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.

Contract No. DE-AC36-08GO28308

Implications of a PTC Extension 

on U.S. Wind Deployment

Eric Lantz, Daniel Steinberg, Michael 

Mendelsohn, Owen Zinaman, Ted James, 

Gian Porro, Maureen Hand, Trieu Mai, 

Jeffrey Logan, Jenny Heeter, and Lori Bird

Technical Report

NREL/TP-6A20-61663

April 2014
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.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Implications of a PTC Extension 

on U.S. Wind Deployment

Eric Lantz, Daniel Steinberg, Michael 

Mendelsohn, Owen Zinaman, Ted James, 

Gian Porro, Maureen Hand, Trieu Mai, 

Jeffrey Logan, Jenny Heeter, and Lori Bird

Prepared under Task No. WE14.CG01

Technical Report

NREL/TP-6A20-61663

April 2014
NOTICE

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

any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately 

owned rights. Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, 

or favoring by the United States government or any agency thereof. The views and opinions of authors 

expressed herein do not necessarily state or reflect those of the United States government or any agency thereof.

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

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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.

Printed on paper containing at least 50% wastepaper, including 10% post consumer waste. 
iii

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Preface

This work responds to a request made in October 2012 by Senator Jeff Bingaman, who has since 

retired. At the time, Senator Bingaman was the Chairman of the Senate Committee on Energy 

and Natural Resources. Senator Bingaman requested that the National Renewable Energy 

Laboratory (NREL) estimate the level of continuing policy support necessary to avoid significant 

disruption to domestic wind industry manufacturing and employment. Funding for the work was 

provided by the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. 

The production tax credit (PTC) has been the primary federal incentive for deployment of wind 

power in the United States since it was first enacted as part of the Energy Policy Act of 1992. 

The credit establishes a production incentive for qualifying projects during the first 10 years of 

commercial operation and has been renewed eight times since its initial passage; renewals have 

often occurred near to or soon after expirations. Most recently, the PTC was extended by one 

year through December 31, 2013. Although the PTC has now expired, this extension included an 

adjustment of eligibility criteria that is expected to result in the qualification of projects that 

began construction in 2013 and maintain construction into 2014 and 2015; under current IRS 

guidance, projects that maintain construction into 2016 might also qualify.
iv

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Executive Summary

The production tax credit (PTC) has been the primary federal incentive for deployment of wind 

power in the United States since it was first enacted as part of the Energy Policy Act of 1992. 

The PTC establishes a production incentive for qualifying projects during the first 10 years of 

commercial operation and has been renewed eight times since its initial passage; renewals have

often occurred near to or soon after expirations. Most recently, the PTC was extended by one 

year through December 31, 2013. Although the PTC has now expired, this extension included an 

adjustment of eligibility criteria that is expected to result in the qualification of projects that 

began construction in 2013 and maintain construction into 2014 and 2015; under current IRS 

guidance, projects that maintain construction into 2016 might also qualify. 

The PTC has been critical to the development of the wind industry and deployment of wind 

generation capacity in the United States over the past two decades. The presence of the PTC 

enables wind power project developers to reduce the price at which their electricity can be sold, 

effectively making their projects less costly for power purchasers and ultimately consumers. 

Wind power has been a growing part of U.S. electricity supply. Through 2012, more than 60 

gigawatts (GW) of land-based wind generation capacity have been installed nationally, including 

an average of 8.7 GW per year from 2008 through 2012. To meet recent growth in demand for 

wind capacity, the wind industry has invested heavily in U.S.-based manufacturing facilities. In 

2012, an estimated 550 U.S.-based manufacturing facilities produced turbines, blades, towers, 

and their components. Of these, over 60 were dedicated suppliers to the wind industry. Due to 

growth in U.S. manufacturing capacity, the estimated import fraction for new plant installations 

has steadily declined from 75% of total turbine costs in 2006-2007 to less than 30% in 2012. 

Despite recent record-setting deployment and a trend of increasing domestic content in its supply 

chain, the U.S. wind industry faces several challenges. Current and near-term state renewable 

portfolio standard (RPS) targets have largely been met and are not expected to support more than

1–3 GW per year of new wind construction through 2020. Abundant new sources of low-priced 

natural gas have altered the competitive landscape in the power sector, and the modest economic 

recovery, coupled with successful energy efficiency investments, has limited growth in demand 

for new electricity generation of all types.

In response to these challenges, questions have been raised concerning the effect that PTC 

expiration could have on installations of new wind generation capacity and, more broadly, on 

domestic wind industry manufacturing, economic output, and employment. 

This analysis explores the potential effects of PTC expiration and various extension scenarios on 

future wind deployment with the Regional Energy Deployment System (ReEDS), a model of the 

U.S. electricity sector. ReEDS is unique among national capacity expansion models for its 

detailed regional structure and statistical treatment of the impact that variable wind and solar 

resources have on capacity planning and dispatch. The analysis considers deployment results in 

the context of recent wind industry installation and manufacturing trends. The analysis does not 

estimate the potential implications on government tax revenue associated with the PTC. 
v 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

A PTC expiration scenario (Current Policy/PTC Expiration) and five conceptual designs for a 

PTC extension are explored. Two extension scenarios extend the PTC at its current level (taking 

into account adjustments for inflation over time) for different lengths into the future (Constant 

2020, Constant 2030). Three scenarios ramp the credit down from its current level until it 

terminates in a future year. The three ramp-down designs are intended to explore scenarios in 

which a sufficient incentive is available such that median resource quality wind generation costs 

are on par with estimated electricity generation costs from new gas plants (Ramp Down Low), 

existing gas plants (Ramp Down High), and an intermediate case between these two (Ramp 

Down Mid). In the three ramp-down scenarios the PTC remains in place (with declining value) 

through 2020, 2022, and 2021, respectively. 

Analysis results are reported in ranges to reflect uncertainty in future natural gas prices and load 

growth. Projected fuel prices and load growth are derived from high and low values reported in 

the Energy Information Administration’s Annual Energy Outlook 2013. Wind technology costs 

across all scenarios are grounded in observed 2012 data and assume a reduction in levelized cost 

of energy (LCOE) of approximately 15% by 2020 and 20% by 2025. Two types of power plant 

retirements are simulated in the analysis: those in the near-term that have already been

announced by utilities, and those over the longer-term that occur as a function of plant age and 

dispatch characteristics. 

Figure ES-1 shows the projected average annual wind deployment from 2013–2020 for the 

policy scenarios analyzed. The results indicate that U.S. wind power deployment through 2020 is 

sensitive to both the prospective level of the PTC and market conditions over time. 

Figure ES-1. Projected average annual wind capacity deployed between 2013 and 2020 for 

scenarios examined 

Note: Ranges shown reflect sensitivity to changes in natural gas prices and electricity demand growth. 

Sensitivities are coupled to provide a high and low value for the impact of a given scenario. All modeling 

results rely on a single set of cost and performance inputs for renewable and non-renewable power 

generation technologies as well as a single set of projected electric generation capacity retirements.

Historical Annual 

Average Deployment 

(2008 – 2012): 8.7 GW
vi 

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More specifically, key findings of the analysis include: 

• Under a scenario in which the PTC is not extended (Current Policy/PTC Expiration) and 

all other policies remain unchanged, wind capacity additions are projected to be between 

3 GW and 5 GW per year from 2013–2020. 

• U.S. wind power manufacturing production generally aligns with average annual wind 

power capacity additions from 2008 to 2012. In the absence of U.S. domestic demand for 

new wind capacity, global markets are unlikely to offer many opportunities for U.S.-

based manufacturers. Given the limited export market, a reduction in domestic wind 

power deployment is likely to have a direct and negative effect on U.S.-based wind 

turbine manufacturing production and employment. 

• Modeled PTC extension options that ramp down and cease support by year-end 2022 

(Ramp Down Low, Ramp Down Mid, Ramp Down High) appear to be generally 

insufficient to support deployment close to recent levels and therefore may be insufficient 

to sustain the current industry domestic manufacturing and supply chain through 2020. 

• Of the scenarios considered, an extension of the PTC at its historical level (Constant 

2020) could provide the best opportunity to support deployment consistent with recent 

levels across a range of market conditions; it therefore could also provide the best 

opportunity to sustain the existing wind installation and manufacturing base at its 

current level.

• In the current low-priced natural gas regime, modeling results indicate that future wind 

deployment will be relatively low unless additional incentives are provided that result in 

wind being cost competitive with existing gas-fired generation. 

• Future uncertainty in key modeling variables, including gas prices and load growth, 

translates into high levels of uncertainty in the deployment outcomes of specific 

extension scenarios. 
vii 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table of Contents

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

1.1 PTC Background .............................................................................................................................. 2

1.2 Economics of Wind Deployment ..................................................................................................... 3

2 Analysis Methods ................................................................................................................................. 6

2.1 Model Description ........................................................................................................................... 6

2.2 PTC Extension Scenarios ................................................................................................................. 6

2.3 Modeling Sensitivities and Other Considerations ............................................................................ 8

2.4 Analysis Assumptions in Context .................................................................................................. 10

3 Results................................................................................................................................................. 11

3.1 Results Through 2020 .................................................................................................................... 11

3.1.1 Current Policy/PTC Expiration ....................................................................................... 11

3.1.2 Ramp-Down Scenarios ................................................................................................... 12

3.1.3 Constant 2020 Scenario .................................................................................................. 12

3.2 Analysis Results Through 2030 ..................................................................................................... 12

4 Implications for Domestic Manufacturing........................................................................................ 14

5 Other Policy-Relevant Considerations............................................................................................. 15

6 Conclusions ........................................................................................................................................ 16

References................................................................................................................................................. 17

Appendix A: Additional Information on Model Inputs and Assumptions ........................................... 20

Wind Costs ........................................................................................................................................... 20

Natural Gas Prices ................................................................................................................................ 20

Load Growth ......................................................................................................................................... 22
viii

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List of Figures

Figure ES-1. Projected average annual wind capacity deployed between 2013 and 2020 for 

scenarios examined ....................................................................................................................v

Figure 1. Relative wind and combined cycle natural gas economics ..............................................5

Figure 2. Analysis assumptions in context of standard framework ...............................................10

Figure 3. Projected average annual wind capacity deployed between 2013 and 2020 for PTC 

extension scenarios ..................................................................................................................11

Figure 4. Range of projected cumulative wind capacity deployed through 2030 for PTC 

extension scenarios ..................................................................................................................13

Figure A-1. Projected wind levelized cost per industry literature review .....................................20

Figure A-2. Projected electricity load growth from AEO 2013 assumed in this analysis .............23

List of Tables

Table 1. Applicable PTC Level in Analysis Scenarios (2012$/MWh) ............................................8

Table A-1. Input Electric-Sector Delivered Natural Gas Prices (2013$/MMBtu) ........................21

Table A-2. Model-Calculated Electric-Sector Delivered Natural Gas Prices (2013$/MMBtu)—

Low Wind Deployment Set of Scenarios.................................................................................21

Table A-3. Model-Calculated Electric-Sector Delivered Natural Gas Prices (2013$/MMBtu)—

High Wind Deployment Set of Scenarios ................................................................................22

Table A-4. AEO 2013 Electricity Load Growth—Low and High Economic Growth Cases ........22
1 

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1 Introduction

Wind power has been a growing part of the U.S. electricity supply. First emerging in California 

in the early 1980s, wind generation capacity has been installed more broadly in the United States

since the late 1990s (Wiser and Bolinger 2013; Logan and Kaplan 2008). Through 2012, more 

than 60 GW of land-based wind generation capacity have been installed nationally, including an 

average of 8.7 GW per year from 2008 through 2012. U.S. wind capacity is estimated to supply 

approximately 4.4% of the nation’s electricity demand (Wiser and Bolinger 2013).1 Utility-scale 

wind capacity has been installed and is operating in 39 states; in 9 of these states wind generation 

exceeds 12% of in-state electricity demand, and in 3 of these states—Iowa, South Dakota, and 

Kansas—wind is estimated to supply more than 20% of electricity demand (Wiser and Bolinger 

2013). Moreover, in 2012, wind power was the largest single source of new electric power 

generating capacity, constituting more than 40% of total U.S. additions (Wiser and Bolinger 

2013). Installations in 2012 represented approximately $25 billion in new investment (Wiser and 

Bolinger 2013). 

To meet this recent growth in demand for wind capacity, the wind industry has invested heavily 

in U.S.-based manufacturing facilities. In 2012, an estimated 550 U.S.-based manufacturing 

facilities produced turbines, blades, towers, and their components. Of these, more than 60 were 

dedicated suppliers to the wind industry (AWEA 2013). Due to growth in the U.S. 

manufacturing capacity, the estimated import fraction for new plant installations has steadily 

declined from 75% of total turbine costs in 2006–2007 to less than 30% in 2012 (Wiser and 

Bolinger 2013). The American Wind Energy Association (AWEA) estimates that employment 

from manufacturing has also grown over time. Approximately 25,500 individuals were employed 

in U.S.-based wind turbine component and equipment manufacturing facilities, and total U.S. 

wind industry employment—including manufacturing and facility installation, operation, and 

maintenance—was estimated at approximately 80,000 in 2012 (AWEA 2013). 

Despite recent record-setting annual installations and a trend of increasing domestic content in its 

supply chain, the U.S. wind industry faces several challenges (Wiser and Bolinger 2013; 

Bloomberg NEF 2013; MAKE 2013; IHS EER 2013; EIA 2013b). Current and near-term state 

renewable portfolio standard (RPS) targets have largely been met and are not expected to support 

more than 1–3 GW per year of new wind construction through 2020. Abundant new sources of 

low-priced natural gas, resulting largely from advancements in production techniques for shale 

reservoirs, have altered the competitive landscape in the power sector. And, the modest 

economic recovery, coupled with successful energy efficiency investments, has limited growth in 

demand for new electricity generation of all types. 

In conjunction with these challenges, the loss of the production tax credit (PTC), the primary 

federal incentive supporting the industry, has raised concerns among industry proponents, who 

suggest that PTC expiration could result in a reduction of new wind installations that could 

precipitate the loss of domestic wind industry jobs and the economic output associated with U.S. 

wind deployment and manufacturing. Further, some have speculated that a significant 

 

1 The estimate reported here assumes long-term average wind resource conditions and fleet availability. The Energy 

Information Administration (EIA) reports that through the first three quarters of 2013, U.S. wind generation 

averaged approximately 4% of total net generation and 4.4% of total retail sales (EIA 2013a).
2 

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contraction in the domestic wind market poses the risk of “offshoring” wind power 

manufacturing capabilities and the potential for innovation represented therein. In contrast, 

opponents of a PTC extension often suggest that all forms of electricity generation should 

compete in the marketplace on economic and environmental terms without federal financial 

support. For wind, in particular, some argue that incentives are no longer needed to support what 

is now a relatively mature industry (Brown 2012). 

The analysis in this report is focused on addressing two key questions: 

• What are the potential effects of PTC expiration and various PTC extension designs on 

future wind deployment? 

• What are the implications of these deployment levels on the wind manufacturing sector? 

The analysis applies NREL’s Regional Energy Deployment System (ReEDS) model (Short et al. 

2011) to assess the potential impact of several PTC extension scenarios on future deployment of 

wind generation capacity. A range of potential PTC designs are explored, including extensions 

that simply maintain the PTC at its current level until some future end date, as well as designs 

that ramp down or reduce the level of the PTC through time. The latter are designed to provide 

sufficient support to maintain the cost competitiveness of wind generation with other electricity 

generation technologies. The analysis does not explore the potential impacts on federal 

government revenue or other quantitative impacts associated with the deployment outcomes for 

either current PTC policy or the conceptual extensions explored. The sections that immediately 

follow provide a brief review of the history of the PTC and its impacts on the wind industry, 

along with an overview of the status of wind economics and competitiveness. Section 2 describes 

the analysis and modeling approach used, Section 3 presents modeling results, and Sections 4 

and 5 discuss their implications.

1.1 PTC Background 

Since the first wind plants were commissioned in the United States more than three decades ago, 

state and federal policy have played a critical role in the industry (Bird et al. 2005; Chapman et 

al. 2012). From the 1980s to the early 1990s, wind industry growth was supported by the Public 

Utility Regulatory Policies Act (PURPA), state and federal investment tax credits, and 

accelerated depreciation provisions (Bird et al. 2005). More recently, the federal PTC, continued 

accelerated depreciation provisions, state RPSs, and other state support structures have been 

instrumental to industry expansion (Bird et al. 2005; Wiser et al. 2007; Wiser and Barbose 2008).

The PTC was first enacted as part of the Energy Policy Act of 1992 and established a production 

incentive of $0.015/kWh ($15/MWh) for qualifying projects during the first 10 years of 

commercial operation. The credit is indexed to inflation, and as a result, projects that qualified in 

2013 received a tax credit of $0.023/kWh ($23/MWh). The PTC has expired or been within 5 

months of expiration and subsequently renewed on six different occasions (1999, 2001, 2003, 

2005, 2008, and 2012). In two additional instances (2006 and 2009) the PTC was renewed 12 

and 10 months, respectively, prior to expiration. Most recently, the PTC was extended by one 

year through December 31, 2013. Although the PTC has now expired, the eligibility criteria in 

the latest extension were adjusted from project completion by that date to construction initiation. 

According to IRS guidance, there is no fixed deadline by which time projects beginning 

construction in 2013 must be placed in service; however, continuous activity must be maintained
3 

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in order to qualify, and provisions exist to streamline qualification for those projects that are 

commissioned prior to year-end 2015 (IRS 2013). Construction times for modern wind power 

facilities range from 6 months to multiple years. Given this, it is likely that many projects that 

began construction in 2013 and maintain construction into 2014 and 2015 will qualify for the 

current incentive. Projects that initiated construction in 2013 and are commissioned in 2016 

might also qualify. 

The PTC has provided substantial assistance to the U.S. wind industry. The presence of the PTC 

enables wind power project developers to reduce the price at which their electricity can be sold, 

effectively making them less costly for power purchasers and ultimately consumers. Current 

estimates indicate that the PTC reduces contracted prices for wind power by approximately 

$20/MWh (2012 dollars) or roughly 25%–50% (Wiser and Bolinger 2013).2

 

At the same time, the on-again, off-again historical policy environment has created substantial 

uncertainty and deployment volatility. Past PTC expirations have resulted in reductions in yearon-year installations between 73% and 93% (Wiser et al. 2007). The impact of such boom and 

bust cycles is diverse. Most notably, short-term planning timeframes associated with PTC 

uncertainty can discourage investments in domestic manufacturing capacity, deployment 

capability, component orders, and private sector research and development (R&D) (Wiser et al. 

2007; Lewis and Wiser 2007).3 

The impacts of the PTC on government revenue have not been comprehensively evaluated in the 

literature. However, the Joint Committee on Taxation routinely “scores” tax policy to provide a 

perspective on the implications of a given policy for federal government expenditures. In its 

most recent assessment, which includes the PTC extension through year-end 2013, the Joint 

Committee estimates forward-looking tax expenditures associated with credits for wind energy 

to be approximately $7.7 billion cumulatively for fiscal years 2013–2017 (JCT 2013). 

1.2 Economics of Wind Deployment

Growth in wind power capacity over the past decade can generally be ascribed to a combination 

of three principal factors:

• Renewable Portfolio Standards: Twenty-nine states and the District of Columbia have 

mandated that a certain amount or percentage of generation capacity come from 

renewable energy sources. Historically, state RPSs have been a critical driver for wind 

capacity. While it remains difficult to discern precisely how much wind capacity is a 

direct result of RPS policies, 83% of wind installations in 2012 occurred in states with an 

RPS (Wiser and Bolinger 2013). 

 

2 Average 2011 and 2012 wind power purchase agreement (PPA) prices are reported to be $40/MWh (Wiser and 

Bolinger 2013); prices averaged approximately $70/MWh in 2009. In 20-year levelized terms, the value of the PTC 

approaches the legislated 10-year incentive level of $0.023/kWh because the incentive is in effect after-tax income. 

To calculate the impact of the PTC on levelized cost of energy, this after-tax income must be converted to its larger

pre-tax equivalent and levelized over the full economic life of the plant. 3 Wind power projects can have an extensive lead time prior to construction that incorporates various phases related 

to planning, engineering, permitting, environmental review, contract and legal documentation, and financing.
4 

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• Economic Competitiveness: Under certain conditions, wind power is directly 

competitive with other electricity generation sources and procured based on immediate or 

projected cost savings (Wiser and Bolinger 2013; Bloomberg NEF 2013). To date, the 

PTC and other federal tax incentives (e.g., accelerated depreciation) have boosted wind 

power’s economic position relative to alternative generation sources, enabling wind to be 

lower cost than other generation technologies in some regions (e.g., Texas).4 Wind is also 

sometimes credited as a hedge against potential natural gas price escalation (Bolinger 

2013; Wiser and Bolinger 2006). 

• Discretionary Factors: Utilities, corporations, and others can make investments in wind

power to supply voluntary green pricing programs because of a preference for wind or 

non-emitting energy sources or for various other reasons. This demand driver is not 

considered in the analytical modeling work conducted here.

State tax and other incentives and state or regional carbon markets have also supported wind 

installations in the past but are generally considered to be secondary drivers. 

Looking forward, some of these drivers are likely to have less impact on deployment. Existing 

RPS policies are expected to have only a modest impact: estimates from industry consultancies 

compiled over the past year project RPS wind demand at 1–3 GW/year through 2020 

(Bloomberg NEF 2013; MAKE 2013; IHS EER 2013). Moreover, the emergence of low-priced 

natural gas has dramatically altered the competitive landscape for wind power. Figure 1 is 

illustrative of the gap in projected costs between new wind plants (absent the PTC) and new

combined cycle gas-fired generation (left) as well as between new wind plants and existing gasfired generation (right). This juxtaposition suggests that without policy support to enhance the 

cost position of wind power, purely economic deployment will also likely be modest.5,6 The 

differences noted between the median wind cost reduction trajectory (dark blue line) and the 

range of gas-fired generation costs shown in Figure 1 are used to inform the development of 

ramp-down scenarios described in Section 2.2 and referred to in Section 3.1.

 

4 Today, there are more than 12 GW of operating wind capacity in Texas, a level of capacity that far exceeds 

expected demand from Texas’s RPS (ERCOT 2013). 5 The comparison shown in Figure 1 is relative to new (left) and existing (right) gas generation as these plants are 

often the marginal generation unit(s) as well as a substantial source of new generation capacity (EIA 2013b). 

Accordingly, wind will likely be competing with existing gas units to serve current load and new gas units to serve 

demand for new generation resources. Existing gas-fired generation is assumed to have its capital expenditures fully 

recovered and therefore has a levelized cost of energy equivalent to its fuel and ongoing operations and 

maintenance costs.

6 Notwithstanding these economic conditions, investments in wind power plants could continue to be made as a 

potential long-term hedge against future increases natural gas fuel costs (Bolinger 2013).
5 

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Figure 1. Relative wind and combined cycle natural gas economics

Notes: Dark yellow and green lines represent the projected cost of natural gas-fired generation based on reference 

case fuel prices derived from the Energy Information Administration (EIA) Annual Energy Outlook (AEO) (EIA 

2013b); for wind the dark blue line represents the generation cost associated with wind plants operating in median 

wind resource quality sites plus cost adders to reflect the provision of consistent capacity and energy resources to 

the system. More specifically, when comparing wind with new gas-fired generation (left), cost adders are included 

to reflect the incremental system capacity ($5/MWh as reported by EnerNex [2010], IEA [2010], Milligan and 

Porter [2008]) required to provide a capacity value comparable to a new combined cycle gas-fired plant and to 

cover incremental balancing expenditures ($2/MWh as summarized by Wiser and Bolinger [2013]) associated with 

the addition of variable generation into the power system. When comparing wind with existing gas-fired generation 

(right), as a fuel saver and assuming no need for additional capacity, only the balancing expenditures cost adder is 

included. 7 Wind cost reductions are based on the median, 25th, and 75th percentile literature cost reduction 

trajectory for wind power (Lantz et al. 2012). Bands represent uncertainty in projected costs as reported by Lantz et 

al. (2012) for wind and EIA (2013b) for natural gas. High and low gas prices are based on prices reported in the 

EIA’s AEO low and high resource recovery scenarios. The gaps between the median wind cost reduction trajectory 

(dark blue line) and the reference case gas-fired generation cost (dark yellow and green lines) are used to inform 

the development of ramp-down scenarios discussed in Section 2.

 

7 The system capacity adder is not included as wind power has no effect on overall system capacity when used as a “fuel 

saver” to offset generation provided by an existing asset. Balancing expenditures are included as the system operator is still 

required to maintain adequate spinning reserve to adjust for short-term wind generation variability.

Wind and New Natural Gas Generation Wind and Existing Natural Gas Generation 
6 

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2 Analysis Methods

2.1 Model Description 

This analysis applies ReEDS to explore the potential effects of PTC expiration and various 

extension scenarios on future deployment of wind generation capacity.8, 9 ReEDS is a capacity 

expansion model that simulates the construction and operation of generation and transmission 

capacity to meet electricity demand. The model relies on a least-cost optimization to provide 

estimates of the type and location of conventional and renewable resource development; the 

transmission infrastructure expansion requirements of those installations; and the composition 

and location of generation, storage, and demand-side technologies needed to satisfy regional 

demand requirements and maintain grid system adequacy. The model also considers technology, 

resource, and policy constraints, including state RPSs. ReEDS’s high spatial resolution and 

statistical treatment of the impact of variable wind and solar resources is specifically designed to 

represent the relative value of geographically and temporally constrained renewable 

power resources.

ReEDS does not model constraints associated with the manufacturing sector. All technologies 

are assumed to be available at their defined capital cost in any quantity. As well, technology cost 

reductions from manufacturing economies of scale and “learning-by-doing” are not 

endogenously modeled; rather, current and future cost reduction trajectories are defined as inputs 

to the model. The ReEDS model has limited market foresight and, with the exception of future 

fuel prices, does not make decisions based on any expectation of future market conditions. The 

model’s least-cost optimization also does not fully represent the prospecting, permitting, and 

siting hurdles that are faced by project developers for either electricity generation capacity or 

transmission infrastructure. 

2.2 PTC Extension Scenarios

Six specific PTC scenarios were explored in this analysis and are described below. These six 

scenarios were selected based on their ability to represent a potential range of PTC incentive 

levels and policy design features. One scenario represents current policy (i.e., expiration of the 

PTC in 2013). This case provides an estimate of future wind deployment by assuming no further 

extensions to the PTC. Three scenarios explore different approaches to a PTC ramp down, 

reflecting a multi-year policy that offers a gradual reduction in the level of the PTC. Two 

additional scenarios consider extensions of the PTC at its historical level (currently $23/MWh). 

The ramp-down scenarios are conceptually aligned with anticipated costs of combined cycle 

natural gas-fired units assuming reference case fuel prices (EIA 2013b); these scenarios are 

driven significantly by assumed projections of future natural gas prices. The range represented 

by the three ramp-down scenarios reflects different levels of support that enable pricing from 

wind (assuming a singular median cost reduction trajectory across all three scenarios) to be 

competitive with new units (those required to generate sufficient revenue to cover both operating 

costs and capital recovery), existing units (those that must only cover operating costs, including 

 

8 ReEDS is a widely-recognized electric sector modeling tool that has been applied across an array of past work 

including: DOE 2008, DOE 2012, NREL 2012, Mignone et al. 2012, among others.

9 See Short et al. 2011 for more information about the ReEDS model. The version of the model used in this analysis 

is consistent with the NREL base model as of October 2013. 
7 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

fuel), and the midpoint in between these two price points (Figure 1). The principal features of 

each scenario are summarized below (resulting PTC levels for each scenario are shown in 

Table 1): 

• Current Policy/PTC Expiration: Assumes PTC expiration in accord with current law. 

• Ramp Down Low: Provides a PTC that enables the median wind resource site to be 

competitive with new combined cycle gas generation. Wind projects commissioned by 

year-end 2014 qualify for the PTC at its current level. In 2015 the level of the PTC begins 

to decline. Wind projects commissioned after year-end 2020 do not qualify. Figure 1

(left) is illustrative of the generation cost gap between wind (blue wedge) and new 

combined cycle gas generation (orange wedge) that is bridged by this PTC scenario.

• Ramp Down High: Provides a PTC that enables the median wind resource site to be 

competitive with existing combined cycle gas generation. Wind projects commissioned 

by year-end 2014 qualify for the PTC at its current level. Beginning in 2016, the PTC

declines to $6/MWh by 2022. Projects commissioned after year-end 2022 do not qualify. 

Figure 1 (right) is illustrative of the cost gap between wind (blue wedge) and existing 

combined cycle gas generation (green wedge) that is bridged by this PTC scenario.

• Ramp Down Mid: Provides a PTC that is designed to split the difference between the

Ramp Down Low and Ramp Down High scenarios. Projects commissioned by year-end

2014 qualify for the PTC at its current level. In 2015 the level of the PTC begins to 

decline. Projects commissioned after year-end 2021 do not qualify.

• Constant 2020: Enables projects commissioned by year-end 2020 to qualify for the PTC 

at its historical level ($15/MWh adjusted for inflation).

• Constant 2030: Enables projects commissioned by year-end 2030 to qualify for the PTC 

at its historical level ($15/MWh adjusted for inflation).
8 

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Table 1. Applicable PTC Level in Analysis Scenarios (2012$/MWh) 

Year

Current 

Policy/PTC 

Expiration

Ramp 

Down Low

Ramp

Down 

High

Ramp 

Down Mid

Constant 

2020

Constant 

2030

2013 23 23 23 23 23 23

2014 23 23 23 23 23 23

2015 0 16 23 19 23 23

2016 0 12 18 15 23 23

2017 0 10 16 13 23 23

2018 0 7 13 10 23 23

2019 0 6 11 8 23 23

2020 0 5 10 7 23 23

2021 0 0 8 6 0 23

2022 0 0 6 0 0 23

2023 0 0 0 0 0 23

2024 0 0 0 0 0 23

2025 0 0 0 0 0 23

2026 0 0 0 0 0 23

2027 0 0 0 0 0 23

2028 0 0 0 0 0 23

2029 0 0 0 0 0 23

2030 0 0 0 0 0 23

Note: PTC values shown above are assumed paid in nominal dollars for a period of 10 years once the qualifying 

project becomes operational. 

PTC policy is considered independent of other policy changes that could affect renewable power 

or low carbon generation technologies (statutory and regulatory policy in effect today is 

captured; EPA regulations that are pending or under development are not). All scenarios apply a 

common median wind industry anticipated cost reduction trajectory. Wind technology costs 

across all scenarios are grounded in observed technology cost and performance for 2012 (Wiser 

and Bolinger 2013; Wiser et al. 2012) and assume a reduction in levelized cost of energy 

(LCOE) of approximately 15% by 2020 and 20% by 2025 (Lantz et al. 2012).

2.3 Modeling Sensitivities and Other Considerations

Common high and low deployment sensitivity cases were developed and modeled for each PTC 

extension scenario. This approach is intended to generally bound the potential range of wind 

deployment that could result from each policy scenario given uncertainty in key power sector 

variables, specifically natural gas fuel prices and future load growth. High and low natural gas 

price projections were derived from the High and Low Oil and Gas Resource cases reported in 

the Energy Information Administration (EIA) Annual Energy Outlook (AEO) (EIA 2013b). High 

and low load growth estimates were also derived from the AEO, specifically the High and Low 

Economic Growth cases (EIA 2013b). 

Assumptions for future natural gas price and load growth are presented in detail in Appendix A. 

Given relatively high uncertainty associated with these assumptions, this analysis focuses 
9 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

exclusively on bounding sensitivities and does not consider the likelihood of individual 

outcomes; accordingly, there is no median or reference case reported.

Approximately 60 GW of coal generation capacity was assumed to retire by 2020 in all cases. 

These retirements were based on data reported by Ventyx (2013) and Saha (2013) and include 

announced retirements only.10 

Solar technologies, including utility-scale photovoltaics (PV), concentrated solar power (CSP), 

and distributed rooftop PV (DG-PV) in the residential and commercial sectors, were considered 

for new capacity additions in all scenarios. Solar technology cost and performance assumptions 

were consistent with the SunShot 62.5% cost reduction scenario documented by Eurek et 

al. (2013).11

New geothermal and hydropower generation capacity was not allowed in core modeling 

scenarios due to high uncertainty in both the resource potential and prospective cost of these 

technologies. However, sensitivity analysis allowing capacity additions for these technologies, 

assuming current costs and the best available resource potential estimates, showed minimal 

effect on scenario outcomes.

Dispatch and deployment of fossil and nuclear technologies across all scenarios was based on 

cost and performance assumptions informed by the AEO 2013 Reference Case.

Deployment projections assume sufficient tax appetite on the part of project sponsors to utilize 

all accelerated depreciation deductions and PTCs in the years in which they are generated. In 

practice however, PTC monetization results in lower project debt levels and frequently requires 

third-party tax equity, with an associated incremental cost. As a result, scenario results may 

overestimate the impact that a given PTC incentive level could have on future deployment. At 

the same time, the lack of explicit consideration of discretionary deployment (e.g., voluntary 

Green Power Pricing Programs) suggests that the model results may underestimate this aspect of 

future deployment. 

This analysis does not consider the potential federal government revenue impacts associated with 

the PTC scenarios modeled here. A net revenue impacts assessment would estimate tax 

expenditures and tax receipts associated with wind generation capacity investment in relation to 

other investments that might be pursued in the absence of the PTC. A more simplistic approach 

to estimate federal revenue impacts might consider only the present value of the tax credits to be 

paid to wind project owners; however, this is only one of several components of the overall 

revenue impact. 

 

10 More speculative estimated retirements could not be modeled due to a lack of data, specifically the location and 

the timing of affected plants. However, the opportunity for new capacity additions resulting from additional coal 

plant retirements beyond the approximately 60 GW reflected here is at least in part captured by the load growth 

assumptions included in high deployment sensitivity cases.

11 For utility-scale PV, this trajectory reduces installation costs from $4.0/WDC in 2010 to $1.5/WDC by 2020. DGPV capacity additions are modeled outside of ReEDS and are consistent with the SunShot 62.5% cost reduction 

trajectory. 
10 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Scenarios analyzed (including those presented above) are not intended to be forecasts or 

predictions; rather, the model employed provides a consistent framework for assessing the 

impact of different technology, market, and policy conditions reflected in the scenarios analyzed. 

2.4 Analysis Assumptions in Context 

Figure 2 summarizes the range of values applied in this study for key model inputs, including 

energy demand, technology cost and performance, fuel prices, and policy/regulatory support. 

The figure also places the explicit values modeled within a range of potential inputs for these 

variables. Values used in recent studies are shown for reference. This standardized contextual

framework informs the design of specific scenarios explored in the analysis and provides a visual 

means for conveying these values in the context of a range of study assumptions employed for 

future technology, market, and policy conditions. 

Figure 2. Analysis assumptions in context of standard framework

Notes: Scenarios assessed in this analysis are shown as stars, distinguished by color, positioned above each bar 

relative to the qualitative end points identified for the input variable (e.g., low prices, high price for natural gas). 

Corresponding input assumptions for other recent studies are identified below each bar and referred to specifically 

to the right. 

U.S. Economy/ Electricity Demand Growth

Renewable Technology Cost and Performance

Fossil and Nuclear Cost and Performance 

Clean Energy Policy/Regulatory Environment

Key to Published Reference Studies

AEO: EIA Annual Energy Outlook (AEO) 2013 Scenario s

REF: Renewable Electricity Futures Study - NREL (2012), Mai et al 2014

SS: SunShot Vision Study - DOE (2012), Eurek et al 2013 (applies to solar techs only)

Low Wind Deployment Scenarios 

High Wind Deployment Scenarios 

Current Policy/No Extension Scenarios 

PTC Extension Scenarios through 2022

PTC Extension Scenarios through 2030

Load Reduction High Load Growth

No 

Growth

Natural Gas Prices

L R H

L AEO 2013 Low Economic Growth

R AEO 2013 Reference

H AEO 2013 High Economic Growth

No Improvement Tech. Breakthroughs

I R E A

I REF RE-ITI (Incremental Tech. Improvement)

R AEO 2013 Reference

5 SS 50% Reduction

E REF RE-ETI (Evolutionary Tech. Improvement)

6 SS 62.5% Reduction

A REF RE-ATI (Advanced Tech. Improvement)

7 SS 75% Reduction (Core Projection)

No Improvement Tech. Breakthroughs

I R

I REF RE-ITI (Incremental Tech. Improvement)

R AEO 2013 Reference

Low Prices High Prices

Reduced Support Extended Support

Current 

Law

HG AEO 2013 High Oil & Gas Resource

R AEO 2013 Reference

LG AEO 2013 Low Oil & Gas Resource

HG R LG

7

65

This Study
11 

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3 Results

The presentation of results is focused on near-term implications of a PTC extension. Results 

through 2020 are discussed in detail in Section 3.1. Results through 2030 are discussed more 

generally in Section 3.2. 

3.1 Results Through 2020

Analysis results indicate that U.S. wind power deployment through 2020 is sensitive to both the 

prospective PTC level and market conditions over time (Figure 3). Detailed discussions of the 

results for each individual scenario follow below. Implications from these results are considered 

in Sections 4–6. 

Figure 3. Projected average annual wind capacity deployed between 2013 and 2020 

for PTC extension scenarios

Note: High and low ends of the projected ranges are based on the ranges of assumed future natural gas prices (high 

and low, respectively) and electricity demand growth (high and low, respectively). While an average projected 

annual addition through 2020 is depicted, wind capacity additions may not be distributed uniformly across 

the period.

3.1.1 Current Policy/PTC Expiration

Modeling results indicate an average of approximately 3–5 GW per year of wind installations 

from 2013 to 2020 for the Current Policy/PTC Expiration scenario. Installations in this scenario 

are driven in part by remaining unfilled existing state RPS requirements and are comparable to 

other short-term industry estimates (also based on the absence of a new PTC extension)

(Bloomberg NEF 2013; MAKE 2013; Navigant 2013; IHS EER 2013). The relatively narrow 

band projected under this scenario indicates a general lack of sensitivity to changes in natural gas

prices and load growth in the absence of policy support. Discretionary factors (e.g., bilateral 

corporate contracts or utility green power pricing programs) could supplement this level of 

deployment; however, in the absence of new policy support, annual additions are projected to

remain well below the 8.7 GW per year achieved from 2008 to 2012. 

Historical Annual 

Average Deployment 

(2008 – 2012): 8.7 GW
12 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

3.1.2 Ramp-Down Scenarios

The near-term deployment implications of PTC ramp-down scenarios depend on the PTC level

trajectory over time. Modeling results indicate that the three ramp-down scenarios considered 

here (Ramp Down Low, Ramp Down Mid, Ramp Down High) could support average annual 

wind installations through 2020 of 3–4 GW under low gas price/low load growth conditions and 

6–8 GW under high gas price/high load growth conditions. 

Notably, only the Ramp Down High case appears capable of supporting average annual 

installations close to the 2008–2012 annual average of 8.7 GW; the Ramp Down Low scenario 

appears to provide only a small amount of incremental deployment beyond the PTC 

Expiration scenario. 

3.1.3 Constant 2020 Scenario

Modeling results indicate that extending the PTC at its current level through 2020 (Constant 

2020) could result in additions within the range of recent builds. The full range of projected 

average annual installations is 5–15 GW. At this level of support, even low gas prices and low 

load growth conditions could result in a 65% increase in installations beyond the Current 

Policy/PTC Expiration scenario. 

Given widespread historical reliance on third-party tax equity and the subsequent reduction in 

effective PTC value to project sponsors noted above, an additional Constant 2020 sensitivity was 

conducted assuming a one-third lower value for the PTC (i.e., modeling the PTC at an effective 

value of approximately $15/MWh as opposed to the $23/MWh full value achieved if a project 

sponsor were to have sufficient internal tax appetite to monetize the credit or if the credit were 

made refundable).12 Under these conditions the Constant 2020 range of projected average annual 

installations is reduced to 3–9 GW. 

3.2 Analysis Results Through 2030

The policy pathways described in Section 2 were modeled through the year 2030 to assess 

potential mid-term (2020 to 2030) deployment implications of the PTC extension scenarios 

considered here. As numerous market dynamics are at play, not all of which are represented in 

the modeling, and key model inputs—notably gas prices, load growth, and retirements—become 

increasingly uncertain over time, these results should be viewed as indicative only. 

Near-term PTC policy scenarios (those expiring by the end of 2022) have only modest impacts 

on mid-term cumulative wind deployment (Figure 4); cumulative deployment of wind power in 

the electric sector through 2030 is projected to be comparable for these extension scenarios

(roughly 90 GW or 7% of total generation for low sensitivity cases; 180 GW or 14% of 

generation for high sensitivity cases) and virtually the same as the Current Policy/PTC 

Expiration case. The provision of near-term policy support appears to effectively shift 

 

12 The actual impact of third-party tax equity on the effective value of the PTC is uncertain and varies depending on 

the explicit project financial structure. However, a one-third reduction has been suggested as a gross approximation. 

For additional detail, see Bloomberg NEF (2013) and Chadbourne & Park (2013).
13 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

deployment earlier in time.13 However, this conclusion assumes that global innovation and wind 

industry cost reductions proceed with or without U.S. deployment. If U.S. deployment is material 

to global wind industry innovation and a key driver of future cost reductions, policy scenarios 

that result in lower near-term deployment may not achieve the mid-term deployment levels 

presented below. In contrast to the near-term policy scenarios, the Constant 2030 scenario, where 

the historical support structure is maintained throughout the analysis period, results in greater 

deployment under both low and high sensitivity cases. 

 

Figure 4. Range of projected cumulative wind capacity deployed through 

2030 for PTC extension scenarios

 

13 Under the conditions assumed in this analysis, policy results in a temporary shift in wind supply making more 

wind power potential cost competitive. Following policy termination, a period of little deployment is observed due 

to an effective step-change in the cost of the next wind plant.
14 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

4 Implications for Domestic Manufacturing

U.S. wind power manufacturing production varies by component type. Among major turbine 

components in 2012, an estimated 7.4 GW of towers, 8.1 GW of blades, and 13.0 GW of 

nacelles were produced or assembled domestically (James and Goodrich 2013). In aggregate, 

these production levels generally align with annual average wind power capacity additions in the 

United States from 2008 to 2012. 

In the absence of U.S. domestic demand for new wind capacity, global markets are unlikely to

offer many opportunities for U.S.-based manufacturers. Trade flows of wind products are 

generally limited in the global industry due to relatively high shipping costs for major turbine 

components. As a result, foreign direct investment in regions with strong demand for wind 

products is common as the cost structure of the industry favors regional manufacturing hubs 

(Kirkegaard et al. 2009). In the United States, the factory gate prices for components like blades, 

which are labor-intensive to produce, also tend to be higher than the prices of the same goods 

manufactured in many other regions, further limiting export opportunities from U.S.-based 

facilities (James and Goodrich 2013). 

Given the limited export market, a reduction in domestic wind power deployment is likely to 

have a direct and negative effect on U.S.-based wind turbine manufacturing production and 

employment. This is notable as the manufacturing sector has been observed to represent a 

substantial share of wind industry jobs (Bloomberg NEF 2012; Lantz and Tegen 2008). In 

addition, reductions in demand can be expected to translate relatively rapidly into factory 

closures and job losses. The effects of reduced demand for 2013 equipment deliveries became 

evident as early as 2012 as year-over-year employment in wind manufacturing fell by nearly 

5,000 workers, and 12 facilities exited the U.S. wind market (Wiser and Bolinger 2013). 

Under some extension scenarios analyzed in this report, negative effects on U.S.-based wind 

manufacturers may be muted. The Constant extension scenarios could offer an opportunity to 

achieve deployment levels for a range of potential market conditions that align with both recent 

installation trends and domestic manufacturing production. Under relatively high gas prices and 

load growth, the Ramp Down High scenario can also enable current production levels to remain 

relatively constant through 2020. Projected deployment in the other PTC extension scenarios is 

likely to be insufficient to maintain domestic manufacturing at recent historical levels. 
15 

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5 Other Policy-Relevant Considerations

Results presented above suggest that when considering PTC extensions, an extension of current 

policy can provide an opportunity to maintain a rate of wind installations consistent with 

deployment observed from 2008 to 2012 for a range of potential market conditions. However, 

under nearly all conditions analyzed, a PTC that expires or ramps down prior to 2022 is unlikely 

to generate levels of wind deployment consistent with the 2008–2012 5-year average. 

At the same time, stable wind deployment is only one of many objectives that might be served by 

a PTC extension. Other factors, although not explored in this study, could also be considered as 

objectives and include: 

• Greater certainty for foreign and domestic investment in U.S. industry 

• Sustained conditions for continued technology innovation 

• Reduced electric sector greenhouse gas emissions, air pollution, and water use

• Greater diversity of electric generation sources 

• Reduced electric sector demand for natural gas, potentially enabling reduced pipeline 

congestion in critical regions, lower gas prices, or increased exports 

• Maintained or improved global competitiveness of U.S.-based manufacturing

• Maintained or reduced cost of generation as a key economic input to U.S. economic 

competitiveness. 

The contribution of a PTC extension to the achievement of the above objectives could also 

be assessed. 

In addition, the complexity associated with the use of a tax credit as the primary incentive for 

wind technology has some associated challenges. Chiefly, the PTC, in its current form, is widely 

recognized as costly to monetize due to lack of financial market fungibility and constraints to tax 

equity supply (Mendelsohn and Harper 2012; Bloomberg NEF 2013; Chadbourne & Park 2013). 

In contrast, a refundable form of the credit would obviate the need for project sponsors lacking 

tax appetite to rely on third-party tax equity, with its associated transaction costs. As such, this 

refundable form could result in a higher level of wind deployment for the same cost to the 

federal government. Alternative policies, such as opening public capital vehicles (e.g., master 

limited partnerships) to wind power technologies or federal carbon standards, also offer the 

opportunity to support wind deployment and provide associated manufacturing and installationrelated employment support at potentially lower total cost.

Finally, given the uncertainty associated with key variables (e.g., fossil fuel prices, load growth) 

in this analysis, if the policy objective is to maintain a minimum level of wind power deployment 

or to limit contraction of the existing wind industry, policymakers could also consider alternative 

policies that might provide greater certainty in future deployment levels. 
16 

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6 Conclusions

The high-level findings from this analysis are summarized as follows: 

• Under a scenario in which the PTC is not extended and all other policies remain 

unchanged, wind capacity additions are projected to be between 3 GW and 5 GW per 

year from 2013–2020. 

• U.S. wind power manufacturing production generally aligns with average annual wind 

power capacity additions from 2008 to 2012. In the absence of U.S. domestic demand for 

new wind capacity, global markets are unlikely to offer many opportunities for U.S.-

based manufacturers. Given the limited export market, a reduction in domestic wind 

power deployment is likely to have a direct and negative effect on U.S.-based wind 

turbine manufacturing production and employment.

• Modeled PTC extension options that ramp down and cease support by year-end 2022 

appear to be generally insufficient to support deployment close to recent levels and 

therefore may be insufficient to sustain the current industry domestic manufacturing and 

supply chain through 2020. 

• Of the scenarios considered, an extension of the PTC at its historical level could provide 

the best opportunity to support deployment consistent with recent levels across a range of 

market conditions; it therefore could also provide the best opportunity to sustain the 

existing wind installation and manufacturing base at its current level.

• In the current low-priced natural gas regime, modeling results indicate that future wind 

deployment will be relatively low unless additional incentives are provided that result in 

wind being cost competitive with existing gas-fired generation. 

• Future uncertainty in key modeling variables, including gas prices and load growth, 

translates into high levels of uncertainty in the deployment outcomes of specific 

extension scenarios. 

This work provides insight into wind deployment under current policy and various PTC 

extension scenarios. One possible next step would be to estimate the federal government revenue 

impacts associated with these scenarios. This might entail evaluation of tax expenditures but 

could also look more comprehensively at net revenue impacts also accounting for changes in tax 

receipts. Future work could also consider how other policy mechanisms affect U.S. wind 

deployment or further consider how changes in deployment could affect domestic wind industry 

manufacturing. Exploring the role of U.S. wind deployment in driving global wind technology 

and manufacturing innovations, along with associated future cost reductions, can also provide 

critical insights into the interaction of policy and future U.S. wind deployment. 
17 

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20 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix A: Additional Information on Model Inputs

and Assumptions

Wind Costs

Supply curves for wind technology, which reflect wind cost as a function of available resource,

are developed from current and projected wind technology cost and performance. This analysis

assumes a 2012 LCOE (excluding the PTC) of approximately $61/MWh for projects sited in 

median resource conditions (based on 2011 and 2012 installations). The overall range in 2012 

LCOE varies from approximately $55/MWh to $91/MWh, depending on resource quality. 

Cost projections apply the median case cost reduction trajectory shown in Figure A-1 and are 

based on a literature review reported by Lantz et al. (2012). The median cost reduction trajectory 

results in a 15% reduction in LCOE by 2020 and achieves an approximately 20% reduction 

by 2025. 

Year

Figure A-1. Projected wind levelized cost per industry literature review

Source: Lantz et al. (2012)

Natural Gas Prices 

Supply curves for gas-fired technologies in the ReEDS model are developed using natural gas 

price trajectories from the High and Low Oil and Gas Resource cases reported in the AEO (EIA 

2013b). Input gas prices from both cases are shown in the Table A-1. These natural gas price 

trajectories are the inputs to the Low and High Wind Deployment sets of scenarios, respectively. 

$35

$40

$45

$50

$55

$60

$65

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

2012 $/MWh

Min Cost 

Reduction

75th Percentile

Median

25th Percentile

Max Cost 

Reduction
21 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table A-1. Input Electric-Sector Delivered Natural Gas Prices (2013$/MMBtu)

Year AEO 2013 High Oil & 

Gas Resource

AEO 2013 Low Oil & Gas 

Resource

2013 $3.68 $4.10

2014 $3.49 $4.25

2015 $3.38 $4.40

2016 $3.59 $5.02

2017 $3.56 $5.37

2018 $3.63 $5.73

2019 $3.65 $6.06

2020 $3.66 $6.29

2021 $3.70 $6.53

2022 $3.75 $6.76

2023 $3.80 $6.92

2024 $3.86 $7.06

2025 $3.93 $7.22

2026 $3.95 $7.48

2027 $3.99 $7.61

2028 $4.01 $7.78

2029 $4.03 $7.86

2030 $4.15 $7.87

Source: EIA (2013b)

Gas prices driving dispatch of the existing fleet and factoring into new build decisions are 

subsequently calculated endogenously in the model and are responsive to changes in modeled

electric sector demand for natural gas. Calculated natural gas prices applied in the ReEDS 

modeling completed in this analysis are shown in Tables A-2 and A-3. 

Table A-2. Model-Calculated Electric-Sector Delivered Natural Gas

Prices (2013$/MMBtu)—Low Wind Deployment Set of Scenarios

Low Wind Deployment

Year

Current 

Policy/ 

PTC 

Expiration

Ramp 

Down 

Low

Ramp 

Down 

High

Ramp 

Down 

Mid

Constant 

2020

Constant 

2030

2012 $3.71 $3.71 $3.71 $3.71 $3.71 $3.71

2014 $3.51 $3.48 $3.51 $3.51 $3.51 $3.51

2016 $3.28 $3.21 $3.28 $3.28 $3.27 $3.27

2018 $3.18 $3.14 $3.18 $3.18 $3.18 $3.18

2020 $3.10 $3.06 $3.10 $3.10 $3.10 $3.10

2022 $3.21 $3.17 $3.19 $3.20 $3.11 $3.06

2024 $3.21 $3.17 $3.19 $3.20 $3.15 $3.11

2026 $3.26 $3.23 $3.26 $3.26 $3.21 $3.17

2028 $3.24 $3.19 $3.23 $3.24 $3.22 $3.17

2030 $3.27 $3.23 $3.26 $3.27 $3.25 $3.20

Source: EIA (2013b) and NREL
22 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table A-3. Model-Calculated Electric-Sector Delivered Natural Gas Prices (2013$/MMBtu)—High

Wind Deployment Set of Scenarios

High Wind Deployment

Year

Current 

Policy/ 

PTC 

Expiration

Ramp 

Down 

Low

Ramp 

Down 

High

Ramp 

Down 

Mid

Constant 

2020

Constant 

2030

2012 $3.71 $3.71 $3.71 $3.71 $3.71 $3.71

2014 $4.20 $4.20 $4.20 $4.20 $4.20 $4.18

2016 $4.77 $4.77 $4.76 $4.77 $4.68 $4.64

2018 $5.69 $5.65 $5.56 $5.63 $5.36 $5.33

2020 $6.37 $6.28 $6.17 $6.24 $5.74 $5.71

2022 $6.85 $6.83 $6.66 $6.82 $6.34 $6.09

2024 $7.14 $7.15 $7.07 $7.15 $6.77 $6.35

2026 $7.51 $7.52 $7.51 $7.52 $7.26 $6.72

2028 $7.78 $7.79 $7.78 $7.78 $7.63 $6.99

2030 $7.98 $7.95 $7.97 $7.96 $7.87 $7.32

Source: EIA (2013b) and NREL

In general, scenarios resulting in higher levels of wind deployment result in lower natural gas 

consumption in the electric sector; this reduction in the overall demand for gas contributes to 

lower relative gas prices.

Load Growth 

High and low electricity load growth estimates are derived from the AEO High and Low 

Economic Growth cases (EIA 2013b). Detailed information on those cases is shown in Table A4 and Figure A-2. 

Table A-4. AEO 2013 Electricity Load Growth—Low and High Economic Growth Cases

Average Annual Load Growth 

2013 -

2020

2021-

2030

2013-

2030

AEO 2013 Low Economic 

Growth 0.4% 0.5% 0.5%

AEO 2013 High Economic 

Growth 1.2% 1.0% 1.1%
23 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure A-2. Projected electricity load growth from AEO 2013 assumed in 

this analysis

Source: EIA (2013b)

Note: Demand axis (y-axis) does not begin at zero.

4,289 

4,755 

3,995 

4,200 

 3,800

 3,900

 4,000

 4,100

 4,200

 4,300

 4,400

 4,500

 4,600

 4,700

 4,800

National Electricity Demand 

[Terawatthours]

AEO 2013 High Economic Growth AEO 2013 Low Economic Growth