columns show what has already been developed (or is currently under 

development) within the state borders up to the end of 2012 and its estimated cost.68 Most 

of the biomass and small hydro developed to date—typically small installations that are 

scattered widely across the state—are outside a renewable energy zone. Most of the 

geothermal power that has already been developed is at two older projects located in the 

67 Pletka, R.; Finn, J. Western Renewable Energy Zones, Phase 1 QRA Identification Technical Report.
 

NREL/SR-6A2-46877. Golden, CO: National Renewable Energy Laboratory, 2009. 68 These estimates draw on two sources: SNL Energy and the California PUC’s list of projects approved for
 

RPS eligibility. We supplement the California PUC’s list for IOUs with information provided by SMUD
 

and LADWP, two large public utilities not under PUC jurisdiction. These sources differ in purpose and 

with respect to when new projects are added and therefore do not overlap completely. Here, we have
 

selected the source with the largest subtotal for each technology group—wind, solar, geothermal, biomass,
 

and small hydro—to estimate California’s total renewable energy development as of December 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 33 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

northern part of the state and outside of a renewable energy zone. The geothermal 

resources quantified in the WREZ analysis are located in the Imperial Valley of 

southern California. 

The state’s most abundant renewable resource is solar, with more than 37 TWh of 

potential within the renewable energy zones. More than 16 TWh of solar PV and nearly 

11 TWh of solar thermal have been developed within the state. This leaves between 

17 TWh and 19 TWh of developable potential, depending on which solar technology 

is chosen. 

2.2.4 Conclusion 

Resources within California’s renewable energy zones, combined with what it is already 

importing from other states, could provide enough generation to meet low demand 

scenarios to 2025. It might not be enough if demand turns out to be higher, however. In 

this case, California would need to draw more heavily from in-state renewable resources 

not located in a concentrated zone or it might need to draw on out-of-state resources. 

Moving toward a post-2025 environment, California’s undeveloped in-state renewable 

resources will become scarce, more costly, and more widely dispersed. While most of the 

high-quality renewable resources areas within the state will already have been developed, 

some in-state renewable resources could become more attractive if technology costs 

come down further, performance improves, or new technological innovations come to 

market. 

Despite its high demand and limited remaining resources, California may have one major 

niche for exporting renewable power: geothermal from the Imperial Valley to Arizona for 

use as a baseload renewable resource to balance out solar. APS and SRP have both 

indicated in their planning processes a desire to purchase geothermal from California. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 34 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

2.3 Colorado 

2.3.1 State Highlights 

• Colorado will need between 10.4 TWh and 10.8 TWh of renewable energy in 2025 to 

meet targets stipulated by current state law. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 5.5 TWh annually. 

• Prime wind resources that have not yet been developed could provide at least 53.5 

TWh annually to meet in-state requirements and potentially be exported. The state 

has an additional 26.7 TWh of non-prime wind, solar, and biomass resources that 

could meet in-state demand. 

Colorado has about 53.5 TWh of unused prime wind energy resources. This is twice what 

is needed to meet the expected demand for renewable energy in 2025 and is about equal 

to Colorado’s total retail electricity sales in 2012. This leaves a significant amount of 

prime-quality wind for potential export to other states. It already exports some wind 

power besides importing a small amount of wind power from Wyoming. Colorado also 

has significant quantities of non-prime solar, biomass, and wind resources suitable to 

meet in-state demand. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-13. Colorado’s renewable energy supply and demand69 

69 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 35 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.3.2 Demand70 

Colorado’s demand for renewable energy is driven largely by the state’s RPS, which was 

first passed in 2004 by ballot initiative. Colorado utilities are mandated to supply an 

increasing percentage of retail sales with renewable resources. For IOUs, the requirement 

reaches a maximum of 30% by 2020, with 3% coming from retail DG. Electric 

cooperatives providing service to and municipal utilities serving more than 40,000 

customers have a 20% renewable energy mandate by 2020. Municipal utilities are not 

subject to the DG requirement. 

Small-scale community-based projects as well as solar and small-scale projects within a 

cooperative or municipal utility territory are eligible for credit multipliers. In-state 

generation (excluding distributed generation) is eligible for a multiplier, but recent state 

legislation sunsets that provision for generators built in 2015 or later.

71 REC trading is 

allowed, but third-party oversight of the trading system has not yet been established. 

Because the RPS requirement is calculated as percentages of sales, the amount of 

renewable energy needed to meet the requirement is sensitive to total electricity demand 

and, similarly, to the success of energy efficiency programs. The level of energy 

intensity, GDP, population growth, and energy efficiency all affect total electricity 

demand. 

2.3.2.1 Residential Consumption 

Colorado’s residential electricity use per capita is one of the lowest in the region. In 

2010, the average Colorado resident used 3.59 MWh (see Figure 2-14). Per-capita 

consumption is expected to reach 4.25 MWh per person by 2025 (see Figure 2-16). The 

U.S. Census Bureau projects that Colorado’s population will increase 9% between 2011 

and 2025, bringing the state’s population to 5.5 million in 2025. 

2.3.2.2 Nonresidential Consumption 

Colorado’s electricity intensity (nonresidential electricity sales per dollar of GDP) is 

about average for the region. In 2010, the state used 0.14 kWh for each dollar of GDP 

(see Figure 2-15). As with other states, Colorado’s electricity intensity in the 

nonresidential sector has declined significantly in recent decades (see Figure 2-16), 

indicating increasing electricity efficiency in the output of goods and services. The state 

is expected to reduce electricity intensity even more between 2011 and 2025. 

70 Colorado made two major changes to its RPS after this study was completed: it increased the requirement 

for electric cooperatives and rural electric associations to 20% of sales by 2020 (up from 10%); and it 

eliminated the 25% adder for eligible in-state renewable resources beginning January 1, 2015. Colorado 

Revised Statutes, 40-2-124 (amended by Senate Bill 13-252, signed into law June 5, 2013). Applying the 

demand growth assumptions described elsewhere in this section, these changes are projected to increase 

annual RPS-related demand in 2020 by an additional 1.2 TWh to 1.3 TWh. The increase is much smaller 

than the stock of surplus prime resources projected in this analysis. Assuming all of the additional RPS 

demand comes from Colorado resources, the estimated surplus of prime resources would drop to between 

52.7 TWh and 52.8 TWh (annual equivalent), down from the 54 TWh this analysis had projected before the
 

changes had been adopted. 71 For more information, see DSIRE at http://www.dsireusa.org/.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 36 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

Figure 2-14. Colorado’s residential electricity use per capita (2010)72 

Figure 2-15. Colorado’s nonresidential electricity use per dollar of GDP (2010)73 

72 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 73 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012;
 

“Regional Economic Accounts.” U.S. Bureau of Economic Analysis, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 37 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

Figure 2-16. Colorado’s historical and projected electricity efficiencies74 

2.3.2.3 Energy Efficiency and Customer-Sited Renewables 

Energy efficiency programs and funding to reduce electricity demand have been 

expanding rapidly in Colorado. In accordance with the EERS passed in 2007 (HB-07­

1037), the Colorado PUC has established energy savings goals for the utilities that they 

oversee. The current EERS sets a goal of reducing demand by at least 5% of an IOU’s 

retail megawatt-hour energy sales in the base year (2006) by the end of 2018. The PUC 

also provides utilities with financial incentives for implementing cost-effective efficiency 

programs, the costs of which are recoverable.75 

In 2011, utilities spent over $64 million on efficiency programs, amounting to 1.28% of 

revenues. The American Council for an Energy-Efficient Economy (ACEEE) estimates 

that a net incremental savings of 310 GWh was achieved in 2010, which was about 

0.58% of retail sales.76 

2.3.2.4 Plausible Range of Demand for Renewables 

Historical trends in population, GDP, and per-unit electricity consumption suggest that 

retail sales could rise 20% from 2011 to 2025, reaching a projected total of 53.8 TWh by 

2025. Strong energy efficiency gains between 2000 and 2007 accelerate the future 

74 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012; “Regional Economic Accounts.” U.S. Bureau of Economic Analysis, June 2012. 75 State Energy Efficiency Policy Database.” American Council for an Energy-Efficient Economy
 

(ACEEE), 2013. Accessed Oct 16, 2012: http://www.aceee.org/sector/state-policy/colorado.
 76 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE),
 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 38 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reductions predicted for nonresidential energy efficiency, which in turn reduces the 

forecast for nonresidential sales. The SPSC’s extended demand forecast suggests 2025 

retail sales of 68.4 TWh, taking into account energy efficiency improvements consistent 

with state requirements. These two forecasts establish a plausible range for future retail 

electricity sales. Applying current RES requirements to these two retail sales forecasts 

suggests that the demand for renewable energy related to the RES will most likely be 

between 10.4 TWh and 10.8 TWh in 2025. These estimates assume that utilities make 

maximum use of credit multipliers for in-state resources. 

The size of the market for voluntary purchase of renewable energy increases demand for 

renewable generation beyond that stimulated by state RPS policy. In 2009, electric 

customers in Colorado voluntarily purchased over 345,000 MWh of renewable energy.77 

In the region, only California had higher levels of voluntary sales. Estimates indicate a 

45% growth in voluntary demand across the West between 2009 and 2015.78 

2.3.3 Supply 

Electricity customers in Colorado receive service from 29 municipal utilities, 26 rural 

cooperatives, and two IOUs. Xcel, which operates in the state as Public Service Company 

of Colorado (PSCo), is the largest provider, serving 1.3 million customers in the state. 

Black Hills Energy Corporation serves 4% of the state electrical demand and 

approximately 92,000 customers. Tri-State Generation and Transmission Association 

supplies power and transmission service to the state’s co-ops. The Colorado PUC 

regulates the IOUs with respect to retail rates and transmission and all utilities with 

respect to transmission siting.79 

*2% of Colorado’s wind generation goes to other states as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation and includes power exported to 

other states. Hydropower and biomass built before 2000 is considered conventional generation. 

Figure 2-17. Colorado’s current electricity supply80 

77 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 78 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009. 79 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 80 SNL Energy, extracted Dec. 10, 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 39 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The majority of Colorado’s in-state electricity generation is produced by coal-fired 

facilities (65%), with an additional 21% generated by natural gas plants and 4% 

generated by conventional hydropower (constructed prior to 2000). 81 

2.3.3.1 Existing Renewable Energy Supply 

Renewable energy technologies contribute 9.6% to electricity generation, almost all of 

which is wind power (4.7 TWh per year). Existing in-state facilities, those under 

construction, and electricity imports are currently capable of producing over 5.4 TWh per 

year. Only 2% of the electricity generated from renewable energy sources in Colorado is 

exported out of the state. 

2.3.3.2 Planned Renewable Energy Supply 

Legislation passed in 2010 and 2011 encourages utility planning of further clean energy 

projects. In April 2010, then-Governor Bill Ritter signed the Clean Air-Clean Jobs Act, 

which requires improved environmental performance in the electricity sector (HB10­

1365). Under the new legislation, PSCo must retire the lesser of 900 MW of coal-fired 

capacity or 50% of its coal-based capacity by 2015, in addition to the plants that were 

already scheduled for retirement. These retirements will need to be made up for through 

demand-side management and cleaner new generating capacity. 

Colorado SB11-071, passed in 2011, states that the PUC is to give “the fullest possible 

consideration to the cost-effective implementation of new clean energy and energyefficient technologies.” Utilities are required to provide at least three alternative strategies 

in their resource plans, each consisting of increasing proportions of renewable 

resources.82 Xcel’s 2011 Electric Resource Plan describes alternative strategies with 

renewable capacity additions ranging from 200 MW to 1,025 MW.83 In its 2010 

integrated resource plan (IRP), Tri-State considered 513 MW of new renewable capacity 

in its generation expansion modeling process.84 

Current PUC rules do not allow regulated utilities to acquire new renewable capacity 

greater than 30 MW unless listed in an approved resource plan, but Xcel Energy has 

requested the ability to use a flexible approach to acquiring new renewable capacity in 

the future by conducting targeted solicitations.85 

81 Form EIA-860, Annual Electric Generator Data. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 82 4 CCR 723-3, Part 3: Rules Regulating Electric Utilities. Decision No. C10-1111, Docket No. 10R214E. Colorado Public Utilities Commission (Nov. 22, 2010).

83 2011 Electric Resource Plan, Vol. 1. CPUC Docket No. 11A-. Public Service Company of Colorado,
 

Oct. 31, 2011.
 

http://www.xcelenergy.com/staticfiles/xe/Corporate/Corporate%20PDFs/AttachmentA2011ERPErrata_Fin 

al.pdf. 84 Integrated Resource Plan/Electric Resource Plan for Tri-State Generation and Transmission 

Association, Inc. Submitted to: Western Area Power Authority and Colorado Public Utilities Commission, 

November 2010. http://www.tristategt.org/ResourcePlanning/documents/Tri-State_IRP-ERP_Final.pdf. 85 2011 Electric Resource Plan, Vol. 1. CPUC Docket No. 11A-. Public Service Company of Colorado, 

Oct. 31, 2011. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 40 

at www.nrel.gov/publications. 
 

 

 

 

 

2.3.3.3 Undeveloped Renewable Energy Supply 

Within Colorado’s renewable energy zones, there is an estimated 54 TWh of unused 

prime wind resources that could be made available for export in a regional market. 

Another 26.7 TWh of lower-quality wind, solar, and biomass could be developed to meet 

in-state demand. 

2.3.4 Conclusion 

Colorado has twice the prime wind energy resources needed to meet RPS-related demand 

in 2025, even in the high demand scenario. This will leave the state with a large surplus 

of low-cost wind potential in a post-2025 market. The state also has significant quantities 

of lower-quality solar, biomass, and wind resources that are suitable to meet in-state 

loads. To the extent that Colorado makes use of these non-prime resources to meet its 

own demand, additional wind electricity would be available for export. 

http://www.xcelenergy.com/staticfiles/xe/Corporate/Corporate%20PDFs/AttachmentA2011ERPErrata_Fin 

al.pdf. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 41 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

2.4 Idaho 

2.4.1 State Highlights 

• Idaho has no RPS. Future demand for renewable energy in 2025 will depend on 

capacity retirements, purchased power costs, and utility resource planning objectives. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 3.3 TWh annually. Idaho utilities also purchase some 4.6 TWh of wind power 

in other states to serve native load or for sales of RECs. 

• Prime, export-quality geothermal resources that have not yet been developed could 

provide at least 2.0 TWh annually. The state has an additional 2.8 TWh of biomass 

and wind resources that could meet in-state demand. 

Idaho does not have an RPS. Nevertheless, 13% of the electricity currently generated in 

the state comes from non-hydro renewable resources; conventional hydroelectric 

resources provide 73%. The state’s largest utility anticipates adding geothermal and solar 

resources by 2025. Idaho utilities currently purchase Wyoming wind power and small 

amounts of hydro power from other states; Idaho currently exports small amounts of 

wind and biomass power. The state has a significant amount of undeveloped geothermal 

resources, as well as some non-prime wind and biomass. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-18. Idaho’s renewable energy supply and demand86 

86 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013.; SNL Energy. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 42 

at www.nrel.gov/publications. 
 

 

 

 

 

 

2.4.2 Demand 

Given that Idaho does not have an RPS, the demand for renewable energy is driven by 

other factors, including exporting power to meet neighboring states’ RPSs and individual 

utility needs. Idaho currently exports 0.7 TWh of renewable energy annually to other 

states, nearly all of which is wind power. About 40% of wind power and 10% of biomass 

power produced within the state is exported. About 1.3 TWh generated from renewable 

energy technologies in Idaho remains in-state and is used to meet in-state demand. 

2.4.2.1 Residential Consumption 

The U.S. Census Bureau projects a 15% increase in Idaho’s population between 2010 and 

2025. This would put the state’s population at 1.8 million in 2025. Idaho’s residential 

electricity use per person is one of the highest in the region. On average, Idaho residents 

used 5.18 MWh per person in 2010 (see Figure 2-20), more than double the per-capita 

consumption of California. Historical trends indicate that this will increase 1% by 2025 

with consumption reaching 5.21 MWh per person by 2025 (see Figure 2-22). 

2.4.2.2 Nonresidential Consumption 

Idaho’s energy intensity (the nonresidential energy use per dollar of GDP) is on the 

higher end of the spectrum in the region. In 2010, the state used 0.26 kWh per dollar of 

GDP (see Figure 2-21). As with other states, Idaho’s electricity intensity in the 

nonresidential sector has declined significantly in recent decades (see Figure 2-22), 

indicating increasing electricity efficiency in the output of goods and services. Another 

cause that could be accelerating the trend is a sectoral shift in the Idaho economy, with 

less state product coming from forestry and agriculture and more from services. Trends 

based on recent historical data suggest that nonresidential energy intensity could reach 

0.08 kWh per dollar of GDP in 2025. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 43 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-19. Idaho’s residential electricity use per capita (2010)87 

Figure 2-20. Idaho’s nonresidential electricity use per dollar of GDP (2010)88 

87 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 88 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “Regional Economic Accounts.” U.S. Bureau of
 

Economic Analysis, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 44 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

Figure 2-21. Idaho’s historical and projected electricity efficiencies89 

2.4.2.3 Energy Efficiency and Customer-Sited Renewables 

Greater energy efficiency and demand-side management curbs electricity demand 

growth. Idaho’s IOU budgets for energy efficiency in 2011 totaled $40 million, 

amounting to 2.67% of statewide utility revenues. The state has made progress: the 

ACEEE estimates that efficiency programs in 2010 achieved a net incremental savings of 

224 GWh, about 0.98% of statewide retail electric sales.90 

Incentive programs that encourage customer-sited renewable energy projects also have 

the effect of decreasing the total electrical load. Idaho offers numerous loans, rebates, 

grants, tax incentives, and bonds that stimulate customer-sited renewable energy projects. 

2.4.2.4 Plausible Range of Demand for Renewables 

The foregoing assumptions and calculations for population, GDP, and per-unit electricity 

consumption suggest that the state’s electricity consumption could decrease 21% from 

2010 to 2025. The reduction is due to trends in the nonresidential sector. These historical 

trends suggest total retail sales of 19 TWh by 2025. Combining this estimate with the 

SPSC’s extended demand forecast of 29.1 TWh, which accounts for anticipated energy 

efficiency measures, establishes a plausible range for future electricity demand. 

89 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012; “Regional Economic Accounts.” U.S. Bureau of Economic Analysis, June 2012. 90 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE),
 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 45 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Idaho’s total electricity consumption is small compared to other western states. In 2010 it 

accounted for 3% of all western states’ electricity consumption. 

Although Idaho has no RPS, the state’s largest utility (Idaho Power) anticipates procuring 

52 MW of geothermal power and 50 MW of solar power by 2025.91 This would be about 

390 GWh and 140 GWh per year, which together would be 3% to 4% of the utility’s 

anticipated energy demand in 2025.92 About half of Idaho Power’s supply currently 

comes from hydroelectric resources, and the utility expects that share to increase slightly 

by 2025. 

In 2009, electric customers in Idaho voluntarily purchased more than 48 GWh of 

renewable energy.93 Estimates indicate a 45% growth in voluntary demand across the 

West between 2009 and 2015, which means that Idaho’s voluntary market could exceed 

70 GWh by 2015.94 

There is currently 3.6 TWh of renewable energy serving in-state loads. 

2.4.3 Supply 

The majority (73%) of Idaho’s electricity is generated from conventional hydropower 

plants, constructed prior to 2000. Coal, gas, and other non-renewable technologies 

contribute an additional 14% of Idaho’s electricity. Renewable energy accounts for 13% 

of Idaho’s electricity supply, the majority of which is wind power (11%). 

*10% of Idaho’s biomass generation goes to other states as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. 

Figure 2-22. Idaho’s current electricity supply95 

91 “2011 Integrated Resource Plan.” Idaho Power Company, June 2011.
 92 Solar output estimated using NREL’s System Advisor Model (SAM) based on solar conditions near
 

Boise, Idaho, and assuming a 50-MW power-tower concentrating thermal solar configuration with six 

hours of thermal storage capacity.

93 Survey Form EIA-861: Annual Electric Power Industry Report. Washington, D.C.: Energy Information
 

Administration (EIA), 2012. Accessed September 2011:
 

http://www.eia.gov/cneaf/electricity/page/eia861.html.
 94 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009.

95 SNL Energy, extracted Dec. 10, 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 46 

at www.nrel.gov/publications. 
 

 

 

 

 

 

2.4.3.1 Existing Renewable Energy Supply 

Together, renewable energy technologies (excluding large-scale hydro) produced about 

13% of Idaho’s electricity. In-state facilities are currently capable of producing over 

2.0 TWh per year. Nearly all of the renewable energy generated in Idaho is from wind 

(1.7 TWh). About 35% of the electricity generated from renewable energy sources in 

Idaho is exported out of the state (40% of wind power is exported and 10% of biomass 

is exported). 

2.4.3.2 Planned Renewable Energy Supply 

Nearly 500 MW of wind are planned for construction in Idaho.96 A small biomass and a 

small hydro project are also being planned. Grand View Solar PV One is developing a 

20-MW PV plant—the first utility-scale solar plant in Idaho. 

2.4.3.3 Undeveloped Renewable Energy Supply 

Idaho has developed 2.8 TWh of wind resources, more than the amount of prime wind 

resources estimated to exist within Idaho’s renewable energy zones. The state has 

2.1 TWh of prime geothermal resources in these zones, however, most of which remains 

undeveloped. As a baseload resource, geothermal could be a candidate for export in a 

regional market. In addition, 2.8 TWh of non-prime resources (1.0 TWh of non-prime 

wind and 1.8 TWh of non-prime biomass) are still undeveloped. 

2.4.4 Conclusion 

Idaho has no RPS and therefore does not need to fulfill RPS-related obligations. Demand 

is currently driven by utility-specific resource plans and RPS requirements in neighboring 

states. An analysis of the unused prime resources reveals that 2.1 TWh of prime resources 

(from geothermal) could be developed for exports to other states. In addition, another 2.8 

TWh of non-prime wind and biomass resources could potentially be developed as well. 

96 SNL Energy, updated December 2012. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 47 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.5 Montana 

2.5.1 State Highlights 

• Montana will need about 1.0 TWh of renewable energy in 2025 to meet targets 

stipulated by current state law. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 2.2 TWh annually. About one-third of this amount serves native load in 

Montana; the remainder is exported. 

• Prime, export-quality wind resources that have not yet been developed could provide 

at least 30.5 TWh annually. The state has an additional 3.3 TWh of non-prime wind 

and biomass resources that could meet in-state demand. 

Montana’s prime wind resources have an energy potential twice that of Colstrip, the 

West’s third-largest coal plant located in the southeastern part of the state. These low-cost 

resources are far in excess of what will be needed in 2025 under Montana’s current 

renewable energy target. Current wind development is already more than twice the 

amount likely to be needed in 2025, with most of the generation exported to other states. 

Montana also exports a small amount of hydro power. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-23. Montana’s renewable energy supply and demand97 

97 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 48 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

2.5.2 Demand 

Montana’s demand for renewable energy is currently driven primarily by the state’s 

Renewable Resource Standard (RRS) legislation, enacted in 2005. It requires public 

utilities and competitive electricity suppliers to obtain 15% of their retail sales from 

eligible renewable resources by the end of 2015. There are interim requirements of 5% 

for compliance years 2008–2009 and 10% for compliance years 2010–2014.98 

In addition, the RRS legislation includes specific requirements to purchase power from 

community renewable energy projects, defined as installations under 25 MW where local 

owners have a controlling interest. For years 2012–2014, public utilities must purchase 

the RECs and the electricity from community projects totaling at least 50 MW in 

nameplate capacity. For 2015 and beyond, the total requirement increases to 75 MW in 

nameplate capacity. 

The RRS requirement is calculated as percentages of load. Consequently, the amount of 

renewable energy needed to meet the requirement is sensitive to total electricity demand 

and, similarly, to the success of energy efficiency programs. The level of energy 

intensity, GDP, population growth, and energy efficiency all affect total electricity 

demand. 

2.5.2.1 Residential Consumption 

The U.S. Census Bureau projects a 4% increase in Montana’s population between 2010 

and 2025. This would put the state’s population at just over 1.0 million in 2025. 

Montana’s residential electricity use per person is one of the highest in the region. On 

average, Montana residents used 4.79 MWh per person in 2010 (see Figure 2-25), more 

than double the per-capita consumption of California. Historical trends indicate that this 

will increase 9% by 2025, with consumption reaching 5.27 MWh per person by 2025 (see 

Figure 2-27). 

2.5.2.2 Nonresidential Consumption 

Montana’s energy intensity (the nonresidential energy use per dollar of GDP) is on the 

higher end of the spectrum in the region. In 2010, the state used 0.24 kWh per dollar of 

GDP (see Figure 2-26). As with other states, Montana’s electricity intensity in the 

nonresidential sector has declined significantly in recent decades (see Figure 2-27), 

indicating increasing electricity efficiency in the output of goods and services. A sectoral 

shift in the Montana economy that occurred between 1998 and 2002 may also influence 

the trend: forestry, agriculture, and manufacturing declined during this time, while the 

service sector increased. Montana’s nonresidential energy intensity is expected to get 

even smaller in the future; the forecast based on historical data suggests an energy 

intensity of 0.09 kWh per dollar of GDP in 2025. 

98 For details, see DSIRE at http://www.dsireusa.org/. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 49 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-24. Montana’s residential electricity use per capita (2010)99 

Figure 2-25. Montana’s nonresidential electricity use per dollar of GDP (2010)100 

99 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 100 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “Regional Economic Accounts.” U.S. Bureau of
 

Economic Analysis, June 2012 .
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 50 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

Figure 2-26. Montana’s historical and projected electricity efficiencies101 

2.5.2.3 Energy Efficiency and Customer-Sited Renewables 

Greater energy efficiency and demand-side management curbs electricity demand 

growth, which also reduces demand for renewable energy under the state RPS. Montana’s 

IOU budgets for energy efficiency in 2011 totaled $21 million, amounting to 1.86% of 

statewide utility revenues. The state has made progress: the ACEEE estimates that 

efficiency programs in 2010 achieved a net incremental savings of 114 GWh, about 

0.85% of statewide retail electric sales.102 

Incentive programs that encourage customer-sited renewable energy projects also have 

the effect of decreasing the total electrical load, and these projects serve to reduce the 

amount of renewable energy the utility must supply to comply with the RRS. Montana 

offers numerous loans, rebates, grants, tax incentives, tax credits, and industry support 

programs that stimulate customer-sited renewable energy projects. 

2.5.2.4 Plausible Range of Demand for Renewables 

Historical trends in population, GDP, and per-unit electricity consumption suggest that 

retail sales could rise 20% from 2011 to 2025, reaching a projected total of 66 TWh by 

2025. Strong energy efficiency gains and changes in the Montana economy between 1998 

and 2007 accelerate the future reductions predicted for nonresidential energy efficiency, 

which in turn reduces the forecast for nonresidential sales. 

101 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012; “Regional Economic Accounts.” U.S. Bureau of Economic Analysis, June 2012. 102 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE),
 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 51 

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The SPSC’s extended demand forecast suggests 2025 retail sales of 69 TWh, taking into 

account energy efficiency improvements consistent with state requirements. These two 

forecasts establish a plausible range for future retail electricity sales. Applying current 

RES requirements to these two retail sales forecasts suggests that the demand for 

renewable energy related to the RES will most likely be between 10.4 TWh and 

10.7 TWh in 2025. 

The voluntary market also increases demand for renewable energy because voluntary 

sales do not count toward the RRS requirement. In 2009, electric customers in Montana 

voluntarily purchased more than 6 GWh of renewable energy.103 Estimates indicate a 

45% growth in voluntary demand across the West between 2009 and 2015, which means 

that Montana’s voluntary market could exceed 9 GWh by 2015.104 

There is currently 0.7 TWh of renewable energy serving in-state loads. This suggests 

0.34 TWh to 0.37 TWh of currently unmet future demand. 

2.5.3 Supply 

Approximately 60% of the electricity produced in Montana comes from coal-fired 

generating facilities, with an additional 35% produced from conventional hydropower 

(constructed prior to 2000). Colstrip, a 2,094-MW coal-fired plant located in southeastern 

Montana, produces more than 13 TWh annually. Most of the power produced at Colstrip 

is exported to other states; exports from Colstrip amount to 29% of Montana’s total 

annual electric production. 

*46% of Montana’s small hydro generation goes to other states as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. Exports from the Colstrip coal plant account for 29% of 

Montana’s total generation. 

Figure 2-27. Montana’s current electricity supply105 

103 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 104 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009.
 105 SNL Energy, extracted Dec. 10, 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 52 

at www.nrel.gov/publications. 
 

 

 

2.5.3.1 Existing Renewable Energy Supply 

The remaining 5% of electricity is produced from renewable sources, almost all of which 

is wind power. In-state facilities are currently capable of producing over 1.4 TWh per 

year, with about 1.3 TWh per year coming from wind power. About 61% of the 

electricity generated from renewable energy sources in Montana is exported out of 

the state. 

2.5.3.2 Planned Renewable Energy Supply 

Montana has two planned wind projects totaling 229 MW. San Diego Gas & Electric has 

signed a PPA to purchase power from the 189-MW Rim Rock Wind Farm, and 

Northwestern Energy has a PPA with the 40-MW Spion Kop Wind Project. A small 

biomass plant is also being planned. 

2.5.3.3 Undeveloped Renewable Energy Supply 

Montana has an estimated 30.5 TWh of unused prime resources in its renewable energy 

zones (all from wind). This far exceeds what the state is likely to need for its own RRSrelated demand, leaving a large surplus that could be developed for export. An additional 

3.3 TWh of lesser-quality wind and biomass resources would be competitive to meet any 

in-state demand. 

2.5.4 Conclusion 

In 2025, Montana’s demand for renewable energy related to the RRS will most likely be 

between 1.04 TWh and 1.07 TWh. With 0.7 TWh of renewable energy currently serving 

in-state loads, this suggests 0.34 to 0.37 TWh of currently unmet future demand. About 

30.5 TWh of unused prime wind resource base still remains for development, with an 

additional 3.3 TWh of non-prime wind and biomass resources available for development 

as well. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 53 

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2.6 Nevada 

2.6.1 State Highlights 

• Nevada will need between 5.6 TWh and 6.6 TWh of renewable energy in 2025 to meet 

targets stipulated by current state law. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 3.5 TWh annually. 

• Prime, export-quality geothermal and solar resources that have not yet been 

developed could provide at least 12.7 TWh annually. The state has an additional 36.8 

TWh of non-prime solar, biomass, and wind resources that could meet in-state 

demand. 

Nevada’s prime-quality solar and geothermal resources are three times what it will need 

in 2025 to meet the state’s RPS requirement (see Figure 2-29). The energy equivalent of 

these prime resources is more than one and a half times the amount of power generated 

by Nevada’s Mohave coal plant before it closed in 2006. New transmission corridors will 

improve the connections between northern and southern Nevada, enabling wider resource 

utilization within the state. The new lines could also provide the opportunity for 

importing low-cost wind power from Wyoming and Montana and for exporting its 

baseload geothermal power. Nevada currently exports geothermal power and a small 

amount of solar power to other states. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-28. Nevada's renewable energy supply and demand106 

106 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

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National Renewable Energy Laboratory (NREL) 54 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

2.6.2 Demand 

Nevada’s demand for renewable energy is driven largely by the state’s RPS, which was 

first passed in 1997 and subsequently amended. Every 2 years NV Energy must increase 

the amount of renewable power it provides to customers (as a share of total sales). By 

2025, 25% of what it sells to customers must come from eligible renewable resources. At 

least 5% of the annual RPS requirement must come from solar energy through 2015 and 

at least 6% after that. 

Customer-sited demand reductions can offset up to one-quarter of the annual 

requirement.107 Eligible measures include those that are implemented in 2005 or after and 

are subsidized by the utility. Measures must reduce demand rather than simply shift 

demand to off-peak hours. 

The RPS requirement is calculated as percentages of sales. Consequently, the amount of 

renewable energy needed to meet the requirement is sensitive to total electricity demand 

and, similarly, to the success of energy efficiency programs. The level of energy 

intensity, GDP, population growth, and energy efficiency all affect total electricity 

demand. 

2.6.2.1 Residential Consumption 

Nevada is sparsely populated and has the lowest total electricity demand in the 

Southwest.108 Most of the consumption is in the Eldorado Valley around Las Vegas. The 

U.S. Census Bureau projects that Nevada’s population will increase 30% between 2010 

and 2025, which would affect the state’s demand for electricity. 

The average resident in Nevada used 4.30 MWh in 2010 (see Figure 2-30). Residential 

electricity use per capita has stayed fairly level for the last decade (see Figure 2-32), 

likely as a result of increasing state focus on efficiency over recent years. If past trends 

continue, electricity use per person will increase 7% between 2010 and 2025, with 

consumption at 4.62 MWh per person in 2025. 

2.6.2.2 Nonresidential Consumption 

Nevada’s energy intensity (the nonresidential energy use per dollar of GDP) is one of the 

highest in the region (see Figure 2-31). In 2010, the state used 0.29 kWh per dollar GDP. 

As with other states, Nevada’s electricity intensity in the nonresidential sector has 

declined in recent decades (see Figure 2-32), indicating greater electricity efficiency in 

the output of goods and services. The historical trend suggests that energy intensity will 

continue to improve between 2010 and 2025. 

107 For more information, see DSIRE at http://www.dsireusa.org/. 108 Total retail electricity sales in 2010 totaled 33 TWh. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 55 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-29. Nevada’s residential electricity use per capita (2010)109 

Figure 2-30. Nevada’s nonresidential electricity use per dollar of GDP (2010)110 

109 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 110 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “Regional Economic Accounts.” U.S. Bureau of
 

Economic Analysis, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 56 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 2-31. Nevada’s historical and projected electricity efficiencies111 

2.6.2.3 Energy Efficiency Measures 

The degree to which energy efficiency measures reduce total demand is one of the 

variables that will influence actual demand for renewable energy in the future. Nevada 

requires utilities to offer energy efficiency programs and to include energy efficiency in 

their integrated resource planning. Utilities recover the costs of the programs through 

their annual rate cases, and as of 2011, may recover revenue losses resulting from the 

programs. Budgets for energy efficiency programs were around $47.2 million, amounting 

to about 1.55% of retail sales. Net incremental savings from efficiency programs in 2010 

are estimated at 355 GWh, or 1.05% of retails sales.112 

NV Energy’s 2010 integrated resource plan included a 20% increase in the efficiency 

program budget. If Nevada’s electricity consumption patterns do better than the historical 

trend of the past few years, improved efficiency could further curb increases in total 

electricity demand. 

2.6.2.4 Plausible Range of Demand for Renewables 

Historical trends in population, GDP, and per-unit electricity consumption suggest that 

retail sales could rise 23% from 2011 to 2025, reaching a projected total of 43.6 TWh by 

2025. The SPSC’s extended demand forecast suggests 2025 retail sales of 37.2 TWh, 

taking into account energy efficiency improvements consistent with state requirements. 

111 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 112 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE),
 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 57 

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These two forecasts establish a plausible range for future retail electricity sales. Applying 

current RES requirements to these two retail sales forecasts suggests that the demand for 

renewable energy related to the RES will most likely be between 5.6 TWh and 6.6 TWh 

in 2025. 

The voluntary market for renewable energy could increase the demand for renewable 

energy beyond what state RPS policy requires. Voluntary purchases in Nevada have not 

historically been strong, however—only 69 MWh in 2010.113 Estimates suggest a 45% 

growth in voluntary demand across the West from 2009 to 2015, but actual growth for 

Nevada may continue to be limited.114 

The state’s existing renewable energy facilities and imports provide 3.5 TWh. This 

suggests 2.1 TWh to 3.1 TWh will still be needed by 2025 to meet RPS requirements. 

2.6.3 Supply 

NV Energy’s two operating subsidiaries—Nevada Power Company (NPC) and Sierra 

Pacific Power Company (SPPC)—serve the majority of the customers in Nevada. The 

subsidiaries function as two separate balancing authorities with limited transfers between 

them.115 NPC serves southern Nevada around Las Vegas, Henderson, and adjoining 

areas, including Nellis Air Force Base and DOE’s Nevada Test Site. SPPC serves 

367,000 customers in northern Nevada and northeastern California.116 Eight rural electric 

cooperatives, four municipal utilities, and three general improvement districts provide 

power to the remaining customers in Nevada, who make up about 7% of the state’s peak 

load.117 

Planned fossil fuel capacity retirements in the state could accelerate new renewable 

energy procurement. Currently, NV Energy stands to lose 670 MW of coal capacity from 

its portfolio by 2020, either through plant retirement or contract expiration.118 Some of 

this baseload capacity could potentially be replaced with geothermal generation. Sixtyfive geothermal projects are already in development, which is more than any other state. 

Additional retirements of 400 MW of natural gas and diesel generation could be replaced 

with wind, solar, and other renewables not serving baseload.119 

113 Survey Form EIA-861: Annual Electric Power Industry Report. Washington, D.C.: Energy Information
 

Administration (EIA), 2012. Accessed September 2011:
 

http://www.eia.gov/cneaf/electricity/page/eia861.html.
 114 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009.

115 On September 22, 2008, Nevada Power and Sierra Pacific Power began doing business as subsidiaries of
 

NV Energy.

116 SNL Energy, updated December 2012.
 117 These include Valley Electric Association, the City of Boulder City, Mount Wheeler Power Company,
 

Wells Rural Electric Company, Raft River Rural, Harney Electric Cooperative, and Plumas-Sierra Rural
 

Electric Cooperative. http://www.swenergy.org/programs/utilities/nevada.htm.
 118 NV Energy 2013-2032 Triennial Integrated Resource Plan. Submitted 2012 to the Nevada Public
 

Utilities Commission. https://www.nvenergy.com/company/rates/filings/.
 119 “GEA: Geothermal Installations Fell in 2010, but Industry Poised for Growth.” SNL NewsWire. SNL
 

Energy, March 30, 2011.
 

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National Renewable Energy Laboratory (NREL) 58 

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*22% of Nevada’s solar generation goes to other states as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. 

Figure 2-32. Nevada’s current electricity supply120 

Nevada was a net exporter of power until 2006, when the coal-fired Mohave Generating 

Station ceased operation. Since then, the state’s net balance has been near zero. The 

majority of in-state electricity generation is fueled by natural gas (67%) and coal (18%). 

2.6.3.1 Existing Renewable Energy Supply 

About 9.7% of the electricity generated within Nevada comes from renewable energy 

resources (see Figure 2-33). About three-fourths of this production comes from 

geothermal resource; the rest is solar, including the Solar One CSP plant and a PV array 

on Nellis Air Force Base. Additional large-scale solar is now being added, including a 

110-MW CSP facility and multiple large-scale PV projects ranging from 20 MW to 55 

MW. About 16% of the electricity generated from renewable energy sources in Nevada is 

exported out of the state (22% of solar power produced and 19% of geothermal power 

produced is exported). 

2.6.3.2 Planned Renewable Energy Supply 

According to its 2011 compliance report, NV Energy expects to increase in-state 

renewable energy generation through three new renewable energy contracts, the 

modification of an existing contract, and the repowering of an existing geothermal 

facility. The utility is on track to meet renewable energy requirements for the near term. 

The approach of Sierra Power in the North is to focus on managing existing resources, 

while Nevada Power in the South requires more focus on project development to meet 

renewables demand.121 

2.6.3.3 Undeveloped Renewable Energy Supply 

Nevada has an estimated 12.7 TWh of unused prime resources in its renewable energy 

zones, including 6.1 TWh of prime solar in the southern portion of the state and 6.6 TWh 

120 SNL Energy, extracted Dec. 10, 2012.
 121 The NV Energy Portfolio Standard Annual Report for Compliance Year 2011 (Docket 12-03036) can be
 

downloaded from the Nevada Public Utilities Commission Dockets website at:
 

http://pucweb1.state.nv.us/PUC2/Dktinfo.aspx?Util=RenewableClosed.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 59 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

of geothermal further north. Electricity from these resources would be available for 

export in a regional market. The geothermal resources would be a particularly valuable 

export because it serves as a baseload resource. An additional 36.8 TWh of non-prime 

solar and biomass resource would be competitive to meet in-state demand. 

2.6.4 Conclusion 

Nevada is rich in prime renewable resources. There is more than four times the amount of 

prime quality geothermal and solar resources needed to meet the state’s RPS in a highgrowth scenario, putting Nevada in a good position to meet post-2025 demand, as well as 

provide exports in a regional market. 

Historically, the absence of a north-south transmission corridor has been a barrier to 

bringing geothermal resources from the northern part of the state to load centers around 

Las Vegas. A new 500-kV line will increase north-south power flows and at the same 

time will enable delivery of Nevada geothermal power to California and Arizona. The 

new line is part of a larger corridor extending to Wyoming that will also provide Nevada 

with access to some of the most productive and least-cost wind resources in the nation. 

To the extent it does so, importing Wyoming wind power would enable Nevada to export 

more of its prime geothermal and prime solar resources to California and Arizona. 

Nevada geothermal would be a particularly valuable export because it provides 

baseload power. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 60 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

2.7 New Mexico and El Paso, Texas 

2.7.1 State Highlights 

• New Mexico will need between 3.0 TWh and 4.0 TWh of renewable energy in 2025 to 

meet targets stipulated by current state law. Wind may count for no more than 75%. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 2.0 TWh annually. 

• Prime, export-quality wind resources that have not yet been developed could provide 

at least at least 3.8 TWh annually. The state has an additional 75 TWh of non-prime 

wind, solar, and biomass resources that could meet in-state demand. 

New Mexico’s prime, export-quality wind resources are more than three times what it 

needs to meet its anticipated state demand for renewable energy in 2025. New Mexico 

has sufficient solar and biomass resources to fulfill non-wind set-asides, and developing 

these lower quality resources for in-state use means that even more high-quality wind 

will be available to export in the regional market. The greatest likely demand for 

New Mexico’s surplus wind-generated electricity is Arizona and California. While some 

New Mexico wind power flows east to serve load in the Texas Panhandle, access to the 

large Texas market is currently limited. New Mexico exports wind power and solar 

power to other states. It does not import renewable power from any other state. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-33. New Mexico's renewable energy supply and demand122 

122 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 61 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.7.2 Demand 

Demand for renewable energy in New Mexico is driven largely by the state RPS, which 

requires the IOUs and electric cooperatives to supply a percentage of their electricity 

sales with renewable resources by 2020. State law requires IOUs to have 20% of sales 

from renewables, with at least one-fifth coming from solar, at least one-fifth from wind, 

and at least one-tenth from biomass, geothermal, or hydro resources. Three percent of the 

requirement must be from distributed renewable generation. RECs may count toward the 

requirement. Electric cooperatives must supply 5% of sales with renewable energy by 

2015, increasing 1% each year to reach 10% by 2020.123 

The RPS requirement is calculated as percentages of sales. Consequently, the amount of 

renewable energy needed to meet the requirement is sensitive to total electricity demand 

and, similarly, to the success of energy efficiency programs. The level of energy 

intensity, GDP, population growth, and energy efficiency all affect total electricity 

demand. 

2.7.2.1 Residential Consumption 

New Mexico has had the smallest population in the region since 2000, and its population 

has not grown as sharply as in neighboring states. Continuing this trend would result in a 

population increase of only 2% between 2011 and 2025. By comparison, historical 

trends indicate population increases of 30%–33% for Arizona and Nevada and 16% for 

California and Washington. Slower population growth in New Mexico will curb total 

residential electricity demand growth. 

New Mexico’s per-capita consumption of electricity for residential use is among the 

lowest in the region. In 2010, the average resident in New Mexico used 3.27 MWh (see 

Figure 2-35). However, per capita consumption has been rising sharply, which is a trend 

that is expected to continue (see Figure 2-37). Between 2011 and 2025, per-capita 

consumption is expected to rise 19%, reaching 4.05 MWh per person by 2025. 

2.7.2.2 Nonresidential Consumption 

As in other states in the region, New Mexico’s economy is becoming more efficient with 

respect to the use of electricity as an input to state productivity. There are also sectoral 

shifts in the New Mexico economy that could influence nonresidential consumption: 

manufacturing’s share of state output is decreasing while the services sector is increasing. 

The state’s electricity intensity—the nonresidential consumption per dollar of state 

GDP—was 0.12 kWh per dollar of product in 2010. 

123 For more information, see DSIRE at http://www.dsireusa.org/. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 62 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-34. New Mexico’s residential electricity use per capita (2010)124 

Figure 2-35. New Mexico’s nonresidential electricity use per dollar of GDP (2010)125 

124 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 125 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “Regional Economic Accounts.” U.S. Bureau of
 

Economic Analysis, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 63 

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Figure 2-36. New Mexico’s historical and projected electricity efficiencies126 

The GDP growth is not expected to rise as sharply in New Mexico, as compared to other 

western states. A 42% increase in GDP is expected between 2011 and 2025. Total 

nonresidential electricity demand is expected to decline at the same rate. Based on these 

estimates, the electricity intensity of the state is anticipated to decline to 0.04 kWh per 

dollar of GDP by 2025, among the lowest in the region. 

2.7.2.3 Energy Efficiency Measures 

The degree to which energy efficiency measures reduce total demand is one of the 

variables that will influence actual demand for renewable energy in the future. New 

Mexico has an energy efficiency resource standard that requires IOUs to reduce 

electricity use by 5% of 2005 retail sales by 2014 and 10% by 2020. Cooperative utilities 

have self-imposed targets and submit annual reports to the Public Regulatory 

Commission (PRC) describing their demand-side management efforts.127 

New Mexico’s Efficient Use of Energy Act of 2005 enacted several new energy 

efficiency policies. Utilities’ total revenues are partially decoupled from the volume of 

electricity they sell, reducing the financial disincentive against efficiency measures. 

Utilities are now required to implement demand-side management programs and can 

receive financial incentives and bonuses for effective efficiency programs. In resource 

126 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012. 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau, 

October 2012; “Regional Economic Accounts.” U.S. Bureau of Economic Analysis, June 2012. 127 For more information, see: 

http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=NM19R&re=1&ee=1. 

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National Renewable Energy Laboratory (NREL) 64 

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planning, utilities must make use of all achievable, cost-effective energy efficiency 

128 resources.

Following these policies, there is evidence of a shift toward greater efficiency in New 

Mexico. Budgets for efficiency programs in 2011 totaled $26.2 million, amounting to 

about 1.31% of retail sales. Net incremental savings from efficiency programs in 2010 

are estimated at 85.7 GWh, or 0.38% of retails sales.129 

2.7.2.4 Plausible Range of Demand for Renewables 

Historical trends in population, GDP, and per-unit electricity consumption suggest that 

retail sales could decrease 15% from 2011 to 2025, reaching a projected total of just 

under 20 TWh by 2025. Energy efficiency gains and sectoral changes in the New Mexico 

economy accelerate the future reductions predicted for nonresidential energy efficiency, 

which in turn reduces the forecast for nonresidential sales. 

The SPSC’s extended demand forecast suggests 2025 retail sales of 26.4 TWh, taking 

into account energy efficiency improvements consistent with state requirements. These 

two forecasts establish a plausible range for future retail electricity sales. Applying 

current RES requirements to these two retail sales forecasts suggests that the demand for 

renewable energy related to the RES will most likely be between 3.0 TWh and 4.0 TWh 

in 2025. 

The size of the market for voluntary purchase of renewable energy increases demand for 

renewable generation beyond that stimulated by state RPS. In 2010, New Mexico 

electric customers in all sectors voluntarily purchased 190,600 MWh of renewable 

energy, down 13% from the previous year. Estimates indicate a 45% growth in voluntary 

demand across the West from 2009 to 2015.130 

Retirement of existing generation facilities could also affect future demand for 

renewables, especially if capital costs for new installations continue to decrease. 

The state’s existing facilities provide 2.0 TWh. This suggests 1.0 TWh to 2.0 TWh will 

still be needed by 2025 to meet RPS requirements. 

2.7.3 Supply 

Three IOUs sell electricity in the state and account for most renewable energy demand: 

Public Service Company of New Mexico (PNM), El Paso Electric Co. (EPE), and 

Southwestern Public Service Co. (SPS, an operating company of Xcel Energy). PNM is 

the state’s largest provider, with approximately 487,000 customers statewide. EPE serves 

379,000 customers in the El Paso region (one-quarter of them in New Mexico), and Xcel 

128 For more information, see: http://www.aceee.org/energy-efficiency-sector/statepolicy/new%20mexico/203/all/191.
 129 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE),
 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf.
 130 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 65 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

serves 114,000 in the eastern part of the state. There are 21 rural electric cooperatives that 

sell power to the state’s remaining customers. 

New Mexico generates more electricity than it uses and is consistently a net exporter of 

power. Most of what New Mexico generates is fueled by coal (71%), with the majority 

coming from the state’s two coal-fired gigaplants: the San Juan and Four Corners power 

plants, both located in northwest New Mexico. Arizona’s Tucson Electric Power and 

SCE together own nearly one-third of the San Juan plant. APS and SCE own nearly 

three-fourths of the Four Corners plant. Power generated from both San Juan and Four 

Corners is exported to neighboring states; combined, the power exported from these two 

plants account for half of all the power generated within New Mexico annually. 

Natural gas, wind, and hydro provide most of the remainder of electricity generation, 

with a small percentage from biomass (see Figure 2-38). 

2.7.3.1 Existing Renewable Energy Supply 

Together, renewable energy technologies produced about 6.8% of New Mexico’s 

electricity. In-state facilities are currently capable of producing more than 2.6 TWh per 

year. The majority of renewable energy generation produced in New Mexico is from 

wind (2.2 TWh per year). About 31% of the electricity generated from renewable energy 

sources in New Mexico is exported out of the state 

*36% of New Mexico’s solar generation goes to other states as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. Exports from the Four Corners and San Juan coal plants 

account for 47.4% of New Mexico’s total generation. 

Figure 2-37. New Mexico’s current electricity supply131 

131 SNL Energy, extracted Dec. 10, 2012. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 66 

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While New Mexico has prime-quality wind resources in abundance, the three New 

Mexico IOUs have had challenges finding renewable resources besides wind and solar. 

Each has requested a temporary variance from the requirement pertaining to resources 

other than wind and solar.132 

2.7.3.2 Planned Renewable Energy Supply 

PNM plans to add renewable energy to its portfolio, including generation from a new 20­

MW solar PV facility in 2013, 9 MW of new customer sited PV by 2016, and generation 

from a 10-MW geothermal plant that is planned to be in service by 2014.133 EPE submits 

that its only new renewable energy acquisition would be the purchase of biogas from an 

existing or new supplier in order to meet its requirement for renewable power from 

resources other than wind and solar. SPS is investing in new distributed solar projects to 

assist in meeting its 2014 requirement.134 

2.7.3.3 Undeveloped Renewable Energy Supply 

Within the state’s renewable energy zones, there is 3.8 TWh of prime wind resource that 

is yet undeveloped, the generation of which would be competitive for export in a regional 

market. An additional 74 TWh of non-prime resources are available to meet in-state 

demand, including 41 TWh of wind, 32 TWh of solar, and 1.6 TWh of biomass. 

2.7.4 Conclusion 

New Mexico has nearly twice as much prime quality wind resource as it is likely to need 

for RPS requirements in 2025 under current state law. This positions New Mexico to 

meet its own post-2025 demand and to export surplus prime wind in a regional market. 

Developing its solar and biomass resources for in-state use will leave even more highquality wind available for export. 

The most likely demand for surplus wind will be in Arizona and California, and several 

regional transmission projects that are in planning or permitting would connect New 

Mexico with these major western markets. While some New Mexico wind power flows 

east to serve load in the Texas Panhandle, access to the large Texas market is 

currently limited. 

132 “Public Service Company of New Mexico: Renewable Energy Portfolio Procurement Plan for 2013.” 

PNM, 2012. http://www.pnm.com/regulatory/pdf_electricity/renewables-plan-2013.pdf.; “El Paso Electric 

Company’s Application for Approval of its 2012 Annual Procurement Plan and Request for 2012 

Variance.” El Paso Electric Company, undated. 

http://www.epelectric.com/files/html/Renewable/Procurement_Plans/2012/Application_2012_Procurement.
 

pdf; “Annual Renewable Energy Portfolio Report for 2011.” Southwestern Public Company, July 1, 2012.
 

http://www.xcelenergy.com/staticfiles/xe/Regulatory/Regulatory%20PDFs/CLB22011RPSPlanfor2013.pdf.
 133 “Public Service Company of New Mexico: Renewable Energy Portfolio Procurement Plan for 2013.”
 

PNM, 2012. http://www.pnm.com/regulatory/pdf_electricity/renewables-plan-2013.pdf.
 134 “2012 Annual Renewable Energy Portfolio Procurement Plan.” Southwestern Public Service Company,
 

July 1, 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 67 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.7.5 El Paso, Texas 

EPE’s service area is divided between Texas and New Mexico. Its service area in and 

around El Paso is the only part of Texas that is in the Western Interconnection. 

Even though most of its retail sales occur in Texas, the utility’s 2025 renewable energy 

obligation under the Texas RPS is expected to be less than its requirement under the New 

Mexico RPS. Like most other electric retailers in Texas, EPE meets its Texas RPS 

obligation through RECs rather than direct procurement of renewable resources. Because 

Texas RECs trade in a relatively robust market, EPE can use RECs from renewable 

resources anywhere in Texas to meet its state requirement. 

For this analysis, we assume that EPE will continue to use Texas RECs to satisfy its 

requirement under the Texas RPS. The implication is that the utility would need virtually 

no renewable resources in the Western Interconnection to meet obligations under the 

Texas RPS. Similarly, it suggests that most of EPE’s demand for renewable power in the 

Western Interconnection will come from its obligation under the New Mexico RPS. The 

utility’s New Mexico sales, which account for about 22% of its total sales, are included in 

the analysis of supply and demand for New Mexico. 

Table 2-3. El Paso Electric in Texas and New Mexico135 

Texas New Mexico 

Total consumers 287,516 91,031 

GWh sold in 2011 5,965 1,696 

Projected GWh sales in 2025a 8,098 2,303 

Projected RPS requirement in 2025 (GWh) 326b 460c 

a EPE projects a native system energy demand of 9,819 GWh for 2021. It also projects a system growth rate 

of 1.45% by 2021. 

b We assume that EPE’s share of the Texas RPS requirement in 2025 will be the same as its share in 2010, 

which was 2.5%. The Texas RPS ultimately requires 5,000 MW of new renewable capacity by 2015, 

equivalent to 13,060 GWh based on a 30% capacity factor. 

c Based on 20% of projected GWh sales in New Mexico. 

135 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012. 

http://www.eia.gov/electricity/data/eia861/index.html.; “Integrated Resource Plan Presentation.” El Paso 

Electric Company, April 11, 2012; “Annual Report on the Texas Renewable Energy Credit Trading 

Program.” Electric Reliability Council of Texas, Inc., 2010 and 2011. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 68 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

2.8 Oregon 

2.8.1 State Highlights 

• Oregon will need between 7.2 TWh and 8.3 TWh of renewable energy in 2025 to meet 

targets stipulated by current state law. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 8 TWh annually. Nearly half serves in-state load in Oregon; more than half is 

exported. 

• Explored geothermal resources could provide up to 5.7 TWh annually, but little has 

been developed to date. The state has an estimated 5.3 TWh of biomass and solar 

potential, also largely undeveloped. 

Most of Oregon’s renewable energy development to date has been wind power, but much 

of that is exported to other states and there is limited potential for further expansion. 

Currently the state imports a very small amount of wind power. Oregon also has some 

non-prime solar that could meet in-state loads. Technically, Oregon has enough explored 

geothermal potential to meet the balance of state renewable energy targets in 2025, but 

very little has been developed to date. Oregon currently exports a small amount of 

biomass power. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-38. Oregon’s renewable energy supply and demand136 

136 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 69 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

2.8.2 Demand 

Oregon’s demand for renewable energy is currently driven primarily by the state’s RPS 

legislation, established in 2007 as part of the Oregon Renewable Energy Act of 2007. It 

requires the large utilities that serve more than 3% of the state’s load to obtain 25% of 

their retail sales from eligible renewable resources by the end of 2025. There are interim 

requirements of 5% by the end of 2011, 15% by the end of 2015, and 20% by the end of 

2025. Smaller utilities, such as those that serve between 1.5% and 3% of the state’s load 

must meet a 10% RPS by 2025. Utilities that serve less than 1.5% of the state’s load must 

meet a 5% RPS by 2025. Any utility, regardless of size, that purchases a stake of or 

contracts with a new coal plant is subject to meeting the largest utility standard.137 

In addition, the Oregon Renewable Energy Act of 2007 established a goal of acquiring 

8% of retail electric load from small-scale—under 20 MW—projects by 2025. 

The RPS requirement is calculated as percentages of load. Consequently, the amount of 

renewable energy needed to meet the requirement is sensitive to total electricity demand 

and, similarly, to the success of energy efficiency programs. The level of energy 

intensity, GDP, population growth, and energy efficiency all affect total electricity 

demand. 

2.8.2.1 Residential Consumption 

The U.S. Census Bureau projects a 15% increase in Oregon’s population between 2010 

and 2025. This would put the state’s population at over 4.5 million in 2025. Oregon’s 

residential electricity use per person is one of the highest in the region. On average, 

Oregon residents used 4.91 MWh per person in 2010 (see Figure 2-40), more than double 

the per-capita consumption of California. However, historical trends indicate that this 

will decrease 3% by 2025, with consumption reaching 4.78 MWh per person by 2025 

(see Figure 2-42). 

2.8.2.2 Nonresidential Consumption 

Oregon’s energy intensity (the nonresidential energy use per dollar of GDP) is on the 

lower end of the spectrum in the region. In 2010, the state used 0.15 kWh per dollar of 

GDP (see Figure 2-41). As with other states, Oregon’s electricity intensity in the 

nonresidential sector has declined significantly in recent decades (see Figure 2-42), 

indicating increasing electricity efficiency in the output of goods and services. The 

change also reflects a sectoral shift in the Oregon economy toward manufacturing at a 

stronger pace than in the West as a whole. The state is expected to cut nonresidential 

energy intensity even more between 2010 and 2025; trends based on historical data 

forecast an energy intensity of 0.06 kWh per dollar of GDP in 2025. 

137 For more information, see DSIRE at http://www.dsireusa.org/. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 70 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-39. Oregon’s residential electricity use per capita (2010)138 

Figure 2-40. Oregon’s nonresidential electricity use per dollar of GDP (2010)139 

138 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 139 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “Regional Economic Accounts.” U.S. Bureau of
 

Economic Analysis, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 71 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-41. Oregon’s historical and projected electricity efficiencies140 

2.8.2.3 Energy Efficiency and Customer-Sited Renewables 

Greater energy efficiency and demand-side management curbs electricity demand 

growth, which also reduces demand for renewable energy under the state RPS. Oregon’s 

IOU budgets for energy efficiency in 2011 totaled $172 million, amounting to 4.51% of 

statewide utility revenues. The state has made progress: the ACEEE estimates that 

efficiency programs in 2010 achieved a net incremental savings of 511 GWh, over 1.1% 

of statewide retail electric sales.141 

Incentive programs that encourage customer-sited renewable energy projects also have 

the effect of decreasing the total electrical load, and these projects serve to reduce the 

amount of renewable energy the utility must supply to comply with the RPS. Oregon 

offers numerous loans, rebates, grants, tax incentives, tax credits, and performance-based 

incentives that stimulate customer-sited renewable energy projects. 

2.8.2.4 Plausible Range of Demand for Renewables 

Historical trends in population, GDP, and per-unit electricity consumption suggest that 

retail sales could decrease 4% from 2011 to 2025, reaching a projected total of 44.4 TWh 

by 2025. Energy efficiency gains and sectoral changes in the Oregon economy accelerate 

the future reductions predicted for nonresidential energy efficiency, which in turn reduces 

the forecast for nonresidential sales. 

140 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 141 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE),
 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 72 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The SPSC’s extended demand forecast suggests 2025 retail sales of 51.3 TWh, taking 

into account energy efficiency improvements consistent with state requirements. These 

two forecasts establish a plausible range for future retail electricity sales. Applying 

current RES requirements to these two retail sales forecasts suggests that the demand for 

renewable energy related to the RES will most likely be between 7.2 TWh and 8.3 TWh 

in 2025. 

The voluntary market also increases demand for renewable energy because voluntary 

sales do not count toward the RPS requirement. In 2009, electric customers in Oregon 

voluntarily purchased more than 1.1 TWh of renewable energy.142 Estimates indicate a 

45% growth in voluntary demand across the West between 2009 and 2015, which means 

that Oregon’s voluntary market could exceed 1.6 TWh by 2015.143 

There are currently 3.7 TWh of renewable energy serving in-state loads. This suggests 

3.4 TWh to 4.6 TWh of new renewable energy procurements needed to meet RPS 

requirements in 2025. 

2.8.3 Supply 

More than half of Oregon’s electricity is produced from conventional hydropower plants 

(hydropower plants constructed prior to 2000 are categorized as conventional 

generation), with gas and coal plants providing over 32% of the electricity produced. 

*28% of Oregon’s biomass generation goes to other states as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. 

Figure 2-42. Oregon’s current electricity supply144 

142 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 143 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009.

144 SNL Energy, extracted Dec. 10, 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 73 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

2.8.3.1 Existing Renewable Energy Supply 

Together, renewable energy technologies produced about 14% of Oregon’s electricity. Instate facilities are currently capable of producing over 7.3 TWh per year. The majority of 

renewable energy produced in Oregon is from wind (6.8 TWh per year) and biomass (0.5 

TWh per year). About 70% of the electricity generated from renewable energy sources in 

Oregon is exported out of the state. 

2.8.3.2 Planned Renewable Energy Supply 

By the end of 2012, Oregon had two geothermal plants planned totaling 67 MW and two 

hydropower plants planned totaling 58.3 MW.145 The 63-MW Neal Hot Springs 

Geothermal Plant, operated by U.S. Geothermal Inc., has signed a power purchase 

agreement with Idaho Power. 

2.8.3.3 Undeveloped Renewable Energy Supply 

Wind power development in Oregon’s renewable energy zones already exceeds the 

amount of prime-quality wind potential estimated to be in those areas. This suggests that 

Oregon might be facing constraints on future wind expansion. The state has some 5.7 

TWh of prime geothermal potential as well as an estimated 4.7 TWh of biomass 

potential, but so far both have seen limited development. 

2.8.4 Conclusion 

Oregon’s demand for renewable energy related to its RPS will most likely be between 

7.2 TWh and 8.3 TWh in 2025. With 3.7 TWh of renewable energy currently serving instate loads, this suggests 3.4 TWh to 4.6 TWh more will be needed to meet state RPS 

levels in 2025. As its own prime-quality wind resources become fully developed, Oregon 

may have to turn to other resources in order to meet out-year RPS requirements as well as 

any post-2025 demand. 

145 SNL Energy, updated December 2012. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 74 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

2.9 Utah 

2.9.1 State Highlights 

• Utah will need approximately 7.5 TWh of renewable energy in 2025 to meet targets 

stipulated by current state law. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 1.5 TWh annually. Current renewable energy projects supporting state targets 

amount to about 3.6 TWh annually, some of which is wind power imported from 

Wyoming. 

• Utah has an estimated 0.7 TWh of undeveloped geothermal resources. Its renewable 

energy zones also contain about 4.2 TWh of non-prime wind and biomass resources. 

Utah has already tapped most of its best renewable resources. Existing development 

exceeds the amount of prime wind resources estimated to be in the state’s renewable 

energy zones, although some 700 GWh worth of geothermal baseload potential remains 

untapped. The state already imports a large amount of low-cost wind power from 

Wyoming. It exports some wind power as well as small amounts of biomass and 

geothermal power. Utah will need an estimated 3.9 TWh in additional resources to meet 

its renewable energy target in 2025; it has slightly more than that amount of non-prime 

wind and biomass resources. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-43. Utah’s renewable energy supply and demand146 

146 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 75 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.9.2 Demand 

Utah’s demand for renewable energy is currently driven primarily by the state’s Energy 

Resource and Carbon Emission Reduction Initiative (S.B. 202) legislation, enacted in 

March 2008. The legislation states that utilities—IOUs, cooperative, and municipal— 

should utilize eligible renewables to account for 20% of their adjusted retail sales by 

2025 to the extent it is cost effective. 

2.9.2.1 Residential Consumption 

The U.S. Census Bureau projects a 14% increase in Utah’s population between 2010 and 

2025. This would put the state’s population at nearly 3.3 million. Utah’s residential 

electricity use per person is one of the lowest in the region. On average, Utah residents 

used 3.18 MWh per person in 2010 (see Figure 2-45). However, historical trends indicate 

that this will increase 19% by 2025, with consumption reaching 3.92 MWh per person by 

2025 (see Figure 2-47). 

2.9.2.2 Nonresidential Consumption 

Utah’s energy intensity (the nonresidential energy use per dollar of GDP) is on the lower 

end of the spectrum in the region. In 2010, the state used 0.16 kWh per dollar of GDP 

(see Figure 2-46). As with other states, Utah’s electricity intensity in the nonresidential 

sector has declined significantly in recent decades (see Figure 2-47), indicating increasing 

electricity efficiency in the output of goods and services. The state is expected to see 

further improvements in nonresidential energy intensity between 2010 and 2025. 

2.9.2.3 Energy Efficiency and Customer-Sited Renewables 

Greater energy efficiency and demand-side management curbs electricity demand 

growth, which also reduces demand for renewable energy under the state RES. Utah’s 

IOU budgets for energy efficiency in 2011 totaled $49.2 million, amounting to 3.19% of 

statewide utility revenues. The state has made some progress: the ACEEE estimates that 

efficiency programs in 2010 achieved a net incremental savings of 182 GWh.147 

Incentive programs that encourage customer-sited renewable energy projects also have 

the effect of decreasing the total electrical load, and these projects serve to reduce the 

amount of renewable energy the utility must supply to comply with the RPS. Utah offers 

numerous loans, rebates, and tax incentives that stimulate customer-sited renewable 

energy projects. 

147 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE), 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 76 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-44. Utah’s residential electricity use per capita (2010)148 

Figure 2-45. Utah’s nonresidential electricity use per dollar of GDP (2010)149 

148 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 149 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “Regional Economic Accounts.” U.S. Bureau of
 

Economic Analysis, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 77 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 2-46. Utah’s historical and projected electricity efficiencies150 

2.9.2.4 Plausible Range of Demand for Renewables 

Historical trends in population, GDP, and per-unit electricity consumption suggest that 

retail sales could rise 26% from 2011 to 2025, reaching a projected total of 37.8 TWh by 

2025. The SPSC’s extended demand forecast, which takes into account energy efficiency 

improvements consistent with state requirements, suggests a similar level of retail sales: 

37.7 TWh. Applying current RES requirements to these two retail sales forecasts suggests 

that the demand for renewable energy related to the RES will most likely be around 7.5 

TWh in 2025. 

The voluntary market also increases demand for renewable energy because voluntary 

sales do not count toward the RPS requirement. In 2009, electric customers in Utah 

voluntarily purchased 0.18 TWh of renewable energy.151 Estimates indicate a 45% 

growth in voluntary demand across the West between 2009 and 2015, which means that 

Utah’s voluntary market could exceed 0.26 TWh by 2015.152 

There are currently 3.6 TWh of renewable energy serving in-state loads. This suggests 

approximately 3.9 TWh that utilities in Utah will need to procure by 2025 to meet 

state targets. 

150 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 151 Survey Form EIA-861: Annual Electric Power Industry Report. Washington, D.C.: Energy Information
 

Administration (EIA), 2012. Accessed September 2011:
 

http://www.eia.gov/cneaf/electricity/page/eia861.html.
 152 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 78 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

*14% of Utah’s biomass generation and 1% of geothermal generation goes to other states as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. Exports from the Intermountain coal plant account for 

23.1% of Utah’s total generation. 

Figure 2-47. Utah’s current electricity supply153 

2.9.3 Supply 

Over 81% of Utah’s electricity is produced from coal-fired plants, with natural gas and 

conventional hydropower plants (constructed prior to 2000) providing an additional 16% 

of the electricity. Utah is home to the Intermountain Power Plant, a 1,800-MW coal-fired 

plant that exports nearly 10 TWh annually to California. The power exported from 

Intermountain alone amounts to 23% of the total power generated annually in the State 

of Utah. 

2.9.3.1 Existing Renewable Energy Supply 

Together, renewable energy technologies produced about 2.3% of Utah’s electricity. Instate facilities are currently capable of producing nearly 1 TWh per year. The majority of 

renewable energy generation produced in Utah is from wind (0.6 TWh per year) and 

geothermal (0.3 TWh per year). About 58% of the electricity generated from renewable 

energy sources in Utah is exported out of the state (97% of wind power, 13% of biomass 

power, and 1% of geothermal power produced is exported). 

2.9.3.2 Planned Renewable Energy Supply 

One of the largest planned renewable energy facilities in Utah is the 65-MW Cove Fort 

geothermal plant, currently being constructed by Enel Green Power North America. A 

biomass project approximately 2.3 MW in capacity is in the pipeline as well. It is unclear 

whether power purchase agreements have been negotiated for either of these facilities. 

2.9.3.3 Undeveloped Renewable Energy Supply 

Wind resources already developed in Utah’s renewable energy zones are more than the 

amount of prime-quality wind estimated to be in the zones. Some 786 GWh of prime 

geothermal resources remain undeveloped, however. Another 4.2 TWh of lower-quality 

wind and biomass resources are undeveloped as well and would be competitive to meet 

in-state demand. 

153 SNL Energy, extracted Dec. 10, 2012. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 79 

at www.nrel.gov/publications. 
 

 

 

2.9.4 Conclusion 

Utah will need approximately 7.5 TWh of renewable power by 2025 to meet state goals. 

With 3.6 TWh of renewable energy currently serving in-state loads, this suggests a 

balance of 3.9 TWh that utilities will need to procure over the next decade. Undeveloped 

prime and nonprime resources in Utah’s renewable energy zones may be of sufficient 

quantity to meet this balance. As the most cost-effective of these resources are developed, 

however, additional imports will likely become more economically competitive. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 80 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

2.11Washington 

2.11.1 State Highlights 

• Washington will need between 8.4 TWh and 12.2 TWh of renewable energy in 2025 to 

meet targets stipulated by current state law. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 8.8 TWh annually. About one-third of the state’s current renewable energy 

generation—primarily wind power—is exported. 

• Washington has 4.0 TWh of non-prime wind, biomass, and small hydro resources that 

could meet in-state demand. 

Washington can meet the balance of its current renewable energy targets with in-state 

resources, but there is likely to be little left for subsequent demand beyond 2025. Power 

from wind and biomass already flows across the state’s border in both directions, with 

some exports and some imports. Washington has additional undeveloped wind, biomass, 

and hydro resources, but little of it is prime quality. Most of these untapped resources are 

likely to be relatively expensive to develop and are not likely to be competitive in a post2025 market. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-48. Washington’s renewable energy supply and demand154 

154 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 81 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

2.11.2 Demand 

Washington’s demand for renewable energy is currently driven primarily by the state’s 

RES legislation, established in 2006, most recently updated by SB 5575, and enacted in 

March 2012. It requires all utilities that serve more than 25,000 customers within the state 

to obtain 15% of their load from renewable resources by the end of 2020. There are 

interim requirements of 3% by the end of 2012 and 9% by the end of 2015. In addition, 

utilities must undertake all cost-effective energy conservation options.155 

The RES requirement is calculated as percentages of load. Consequently, the amount of 

renewable energy needed to meet the requirement is sensitive to total electricity demand 

and, similarly, to the success of energy efficiency programs. The level of energy 

intensity, GDP, population growth, and energy efficiency all affect total electricity 

demand. 

2.11.2.1 Residential Consumption 

The U.S. Census Bureau projects a 16% increase in Washington’s population between 

2010 and 2025. This would put the state’s population at nearly 8.0 million, making it the 

most populous state in the northwestern United States. Washington’s residential 

electricity use per person is the highest in the region. On average, Washington residents 

used 5.18 MWh per person in 2010 (see Figure 2-50), more than double the per-capita 

consumption of California. However, historical trends indicate that this will decrease 7% 

by 2025, with consumption reaching 4.86 MWh per person by 2025 (see Figure 2-52). 

2.11.2.2 Nonresidential Consumption 

Washington’s energy intensity (the nonresidential energy use per dollar of GDP) is on the 

lower end of the spectrum in the region. In 2010, the state used 0.16 kWh per dollar of 

GDP (see Figure 2-51). As with other states, Washington’s electricity intensity in the 

nonresidential sector has declined significantly in recent decades (see Figure 2-52), 

indicating increasing electricity efficiency in the output of goods and services. Sectoral 

shifts in the Washington economy—large output increases in the services sector, with 

manufacturing and trade accounting for smaller percentages of output—correlate with a 

significant drop in electricity per dollar of output between 1997 and 2001. The state is 

expected to cut nonresidential energy intensity even more between 2010 and 2025. 

155 For more information, see DSIRE at http://www.dsireusa.org/. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 82 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-49. Washington’s residential electricity use per capita (2010)156 

Figure 2-50. Washington’s nonresidential electricity use per dollar of GDP (2010)157 

156 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 157 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html; U.S. Bureau of Economic Analysis, Regional
 

Economic Accounts, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 83 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

Figure 2-51. Washington’s historical and projected electricity efficiencies158 

2.11.2.3 Energy Efficiency and Customer-Sited Renewables 

Greater energy efficiency and demand-side management curbs electricity demand 

growth, which also reduces demand for renewable energy under the state RES. 

Washington’s IOU budgets for energy efficiency in 2011 totaled $275 million, amounting 

to 4.36% of statewide utility revenues. The state has made some progress: the ACEEE 

estimates that efficiency programs in 2010 achieved a net incremental savings of 763 

GWh.159 

Incentive programs that encourage customer-sited renewable energy projects also have 

the effect of decreasing the total electrical load, and these projects serve to reduce the 

amount of renewable energy the utility must supply to comply with the RES. Washington 

offers numerous loans, rebates, grants, tax incentives, and performance-based incentives 

that stimulate customer-sited renewable energy projects. 

2.11.2.4 Plausible Range of Demand for Renewables 

Historical trends in population, GDP, and per-unit electricity consumption suggest that 

retail sales could decrease over the next decade to as low as 64.3 TWh by 2025. Energy 

efficiency gains and sectoral changes in the Washington economy accelerate the future 

reductions predicted for nonresidential energy efficiency, which in turn reduces the 

nonresidential portion of the forecast. 

158 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html; U.S. Census Bureau, State Intercensal Estimates,
 

October 2012; U.S. Bureau of Economic Analysis, Regional Economic Accounts, June 2012.

159 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE),
 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 84 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

The SPSC’s extended demand forecast suggests 2025 retail sales of 93.5 TWh, taking 

into account energy efficiency improvements consistent with state requirements. These 

two forecasts establish a plausible range for future retail electricity sales. Applying 

current RES requirements to these two retail sales forecasts suggests that the demand for 

renewable energy related to the RES will most likely be between 8.4 TWh and 12.2 TWh 

in 2025. 

The voluntary market also increases demand for renewable energy because voluntary 

sales do not count toward the RES requirement. In 2009, electric customers in 

Washington voluntarily purchased nearly 0.6 TWh of renewable energy.160 Estimates 

indicate a 45% growth in voluntary demand across the West between 2009 and 2015, 

which means that Washington’s voluntary market could exceed 0.8 TWh by 2015.161 

There are currently 6.7 TWh of renewable energy serving in-state loads. This suggests 

Washington will need to procure another 1.7 TWh to 5.5 TWh of renewable resources by 

2025 to achieve goals stipulated under current law. 

2.11.3 Supply 

More than 70% of Washington’s electricity is produced from hydroelectric plants 

(hydropower plants constructed prior to 2000 are categorized as conventional 

generation), with nuclear, natural gas, and coal plants providing over 21% of the 

electricity. The remaining 7.5% of electricity is supplied by renewable energy 

technologies, with 6% generated from wind power. Two large baseload plants located in 

Washington are Centralia (a 1,376-MW coal plant that exports all of its power produced 

to Canada), and Columbia (a 1,146-MW nuclear plant whose power remains in-state). 

The power exported from Centralia alone amounts to 4.5% of the total power generated 

in the state of Washington. 

2.11.3.1 Existing Renewable Energy Supply 

Together, renewable energy technologies produced about 7.5% of Washington’s 

electricity. In-state facilities are currently capable of producing over 8 TWh per year. The 

majority of renewable energy generation produced in Washington is from wind (7 TWh 

per year) and biomass (0.8 TWh per year). About 38% of the electricity generated from 

renewable energy sources in Washington is exported out of the state (41% of wind power 

produced and 33% of biomass power produced is exported). 

160 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 161 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 85 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

*33% of Washington’s biomass generation goes to other states as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. 

Figure 2-52. Washington’s current electricity supply162 

2.11.3.2 Planned Renewable Energy Supply 

One of the largest planned renewable energy facilities in Washington is the 105-MW 

Palouse Wind Farm, currently being constructed by First Wind. Avista Utilities has 

signed a power purchase agreement. Several biomass projects totaling approximately 

21 MW in capacity are in the pipeline as well. 

2.11.3.3 Undeveloped Renewable Energy Supply 

Wind resources already developed in Washington’s renewable energy zones are more 

than the amount of prime-quality wind estimated to be in the zones. As with Oregon, this 

suggests possible supply constraints affecting future wind development in the state. 

Another 4 TWh of lower-quality wind, biomass, and hydro resources are yet undeveloped 

and would be competitive to meet in-state demand. Most of these additional resources— 

2.5 TWh—are hydropower. 

2.11.4 Conclusion 

In 2025, Washington’s demand for renewable energy related to the RPS will most likely 

be between 8.4 TWh and 12.2 TWh. With 6.7 TWh of renewable energy currently 

serving in-state loads, this suggests 1.7 TWh to 5.5 TWh of additional resources 

Washington will need by 2025 to achieve goals stipulated under current state law. 

Washington appears to have little left in the way of undeveloped prime-quality resources, 

although 4 TWh of non-prime resources have yet to be developed. 

162 SNL Energy, extracted Dec. 10, 2012. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 86 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

2.12Wyoming 

2.12.1 State Highlights 

• Wyoming has no RPS; its demand for renewable energy in 2025 will depend on 

capacity retirements, purchased power costs, and utility resource planning objectives. 

• Renewable electricity projects either existing or under development as of 2012 can 

supply 4.7 TWh annually. About 1.3 TWh serves native load in Wyoming. 

• Prime, export-quality wind resources that have not yet been developed could provide 

at least 42.7 TWh annually, almost twice Wyoming’s projected total retail sales in 

2025. The state has an additional 1.7 TWh of non-prime wind and biomass resources. 

Wyoming’s untapped, prime wind resources amount to more than twice the output of the 

Jim Bridger generating station, the West’s second-largest coal plant located in the 

southern part of the state. Because the state has no RPS and relatively low native load, 

demand in other states will be the most likely driver for future wind development. 

Wyoming already exports most of the low-cost wind energy it generates. There are still 

significant amounts of undeveloped, high-quality wind resource within Wyoming’s 

renewable energy zones. Besides wind, Wyoming exports a small amount of hydro power 

to other states. It does not import renewable power from any other state. 

Note: Prime renewable resources include wind (40% capacity factor or better), solar (7.5 DNI or better), 

and discovered geothermal potential. All other renewable resources are non-prime. 

Figure 2-53. Wyoming’s renewable energy supply and demand163 

163 Western Renewable Energy Zones Generation & Transmission Model (GTM) 

(http://www.westgov.org/); Form EIA-923, Annual Electric Utility Data. U.S. Energy Information 

Administration, 2013. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 87 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

2.12.2 Demand 

Wyoming does not have an RPS, and thus the demand for renewable energy is driven by 

other factors, including exporting power to meet neighboring states’ RPSs and individual 

utility needs. Wyoming currently exports 3.5 TWh of renewable energy annually to other 

states, nearly all of which is wind power. About 74% of both wind and hydro power 

produced within the state is exported. About 1.2 TWh generated from renewable energy 

technologies in Wyoming remains in-state and is used to meet in-state demand. Future 

demand of renewable energy is a function of continued demand growth and the 

retirement of existing generation facilities. 

2.12.2.1 Residential Consumption 

The U.S. Census Bureau projects a 7% decrease in Wyoming’s population between 2010 

and 2025. This would put the state’s population at about 529,000 in 2025, the leastpopulated state in the region. Wyoming’s residential electricity use per person is one of 

the highest in the region. On average, Wyoming residents used 4.83 MWh per person in 

2010 (see Figure 3-54), more than double the per-capita consumption of California. 

Historical trends indicate that this will increase 19% by 2025, with consumption reaching 

5.93 MWh per person by 2025 (see Figure 2-57). 

2.12.2.2 Nonresidential Consumption 

Wyoming’s energy intensity (the nonresidential energy use per dollar of GDP) is by far 

the highest in the region, most likely due to the fact that the mining and utilities sector 

makes up a much larger share of the state economy than anywhere else in the West. In 

2010, the state used 0.40 kWh per dollar of GDP (see Figure 2-56). As with other states, 

Wyoming’s electricity intensity in the nonresidential sector has declined significantly in 

recent decades (see Figure 2-57), indicating increasing electricity efficiency in the output 

of goods and services. The state is expected to cut nonresidential energy intensity even 

more between 2010 and 2025; trends projected from historical data suggest an energy 

intensity of 0.14 kWh per dollar of GDP in 2025. 

2.12.2.3 Energy Efficiency and Customer-Sited Renewables 

Greater energy efficiency and demand-side management curbs electricity demand 

growth. Wyoming’s IOU budgets for energy efficiency in 2011 totaled $5.4 million, 

amounting to 0.47% of statewide utility revenues. The state has made some progress: the 

ACEEE estimates that efficiency programs in 2010 achieved a net incremental savings of 

24 GWh, about 0.14% of statewide retail electric sales.164 

164 “State Spending and Savings Tables.” American Council for an Energy-Efficient Economy (ACEEE), 

2012. Accessed Oct. 16, 2012: http://aceee.org/files/pdf/fact-sheet/2012-spending-and-savings-tables.pdf. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 88 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Figure 2-54. Wyoming’s residential electricity use per capita (2010)165 

Figure 2-55. Wyoming’s nonresidential electricity use per dollar of GDP (2010)166 

165 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 166 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “Regional Economic Accounts.” U.S. Bureau of
 

Economic Analysis, June 2012.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 89 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

Figure 2-56. Wyoming’s historical and projected electricity efficiencies167 

Incentive programs that encourage customer-sited renewable energy projects also have 

the effect of decreasing the total electrical load. Wyoming offers numerous loans, rebates, 

and grants that stimulate customer-sited renewable energy projects. 

2.12.2.4 Plausible Range of Demand for Renewables 

In 2010, Wyoming’s total electricity consumption accounted for 2.6% of all electricity 

consumption throughout the western United States. The foregoing assumptions and 

calculations for population, GDP, and per-unit electricity consumption suggest that the 

state’s electricity consumption will decrease 1% from 2010 to 2025, to reach a total of 

17 TWh by 2025. Combining this calculation with the SPSC’s extended demand forecast 

of 24.7 TWh, which accounts for anticipated energy efficiency measures, establishes a 

plausible range for future electricity demand. 

There are currently 1.3 TWh of renewable energy serving in-state loads. In 2009, electric 

customers in Wyoming voluntarily purchased nearly 43 GWh of renewable energy.168 

Trends indicate a 45% growth in voluntary demand across the West between 2009 and 

2015, which means that Wyoming’s voluntary market could exceed 62 GWh by 2015.169 

167 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.; “State Intercensal Estimates.” U.S. Census Bureau,
 

October 2012.
 168 Form EIA-861, Annual Electric Power Industry Report. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia861/index.html.
 169 Bird, L.; Hurlbut, D.; Donohoo, P.; Cory, K. and Kreycik, C. “An Examination of the Regional Supply
 

and Demand Balance for Renewable Electricity in the United States through 2015,” NREL/TP-6A2-45041.
 

National Renewable Energy Laboratory: Golden, CO, 2009.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 90 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

*74% of Wyoming’s small hydro generation goes to other states as exports. 

Generation shown is the average of 2009, 2010, and 2011 net generation. Hydropower and biomass built 

before 2000 is considered conventional generation. Exports from the Jim Bridger coal plant account for 

23.6% of Wyoming’s total generation. 

Figure 2-57. Wyoming’s current electricity supply170 

2.12.3 Supply 

The overwhelming majority (87%) of Wyoming’s electricity is currently produced from 

coal-fired generating facilities. Conventional hydropower (constructed prior to 2000) 

supplies approximately 2% of the electricity. The remaining 10% of the electricity 

produced in Wyoming is generated from wind power. EIA data show no utility-scale 

solar or biomass facilities currently exist in Wyoming, so almost the entirety of 

Wyoming’s renewable electricity is generated from wind. One very large baseload plant 

located in Wyoming is of note: the 2,117-MW coal- and oil-fired Jim Bridger power 

plant exports more than 11 TWh of power annually out of Wyoming, amounting to over 

23% of the total electricity generated in Wyoming. 

2.12.3.1 Existing Renewable Energy Supply 

Together, renewable energy technologies produced about 9.6% of Wyoming’s electricity. 

In-state facilities are currently capable of producing over 4.7 TWh per year. Nearly all of 

the renewable energy generated in Wyoming is from wind, which accounts for virtually 

all renewable energy generated in the state. About 74% of the electricity generated from 

renewable energy sources in Wyoming is exported out of the state. 

2.12.3.2 Planned Renewable Energy Supply 

No additional renewable energy facilities were under construction in Wyoming as of 

early 2013, although a number of wind projects—including three gigawatt-scale 

projects—were in some phase of planning.171 

2.12.3.3 Undeveloped Renewable Energy Supply 

Wyoming has an estimated 42.7 TWh of unused prime resources in its renewable energy 

zones (all from wind), the electricity from which would be a premium candidate for 

170 SNL Energy, extracted Dec. 10, 2012. 171 Data obtained from SNL Energy. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 91 

at www.nrel.gov/publications. 
 

 

export in a regional market. An additional 1.8 TWh of lower-quality wind and biomass 

resource would be competitive to meet any in-state demand. 

2.12.4 Conclusion 

Wyoming has no RPS, and therefore does not need to fulfill RPS-related obligations. 

Demand is primarily driven by the RPSs in neighboring states. An analysis of the unused 

prime resources reveals that nearly 43 TWh of prime resources (from wind) could be 

developed for exports to other states. In addition, another 1.8 TWh of non-prime wind 

and biomass resources could potentially be developed as well. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 92 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

2.13Regional Summary 

2.13.1 Highlights 

•	 The western states all together will need between 127 TWh and 149 TWh of 

renewable energy in 2025 to meet targets stipulated by current state laws. California 

accounts for about 60% of this demand. 

• Renewable energy projects either existing or under construction in the western 

United States as of 2012 can supply an estimated 86 TWh. 

•	 Colorado, Montana, Nevada, and New Mexico each has within its borders more 

untapped prime-quality renewable resources than it needs to meet the balance of its 

forecasted requirement for 2025. 

• Wyoming and Idaho have no requirement, but they have large supplies of primequality renewable resources. 

• Arizona has sufficient prime and near-prime solar resources to meet the balance of 

its forecasted requirement for 2025. It has a limited amount of non-solar resources, 

none of which is prime quality. 

• California, Oregon, Utah, and Washington have already developed most (if not all) of 

their prime-quality in-state resources. Their non-prime resources could be of 

sufficient quantity to meet the balance of their forecasted 2025 requirements, but the 

cost is likely to be higher than the cost of resources developed prior to 2012. 

All western states with renewable energy targets are making progress toward their goals. 

Some, however, show signs of reaching the end of their stocks of prime-quality 

developable resource areas. Potential technological breakthroughs, such as enhanced 

geothermal systems or low-speed wind turbines, could improve the viability of resource 

areas that with current technologies are marginally productive. By 2025, when all current 

RPS requirements will have matured to their ultimate target levels, the largest untapped 

surpluses of prime-quality renewables will be in Wyoming, Montana, Colorado, New 

Mexico, Idaho, and Nevada. 

If RPS compliance using in-state resources is a strong preference for renewable resource 

planning, then utilities and regulators in California, Oregon, and Washington (and 

possibly Arizona and Utah) may need to weigh the acceptability of meeting the last 

increments of their targets with a small amount of high-cost renewables that require no 

major investment in new transmission. By then, most of their low-cost local resources 

will likely be in use already. 

On the other hand, if states anticipate renewable power growth beyond 2025, then early 

strategies for post-2025 procurement might at the same time provide new low-cost 

options for meeting the final segments of RPS requirements. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 93 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3 Post-2025 Value Propositions 

The state-by-state examination in the previous section suggests that by 2025 the West’s 

largest surpluses of prime-quality utility-scale renewable resource potential will be in 

Colorado, Montana, New Mexico, and Wyoming (wind power); Idaho (geothermal 

power); and Nevada (geothermal and solar power). 

To the extent that future scarcity of untapped prime-quality resources could signal 

potential demand, the most likely importing states are California, Oregon, Utah, 

and Washington. 

We categorize Arizona as a potential exporter of solar power (which the state will most 

likely have in surplus in 2025) and a potential importer of prime wind and 

geothermal power. 

The estimated 2025 state balances for prime-quality renewables suggest a number of 

cross-region source-to-sink resource paths for closer economic examination: 

•	 Montana and Wyoming wind power delivered to Arizona, California, Oregon, 

Utah, and Washington 

•	 Colorado and New Mexico wind power delivered to Arizona, California,
 

and Utah
 

•	 Idaho and Nevada geothermal power delivered to Arizona, California, Oregon, 

Utah, and Washington 

•	 Arizona and Nevada solar power delivered to California, Oregon, Utah,
 

and Washington.
 

Power flows from Colorado and New Mexico to the Northwest are not examined due to 

extraordinary transmission limitations. Very little power flows in that direction today, 

and very little of the power flowing westward via the Southwest goes any farther 

than California. 

This section describes the methodology used to test these paths for their relative 

economic viability. The results suggest which resource paths have the greatest potential 

for value in 2025 if there is additional demand for utility-scale renewable resources after 

current RPS goals are achieved. 

Instead of predicting future costs, the analysis described in this section applies a more 

flexible “what-if” test based on conditions observed today and cautiously applied in the 

future. The cost of new transmission and the cost of integrating variable renewable 

resources are the two future cost components with the greatest uncertainty. The test used 

here hypothetically doubles the rates reflected in current tariffs, adds them to the 

levelized cost of generating power in a renewable energy zone, and compares the total 

cost with the projected cost of building and operating a new CCGT in the destination 

state. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 94 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

3.1 Methodology 

The value of imported renewable power depends on three factors: the cost of generating 

power (the busbar cost), the transmission charges involved in getting the power across the 

network to the load it is intended to serve, and the cost of power supply alternatives in the 

destination market. The first two factors make up the delivered cost of renewable power 

imported from outside the local network. 

The economic strength of a potential import can be measured by how its delivered cost 

compares to a common benchmark, which for this analysis is the all-in cost of a new 

CCGT. The difference between the delivered cost and the benchmark indicates the 

margin for absorbing future transmission and integration costs beyond what is reflected in 

current tariff rates. If the margin is large enough, it can also reflect potential cost savings 

to retail customers. The test imposes a hurdle by doubling current transmission costs to 

act as a standard proxy for future delivery costs. Figure 3-1 illustrates the test. 

To benchmark delivered cost, this analysis relies on the market price referent (MPR) 

developed by the California PUC to evaluate new power purchase agreements for 

renewable energy projects. The MPR is based on the estimated cost of building and 

operating a new CCGT in California and is adjusted based on the duration of the power 

purchase contract and when initial delivery would occur. It assumes that the price of 

natural gas for electric generation in California will be $8.43/mmBtu. The MPR for 

energy to be delivered in 2023 under a 20-year contract is $132 per MWh.

172 We apply 

this value to 2025. (California’s new RPS legislation calls for replacing the MPR with 

utility-specific caps on total procurement expenditures for resources used to comply with 

the RPS. The California PUC is currently developing new rules to meet this directive. 

The metrics and methodology used in calculating the MPR are suitable to the purposes of 

this analysis, however.) 

Benchmark for 

testing delivered High potential cost in destination for value— market index score <1 

Moderate or 

low potential 

for value—
 

index score >1
 

Figure 3-1. Illustration of cost benchmarking methodology 

172 Resolution E-4442. Public Utilities Commission of the State of California (Dec. 1, 2011). MPR values 

for initial delivery past 2023 were not calculated. 

Busbar cost transmission 

Busbar cost transmission 

Current 

cost x 2 

Current 

cost x 2 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 95 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The MPR is a somewhat conservative benchmark, as indicated by what utilities in 

California have actually paid for renewable power to date. The MPR for current delivery 

of renewable energy—delivered beginning in 2012 delivered under a 20-year contract— 

was $90/MWh, compared to an average price of $119/MWh for all contracts approved by 

the California PUC from 2003 through 2011.173 

The all-in cost of a new CCGT consists of fixed costs (primarily the annualized cost of 

construction) and variable costs (primarily the cost of natural gas).174 Both differ across 

the West, so we apply adjustments to the MPR for states other than California that could 

be destination markets for renewable power. 

•	 The fixed-cost component—about 17% of the all-in cost—is adjusted by the 

difference in total construction costs between the California plants used to 

calculate the MPR and comparable CCGT built in the destination state. 

•	 The variable-cost component—about 83% of the all-in cost—is adjusted by 

historical differences in natural gas prices at major trading hubs across the West. 

Table 3-1 and Table 3-2 show the component adjustments made for each destination 

state. Table 3-3 shows the baseline cost benchmarks used for each destination state. 

Finally, we apply resource-specific adjustments to the baseline benchmarks to account for 

how well wind and solar power match hourly load in the destination markets. The 

adjustments are the product of two matrices of weights applied hourly. One matrix 

reflects hourly load for 2012 in BA areas with the largest demand, with high-load hours 

weighted more than low-load hours. The second matrix is based on wind or solar 

production profiles during a typical year, specific to the renewable energy zone being 

examined. Hours with high capacity factors are weighted more than hours with low 

capacity factors. We then multiply the two weights for each hour. The average of the 

hourly results is the time-of-delivery adjustment applied to the state benchmark for the 

wind or solar resource being tested. 

These time-of-delivery adjustments generally result in more generous benchmarks for 

solar power delivered to California and the Southwest because it produces most of its 

power when demand is high. Benchmark adjustments for wind are generally—but not 

always—more stringent because wind production is often higher during off-peak hours. 

Wind power delivered to the Northwest was an exception, however; load profiles there do 

not peak as strongly in the summer, so there is a closer fit with the production patterns of 

wind from Wyoming and Montana. 

Geothermal is a dispatchable baseload resource and requires no time-of-delivery 

adjustment. 

173 Weighted average time-of-delivery adjusted cost of all contracts approved. California PUC,
 

“Renewables Portfolio Standard Quarterly Report,” 4th quarter 2011.
 174 The California PUC relied on cost data from three combined-cycle plants in the state to estimate and
 

project all-in costs. The assumptions are contained in a spreadsheet model available on the California PUC 

website. California PUC, 2011 MPR model, http://www.cpuc.ca.gov/PUC/energy/Renewables/mpr
 

(accessed March 6, 2013).
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 96 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

Table 3-1. Adjustments Applied to the MPR Fixed-Cost Component175 

Plant (State) 

Total Construction Cost 

(2013 Dollars per kW of 

Operating Capacity) 

Difference from 

California Average 

Colusa (CA) $1,062 

(adjustment to fixed 

cost component) 

Palomar (CA) $1,032 

Weighted average $1,047 

Redhawk (AZ) $570 54% 

Silverhawk (NV) $894 67% 

Port Westward (OR) $716 68% 

Currant Creek (UT) $646 63% Lake Side Power (UT) $670 

Chehalis (WA) $661 63% 

Table 3-2. Adjustments Applied to the MPR Variable-Cost Component176 

Hub (State) 

Average Daily 

Price, 2012 

($/mmBtu) 

Difference from 

California Average 

PG&E Gate (CA) $3.118 

(adjustment to 

variable cost 

component) 

PG&E South (CA) $2.916 

SoCal Citygate (CA) $3.039 

Average $3.024 

Sumas (OR, WA) $2.687 89% 

Opal (UT) $2.686 89% 

Socal Border (AZ, NV) $2.934 97% 

175 Data was obtained from Federal Energy Regulatory Commission Form 1 filed by utility plant owners for
 

year following plant online date. Cost data for Chehalis is total purchase cost.

176 Data obtained from SNL Energy.
 

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at www.nrel.gov/publications. 
 

 

 

 

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Table 3-3. State Cost Benchmarks 

Destination 

market 

For 

geothermal 

For 

Wyoming 

wind 

For 

Montana 

wind 

For 

New 

Mexico 

wind 

For 

Colorado 

wind 

For 

Nevada 

solar 

For 

Arizona 

solar 

(no 

adjustment) (with time of day adjustment) 

Arizona $118 $113 $119 $111 $114 

California $132 $129 $131 $126 $132 $160 $165 

Oregon $113 $120 $120 

Utah $112 $114 $113 $113 $113 

Washington $112 $120 $120 

3.1.1 Estimating Busbar Costs 

The busbar costs used here are the same used in updates to the WREZ modeling tools 

developed by Black & Veatch, current as of 2013.177 These incorporate the most recent 

overnight costs for solar, geothermal, and wind technologies. These costs have been 

falling over recent years, and further reductions are likely between now and 2025. The 

pace of future reductions, however, will depend on how quickly improvements migrate 

from research and development to market deployment. Here we make the following 

assumptions about cost changes from 2012 to 2025.178 

•	 Wind power: All-in costs will decrease 19% on a constant-dollar basis and will 

increase 9% in nominal dollars 

•	 Solar power: All-in costs will decrease 35% on a constant-dollar basis and will 

decrease 5% in nominal dollars 

•	 Geothermal power: All-in costs will decrease 9% on a constant-dollar basis and 

will increase 19% in nominal dollars 

•	 CCGT (benchmark value): All-in costs will remain unchanged on a constantdollar basis and will increase 29% in nominal dollars. 

Throughout, we use inflation-adjusted values to calculate adjustments such as those 

shown in Table 4-1. Comparisons between technologies are calculated as nominal values 

for 2025, assuming an annual inflation rate of 2%. 

177 For more information, see the Western Interstate Energy Board at http://www.westgov.org/wieb/. 178 Wind power cost estimates are based on: Lantz, E.; Wiser, R.; Hand, M. IEA Wind Task 26: The Past 

and Future Cost of Wind Energy. NREL/TP-6A20-53510. Golden, CO: National Renewable Energy 

Laboratory, May 2012. Cost estimates for solar and geothermal power are based on: Augustine, C.; Bain, 

R.; Chapman, J.; Denholm, P.; Drury, E.; Hall, D.G.; Lantz, E.; Margolis, R.; Thresher, R.; Sandor, D.; 

Bishop, N.A.; Brown, S.R.; Cada, G.F.; Felker, F.; Fernandez, S.J.; Goodrich, A.C.; Hagerman, G.; Heath, 

G.; O’Neil, S.; Paquette, J.; Tegen, S.; Young, K. Renewable Electricity Futures Study Volume 2: 

Renewable Electricity Generation and Storage Technologies. NREL/TP-6A20-52409-2. Golden, CO: 

National Renewable Energy Laboratory, 2012. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 98 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

The capacity factor that a given technology can achieve at a given site affects a project’s 

busbar cost. If the same investment generates more electricity, the cost is spread over 

more megawatt-hours and the cost per megawatt-hour is lower. The WREZ Phase 1 

analysis identified renewable energy zones where high capacity factors were most likely 

over a large area. 

The capacity factors for wind power are estimates for turbines with a hub height of 

80 meters or 100 meters. These incorporate recent modeling results from 

AWS TruePower of average annual wind speed potential across the continental United 

States. Capacity factors for solar power are based on utility-scale PV installations that use 

single-axis tracking. Large single-axis PV generally has annualized costs that are less 

than other solar configurations. 

Estimates for geothermal power account for advancements in engineered geothermal 

systems (EGS). Pilot projects suggest that including an EGS component in new 

infrastructure at sites with known geothermal potential could increase productivity by 

25% and could reduce total costs (on a per-megawatt-hour basis) by 2%.179 In this study, 

these adjustments to quantity and cost are applied to known geothermal potential that had 

not yet been developed as of 2013. 

Excluded from the analysis is a large amount of geothermal potential currently 

categorized as “undiscovered.” Its existence is inferred from statistical models of the 

spatial correlation of geologic factors that are indicative of geothermal systems, but its 

specific location is unknown. If more undiscovered resources can be located, the amount 

of developable geothermal potential incorporated into long-term regional planning could 

increase. Predicting the quantity is infeasible at this point because of insufficient data and 

the lack of a sound forecasting methodology. For the purposes of this study, we assume 

that the unknown increase in discovered geothermal resources will mostly offset the 

unknown decrease in future geothermal potential that may be due to the infeasibility of 

EGS at some sites. 

Significant technological breakthroughs could have implications for the assumptions 

about resource availability and busbar cost. For wind power, technological breakthroughs 

in turbines designed for moderate wind speeds could improve the productivity of sites 

that are less productive using current technologies. This could reduce the cost differential 

between remote prime-quality wind resources and local wind resources of moderate 

quality. Much of this improvement in moderate-wind technology has already taken place 

and is incorporated into the costs used in this study, but further improvements 

are possible. 

For geothermal power, two types of breakthroughs could be particularly important: 

improvements in locating new sites that offer a high probability of success and 

advancements in engineered geothermal systems. A large amount of geothermal potential 

is currently categorized as “undiscovered,” meaning that its existence is inferred from 

179 “Nevada Deploys First U.S. Commercial, Grid-Connected Enhanced Geothermal System,” Washington, 

D.C.: U.S. Department of Energy, April 12, 2013. 

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at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

statistical models of the spatial correlation of geologic factors that are indicative of 

geothermal systems, but its specific location is unknown. If more undiscovered resources 

can be located, the amount of developable geothermal potential incorporated into longterm regional planning could increase. 

3.1.2 Estimating Transmission Costs 

Current tariff rates for firm point-to-point service form the basis for estimating 

transmission costs. The resource paths examined here can extend over several 

transmission service territories, and we pancake the indicative rates along each path. That 

is, the assumed transmission cost is the sum of the tariff rates charged by the indicative 

transmission providers along the path. Estimates for each territory include charges for 

long-term firm point-to-point service; scheduling, system control, and dispatch service; 

and reactive supply and voltage control. Rates as of 2013 are escalated by 2% per year 

out to 2025. 

Table 3-4 shows the aggregated tariff charges and their per-megawatt-hour equivalents at 

various capacity factors. Generally, the highest tariff rates (such as those for Tri-State and 

NorthWestern) correspond with mountainous and heavily forested areas where 

transmission construction is extraordinarily difficult. 

The matrix in Table 3-5 identifies the transmission tariffs that are pancaked for each 

source-to-sink resource path. Two additional paths were modeled in addition to those 

shown in Table 3-5: geothermal power from California’s Imperial Valley to Arizona 

(through the Imperial Irrigation District and APS transmission territories); and solar 

power from Arizona to California (through the APS territory into the California 

Independent System Operator. 

Transmission tariffs in the destination markets are not pancaked. This is because the cost 

benchmarks, which are based on the busbar cost of a new combined-cycle gas plant built 

in the destination market, do not include local network transmission charges. By 

eliminating the destination market from the transmission rate pancaking for remote 

renewables, the estimated delivered cost is more readily comparable to the cost of a 

combined-cycle plant that excludes local network charges. (An exception to this rule is 

for large transmission areas that cross state lines: If the network serving the destination 

market extends into a neighboring state, and the transmission path includes the extended 

area, the network is included in the rate pancaking.) 

This report is available at no cost from the 

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Table 3-4. Current Tariff Rates for Long-Term Firm Point-to-Point Transmission Service180 

Utility and tariff ratea 

($/kW per year) 

Loss 

factor 

Calculated transmission cost per 

MWh, 

by capacity factor of resource 

30% 40% 80% 

Arizona Public Serviceb $37.38 2.5% $14.70 $11.02 $5.51 

Bonneville Power Admin. $18.01 1.9% $6.99 $5.24 $2.62 

Idaho Power $21.32 4.0% $8.45 $6.34 $3.17 

Imperial Irrigation District $20.28 3.0% $9.06 $6.79 $3.40 

Nevada Power $16.80 1.3% $7.73 $5.80 $2.90 

NorthWestern $39.92 4.0% $15.82 $11.87 $5.93 

PacifiCorp $26.37 5.0% $10.56 $7.92 $3.96 

Portland Generalc $6.89 1.6% $2.66 $2.00 $1.00 

Pub. Service of Colorado $28.91 2.6% $11.98 $8.99 $4.49 

Pub. Service of New Mexico $31.80 3.2% $9.87 $7.40 $3.70 

Puget Sound $18.54 2.7% $7.25 $5.44 $2.72 

Sierra Pacific $34.08 2.3% $14.90 $11.18 $5.59 

Tri-State G&T $47.85 4.9% $19.15 $14.36 $7.18 

Western Area Power Admin. $15.36 1.6% $5.94 $4.45 $2.23 a Combined charges for long-term firm point-to-point service; scheduling, system control, and dispatch 

service; and reactive supply and voltage control. Some transmission utilities may have additional charges. 

Rates are those reflected in utility tariffs as of January 2013. Rates shown here do not include the 2% annual 

escalation that is applied in the indexing methodology. 

b Weighted average of summer and non-summer transmission charges. 

c Tariff rates applicable to PGE’s Oregon network; excludes charges applicable only to PGE’s line from 

Colstrip to Oregon. 

In most cases, customers who reserve transmission service are responsible for covering 

line losses. We represent this mathematically by derating the indicative capacity factors 

using the system loss factor reported in the transmission utility’s tariff. This raises the 

effective cost of transmission per megawatt-hour delivered. 

Besides pancaking transmission rates and assigning line losses to the generator, we 

impose one other conservative assumption. That is, the amount of transmission service 

(in megawatts) reserved for a renewable energy project is equal to the project’s full 

operating capacity (also in megawatts) and is reserved at that constant level for the entire 

year. This assumes that a generation owner does not use forecasting to either reduce or 

resell transmission reservations when the full amount is not likely to be needed. 

180 Data obtained from Open Access Transmission Tariffs for listed transmission utilities, available for 

download at http://www.oatioasis.com/. 

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National Renewable Energy Laboratory (NREL) 101 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 3-5. Tariffs Used for Indicative Source-to-Sink Transmission Charges 

To: 

CA OR WA AZ UT 

ID 

Idaho Power 

Sierra Pacific 

Idaho Power 

BPA 

Idaho Power 

BPA 

Idaho Power 

Sierra Pacific 

Nevada Power 

Idaho Power 

PacifiCorp 

MT 

NorthWestern 

PacifiCorp 

Nevada Power 

Sierra Pacifica 

NorthWestern 

Idaho Power 

BPA 

NorthWestern 

Idaho Power 

BPA 

NorthWestern 

PacifiCorp 

Western 

NorthWestern 

PacifiCorp 

WY 

PacifiCorp 

Nevada Power 

Sierra Pacifica 

PacifiCorp 

Idaho Power 

BPA 

PacifiCorp 

Idaho Power 

BPA 

PacifiCorp 

Western 

PacifiCorp 

NV 

Geothermal: 

Sierra Pacific 

Solar: Nevada 

Power 

Sierra Pacific 

BPA 

Nevada Power 

(for solar) 

Sierra Pacific 

BPA 

Nevada Power 

(for solar) 

Nevada Power 

Sierra Pacific (for 

geotherrmal) 

Geothermal: 

Sierra Pacific 

Solar: Nevada 

Power 

NM 

APS 

PNM 

PNM PNM 

Western 

Tri-State 

CO 

Xcel/PSCo 

Tri-State 

PNM 

APS 

Xcel/PSCo 

Tri-State 

PNM 

Xcel/PSCo 

Tri-State 

a Scoring for paths from Wyoming to California average two sets of pancaked rates: one that 

includes Sierra Pacific, and one that does not. 

Table 3-6. “Tariff Times Two” Values Used in Scoring Resource Paths ($/MWh) 

To: 

From: 

CA OR WA AZ UT 

ID Geothermal: $22 Geothermal: $15 Geothermal: $15 Geothermal: $30 Geothermal: $18 

MT Wind: $79 Wind: $59 Wind: $59 Wind: $61 Wind: $50 

WY Wind: $49 Wind: $49 Wind: $49 Wind: $31 Wind: $20 

NV Geothermal: $14 

Solar: $20 

Geothermal: $21 

Solar: $75 

Geothermal: $21 

Solar: $75 

Geothermal: $22 

Solar: $20 

Geothermal: $14 

Solar: $20 

NM Wind: $47 Wind: $19 Wind: $67 

CO Wind: $106 Wind: $78 Wind: $59 

From: 

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By assuming that the amount of transmission service reserved is constant and equal to the 

project’s operating capacity, estimating the cost of transmission per megawatt-hour of 

energy delivered is a straightforward calculation: 

transmission tariff rate ቀ$ൗMWቁ transmission cost ቀ$ൗMWhቁ = generator capacity factor (%) × (1-loss factor) × 8,760 hours 

Table 3-5 shows the per megawatt-hour cost of transmission charges for each capacity 

factor assumption. Capacity factors higher than those used in these approximations would 

effectively reduce the per-megawatt-hour impact of transmission costs. 

Two points are important to emphasize. First, using existing tariff rates as a measure of 

transmission cost does not mean that the transmission service is currently available. The 

rates are not responsive to surplus or scarcity, as they are the outcome of a regulatory 

determination based on the cost of service. If a path were fully subscribed, the rate would 

remain the same even if there were no capacity to be had. 

Second, this estimation approach assumes only that current tariff rates are reasonable, 

non-arbitrary indicators of transmission costs along a given source-to-sink path. Existing 

rates resolve unpredictable and sometimes litigious uncertainties—how costs are 

allocated among customer classes, the transmission utility’s rate of return, and (most 

importantly) how these and other factors enter into the complex rate-making process that 

determines what a transmission customer actually pays for service. 

This approach does not assume that a new line along the path of an identified value 

proposition would be built by the incumbent transmission utilities, however. A new line 

enabling additional resource delivery could be built by independent merchant developers, 

existing transmission utilities, or a consortium involving both. Depending on the 

ownership, the additional line cost may be added to existing tariff rates for a transmission 

utility’s entire network or recovered directly from those who use the new line. The 

purpose of using existing rates is to establish an empirical, non-arbitrary baseline for 

approximating transmission costs in a manner that accounts for area-specific factors 

affecting actual line costs. 

One additional adjustment is made in applying the methodology to the path from 

Wyoming to California. An indicative path theoretically could go from PacifiCorp’s Utah 

territory into the Nevada Power territory directly or it could pass farther west through the 

Sierra Pacific territory, which would increase the resulting pancaked rates by more than 

80%. Here we average the two scenarios (pancaked with and without Sierra Pacific). The 

resulting indicative tariff is $66/kW per year, which doubled is $131/kW per year. 

The indicative delivery costs resulting from this methodology were then tested against 

several proposed long-distance 500-kV transmission projects in the West and their most 

recent publicly disclosed cost estimates. The projects included TransWest Express 

(Wyoming to Nevada), Zephyr (Wyoming to Nevada), Centennial West (New Mexico to 

California), SunZia (three potential configurations from New Mexico to Arizona), and 

High Plains Express (two potential configurations from Colorado to Arizona). The test 

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uniformly assumed a 12% cost of capital and a 30-year amortization period for 

transmission costs. The test assumed that the line would be fully subscribed with wind 

projects at a capacity factor of 40% and included a $5/MWh adder for integration costs. 

On average, the “two times tariff” indicative costs used in this analysis were 39% higher 

than the costs derived from the proposed transmission projects. In other words, the 

methodology appears to err on the high side, which is appropriate for the purposes of 

this study.181 

3.1.3 Uncertainties Affecting Future Transmission Costs 

The approach used in this analysis provides a quantifiable starting point for comparing 

transmission cost scenarios. The actual cost of future transmission expansion is steeped in 

uncertainty, however. Some factors—impossible to quantify in advance—tend to drive 

costs higher, while others tend to reduce costs. Factors that could push future 

transmission costs higher have to do with the capital costs of new lines, how those costs 

are allocated among control areas, and how the allocated amounts are incorporated into 

transmission rates. Estimates of even the tangible costs (such as lines, substations, and 

right-of-way) vary widely, however.182 

The cost that ultimately matters is the rate charged by the transmission provider, not the 

cost of a new line in isolation from all other factors. The cost may be assigned solely to 

customers using the new line, but often it is combined with cost of the transmission 

owner’s other assets. The total—including the cost of the new line—is then recovered 

through a uniform rate schedule applicable to any transmission customer regardless of 

where on the system the generator connects. How much the transmission rate increases 

due to a new line will depend on several factors that in many cases are specific to that 

particular transmission owner. 

There are factors that would exert downward pressure on a renewable energy project’s 

transmission costs. Forecasting makes it possible to predict when less transmission 

service would be needed. Seasonally scheduled reductions in the amount of transmission 

service reserved would result in lower transmission costs per megawatt-hour delivered 

relative to the assumptions made in this analysis. Similarly, forecasting would enable the 

owner of a wind or solar project to schedule the resale of transmission capacity it has 

reserved. 

Institutional improvements to replace rate pancaking would reduce transmission costs 

from how they are estimated here. WestConnect has conducted an experiment in rate 

design in which separate pancaked rates are replaced with a single rate applicable to 

181 Information on most projects, including project websites, are at WECC’s Interactive Transmission
 

Project Portal, located at http://www.wecc.biz/Planning/TransmissionExpansion/Map/Pages/default.aspx;
 

see also: Charney, A.H. and Popp, A.V. “SunZia Southwest Transmission Project Economic Impact
 

Assessment.” SunZia, April 2011. 182 For example, see: Mills, A., Wiser, R., and Porter, K. The Cost of Transmission for Wind Energy: A
 

Review of Transmission Planning Studies. Berkeley, CA: Lawrence Berkeley National Laboratory, 2009.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 104 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

several transmission service areas.183 A unified rate formula could reduce the effect of 

rate pancaking while ensuring sufficient cost recovery for each transmission owner. 

Similarly, a line built and owned by an independent transmission provider operating 

under a separate tariff would avoid the pancaking problem over the distance covered by 

that line. A corridor from Colorado to California, for example, would incur at least three 

pancaked sets of transmission charges, while a line across that same path owned by one 

independent transmission entity would only have one set of charges. 

3.1.4 Integration Costs 

This study does not specifically quantify the cost of integrating wind power and solar 

power. There is no generally accepted approach to estimating the cost of integration, as 

the inputs and assumptions—and, consequently, the resulting estimates—vary widely 

from region to region and from utility to utility.184 They also vary over time, especially 

for utilities that are adding large amounts of wind power and gaining experience with 

variable resources on their systems. For example, in 2010, PacifiCorp estimated that the 

cost of integrating 2 GW of wind power on its system was $9.60/MWh; just 2 years later, 

the utility placed the cost of integrating 2.1 GW at $1.89/MWh.185 

PacifiCorp has indicated that the prices of natural gas and purchased power were the 

main drivers behind the revision but also noted that changes in the utility’s resource 

portfolio and in regional market design could become more influential over time. With 

respect to regional market design, a study commissioned by PacifiCorp and the California 

ISO found that a two-party energy imbalance market would provide “a low-cost, low-risk 

means of achieving operational savings for both PacifiCorp and ISO and enabling greater 

penetration of variable energy resources.”186 

Integration costs also have limited usefulness in comparing local and regional renewable 

energy options. Wind and solar power are variable regardless of how close they are to the 

load they serve. The treatment of integration costs would affect total cost estimates for 

both local and regional renewables in a similar manner. 

183 “Point-to-Point Regional Transmission Service Experiment Participation Agreement.” Council, Idaho:
 

WestConnect, Nov. 25, 2008 and “Order on Point-to-Point Regional Transmission Service
 

Experiment.” Docket No. ER09-409-000. Federal Energy Regulatory Commission, Feb. 10, 2009.
 

http://www.westconnect.com/documents_results.php?categoryid=114.
 184 Milligan, M. et al. Cost-Causation and Integration Cost Analysis for Variable Generation. NREL/TP5500-51860. Golden, CO: National Renewable Energy Laboratory, June 2011 and Porter, K., Fink, S.,
 

Buckley, M. and Rodgers, J. A Survey of Variable Generation Integration Charges. Golden, CO: National
 

Renewable Energy Laboratory, forthcoming. 185 “2012 Wind Integration Resource Study.” PacifiCorp, Nov. 15, 2012.
 

http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/Wind_I
 

ntegration/2012WIS/2013IRP_2012WindIntegration-DRAFTReport-11-15-12.pdf.
 186 Energy and Environmental Economics, Inc., “PacifiCorp-ISO Energy Imbalance Market Benefits,” 

March 13, 2013.
 

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National Renewable Energy Laboratory (NREL) 105 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

3.1.5 Ranking the Source-to-Sink Resource Paths 

This analysis categorizes the potential value of imported renewable energy according to 

the size of the margin between delivered cost (busbar cost plus transmission costs) and 

the benchmark applicable to the destination market. 

•	 High potential for value. If new lines and integration charges were equivalent to 

doubling the transmission charges indicated by current tariff rates, the delivered 

cost would still be below the applicable benchmark. 

•	 Moderate potential for value. If new lines and integration charges were equivalent 

to doubling the transmission charges indicated by current tariff rates, the delivered 

cost would be no more than 15% above the applicable benchmark. 

These tests provide a basis for constructing an index by which propositions can be 

compared quantitatively. The score of a given resource path is the resource’s busbar cost 

plus twice the pancaked transmission costs, with the sum divided by the applicable 

benchmark for delivered costs. 

resource busbar cost + 2 × ∑ current transmission charges index score = cost benchmark 

Using this metric, a score of 1.0 or less would classify as a high potential for value. 

Scores between 1.0 and 1.15 would classify as a moderate potential for value. 

3.2 The Top Value Propositions 

A number of value propositions stand out, based on the analytical method described in 

this section. They generally cluster around two destination markets: (1) California and the 

Southwest and (2) the Pacific Northwest. Most involve deliveries of wind power, but in 

some circumstances solar and geothermal power may offer targeted opportunities for 

value. 

With respect to California and the Southwest, the results augur considerable cost-based 

competition between Wyoming wind power and New Mexico wind power. Both states 

are likely to have large amounts of untapped, developable prime-quality wind potential 

after 2025. Wyoming’s surplus will probably have the advantage of somewhat higher 

capacity factors and lower busbar costs overall; New Mexico’s will have the advantage of 

being somewhat closer to the California and Arizona markets. 

Montana wind power and Wyoming wind power emerge as likely competitors for post2025 demand in the Pacific Northwest. The competitive challenge for Montana wind 

appears to be the cost of transmission through the rugged forests that dominate the 

western part of the state. 

Geothermal power from Idaho could be competitive in California as well as in the Pacific 

Northwest. Current trends suggest that much of Nevada’s known geothermal resources 

will be developed by 2025, but to date very little of Idaho’s known potential has been 

tapped. The quantity is small, however. 

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Colorado is a major demand center in the West, but these results suggest that the state is 

likely to be self-contained with respect to future renewable energy supplies. Colorado 

will have a considerable surplus of prime-quality wind that by 2025 will probably be 

cost-competitive with a new CCGT. But transmission paths out of the state to other major 

destination markets are so expensive that even the best Colorado wind might not be 

competitive elsewhere in the West. 

California, Arizona, and Nevada are all likely to have their own surpluses of primequality solar resources. None is likely to have a strong comparative advantage over the 

other two within the three-state market for utility-scale solar power. Consequently, local 

use will probably continue to be the main driver for utility-scale solar development 

within these three states. At the same time, in none of the three states is solar power 

likely to be sufficiently cost-effective to compete outside the Southwest against wind, 

geothermal, and natural gas. 

Table 3-7 shows the top 15 value propositions based on this analytical method. The 

scores indicate the relative likelihood of being reasonably competitive in the destination 

markets in 2025 without the production tax credit (PTC) and investment tax credit (ITC), 

and even if current transmission charges were to double. 

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Table 3-7. Highest-Value Source-to-Sink Resource Paths Ranked by Index Score 

High value 

potential 

Index 

scorea 

Wyoming wind to Nevada 0.79 

Wyoming wind to Utah 0.84 

New Mexico wind to Arizona 0.94 

Wyoming wind to Arizona 0.95 

Moderate 

Wyoming wind to California 0.97 

Wyoming wind to Washington 1.04 

Wyoming wind to Oregon 1.04 

New Mexico wind to California 1.06 

Nevada solar to California 1.07 

Idaho geothermal to California 1.11 

Montana wind to Nevada 1.12 

Arizona solar to California 1.13 

Montana wind to Utah 1.17 

Montana wind to Oregon 1.18 

Montana wind to Washington 1.19 

value 

potential 

Wind resource 

Solar resource 

Geothermal resource 

a An index score less than 1.0 indicates a resource with a delivered cost that is still below the 

relevant state benchmark even if current transmission costs are doubled. The formula for 

calculating the score is: 

resource busbar cost + 2 × ∑ current transmission charges index score = state delivered cost benchmark 

This report is available at no cost from the 

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3.2.2 Wyoming Wind 

The highest value potential identified in this analysis is for Wyoming wind power. 

Wyoming itself has no state RPS, and most of its existing wind power development has 

been export-driven. Three-fourths of the 1.4 GW of wind power already operating in 

Wyoming serves customers—and RPS requirements—in other states. 

The best Wyoming wind areas that are likely to remain undeveloped in 2025 have a total 

energy potential that is more than two-and-a-half times the amount of electricity 

produced annually at the Jim Bridger Generating Station, the West’s second-largest coal 

plant located in the southern part of the state. This includes only those wind resources 

with an annual capacity factor estimated at 40% or better. As Figure 3-2 illustrates, about 

37.3 TWh could be developed at a busbar cost of $69–$81/MWh, assuming no financial 

incentives. This would be low enough to keep delivered costs below the time-adjusted 

benchmarks for Nevada, Utah, Arizona, and California even if current transmission 

charges were doubled. 

PacifiCorp is already using Wyoming wind power to serve its customers in Utah. A 

major transmission upgrade planned by PacifiCorp would significantly increase the 

transfer capability from Wyoming to Utah. 

Average busbar cost of best remaining 1,000 GWh: $76/MWh (without PTC) 

Note: Wyoming does not have an RPS and therefore has no projected RPS-related demand. Chart indicates 

energy production from wind resources that are either operating or were under construction in 2013. 

Figure 3-2. Projected supply cost of Wyoming wind power ($/MWh at the busbar) 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 109 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

In California, solar power would be the in-state resource most likely to exist in sufficient 

quantity to compete with Wyoming wind for post-2025 demand. Most of the state’s 

economical and accessible non-solar renewable resources will probably be online by 

2025, along with its least-cost solar resources. Trends suggest that the busbar cost of 

California’s best untapped solar resources in 2025 will be around $155/MWh, assuming 

no ITC. Advances in future PV technology could reduce costs, while permitting issues 

affecting California’s remaining undeveloped sites could drive the cost of competing 

solar higher. 

Wyoming wind power also has a potential for value in the Northwest. Average retail rates 

in Oregon and Washington are lower than in California, so the competitiveness of 

Wyoming wind in these post-2025 markets could be more sensitive to the availability of 

subsidies and incentives. The potential could improve, however, depending on current 

transmission development. PacifiCorp is partnering with Idaho Power on a line that will 

extend from Wyoming to the Oregon-Idaho border.187 As discussed in Section 2.9, most 

of Oregon’s own easily accessible renewable resources probably will have been 

developed by 2025. Geothermal and biomass are the Oregon renewable resources most 

likely to be available for post-2025 expansion but in small quantities. 

187 The two utilities are jointly developing the 500-kV Gateway West transmission project. Rather than 

pancaking the two rates, here we use the higher of the two—PacifiCorp’s—as the indicative transmission 

rate for testing on the assumption that power would be subject to one combined tariff rate. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 110 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

3.2.4 New Mexico Wind 

New Mexico’s best surplus wind resources have a high potential for value in California. 

Even if transmission rates were to double, New Mexico wind could be developed and 

delivered close to the California benchmark. 

This analysis projects that, after meeting its ultimate RPS requirements, New Mexico will 

have a surplus of undeveloped prime wind resource sites in 2025 equivalent to about 

2.1 TWh per year, with an estimated busbar cost of around $79/MWh (assuming no 

PTC). Another 39.6 TWh could be developed at capacity factors ranging from 38% to 

40%, with busbar costs ranging from $84–$93/MWh. These wind resources amount to 

more than two-and-a-half times the historical annual output of the Four Corners coal 

plant in northwestern New Mexico, which is the West’s fourth-largest coal plant.188 

Average busbar cost of best remaining 1,000 GWh: $86/MWh (without PTC) 

Note: “In-state demand 2025” represents projected demand for all renewables—not just wind. The extent to 

which in-state demand is met by resources other than wind would make more of the state’s least-cost wind 

resources available for potential export. 

Figure 3-3. Projected supply cost of New Mexico wind power ($/MWh at the busbar) 

188 “Source Specific Federal Implementation Plan for Implementing Best Available Retrofit Technology for 

Four Corners Power Plant: Navajo Nation.” San Francisco, CA: U.S. Environmental Protection Agency, 

Aug. 6, 2012. The three oldest of the plant’s five generating units will be retired by 2014 to comply with 

new emission requirements. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 111 

at www.nrel.gov/publications. 
 

 

 

 

Figure 3-3 shows how much New Mexico wind power could be available for export and 

at what cost. As explained in Section 2.8, New Mexico’s total demand for renewable 

energy by 2025 will likely be between 3 TWh and 4 TWh per year. Wind power, 

however, can meet no more than 75% of the mandate, reducing the in-state RPS-related 

demand for wind power to between 2.2 TWh and 3 TWh per year. 

Surplus New Mexico wind power could also supply post-2025 demand in Arizona and 

Utah. Retail rates and the cost of alternatives in both states tend to be lower than in 

California, however. We estimate that the cost of wind power imported from New 

Mexico would be 13% to 14% above the state benchmarks ($111/MWh for Arizona and 

$113/MWh for Utah, with time-of-delivery adjustments). Even if transmission charges 

doubled, however, we estimate that New Mexico wind power delivered to Arizona would 

be as much as 20% below the busbar cost of Arizona’s best undeveloped solar resources 

in 2025. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 112 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

3.2.6 Nevada Solar 

Nevada’s projected 2025 surplus of prime-quality solar potential is between 3 TWh and 

6 TWh annually. The amount available for post-2025 development will depend on how 

much Nevada uses for its own renewable energy goal. 

The proximity of these resource areas to California could facilitate direct connection into 

the California ISO network, resulting in a lower delivered cost of power. On a busbar 

basis, these remaining Nevada solar resources are expected to cost about $151/MWh, 

22% more than the benchmark cost of natural gas. The generation patterns of Nevada 

solar tend to coincide with California load patterns, which increases the value of Nevada 

solar in California. We estimate that the value of load coincidence brings the effective 

cost of prime-quality Nevada solar power to about 7% above the post-2025 benchmark. 

Nevada solar’s post-2025 competitiveness with natural gas assumes that costs will 

continue to decline for solar power generally. If this happens, however, California’s own 

solar resources will also benefit. Thus, a major competitor to Nevada solar power could 

be untapped solar resources in California. Two crucial variables will be the ability to site 

new solar projects in California and the ability of Nevada solar projects to connect as part 

of the California ISO. 

Average busbar cost of best remaining 1,000 GWh: $151/MWh (without ITC) 

Note: “In-state demand 2025” represents projected demand for all renewables—not just solar. The extent to 

which in-state demand is met by resources other than solar would make more of the state’s least-cost solar 

resources available for potential export. 

Figure 3-4. Projected supply cost of Nevada solar power ($/MWh at the busbar) 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 113 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

3.2.8 Montana Wind 

The Pacific Northwest and Utah may be the post-2025 markets with the best 

opportunities for Montana wind power. Even if new lines were to result in transmission 

costs that are double current tariff rates, the delivered cost of Montana wind would still 

be within 4% of Oregon’s cost benchmark ($120/MWh) and within 11% of the 

benchmarks for Washington and Utah ($119/MWh and $113/MWh). 

Montana is second only to Wyoming in the productivity and quantity of its wind power. 

Between its prime-quality resources and those that could be developed at capacity factors 

between 38% and 40%, Montana is likely to have enough undeveloped wind potential in 

2025 to equal the power generated annually by Colstrip, the West’s third-largest coal 

plant located in the southeastern part of the state. The estimated busbar costs of wind 

projects in these remaining areas range from $75/MWh to $93/MWh. 

Wind power already accounts for about 1.5 TWh of Montana’s annual electric 

generation. Projects under construction could provide another 787 GWh per year. About 

one-third of Montana’s current wind production is for its own RPS requirement; the rest 

is exported to other states, primarily California. We estimate that Montana will need no 

more than 1 TWh per year by 2025 (from all renewable sources) to satisfy its RPS. 

Average busbar cost of best remaining 1,000 GWh: $82/MWh (without PTC) 

Note: The gray area on the chart represents total in-state demand for all renewables in 2025, plus existing 

wind development dedicated to exports. The extent to which future in-state demand is met by resources 

other than wind would make more of the state’s least-cost wind resources available for potential export. 

Figure 3-5. Projected supply cost of Montana wind power ($/MWh at the busbar) 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 114 

at www.nrel.gov/publications. 
 

 

 

 

 

 

Montana and Wyoming could be strong competitors for delivering wind power to the 

Northwest. The index scores suggest the two wind resource areas would be evenly 

matched and that both have a high likelihood of value in the destination market. 

California’s post-2025 market could be more challenging for Montana wind power, 

however. The distance is farther and indicative transmission costs are higher, as shown in 

Table 3-4. Moreover, the index scores suggest that wind power from Wyoming and New 

Mexico would be the strongest competitors in a California post-2025 market in that their 

delivered costs are more likely to be at or below the state benchmarks. 

3.2.9 Other Regional Surpluses 

This study identified a number of other likely surpluses of prime-quality renewable 

resources in the West. In these cases, however, index scores failed the value tests for two 

general reasons. 

•	 Low costs in the destination market. This particularly affected scores for resource 

paths leading to Washington, where the combined-cycle cost benchmark and 

retail rates are much lower than in California. In many cases, low-cost resources 

failed the value test because the economic hurdle posed by the state benchmark 

was too challenging. 

•	 Transmission rate pancaking. In some cases, a resource path would have passed 

the test for moderate value potential if its indicative transmission charges had 

been based on fewer tariff rates. This was especially true when the paths included 

rugged areas where transmission development is expensive. 

While failing the value tests does not necessarily preclude the likelihood of post-2025 

development, it can indicate the issues that would need to be addressed if projects were to 

move forward. Table 3-8 shows the scores of all resource paths tested in this study. 

This report is available at no cost from the 

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at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

Table 3-8. Full List of Resource Path Scores 

Resource Path Score Resource Path Score 

Wyoming wind to Nevada 0.79 Montana wind to California 1.23 

Wyoming wind to Utah 0.84 Idaho geothermal to Utah 1.27 

New Mexico wind to Arizona 0.94 California geothermal to Arizona 1.30 

Wyoming wind to Arizona 0.95 Idaho geothermal to Arizona 1.30 

Wyoming wind to California 0.97 Colorado wind to Utah 1.34 

Wyoming wind to Washington 1.04 New Mexico wind to Utah 1.35 

Wyoming wind to Oregon 1.04 Nevada geothermal to California 1.39 

New Mexico wind to California 1.06 Nevada geothermal to Arizona 1.44 

Nevada solar to California 1.07 Nevada solar to Arizona 1.44 

Idaho geothermal to California 1.11 Colorado wind to Arizona 1.50 

Montana wind to Nevada 1.12 Colorado wind to California 1.50 

Arizona solar to California 1.13 Nevada solar to Utah 1.51 

Montana wind to Utah 1.17 Nevada geothermal to Oregon 1.57 

Montana wind to Oregon 1.18 Nevada geothermal to Utah 1.58 

Montana wind to Washington 1.19 Nevada geothermal to Washington 1.58 

Idaho geothermal to Oregon 1.19 Nevada solar to Oregon 1.81 

Idaho geothermal to Washington 1.20 Nevada solar to Washington 1.96 

Montana wind to Arizona 1.21 

Wind resource 

Solar resource 

Geothermal resource 

3.2.9.1 Sensitivity Analysis 

The robustness of a value proposition identified in the foregoing analysis depends in part 

on future resource costs. This section tests how the value propositions could change if 

costs vary from the baseline assumptions used in this analysis. 

Two types of sensitivity analysis were conducted. The first looked at how far from grid 

parity a technology might be in a post-2025 environment, based on the assumptions and 

calculations of this analysis. The second sensitivity analysis tested how a 10% change in 

a technology’s assumed 2025 cost would affect a resource path’s score and ranking. 

3.2.9.2 Competitiveness 

The context for this part of the sensitivity analysis is a renewable resource’s estimated 

competitiveness, which we define as the difference between the resource’s levelized 

delivered cost without subsidy and the levelized cost of a CCGT built in 2025 in the 

destination market. Analytically, the difference is the additional reduction in busbar cost 

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at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

that would be needed for the resource to achieve a score of 1.0 in its highest-value post2025 markets. Gaps are calculated for the following resource paths: 

•	 Geothermal power: Idaho to California, Oregon, and Washington; Nevada to 

California; California (Salton Sea) to Arizona 

•	 Solar power: Nevada and Arizona to California 

•	 Wind power: Wyoming and New Mexico to California and Arizona; Montana and 

Wyoming to Oregon and Washington; Montana to California. 

This test allows for future cost uncertainty by increasing and decreasing the forecasted 

busbar costs by 10%. The busbar costs are applied to the “two times tariff” delivered cost 

methodology described above to approximate future transmission and integration costs. 

Each pair of results is then compared to the relevant CCGT cost benchmark to estimate 

the gap in competitiveness. 

Results from this study suggest that a competitiveness gap is likely to persist for 

geothermal power out to 2025, barring a significant breakthrough in current technology 

cost and performance. The gap could diminish for wind and solar to the extent that 

assumptions about future costs are accurate for 2025. A smaller competitiveness gap 

suggests that renewable energy policies in a post-2025 environment that reduce market 

barriers may be more effective than ones that subsidize costs. 

Table 3-9. Competitiveness Indicators for Regionally Developed Renewables in 2025 

Difference from forecasted CCGT cost 

(%) ($/MWh) 

Geothermal 

Idaho to California,
 

Northwest; Nevada to $15–$42 higher 

California; Imperial Valley to

Arizona
 

Solar 

Nevada and Arizona to $1–$31 higher 

California 

Wind 

Wyoming and New Mexico
 

to California and Arizona;
 Parity to $16 higher Montana and Wyoming to 

Oregon, Washington, and

California
 

Competitiveness is measured as the difference between the levelized delivered cost of an unsubsidized 

renewable resource and the levelized cost of a CCGT, with both values projected to 2025. Values shown 

here are averages derived from the resource paths indicated. Upper bounds of the ranges shown are
 

calculated after increasing assumed busbar costs by 10%; lower bounds assume busbar costs that are 10%
 

lower. Delivered costs use double current transmission tariff charges to proxy transmission and integration 

costs in 2025.
 

12%–35% higher 

1%–19% higher 

Parity to 13% higher 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 117 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Benchmark is the projected all-in cost of a new CCGT built in 2025, as calculated by the California PUC 

for its 2011 market price referent. Benchmarks applied to wind and solar are adjusted to account for 

coincidence with California load. Out-of-state delivery costs are approximated using the “two times tariff” 

methodology mentioned in this section; actual project cost for new bulk transmission may be different. 

Transmission costs within California are assumed to be the same for all resources and are not represented. 

Figure 3-6. Cost of resources projected to be available in bulk to California after 2025189 

Figure 3-6 compares the relative economic competitiveness in California of six 

renewable resource options, as calculated in this analysis. For each option shown on the 

chart, empirical evidence exists suggesting that large surpluses will be available in 2025. 

Most are likely to be close to the cost of a new CCGT, even if their busbar costs turn out 

to be 10% higher than estimated. The results suggest that, once the state achieves its 

current RPS goal in 2020, looking regionally for additional renewable energy supplies 

could provide California with reasonable diversity at reasonable cost. 

3.2.9.3 Impact of Variations in Future Costs 

The most pronounced cost sensitivity was for utility-scale solar power from Nevada and 

Arizona delivered to California. If busbar costs were to fall 10% below the assumptions 

used in this analysis, Nevada solar power would be close to parity with a CCGT in 

California. Ideally situated utility-scale solar power would lag only slightly behind 

ideally-situated wind power in market competitiveness. If actual busbar costs are 10% 

higher, then even the best areas for solar power lag behind wind power with respect to 

competitiveness with a CCGT. 

The U.S. Department of Energy’s cost goal for new utility-scale solar power is $1/W of 

installed capacity by 2020.190 This is more than twice as aggressive as the cost reductions 

tested in this sensitivity analysis. 

189 Resolution E-4442. Public Utilities Commission of the State of California (December 1, 2011). Results
 

of cost estimate methodology described in Section 3. 190 “SunShot Vision Study.” Washington, D.C.: U.S. Department of Energy, February 2012.
 

http://www1.eere.energy.gov/solar/pdfs/47927.pdf.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 118 

at www.nrel.gov/publications. 
 

 

 

 

 

The value propositions relating to wind power did not change substantially even after 

increasing the assumed busbar costs 10%. The Northwest remained a relatively strong 

market for Montana wind. Wind power from Wyoming and New Mexico both remained 

reasonably competitive in California. Lower busbar costs had little effect on the 

competitiveness of Colorado wind power, which is affected in this analysis by long 

transmission distances and high indicative delivery costs. 

The sensitivity analysis suggests that lower costs for geothermal could significantly 

improve the post-2025 competitiveness of California geothermal resources in Arizona 

and of Nevada’s residual geothermal resources in California. Results for Idaho’s 

geothermal resources remained relatively robust to higher busbar costs. 

Table 3-10 through Table 3-15 show the full results of the cost sensitivity analysis. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 119 

at www.nrel.gov/publications. 
 

 

 

 

 

Table 3-10. Scores After Decreasing Solar Busbar Costs by 10% 

Resource Path Score Resource Path Score 

Wyoming wind to Nevada 0.79 Montana wind to California 1.23 

Wyoming wind to Utah 0.84 Idaho geothermal to Utah 1.27 

New Mexico wind to Arizona 0.94 California geothermal to 

Arizona 

1.30 

Wyoming wind to Arizona 0.95 Idaho geothermal to Arizona 1.30 

Wyoming wind to California 0.97 Nevada solar to Arizona 1.31 

Nevada solar to California 0.98 Colorado wind to Utah 1.34 

Arizona solar to California 1.04 New Mexico wind to Utah 1.35 

Wyoming wind to Washington 1.04 Nevada solar to Utah 1.38 

Wyoming wind to Oregon 1.04 Nevada geothermal to 

California 

1.39 

New Mexico wind to California 1.06 Nevada geothermal to Arizona 1.44 

Idaho geothermal to California 1.11 Colorado wind to Arizona 1.50 

Montana wind to Nevada 1.12 Colorado wind to California 1.50 

Montana wind to Utah 1.17 Nevada geothermal to Oregon 1.57 

Montana wind to Oregon 1.18 Nevada geothermal to Utah 1.58 

Montana wind to Washington 1.19 Nevada geothermal to 

Washington 

1.58 

Idaho geothermal to Oregon 1.19 Nevada solar to Oregon 1.69 

Idaho geothermal to Washington 1.20 Nevada solar to Washington 1.83 

Montana wind to Arizona 1.21 

Table 3-11. Scores After Increasing Solar Busbar Costs by 10% 

Resource Path Score Resource Path Score 

Wyoming wind to Nevada 0.79 Montana wind to California 1.23 

Wyoming wind to Utah 0.84 Idaho geothermal to Utah 1.27 

New Mexico wind to Arizona 0.94 California geothermal to 

Arizona 

1.30 

Wyoming wind to Arizona 0.95 Idaho geothermal to Arizona 1.30 

Wyoming wind to California 0.97 Colorado wind to Utah 1.34 

Wyoming wind to Washington 1.04 New Mexico wind to Utah 1.35 

Wyoming wind to Oregon 1.04 Nevada geothermal to 

California 

1.39 

New Mexico wind to California 1.06 Nevada geothermal to Arizona 1.44 

Idaho geothermal to California 1.11 Colorado wind to Arizona 1.50 

Montana wind to Nevada 1.12 Colorado wind to California 1.50 

Nevada solar to California 1.17 Nevada solar to Arizona 1.57 

Montana wind to Utah 1.17 Nevada geothermal to Oregon 1.57 

Montana wind to Oregon 1.18 Nevada geothermal to Utah 1.58 

Montana wind to Washington 1.19 Nevada geothermal to 

Washington 

1.58 

Idaho geothermal to Oregon 1.19 Nevada solar to Utah 1.64 

Idaho geothermal to Washington 1.20 Nevada solar to Oregon 1.93 

Montana wind to Arizona 1.21 Nevada solar to Washington 2.09 

Arizona solar to California 1.22 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 120 

at www.nrel.gov/publications. 
 

 

 

 

Table 3-12. Scores After Decreasing Wind Busbar Costs by 10% 

Resource Path Score Resource Path Score 

Wyoming wind to Nevada 0.73 Idaho geothermal to 

Washington 

1.20 

Wyoming wind to Utah 0.77 Colorado wind to Utah 1.26 

New Mexico wind to Arizona 0.86 New Mexico wind to Utah 1.27 

Wyoming wind to Arizona 0.88 Idaho geothermal to Utah 1.27 

Wyoming wind to California 0.91 California geothermal to 

Arizona 

1.30 

Wyoming wind to Washington 0.98 Idaho geothermal to Arizona 1.30 

Wyoming wind to Oregon 0.98 Nevada geothermal to 

California 

1.39 

New Mexico wind to California 0.99 Colorado wind to Arizona 1.41 

Montana wind to Nevada 1.05 Colorado wind to California 1.43 

Nevada solar to California 1.07 Nevada geothermal to Arizona 1.44 

Montana wind to Utah 1.09 Nevada solar to Arizona 1.44 

Idaho geothermal to California 1.11 Nevada solar to Utah 1.51 

Montana wind to Oregon 1.12 Nevada geothermal to Oregon 1.57 

Montana wind to Washington 1.12 Nevada geothermal to Utah 1.58 

Arizona solar to California 1.13 Nevada geothermal to 

Washington 

1.58 

Montana wind to Arizona 1.14 Nevada solar to Oregon 1.81 

Montana wind to California 1.17 Nevada solar to Washington 1.96 

Idaho geothermal to Oregon 1.19 

Table 3-13. Scores After Increasing Wind Busbar Costs by 10% 

Resource Path Score Resource Path Score 

Wyoming wind to Nevada 0.85 Montana wind to Arizona 1.28 

Wyoming wind to Utah 0.90 Montana wind to California 1.29 

Wyoming wind to Arizona 1.02 California geothermal to 

Arizona 

1.30 

New Mexico wind to Arizona 1.02 Idaho geothermal to Arizona 1.30 

Wyoming wind to California 1.03 Nevada geothermal to 

California 

1.39 

Nevada solar to California 1.07 New Mexico wind to Utah 1.42 

Wyoming wind to Washington 1.10 Colorado wind to Utah 1.42 

Wyoming wind to Oregon 1.11 Nevada geothermal to Arizona 1.44 

Idaho geothermal to California 1.11 Nevada solar to Arizona 1.44 

New Mexico wind to California 1.12 Nevada solar to Utah 1.51 

Arizona solar to California 1.13 Nevada geothermal to Oregon 1.57 

Idaho geothermal to Oregon 1.19 Colorado wind to California 1.57 

Montana wind to Nevada 1.19 Colorado wind to Arizona 1.58 

Idaho geothermal to Washington 1.20 Nevada geothermal to Utah 1.58 

Montana wind to Utah 1.24 Nevada geothermal to 

Washington 

1.58 

Montana wind to Oregon 1.25 Nevada solar to Oregon 1.81 

Montana wind to Washington 1.25 Nevada solar to Washington 1.96 

Idaho geothermal to Utah 1.27 

This report is available at no cost from the 

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at www.nrel.gov/publications. 
 

 

 

 

Table 3-14. Scores After Decreasing Geothermal Busbar Costs by 10% 

Resource Path Score Resource Path Score 

Wyoming wind to Nevada 0.79 Montana wind to Washington 1.19 

Wyoming wind to Utah 0.84 Idaho geothermal to Arizona 1.20 

New Mexico wind to Arizona 0.94 Montana wind to Arizona 1.21 

Wyoming wind to Arizona 0.95 Montana wind to California 1.23 

Wyoming wind to California 0.97 Nevada geothermal to 

California 

1.26 

Idaho geothermal to California 1.01 Nevada geothermal to Arizona 1.31 

Wyoming wind to Washington 1.04 Colorado wind to Utah 1.34 

Wyoming wind to Oregon 1.04 New Mexico wind to Utah 1.35 

New Mexico wind to California 1.06 Nevada geothermal to Oregon 1.43 

Nevada solar to California 1.07 Nevada geothermal to Utah 1.43 

Idaho geothermal to Oregon 1.08 Nevada solar to Arizona 1.44 

Idaho geothermal to Washington 1.09 Nevada geothermal to 

Washington 

1.44 

Montana wind to Nevada 1.12 Colorado wind to Arizona 1.50 

Arizona solar to California 1.13 Colorado wind to California 1.50 

Idaho geothermal to Utah 1.16 Nevada solar to Utah 1.51 

Montana wind to Utah 1.17 Nevada solar to Oregon 1.81 

California geothermal to Arizona 1.18 Nevada solar to Washington 1.96 

Montana wind to Oregon 1.18 

Table 3-15. Scores After Increasing Geothermal Busbar Costs by 10% 

Resource Path Score Resource Path Score 

Wyoming wind to Nevada 0.79 Idaho geothermal to 

Washington 

1.30 

Wyoming wind to Utah 0.84 Colorado wind to Utah 1.34 

New Mexico wind to Arizona 0.94 New Mexico wind to Utah 1.35 

Wyoming wind to Arizona 0.95 Idaho geothermal to Utah 1.38 

Wyoming wind to California 0.97 Idaho geothermal to Arizona 1.41 

Wyoming wind to Washington 1.04 California geothermal to 

Arizona 

1.42 

Wyoming wind to Oregon 1.04 Nevada solar to Arizona 1.44 

New Mexico wind to California 1.06 Colorado wind to Arizona 1.50 

Nevada solar to California 1.07 Colorado wind to California 1.50 

Montana wind to Nevada 1.12 Nevada solar to Utah 1.51 

Arizona solar to California 1.13 Nevada geothermal to 

California 

1.52 

Montana wind to Utah 1.17 Nevada geothermal to Arizona 1.56 

Montana wind to Oregon 1.18 Nevada geothermal to Oregon 1.71 

Montana wind to Washington 1.19 Nevada geothermal to 

Washington 

1.72 

Idaho geothermal to California 1.20 Nevada geothermal to Utah 1.73 

Montana wind to Arizona 1.21 Nevada solar to Oregon 1.81 

Montana wind to California 1.23 Nevada solar to Washington 1.96 

Idaho geothermal to Oregon 1.29 

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4 Conclusion and Next Steps 

The aim of this study is to be a resource for an ongoing multi-state policy conversation 

that began in 2007 when the western governors launched the WREZ Initiative. WREZ 

Phase 1 located and quantified the West’s most potentially productive renewable energy 

areas. Phase 2 provided an initial framework for linking these zones to major load areas. 

Phase 3 polled utilities and regulators about their current thinking on future needs for 

renewable energy procurement and transmission and compared the responses to the 

outcomes of Phases 1 and 2. 

This study updates and focuses the information from Phases 1 and 2 and tracks current 

supply and demand trends to help state regulators and utilities address some of the 

uncertainties they identified in Phase 3. It is too early to say how strong the post-2025 

market for renewables will be or whether it will be primarily market-driven or policydriven. In any case, this analysis provides an in-depth examination of a number of 

potential renewable energy corridors that show some potential for being cost-effective 

relative to other utility-scale regional options in 2025. 

A number of follow-on analyses could build on the findings of this study. The first would 

be to juxtapose the value propositions described in Section 3 with current transmission 

planning and development. Each value proposition happens to coincide with one or more 

major transmission projects in various stages of development. A follow-on transmission 

analysis should aim to replace the indicative transmission costs of Section 3 with 

estimates drawn more directly from the specifics of the proposed projects. 

The transmission follow-up study is where grid integration issues would logically enter 

into the picture. The present study set aside grid integration issues, the assumption being 

that one should first narrow down the set of alternatives to those that are likely to be the 

most economically interesting. A grid integration analysis could then use inputs and 

assumptions specific to the transactions of interest (the delivery of wind power from 

Wyoming to California, for example). Such an analysis would be a logical extension of 

work begun with NREL’s Western Wind and Solar Integration Study. 

A valuable complementary analysis would be an assessment and forecast of trends in 

renewable DG. This analysis should parallel this study by providing a market-by-market 

evaluation of DG potential and the degree to which this potential has been developed. 

These follow on studies would serve to inform the ongoing dialogue within and among 

the western states themselves as they approach key decisions regarding long-term 

renewable electricity development in the West. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 123 

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Appendix: Regionalism Past and Present 

Regionalism is not a new concept in the West. The history of electricity resource 

development shows that western states and their utilities have already embraced a limited 

form of regionalism as a model for baseload generation expansion. This earlier 

regionalism was driven in part by the West’s above-average economic growth in the 

1960s and 1970s and was enabled by technological changes in the electricity sector that 

at the time promised low-cost generation. These factors helped give rise to what may be 

termed “gigaplants”: billion-dollar generating stations with more than one gigawatt of 

generating capacity, usually owned by more than one utility in partnership. 

Cross-state partnerships to develop these gigaplants were a major departure from 

business-as-usual four decades ago. This section examines how regional baseload 

gigaplants came into being, focusing on aspects of that experience that could shed light 

on present-day conditions affecting the regional development of renewable power. 

The lessons must be extracted with care, however. The electricity sector is not the same 

today as it was in the 1960s. Public attitudes toward environmental protection have 

changed as well; the same coal or nuclear gigaplant that passed regulatory muster as it 

was designed five decades ago might not today. Key parallels between the baseload 

gigaplant era and renewable energy today include the role of emerging technologies in 

achieving emerging public aims and the location-sensitive characteristics of the emerging 

technologies. 

It is the contrasts, however, that might suggest why regionalism is so difficult today. The 

crucial differences are those that affect the recovery of capital costs and the ability to 

manage the associated risk. Competition has replaced natural monopoly in many parts of 

the supply path from generator to customer. Consequently, the regulatory tools applicable 

to monopoly utilities building coal and nuclear plants in the 1970s and 1980s are not 

necessarily applicable to the wind, solar, or geothermal industries where competitive 

suppliers make most of the capital investment decisions. Risk is different; regulated 

monopolies had a reasonable assurance of guaranteed recovery of capital costs through 

rate base mechanisms. Merchant renewable energy developers have no comparable 

assurance prior to the signing of a long-term power purchase agreement (PPA). 

Precisely why and how regulators four decades ago reached the conclusion that 

regionalism was in the public interest and consistent with law is beyond the scope of this 

analysis. The Arab oil embargo of 1973 and its sudden, dramatic impact on oil prices 

contributed to a heightened public sense of energy vulnerability, but understanding how 

this sentiment translated into utility case law would involve historical analysis of the 

legal records leading up to the major decisions of the day. Of interest here is how market 

circumstances then compare to those of today. 

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National Renewable Energy Laboratory (NREL) 124 

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75 

50 

25 

Net TWh 0 

(generation minus 

retail sales) -25 

-50 

-75 

-100 

Northwest (Idaho, Montana, Oregon, Utah, Washington)
 

Southwest (Arizona, Nevada, New Mexico)
 

Rocky Mountains (Colorado, Wyoming)
 

California
 

The state groupings shown in the graph roughly coincide with planning subregions of the North American 

Electric Reliability Corp. (NERC). Subregions are defined geographically according to transmission 

networks, not state boundaries. Data assume an overall system loss equivalent to 5% of generation. Some 

generation is used for purposes other than retail sales, such as public water delivery, thus the net of 

generation and retail sales will tend to be positive. 

Figure A-1. Implied exports and imports among western regions based on generation 

and consumption191 

The outcomes of baseload gigaplant regionalism are still evident today. Figure A-1 shows 

the amount of electricity moving across state borders. California’s in-state net generation 

is less than its in-state retail sales by about one-quarter, making it a net importer. In 

contrast, about 43 TWh of all the electricity generated in the Southwest each year is used 

somewhere other than the state where it was generated. 

The Advent of Regional Baseload Gigaplants 

Most of the coal-fired generating units in the West were small and local up to 1967. The 

largest single unit had 253 MW in nameplate capacity, all dedicated to Public Service 

Company of New Mexico.192 Public Service Company of Colorado brought a 350-MW 

unit online in 1968. Excluding these two largest units, the average size of all coal units 

built in the West between 1950 and 1968 was 77 MW.

193 

191 Form 906, 920, 923: Net Generation by State by Type of Producer by Energy Source, Annual back to 

1990 and Form 861: Retail Sales by State by Sector by Provider Back to 1990. Washington, D.C.: U.S.
 

Energy Information Administration, 2012. 192 Form EIA-860, Annual Electric Generator Reports. U.S. Energy Information Administration, 2012.
 

http://www.eia.gov/electricity/data/eia860/index.html.
 193 This includes only those coal units in the West that had not been decommissioned as of 2000 and were
 

therefore still in the EIA 860 database. Of the coal units still existing in the U.S. portion of WECC, 45
 

came online between 1950 and 1968.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 125 

at www.nrel.gov/publications. 
1.5 All units in U.S. 

Intermountain 

Four Corners 

1.0 Mohave 

Unit Navajo 

nameplate

GW 0.5 

Colstrip 

Centralia 

Boardman 

Jim Bridger 

0.0 

1940 1950 1960 1970 1980 1990 2000 

Year unit came on line

Figure A-2. U.S. coal units from 1940 to 2000, by nameplate capacity and year online, 

with units built in the Western Interconnection larger than 500 MW194

That changed in 1969. Metallurgical improvements developed after World War II led to 

boilers that were capable of withstanding higher temperature and pressure. This led to 

advancements in supercritical steam processes during the 1950s and 1960s that made coal 

gigaplants technologically feasible.195 Shortly after these improvements were 

demonstrated, larger-capacity coal units began to appear throughout the country, as 

shown in Figure A-2. 

Enabled by the new technology, utilities in the West began partnering with each other to 

build larger and more efficient plants. Most were experiencing significant load growth; 

during the 1960s, total electricity sales throughout the West increased at an annual rate of 

7%. In response, nine new coal units each with more than 700 MW in nameplate capacity 

came online between 1969 and 1976: two at the Four Corners Generating Station in New 

Mexico, two at the Mohave Generating Station in Nevada, two at the Centralia 

Generating Station in Washington, and three at the Navajo Generating Station in Arizona. 

Around this same time, federal research into large-scale electric generation applications 

for nuclear power began to bear fruit. The U.S. Atomic Energy Commission subsidized 

the development of several experimental reactors across the country, including the 436­

MW San Onofre Unit #1 that began operation in 1968 near San Clemente, California. 

Utilities and regulators moved forward in the early 1970s with plans to develop large 

nuclear reactor plants at four sites in the West.196 

194 Form EIA-860, Annual Electric Generator Reports. U.S. Energy Information Administration, 2012.

http://www.eia.gov/electricity/data/eia860/index.html. Data used was archived database for 2000. 195 Smith, J.W. “Supercritical (Once Through) Boiler Technology.” Charlotte, NC: Babcock & Wilcox

Company, 1998. http://www.babcock.com/library/tech-utility.html. 196 Parsons, R.M. “History of Technology Policy—Commercial Nuclear Power.” Journal of Professional

Issues in Engineering Education and Practice, (121:2), 1995; pp. 85-98.

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National Renewable Energy Laboratory (NREL) 126 

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The Columbia nuclear generating station sells its output to the Bonneville Power Administration, which 

Intermountain 

Colstrip 

Navajo Four Corners 

Mohaveb 

San Onofre Palo Verde 

Diablo Canyon 

Jim Bridger 

Boardman 

Centralia 

Columbiaa 

provides bulk power throughout the Northwest. The Mohave coal plant ceased operation in 2006. 

Figure A-3. Direction of historical commercial flows of power from major baseload plants 

in the Western Interconnection (those with units 500 MW or larger) 

The map in Figure A-3 shows the Western Interconnection’s coal and nuclear plants with 

generating units 500 MW or larger and how power from these stations flows 

commercially across the region. Most serve demand in more than one state, and most 

send a share of their output to California. Eastward, El Paso Electric in Texas owns 

shares of the Four Corners coal plant in New Mexico and the Palo Verde nuclear plant 

in Arizona. 

Technological transformation provided a key enabling ingredient for the regionalism that 

took place in the 1970s and 1980s. These new technologies were not widely available to 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 127 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

the electric sector prior to 1969, at least not on a large scale. When they were available, 

they opened commercial opportunities that had not existed before then. The ability of a 

utility to make the most of the emerging technologies, however, depended on economies 

of scale. Scale depended on easy access to inputs that were crucial to the technology’s 

ability to produce electricity efficiently. 

In the West, proximity to fuel and cooling water had a greater bearing on siting than did 

proximity to load. The coal gigaplants took advantage of location, maximizing their 

economic and operational efficiency by siting close to their fuel supplies and to sources 

of cooling water. For example, the Navajo Generating Station, the West’s largest coal 

plant, is located on the Navajo Reservation in northern Arizona just 3 miles from Glen 

Canyon Reservoir and is only 50 miles from the coal mine on the Navajo and Hopi 

reservations that provides its fuel. 

Similarly, the nuclear reactors built to generate electricity had to be located near abundant 

sources of cooling water. The San Onofre and Diablo Canyon nuclear stations were built 

near the ocean so they could use seawater for once-through cooling.197 The Palo Verde 

plant was designed to use reclaimed wastewater for cooling and was built near Phoenix 

where wastewater was sufficient and easily accessible. 

Parallels Between Past with Present 

Baseload gigaplants came into being at a time when emerging societal needs coincided 

with new technological possibilities. Today other factors are converging. States and 

utilities are seeking ways to make their generation portfolios cleaner, in conjunction with 

the more traditional objectives of ensuring reasonable rates and maintaining system 

reliability. 

At the same time, technological improvements in wind, solar, and geothermal generation 

are reducing the cost of making renewable resources a larger part of the generation mix. 

Figure A-4 illustrates the small but growing contributions of renewable power to the 

generation portfolio of the western United States. Wind power reached a point of 

commercial takeoff around 2001, following a 20-year period during which project 

installed costs fell by two-thirds.198 Solar technologies have shown comparable signs of 

cost reduction and market acceleration. From 1998 to 2010 installed PV costs fell by 43% 

while the amount of grid-connected capacity—negligible in 1998—increased to 2 GW.199 

197 “Issues and Environmental Impacts Associated with Once-Through Cooling at California’s Coastal
 

Power Plants.” California Energy Commission, 2005. http://www.energy.ca.gov/2005publications/CEC700-2005-013/CEC-700-2005-013.PDF.
 198 Wiser, R. and Bolinger, M. 2010 Wind Technologies Market Report. Washington, D.C.: U.S.
 

Department of Energy, Energy Efficiency & Renewable Energy, 2011.
 

http://www.osti.gov/greenenergy/rddetail?osti_id=984671.
 199 Ardani, K. and Margolis, R. 2010 Solar Technologies Market Report. Washington, D.C.: U.S.
 

Department of Energy, Energy Efficiency & Renewable Energy, 2011.
 

http://www.nrel.gov/docs/fy12osti/51847.pdf.
 

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National Renewable Energy Laboratory (NREL) 128 

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8% 

6% 

4% 

2% 

0% 

Geothermal 

Solar 

Wind 

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 

Figure A-4. Geothermal, wind, solar share of generation in WECC (U.S. only)200 

As with baseload gigaplants, renewable energy depends on location for operational 

efficiency and economies of scale. There are differences, however. An individual unit at a 

gigaplant was a supersized supercritical steam unit linked to load along a supersized 

transmission corridor. For renewables, economy of scale means efficiently aggregating 

many small units of production—for example, hundreds of 2- to 3-MW wind turbines 

with a common point of interconnection, rather than the same amount of capacity 

embodied in a single supercritical thermal unit. 

The locational factors affecting renewables pertain to the consistency of the energy 

inputs: wind, sunshine, and underground heat. The quality of the natural resources affects 

the productivity of the technology used to create electricity, which in turn affects the 

technology’s economic viability. The WREZ Phase 1 analysis identified a select few 

areas in the West where wind was consistent enough to yield capacity factors of 40% or 

better, across contiguous areas capable of accommodating several gigawatts of capacity. 

High capacity factors mean the same amount of capital investment produces more 

electricity, with potential economies that can favorably affect customer rates. 

Economy of scale with respect to transmission is a key point for reducing the cost of 

future renewable energy development. One 500-kV line is about half the cost of four 230­

kV lines capable of moving the same quantity of power. The large line loses less 

electricity between the point of generation and the point of delivery to load, and it 

requires right-of-way along only one corridor rather than four.201 

200 Form 906, 920, 923: Net Generation by State by Type of Producer by Energy Source, Annual back to 

1990. Washington, D.C.: U.S. Energy Information Administration, 2012.
 201 Heyeck, M. “Interstate Electric Transmission: Enabler for Clean Energy.” American Electric Power,
 

April 2008; Geothermal Power and Interconnection: The Economics of Getting to Market. NREL/TPThis report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 129 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

Differences 

The differences between past and present are at least as important as the similarities. So 

far this century retail electricity sales in the West have grown at an annual rate of 1.5%, 

much slower than the 7% growth seen in the 1960s. The addition of new generation 

capacity of any kind is driven less by growth and more by the retirement of generators 

that have reached the end of their economic lives. 

Another crucial difference is the management of risk with respect to capital cost 

recovery. In the 1960s and 1970s, the electricity sector was a world of monopolies, each 

serving its own captured customer base. The vertically integrated utility dominated nearly 

every step of the supply chain in a given territory, from generation to retail distribution 

and delivery. A regulatory compact governed the relationship between the monopoly 

utility and the people to whom it provided electric service: the public would guarantee the 

utility enough revenue for it to operate soundly, and the utility would provide an essential 

service to the public at rates that were just and reasonable. To guarantee against the 

utility’s abuse of its monopoly, public regulators approved in detail the costs that the 

utility could recover and approved the rates that it charged to its customers. 

The decision landscape for most renewable power projects today is different. Many 

capital decisions are made by entities other than regulated monopolies. While most of the 

baseload gigaplants were owned by regulated monopoly utilities, about 85% of the wind 

and solar power generated in the United States comes from independent power producers 

who either sell their production to utilities on a contract basis or sell directly into a 

wholesale power market.202 

Consequently, a key difference for renewable power today is how revenues from retail 

customers pay for capital costs. At the time that utilities embraced baseload gigaplants, 

the common tool for recovering capital cost was to include the value of the asset in the 

utility’s rate base, as illustrated in Figure A-5. Public regulators reviewed and approved 

all assets deemed necessary for the convenience of serving the public. The aggregated 

value of these approved assets was then annualized at a rate of return that the regulators 

deemed sufficient to finance the assets and to provide the utility with a reasonable profit. 

The resulting value constituted the utility’s annual revenue requirement, which was then 

spread across the utility’s captured customer base through the rates it charged for service. 

6A20-54192. Golden, CO: National Renewable Laboratory, 2012.
 

http://www.nrel.gov/docs/fy12osti/54192.pdf.
 202 Electric Power Annual (2010 Data Tables, Table 1.1B). U.S. Energy Information Administration, 2013.
 

http://www.eia.gov/electricity/annual/.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 130 

at www.nrel.gov/publications. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net value of utility’s 

approved capital assets 

Approved rate of return on 

capital assets 

Total revenue required to 

finance-approved assets Customer rates 

Figure A-5. Recovery of capital costs through a utility’s rate base 

The regulatory compact—especially the ability to guarantee recovery of capital costs 

through rate base—was crucial to financing baseload gigaplants in the West, due to the 

magnitude of the investments. For example, at the time SCE acquired its share of the 

proposed Palo Verde nuclear plant in 1975, the estimated cost of the Arizona plant was 

equivalent to 60% of the utility’s asset base.203 Similarly, when the LADWP agreed to 

participate in the proposed Navajo Generating Station in 1969, the coal plant’s estimated 

cost was about half of the utility’s net plant in service.204 In both cases, spreading shares 

of ownership across several utilities reduced each partnering entity’s financial exposure. 

Most of the owners were then able to add their shares to rate base, thereby guaranteeing 

their share of the capital costs. 

Today, a load-serving utility seldom builds its own renewable generation facilities. 

Merchant developers with specialized expertise can build a wind farm, solar project, or 

geothermal plant with greater operational efficiency, so utilities commonly purchase 

renewable power from independent providers. These developers usually retain 

ownership, but they have no rate base to guarantee capital cost recovery. Their assurance 

comes with the signing of a PPA with a utility. For the developer’s private-sector lenders 

and equity partners, the decision to invest in a prospective renewable energy project: the 

demand signaled by the market, and the developer’s ability to compete for that demand. 

If there is no credible market signal, capital cost recovery might not happen regardless of 

a project’s technical quality. The lack of credible market signals for generation can also 

affect the ability of a merchant transmission provider to finance its project. Federal rules 

require transmission owners to provide service in a nondiscriminatory and nonpreferential manner, so a transmission owner would normally be indifferent to which 

renewable project secured a PPA with a load-serving buyer.205 The crucial factor for a 

transmission developer is whether the market demand for renewable power will 

materialize. 

203 “Statistics of Privately Owned Electric Utilities in the United States.” Federal Power Commission
 

(FPC), 1975; “Business Briefs: Nuclear Power Plant Interest Sold,” New York Times, Aug. 30, 1975.
 204 “Statistics of Publicly Owned Electric Utilities in the United States.” Federal Power Commission (FPC),
 

1968; Assistant Secretary of the Interior James R. Smith, letter to President Nixon, Sept. 30, 1969 (copy on
 

file with authors).

205 For example, see: Transmission Open Access, Promoting Wholesale Competition Through Open Access
 

Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public
 

Utilities and Transmitting Utilities (Final Rule). Federal Energy Regulatory Commission, 1996.
 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 131 

at www.nrel.gov/publications. 
 

 

 

 

 

 

Conclusion 

The history of electricity development in the West shows that when the right 

circumstances converge, states can indeed depart from business as usual and act 

regionally to seize a new opportunity to meet a new need. The precedent is that emerging 

technologies built at scale, in the right places, and serving customers in several service 

areas and jurisdictions can achieve common social aims cost effectively and with less 

financial risk to the public. 

This study identifies a number of development zones and transmission pathways for 

prospects for post-2025 renewable energy development. They suggest transactions across 

a regional network that would be geographically comparable to the existing regional 

network for baseload power. 

Nevertheless, a renaissance of regionalism for renewable power might depend on a 

number of crucial factors, such as: 

•	 Whether states can adapt their policy tools to an electricity sector that is less 

monolithic than it was half a century ago 

•	 Whether the timeline for securing PPAs for new renewable projects can provide 

competitive developers with investment signals that are comparable to what rate 

base mechanisms provided to regulated utilities when they expanded their 

baseload capacity 

•	 How states balance post-2025 regional renewable energy expansion in the context 

of other policy objectives such as DG, in-state economic development, and 

protecting habitat. 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 132 

at www.nrel.gov/publications. 
 

 

 

 

 

 

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