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Contract No. DE-AC36-08GO28308

Wind Power Project 

Repowering: Financial 

Feasibility, Decision Drivers, 

and Supply Chain Effects

Eric Lantz, Michael Leventhal, 

and Ian Baring-Gould

Technical Report

NREL/TP-6A20-60535

December 2013
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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

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303-275-3000 • www.nrel.gov

Wind Power Project 

Repowering: Financial 

Feasibility, Decision Drivers, 

and Supply Chain Effects

Eric Lantz, Michael Leventhal, 

and Ian Baring-Gould 

Prepared under Task No. WE11.0630

Technical Report

NREL/TP-6A20-60535

December 2013
NOTICE

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

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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.
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Acknowledgments

This report was funded by the U.S. Department of Energy’s (DOE) Wind and Water Power 

Technologies Office in accordance with the National Renewable Energy Laboratory’s (NREL) 

Annual Operating Plan, Subtask WE 6.1.3 Wind Turbine Repowering and Recycling 

Assessments, Project 21115, Agreement 24944. The authors thank Cash Fitzpatrick and Jose 

Zayas of DOE’s Wind and Water Power Technologies Office for supporting this research. 

The authors would also like to thank Charles Newcomb (Endurance Wind Power), Mark 

Jacobson (NREL), Neil Habig (Iberdrola Renewables), and Randy Mann (Edison Mission 

Energy) for their reviews and comments on early versions of this manuscript. Any remaining 

errors or omissions are the sole responsibility of the authors.
iv

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List of Acronyms and Abbreviations

BWE Bundesverband WindEnergie (German Wind 

Energy Association)

DOE U.S. Department of Energy

GW gigawatt

IEC International Electrotechnical Commission

kW kilowatt

m meter

MW megawatt

MWh megawatt-hour

NPV net present value

NREL National Renewable Energy Laboratory

O&M operation and maintenance

PPA power purchase agreement

PTC production tax credit

SAM System Advisor Model
v

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Executive Summary

As wind power facilities age, project owners are faced with plant end-of-life decisions. This 

report is intended to inform policymakers and the business community regarding the history, 

opportunities, and challenges associated with plant end of life actions, in particular, repowering. 

Specifically, the report details the history of repowering, examines the plant age at which 

repowering becomes financially attractive, and estimates the incremental market investment and 

supply chain demand that might result from future U.S. repowering activities. 

Repowering as defined here includes two types of actions. Full repowering refers to the complete 

dismantling and replacement of turbine equipment at an existing project site. Partial repowering 

is defined as installing a new drivetrain and rotor on an existing tower and foundation. Partial 

repowering allows existing wind power projects to be updated with equipment that increases 

energy production, reduces machine loads, increases grid service capabilities, and improves 

project reliability at lower cost and with reduced permitting barriers relative to full repowering 

and greenfield projects. 

Repowering first emerged in the early 1990s in the California and Danish wind power markets 

and was followed by the Dutch and German markets in the 1990s and 2000s. Although 

repowering activity has occurred elsewhere, these locales remain the principal markets for 

repowering investments. Historically, repowering has been viewed as a means of increasing 

project productivity while offering an array of other potential attributes of interest.

Fundamentally, however, profitability for a given project is the primary driver of repowering 

decisions. Given limited financing, the anticipated profitability at alternate greenfield sites is 

also relevant. 

Two distinct analyses were conducted to understand the plant age when repowering becomes 

viable. These analyses utilized NREL’s System Advisor Model (SAM), a tool that enables the 

user to predict estimated cash flows from a variety of electric power generation technologies. Net 

present value calculations were utilized to enable comparisons across time.

The first analysis involved creating “proto-typical” wind plants of four different vintages, with 

commissioning years of 1999, 2003, 2008, and 2012. Proto-typical plants are representative of 

the industry at the time of their construction and rely on market data from each of the 

commissioning years to derive installation and equipment costs, power purchase agreement 

revenue, net capacity factor, receipt of federal production tax credit payments, and operation and 

maintenance expenses. For each of these four plants, future investment decisions to repower, or 

build a nearby greenfield site, were evaluated for 2015, 2020, 2025, and 2030.

The second analysis focused on three actual wind plants operating in the United States. These 

plants were chosen for varying vintages and geographical diversity and include a Northeast wind 

plant (15–20 years old), a Midwest wind plant (10–15 years old), and a West Coast wind plant 

(20–25 years old). For these three plants, the decision to repower the current site or invest in a 

nearby greenfield site was assumed to occur in the 2012–2013 timeframe. Estimated costs to 

repower, expected revenue, and operational statistics were acquired from nearby sites that were 

recently placed in service or are in active development.
vi

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Both financial analyses concluded that repowering tends to become financially attractive, relative 

to investing in a nearby greenfield site, after approximately 20–25 years of service. Plants less 

than 20 years old are expected to be capable of generating a favorable revenue stream for several 

more years. However, there are a number of critical variables that could alter both the timing and 

attractiveness of repowering. These variables include the rate of technological advancement, 

availability of quality wind resource sites, wholesale market prices for electricity, durability and 

reliability of turbine equipment over time, and the extent to which owners are able to reuse 

existing infrastructure in the future.

A single partial repowering scenario—replacement of only the turbine drivetrain and rotor—was 

also examined. As defined here, partial repowering was estimated to reduce the cost of 

repowering by about 10%, while achieving about 50% of the energy production improvements 

associated with full repowering. Under these conditions, partial repowering was determined to be 

less economically attractive than full repowering. It should be noted however, that partial 

repowering can take many forms. If other concepts for partial repowering can be developed and

offer reduced operation and maintenance costs or increased energy production at substantially 

lower costs than full repowering, such opportunities may well be financially sound.

Assuming a plant life of 20–25 years, demand for repowering is expected to be low over the next 

decade, reach a few hundred megawatts per year in the early 2020s, and achieve 1–3 gigawatts

per year by the late 2020s. Total estimated value of the repowering market segment is estimated 

at $25 billion through 2030 (constant 2012 U.S. dollars) with the vast majority of this investment 

occurring in the latter half of the 2020s. Policy support in the form of financial incentives, as 

well as solutions to potential regulatory and contractual hurdles, would likely be necessary if an 

acceleration of repowering investment were desired.
vii

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Table of Contents

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

1.1 History and Status ......................................................................................................................... 1

1.2 Critical Variables Influencing Trends........................................................................................... 3

2 General Economic and Financial Feasibility ..................................................................................... 5

2.1 Methods......................................................................................................................................... 5

2.2 Results........................................................................................................................................... 9

3 Case Study Analysis .......................................................................................................................... 15

3.1 Methods....................................................................................................................................... 15

3.2 Results......................................................................................................................................... 17

4 Market Opportunity ............................................................................................................................ 19

4.1 Methods....................................................................................................................................... 19

4.2 Results......................................................................................................................................... 19

5 Supply Chain Impacts ........................................................................................................................ 21

5.1 Methods....................................................................................................................................... 21

5.2 Results......................................................................................................................................... 21

6 Policy and Other Relevant Considerations...................................................................................... 24

7 Summary and Conclusions ............................................................................................................... 25

References................................................................................................................................................. 27

Appendix A: Interview Guide for Wind Owner Operators..................................................................... 29
viii

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List of Figures

Figure 1. Value added to a 1999 wind plant as a result of investing in a new greenfield or 

full repowering ........................................................................................................................... 10

Figure 2. Value added to a 2003 wind plant as a result of investing in a new greenfield or 

full repowering ........................................................................................................................... 11

Figure 3. Value added or lost as a result of investing in a new greenfield or full repowering for a 2008 

wind power plant ........................................................................................................................ 12

Figure 4. Value added or lost as a result of investing in a new greenfield or full repowering for a 2012 

wind power plant ........................................................................................................................ 13

Figure 5. Value added to a 2003 wind plant as a result of investing in a new greenfield, full repowering, 

or partial repowering in 2025 ..................................................................................................... 14

Figure 6. Value added to each case study wind plant as a result of investing in a new greenfield or full 

repowering.................................................................................................................................. 18

Figure 7. Estimated annual capacity repowered by year............................................................................. 20

Figure 8. Estimated turbine demand by nameplate capacity resulting from potential repowering

activity.................................................................................................................................... 21

Figure 9. Estimated blade demand by length (meters) resulting from potential repowering activity......... 22

Figure 10. Estimated tower demand by height (meters) resulting from potential repowering activity ...... 23

List of Tables

Table 1. Key Capacity-Weighted Average Turbine Parameters for Technology Considered for 

Repowering in This Analysis......................................................................................................... 5

Table 2. Summary of Financial Modeling Inputs for Existing and Future Facilities by Year of Project 

Commissioninga ............................................................................................................................. 7

Table 3. Financial Modeling Constants Across Scenarios............................................................................ 9

Table 4. Key Characteristics and Assumptions for the Three Case Study Wind Plants............................. 16

Table 5. Financial Modeling Constants Across Case Study Scenarios....................................................... 17
1

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1 Introduction

As wind power facilities age, project owners are faced with plant end-of-life decisions. In many 

cases, technological advancement suggests that project owners might be able to increase their 

profits by refurbishing or replacing older equipment. However, end of life decisions are often far 

from straightforward. Older facilities are typically fully depreciated and paid for, leaving any 

remaining revenues after operation expenditures essentially as profit. In addition, the potential 

for new contractual or regulatory terms when making substantial alterations at an existing site

can also present hurdles. This report is intended to inform policymakers and the business 

community regarding the history, opportunities, and challenges associated with plant end of life 

actions, in particular repowering.

Repowering as defined in this report entails two types of actions. Full repowering refers to the 

complete dismantling and replacement of turbine equipment at an existing project site, including 

the tower and foundation. With full repowering, some of the existing project infrastructure (e.g., 

roads, buildings, and interconnection equipment) is assumed to be utilized in the new project. 

There is also the potential to offset repowering costs by recycling or selling the older equipment. 

Partial repowering is defined as installing a new drivetrain and rotor on an existing tower (with 

an allowance for some structural tower modifications); some peripheral components, such as the 

power convertors and electronics, may also be replaced. Partial repowering allows existing wind 

power projects to be updated with equipment that increases energy production, reduces machine 

loads, increases grid service capabilities, and improves project reliability. Performance 

improvements associated with partial repowering are assumed to be lesser than under full 

repowering but greater than the original design of the machine.

The remainder of Section 1 entails a brief history of global wind plant repowering activities and 

trends, and summarizes the findings that have emerged from past research. In Section 2 and 

Section 3 financial analyses are conducted that examine the economic drivers of repowering with 

historical and projected cost and performance estimates and case studies. Estimates are carried 

out to better understand the expected lifetime of U.S. wind power plants. In Section 4 and 

Section 5, these results are used to derive estimates of the total repowering market and 

equipment demand resulting from repowering activities. Section 6 discusses policy 

considerations and other relevant decision drivers around repowering. The report concludes with 

a summary of key results and takeaways.

1.1 History and Status

Repowering first emerged in the early 1990s in the California and Danish wind power markets 

and was followed by the Dutch and German markets in the 1990s and 2000s (White and Gipe

1993; Knight 2004; Hulshorst 2008; Munksgaard and Morthorst 2008). There has also been 

interest in repowering in India and other parts of the world (e.g., Kharul 2008; Goyal 2010; 

GlobalData 2012; Filgueira et al. 2009). Based on the data reviewed, Denmark and Germany

have generally been the most active repowering markets, followed by California.

Denmark was the first country to actively promote repowering (Wiser 2007; Sperling et al.

2010). Public policy support for repowering was first instituted there in 1994 (Sperling et al. 

2010). In 2001, policy support was adjusted to provide an additional premium on top of the 

standard feed-in tariff for repowered projects that previously used turbines smaller than 100 
2

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kilowatts (kW) (Sperling et al. 2010; Wiser 2007). Additional incentives beyond the standard 

feed-in tariff remain in place for repowered projects that previously used turbines smaller than 

450 kW (Sperling et al. 2010). Under the policy scheme in place from 2001 through 2003, it has

been estimated that 1,208 turbines were replaced, resulting in an increase in capacity of 202 

megawatts (MW) (Sperling et al. 2010). The stated goal under the policy scheme in place since 

2004 (although modified in 2008) is for an additional 175 MW of existing capacity to be 

replaced by 350 MW of new capacity (Sperling et al. 2010). At least one source indicates that 

Denmark was the largest repowering market in 2011 with an estimated 213 MW of repowered

wind generation (GlobalData 2012). 

Suggested barriers to repowering in Denmark have been anecdotally observed to be greater 

capital requirements of modern wind power projects and shifting ownership models from 

community-based local ownership to larger corporate or utility players. Wiser (2007) also 

suggests that, similar to California, industry stakeholders see relatively limited economic 

incentive to replace a project that continues to operate and generate revenue.

Germany has been estimated to have the largest market potential for repowering, estimated at 

nearly 6,000 MW by 2015 (BWE 2011). However, in spite of more favorable treatment than 

greenfield projects due to the country’s feed-in tariff laws, which incentivize repowering, 

repowering activities to date have still been limited (Wiser 2007; BWE 2008; BWE 2011). 

Through 2005, an estimated 59 MW of wind turbines were removed from service and replaced 

by 169 MW of new capacity (Wiser 2007). Since then, repowering activities have continued but 

remain modest. The German Wind Energy Association (BWE) reports (BWE 2008; BWE 2011) 

that in 2007, an additional 108 turbines (41 MW) were replaced with 45 new turbines (203 MW).

In 2010, 183 MW of new equipment were installed at previously developed sites; in 2011, 170 

turbines (123 MW) were replaced by 95 turbines (238 MW) (GlobalData 2012). The above 

annual repowering statistics represent a relatively small share of the potential installations that 

could be repowered in Germany (BWE 2008), and under the current energy policies, repowering 

appears not to be profitable until an installation has been operating for at least 15 years 

(Knight 2004). 

Repowering in Germany has been limited by local hub and total turbine height restrictions as 

well as requirements for setbacks from existing residential areas (Wiser 2007). In addition, the 

BWE has noted that the existing incentives for wind power are insufficient to drive large-scale 

shifts in the repowering market in Germany (BWE 2008).

Despite its status as a pioneer in the repowering space, California has struggled to develop a 

robust repowering market due to a variety of policy and regulatory challenges. White and Gipe

(1993) observed that repowering was likely affected by the contractual requirements negotiated 

in the original sales agreements under the Public Utility Regulatory Policy Act standard offer 

contracts of the 1980s. Stipulations around the federal production tax credit (PTC) also 

apparently stifled repowering efforts in California (Wiser 2007; Wiser et al. 2008).1 Under all but 

the most conservative assumptions, prior analysis suggests that there is little economic incentive 

 1 The literature occasionally refers to the “California Fix,” whereby projects are ineligible for the PTC if after 

repowering they remain on their existing standard offer contract entered into prior to 1987.
3

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for functioning California projects to pursue repowering (Wiser et al. 2008).2 Through 2007, it 

was estimated that 365 MW of capacity had been repowered in California (Wiser et al. 2008) 

with more than 70% of that occurring before 1999 (Wiser 2007). Total repowered capacity 

through 2007 was equivalent to about 20% of the installed wind power capacity in the state in 

1994, further suggesting that significant technical potential for repowering in the California 

market remains (Wiser et al. 2008).

Other repowering activities have been observed in a limited number of cases in the Netherlands 

and India (e.g., Grontmij; RWE Innogy; Ramesh), and analysis of the potential economics of 

repowering has been conducted in Spain (Filgueira et al. 2009). However, repowering activities 

in these countries have not been widespread. 

Repowering efforts have overwhelmingly resulted in full turbine replacements as opposed to 

partial repowering (White and Gipe 1993; Knight 2004; Fairley 2009; Wiser et al. 2008; 

Ramesh; RWE Innogy; Grontmij).3 This is a result of the rate at which wind power technology 

has improved. Even if existing equipment were refurbished, new turbines are often capable of 

generating much more energy than the existing equipment (Filgueira et al. 2009; Knight 2004). 

Moreover, the replacement of smaller turbines could allow some increase in the potential 

generating capacity from a given land area; as a result, countries with relatively few high-value 

wind resource sites are likely to prefer full repowering at these sites when wind power- or 

climate-related policy provisions are under consideration. 

The literature has indicated two solutions for equipment removed from an existing site. 

California projects repowered in the early 1990s were largely forced to scrap the existing 

equipment due to dramatic improvements in technology (White and Gipe 1993; Knight 2004). 

Repowering efforts in the early 2000s in Europe (for projects using equipment that was 

approximately 10 years old) were more successful in their attempts to refurbish and sell the 

dismantled turbine equipment into emerging markets in eastern Europe and other parts of the 

world (Knight 2004). 

1.2 Critical Variables Influencing Trends

Historically, repowering has been viewed as a possible means of increasing project productivity, 

improving grid support and grid interactions, extending the use of existing infrastructure 

investments, more efficiently utilizing high-value resource areas, and in some cases (e.g., single 

turbines or a single linear array), enabling greater installed capacity in a given land area (White 

and Gipe 1993; Kharul 2008; Hulshorst 2008; Fairley 2009; Filgueira et al. 2009; Wiser et al.

2008). Repowering has also been cited as a means of reducing the visual impact or clutter of 

wind power projects because for a given capacity rating, it reduces the number of turbines in a 

specific location (Knight 2004; Wiser et al. 2008; Filgueira et al. 2009; Meyerhoff et al. 2010). 

At the same time, it has been observed to potentially increase visual and aesthetic impacts by 

introducing new machines that are significantly larger and taller than their predecessors 

(Meyerhoff et al. 2010; Sperling et al. 2010). Repowering is generally anticipated to reduce 

 2 Presently, no data are available detailing functioning versus nonfunctioning wind power plants in California. 3 It should be noted, however, that partial repowering can in fact take many forms. It is feasible that more basic 

turbine upgrades incorporated through power electronics or other means could occur with much greater frequency 

than forms of partial repowering that involve more extensive overhaul and replacement of turbine components.
4

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operation and maintenance (O&M) costs by deploying newer, more reliable equipment and by 

reducing the number of moving parts when moving to larger turbines (White and Gipe 1993; 

European Wind Energy Association 2009).4 Repowering has also been noted to offer the 

possibility of reduced avian and wildlife impacts, at least for some species. However, broadbased data on the empirical change in impacts before and after repowering are not available,

making it difficult to confirm this potential characteristic of repowered facilities (Wiser et al. 

2008; Hotker 2006; Smallwood and Neher 2010).

Fundamentally, however, profitability for a given project is the primary driver of repowering 

decisions. Given limited financing, the anticipated profitability at alternate greenfield sites is also 

relevant. One’s ability to extend, amend, or re-enter power purchase agreements (PPAs) with a 

creditworthy off-taker and to secure potential additional sources of revenue such as renewable

energy certificates is another factor. These themes are consistent throughout markets for wind 

power around the globe.

Detailed financial modeling conducted by Wiser et al. (2008) suggests that the profitability of 

repowering is highly dependent on project-specific performance and annual operation

expenditures. Wiser et al. (2008) also found that older projects can be expected to continue to 

operate profitably for many years, as long as the projects continue to function within a 

reasonable range of performance and are able to avoid dramatic upticks in annual operation

expenditures. They conclude that in the absence of additional financial incentives, it is often in 

the project owner’s interest to continue to produce power at an existing facility rather than to 

repower. Experience from Germany confirms this finding (Knight 2004). 

 4 The parts counts of modern turbines relative to their predecessors are generally comparable; however, by reducing 

the number of machines required to achieve a specific rated capacity, one can reduce plant-wide moving parts by 

simply installing fewer turbines that are far greater in their rated capacity than the original equipment.
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2 General Economic and Financial Feasibility

An initial assessment of the economics of repowering was developed from aggregate U.S. wind 

industry data. This analysis extends and updates prior work by Wiser et al. (2008), which 

focused on the California market. Although this approach does not capture the complete array of 

local and regional variabilities among projects, it provides a basic level of visibility—from the 

project owner’s perspective—regarding the point at which repowering might be considered an 

attractive investment opportunity.

2.1 Methods

Repowering opportunities are examined through 2030 for existing plants. The analyses consider 

both full and partial repowering. The analyses presume capital is available to invest in wind 

infrastructure. Repowering is analyzed as a potential investment opportunity relative to 

developing a new adjacent greenfield. If neither of these options results in added value to the 

project owner, it is assumed the owner will simply maintain the existing plant and invest 

available capital in other opportunities. 

Adjacent greenfields were chosen as the point of reference for alternative wind power investment 

opportunities based on anecdotal evidence and feedback from industry obtained through semistructured interviews. These data sources indicated that new greenfield opportunities in 

proximate or adjacent locations to older facilities do exist. This suggests that the comparison to 

an adjacent greenfield is a realistic tradeoff considered by the development community. This 

approach also simplifies the analysis by eliminating the need to estimate wind resource 

conditions for the “typical” greenfield project at future points in time. It should be noted,

however, that the ability to place a new greenfield in an adjacent site with essentially the same 

wind resource as the existing facility increases the attractiveness of the greenfield relative 

to repowering.

To understand how repowering opportunities might vary as technology and the industry have 

evolved, repowering is examined independently for plants commissioned at four points in the 

past: 1999, 2003, 2008, and 2012. Table 1 details the assumed plant parameters for projects 

completed in each of these years. Plant costs and performance are based on historical industry 

data (Table 2 and Table 3) reported by Wiser and Bolinger (2012). By emphasizing aggregate 

industry data, the analysis is representative of facilities commissioned in each of the respective 

years but not necessarily indicative any single plant’s characteristics.

Table 1. Key Capacity-Weighted Average Turbine Parameters for 

Technology Considered for Repowering in This Analysis

Year

Commissioned

Turbine Rating

(MW)

Hub Height

(m)

Rotor Diameter

(m)

1999 0.7 56 48

2003 1.2 66 64

2008 1.7 79 79

2012 2.1 85 95
6

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Full repowering is considered as a possibility for each of the existing plants at four points in the 

future: 2015, 2020, 2025, and 2030. In addition, for 2003-commissioned plants, the potential for 

partial repowering is also considered. Partial repowering is examined explicitly for this 2003 

plant because of its relatively modern technology compared with 1999 plants (Table 1), and 

unlike plants commissioned later (e.g., 2008 and 2012), it was determined to be a viable 

candidate for full repowering within the time period considered in this analysis. For the 2003 

facility, partial repowering is analyzed for 2025, the year in which full repowering becomes the 

preferred investment relative to an adjacent greenfield. 

In order to analyze the viability of repowering, conceptual projects with specific cost and 

performance characteristics were evaluated and defined (for full repowering and new greenfield 

projects) at each of the prescribed future investment dates (2015, 2020, 2025, and 2030). Partial 

repowering costs and performance were estimated for 2025 (Table 2). Future plant costs, 

performance, and estimated PPA prices are based on historical trends, National Renewable 

Energy Laboratory (NREL) technological advancement projections detailed in Chapman et al. 

(2012), and semi-structured interviews with plant owners. Defining future technology cost and 

performance is critical, as repowering decisions are functions of current plant performance and 

the value added by investing in new state-of-the-art technology. Key financial modeling inputs 

are summarized in Table 3.
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Table 2. Summary of Financial Modeling Inputs for Existing and Future Facilities by Year of Project Commissioninga

Plant

Commission

Date

Installed Capital Cost Net Capacity Factorb PPA Pricec

Operations 

Expenditures

(Year 1)

Greenfield

2012 $/kW

Repower

2012 

$/kW

Partial 

Repower

2012 $/kW

Greenfield Repower Partial 

Repower

2012 

$/MWh

PTC

Available

Fixed

2012 

$/kW-yr

Variable

2012 

$/MWh

1999 1,672 28.1% 50 Yes 12.5 10.2

2003 1,402 29.8% 35 Yes 12.5 8.2

2008 1,998 33.7% 57 Yes 12.5 6.1

2012 1,890 35.6% 52 Yes 12.5 6.1

2015 1,862 1,769 41.0% 41.0% 63 No 12.5 6.1

2020 1,816 1,725 42.0% 42.0% 57 No 12.5 6.1

2025 1,770 1,681 1,504 43.0% 43.0% 37.2% 53 No 12.5 6.1

2030 1,712 1,626 43.0% 43.0% 51 No 12.5 6.1

a Historical data are derived from Wiser and Bolinger (2012); future data are derived from NREL cost projection analyses (e.g., Chapman et al. 2012; U.S. 

Department of Energy 2008), current industry trends, and semi-structured interviews with owner operators.

b Future net capacity factors are equivalent for greenfield and repowering developments, as the analysis assumes a proximate or adjacent facility in a comparable 

wind resource area; the apparent discontinuity between 2012 and 2015 is the result of recent technology advancements that have brought larger rotor and taller 

tower machines to the market. Historical data are intended to reflect the performance of plants installed in a specific year.

c The historical PPA prices shown in this table are reported contract values (Bolinger 2013). As a result, the PTC should be considered as an additional revenue 

stream above and beyond that reported here. This analysis assumes a one-year delay between PPA contract execution date and project commissioning.
8

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National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Underlying data sources, trends, and justifications for the project cost, performance, and revenue 

characteristics summarized in Table 2 are described in greater detail here:

• Installed capital cost: Costs declined from 1999 to 2003 but then increased 2004–2010 

(Wiser and Bolinger 2012). Today, however, costs have once again begun to decline with 

projects in development anticipated to have 20%–30% lower installed costs than during 

2009 and 2010 (Wiser et al. 2012). Future assumptions include a continual, but slower, 

decline in installed costs in line with other independent projections in the literature (Lantz

et al. 2012; Chapman et al. 2012).

Fully repowered plants are assumed to have slightly lower (5%) total installed capital 

costs as a result of the ability to reuse or repurpose existing plant infrastructure noted 

above. Although actual savings will vary from project to project, semi-structured 

interviews completed as part of this effort and the literature reviewed above suggest a 5% 

cost savings is feasible. Partial repowering is estimated to result in an approximately 15% 

cost savings as a result of reusing existing infrastructure as well as cost savings on towers 

and foundations.

• Net capacity factor: Historical net capacity factors were estimated for plants 

commissioned in a specific year and grounded in historical averages reported by Wiser 

and Bolinger (2012). However, larger rotors and taller towers, along with other 

technological advancements, have resulted in significant increases in net capacity factors 

for utility-scale wind plants over the past 13 years (Lantz et al. 2012). Changes are 

particularly evident when examined across fixed wind resource areas with an emphasis 

on performance resulting from the latest turbine models rather than fleet-wide data 

(Wiser et al. 2012). Future installations assume net capacity factor improvements as a 

result of increased turbine optimization for a given site as well as continued incremental 

technology improvements. 

Both repowered and new adjacent greenfield facilities are anticipated to bring about 

substantial (Wiser et al. 2012; Chapman et al. 2012) and equivalent improvements in net 

capacity factor. The latter is assumed as a result of comparing repowered facilities with 

adjacent greenfields where a comparable wind resource is likely. Partial repowering is 

assumed to achieve approximately 50% of the anticipated energy production 

improvement at a given site that results from full repowering. Energy production gains 

from partial repowering are assumed to be limited by the original assets that continue to 

be used (e.g., the tower and foundation).

• PPA prices: Existing plant revenues are approximated from historically bundled

(renewable energy certificates and electricity) PPA price data reported by Bolinger 

(2013) and assume the PTC is utilized. Future project revenues assume current federal 

policy (PTC expiration at year-end 2013) and PPA pricing estimates that are aligned with 

wind power levelized cost of energy projections (Lantz et al. 2012). PPA escalation is 

estimated to increase about 1% (nominally) per year (Bolinger 2013). The PPA escalation 

rate is based on a composite mix of PPA contracts that escalate in line with inflation and 

others that have no stated escalation rate.
9

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at www.nrel.gov/publications.

• Operations expenditures: Historical data (Wiser and Bolinger 2012) indicate that 

variable O&M costs have dropped over the past 13 years. Analyses conducted here 

assume year one total operation expenditures have fallen in the past but are constant into 

the future (Houston 2013). As facilities age, total operation expenditures are assumed to 

escalate at 2% above inflation (a 4.5% nominal escalation rate).

5 Operating costs are 

considered to be equivalent for new greenfield and repowered facilities (both full 

and partial).

Table 3. Financial Modeling Constants Across Scenarios

Inflation 2.5%

Discount rate (nominal) 9%

Cost of financing (nominal) 9%

PPA escalation rate (nominal) 1%

O&M escalation rate (nominal) 4.5%

Data Sources: Wiser et al. (2012), Bolinger (2013), Tegen et al. (2012), and the Bureau of Labor Statistics (2012)

The evaluation of investment options is based on a comparison of the net present value (NPV) of 

future after-tax cash flow. Specifically, the change in projected NPV for repowered facilities is 

compared with the change in projected NPV from future cash flows of an existing facility plus 

the NPV from a new adjacent greenfield plant. This comparison is appropriate because a 

greenfield investment decision allows the existing plant to continue generating revenue, while 

repowering replaces the existing plant’s revenue stream with an alternate one (the repowered 

revenue stream). After-tax cash flows are included in the NPV as long as they remain positive or 

until 30 years of operation.

6 Potential positive cash flows estimated after 30 years of operation

are not considered for any projects (existing, repowered, or greenfield) as a result of potential 

step functions for operating costs that are not captured by applying a generic operating expense

escalation rate (Table 3).

NREL’s System Advisor Model (SAM) was used to calculate expected future cash flow. Post 

analysis processing of these data allowed calculation of the NPV for a project’s remaining cash 

flow and development of a uniform comparison in 2012 dollars for each of the potential future 

investment points. 

2.2 Results

The data presented here represent the change in estimated NPV (2012 dollars) of after-tax cash

flow resulting from the addition of a greenfield plant (i.e., the combined cash flows of the 

existing plant and the new adjacent greenfield) or repowering of each representative historical 

wind plant detailed above. In effect, the data illustrate value gained or lost as a result of a 

specific investment decision. As each of these plants is modeled at an equivalent size, plantspecific NPVs can be compared across time. However, caution is advised against any direct 

assessment of wind plant profitability or return on investment as the overall magnitude of NPV is 

highly correlated to plant size. Moreover, as the data presented represent the change in NPV 

 5 This is the approximate annual inflation rate necessary to achieve a levelized pre-tax O&M cost comparable to the 

value assumed by Tegen et al. (2012).

6 Negative after-tax cash flows are excluded based on the premise that plants will not be operated at a loss.
10

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

relative to simply maintaining the existing facility, they do not represent the full NPV from a 

given investment. Results from both the repowered and greenfield facilities assume a common 

reference project size of 100 MW.

Based on the inputs and analyses completed, wind power plants built in 1999 appear to be 

reasonably profitable moving into their 14th year of operation. In part, this is the result of 

relatively favorable PPAs signed during this time and relatively low capital costs. Nevertheless, 

the age of this facility and the advancements in technology that have occurred to date suggest 

that action in the near term is likely merited. Data analyzed here indicate that in 2015, after 15 

full years of operation, overall profitability for a plant built in 1999 can be enhanced by 

repowering or by building an adjacent facility (Figure 1). If asked to choose the more lucrative 

option, this analysis indicates that developing an adjacent greenfield adds more value than 

simply repowering. By 2020, after 20 years of operation, the result is relatively similar with both 

alternatives adding value, but the combined assets of the new greenfield and the existing facility

appear to be most profitable. 

Full repowering becomes more attractive than an additional new greenfield sometime between 

20 and 25 years of operation, for plants built in 1999; it is an increasingly attractive alternative as 

time progresses. 

Figure 1. Value added to a 1999 wind plant as a result of investing 

in a new greenfield or full repowering

Note: Assumes common reference plant size of 100 MW

 $-

 $5

 $10

 $15

 $20

 $25

 $30

Existing +

Green

Repower Existing +

Green

Repower Existing +

Green

Repower Existing +

Green

Repower

2015 2020 2025 2030

Change in NPV vs. Continuing to Operate Existing Wind Plant 

(Millions of 2012$; Assumes 100 MW)
11

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at www.nrel.gov/publications.

Figure 2 illustrates, in the same manner, the results for a wind plant commissioned in 2003. For 

this facility, analysis suggests that building an adjacent greenfield plant in 2015 and 2020 (after 

11 and 16 years of operation, respectively) is again the preferred alternative relative to full 

repowering. However, in this case it is between 16 and 21 years of operation (2020–2025) that 

repowering becomes financially preferable, somewhat earlier in the life of the plant than for the 

1999 plant. In part, the somewhat shorter anticipated life for the 2003 plant is a function of its

lower estimated PPA price and the relatively slight improvement in net capacity factor observed 

for the 2003 facility relative to the 1999 facility. Combined with lower profitability overall for 

this plant, increasing operational costs begin to erode the value of 2003 vintage plants earlier in 

their life than plants commissioned in 1999 or later.

7

Figure 2. Value added to a 2003 wind plant as a result of investing 

in a new greenfield or full repowering

Note: Assumes common reference plant size of 100 MW

Results for the plants commissioned in 2008 and 2012 are presented in Figure 3 and Figure 4, 

respectively. For both the 2008 and 2012 plants, building an adjacent new greenfield project is 

the financially preferable option through 2030. In fact, throughout this time period (as many as 

21 and 17 years of operation, respectively), full repowering results in a reduction in the NPV of 

future after-tax cash flows. For the 2008 facility, this is in part the result of historically high 

 7 The authors note, however, that even though this analysis indicates that repowering might be financially attractive 

after only 16–21 years, owners/operators might not ultimately choose to repower within this timeframe as a result of 

project-specific financing, depreciation, or other constraints.

 $-

 $5

 $10

 $15

 $20

 $25

 $30

Existing +

Green

Repower Existing +

Green

Repower Existing +

Green

Repower Existing +

Green

Repower

2015 2020 2025 2030

Change in NPV vs. Continuing to Operate Existing Wind 

Plant (Millions of 2012$)
12

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at www.nrel.gov/publications.

PPAs signed during this period. Also playing a role are the assumed declines in PPA pricing 

associated with future technology advancements and cost reductions. Regardless of drivers, more 

recent plants appear to have substantial value remaining beyond 20 years. Accordingly, these 

projects could delay repowering investments until 25 years of operation or beyond. 

Figure 3. Value added or lost as a result of investing in a new greenfield or 

full repowering for a 2008 wind power plant

Note: Assumes common reference plant size of 100 MW

 $(70)

 $(60)

 $(50)

 $(40)

 $(30)

 $(20)

 $(10)

 $-

 $10

 $20

 $30

 $40

Existing +

Green

Repower Existing +

Green

Repower Existing +

Green

Repower Existing +

Green

Repower

2015 2020 2025 2030

Change in NPV vs. Continuing to Operate Existing Wind 

Plant (Millions of 2012$)
13

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Figure 4. Value added or lost as a result of investing in a new greenfield

or full repowering for a 2012 wind power plant

Note: Assumes common reference plant size of 100 MW

Partial repowering is examined for the 2003 plant only. Figure 5 demonstrates the results for 

partial repowering relative to full repowering as well as building a new adjacent greenfield

facility. Results are shown specifically for 2025 when full repowering was determined to be the 

preferred alternative. Based on the inputs summarized in Table 2 and Table 3, partial repowering 

offers less added value to an owner/operator than either full repowering or building an adjacent 

greenfield. This is primarily due to the lower net capacity factor resulting from not replacing the 

tower, and hence not accessing stronger winds aloft, coupled with the modest additional cost 

savings to be gained by keeping the existing tower and foundation intact. It should be noted that 

this conclusion is based on the concept of partial repowering that was identified and defined 

earlier. Were innovations to emerge that boost the productivity of aging equipment at less cost 

than estimated here, partial repowering could be more attractive.

 $(120)

 $(100)

 $(80)

 $(60)

 $(40)

 $(20)

 $-

 $20

 $40

Existing +

Green

Repower Existing +

Green

Repower Existing +

Green

Repower Existing +

Green

Repower

2015 2020 2025 2030

Change in NPV vs. Continuing to Operate Existing Wind Plant 

(Millions of 2012$)
14

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National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Figure 5. Value added to a 2003 wind plant as a result of investing in a new greenfield, 

full repowering, or partial repowering in 2025

Note: Assumes common reference plant size of 100 MW

 $-

 $2

 $4

 $6

 $8

 $10

 $12

 $14

Existing + Green Repower Partial Repower

Change in NPV vs. Continuing to Operate Existing Wind 

Plant (Millions of 2012$)
15

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

3 Case Study Analysis

The financial modeling completed within the general economic feasibility assessment is 

supplemented by additional modeling and semi-structured interviews with project owners. These 

efforts focus on repowering opportunities within three specific regions of the United States: the 

Northeast, Midwest, and West Coast. This approach offers a more nuanced perspective on the 

repowering opportunity. In addition, this supplemental work serves as a check on the more 

general conclusions drawn from industry-wide analysis covered in Section 2. 

3.1 Methods

Analytically, the case study analysis was carried out in an equivalent manner as the more general 

economic analysis. Modeling was performed using SAM, and the change in NPV of after-tax 

cash flows was compared across the two specific investment opportunities (repowering or 

developing an adjacent greenfield). Notably, the case study analysis focuses only on full 

repowering, as partial repowering was determined to offer less added value than full repowering 

(Figure 5). However, unlike the more general assessment, which emphasized aggregated industry 

data, the case study approach developed modeling inputs for existing plants that were specific to 

actual projects within the three regions considered. Table 4 summarizes the general 

characteristics and modeling input variables for the plants chosen for analysis.8

Criteria for plant selection included geographic diversity, an operation history of at least 

10 years, and the presence of recent, or ongoing, development at an adjacent greenfield site.

Choosing existing wind plants with new greenfield sites in active development provided a more 

refined look at real-world factors such as installation costs, expected performance, and PPAs that 

were appropriate for those locations at the present time. In principle, this approach ties the case 

study analysis to more realistic conditions faced by project owners. 

To gather relevant data for these sites, a three-step process was undertaken. First, Web-based 

inquiries were conducted with the intent of extracting key project characteristics for the existing 

plants and the adjacent greenfield projects. Characteristics such as number of turbines, nameplate 

capacity, and expected initial net capacity factor were collected from project websites and 

archived news articles. Second, spreadsheet forms were distributed to contacts at all of the 

companies that own or operate the respective wind plants or those who are developing the nearby 

greenfield sites. Owner/operator contacts were asked to provide supplemental data to fill in the 

gaps that were missing from publicly available sources. Third, relevant modeling input data were 

solicited from the industry databases maintained by Lawrence Berkeley National Laboratory and 

summarized by Wiser and Bolinger (2012). Where data were not available, estimates based on 

comparable projects (both in terms of age and technology type) were developed to allow for 

completion of the financial modeling. Given some persistent data gaps, follow-up semistructured interviews with plant owners/operators were conducted to obtain reactions and review

of results. Final modeling input data and assumptions are summarized in Table 4 and Table 5.

 8 Note that Table 4 contains ranges to protect the confidentiality and anonymity of the specific plants 

being analyzed.
16

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at www.nrel.gov/publications.

Table 4. Key Characteristics and Assumptions for the Three Case Study Wind Plants

Commercial 

Operation 

Date

Turbine 

Size 

(MW)

Plant Rated 

Capacity

Average 

Annual Net 

Capacity 

Factor

PPA 

Price/ 

MWh

Installation 

Cost 

2012$/kW

Federal 

Incentive 

Utilized

Year 1 OpEx

Fixed

(2012$/

kW-yr)

Variable 

(2012$/ 

MWh)

Northeast Wind Plant

Existing 1995–2000 0.5–1.0 5–10 MW 20%–25% 91 2,400–2,900 PTC 12.5 11.2

Nearby greenfield 2010–2015 1.5–2.5 25–35 MW 32%–37% 88 2,400–2,900 PTC 12.5 6.1

Repower existinga 2010–2015 1.5–2.5 25–35 MW 32%–37% 88 2,300–2,800 PTC 12.5 6.1

West Coast Wind Plant

Existing 1988–1993 < 0.5 45–55 MW 17%–22% 135 2,300–2,800 None 12.5 13.3

Nearby greenfield 2010–2015 1.5–2.5 95–105 MW 25%–30%b 115 2,900–3,400 PTC 12.5 6.1

Repower existinga 2010–2015 1.5–2.5 95–105 MW 28%–33% 115 2,700–3,200 PTC 12.5 6.1

Midwest Wind Plant

Existing 1997–2002 0.5–1.0 10–15 MW 32%–37% 69 1,700–2,200 PTC 12.5 10.2

Nearby greenfield 2010–2015 1.5–2.5 25–35 MW 35%–40% 68 1,700–2,200

ITC/1603 

Cash 

Grant

12.5 6.1

Repower existingb 2010–2015 1.5–2.5 25–35 MW 35%–40% 68 1,600–2,100

ITC/1603 

Cash 

Grant

12.5 6.1

a Installation costs for “Repower existing” were again assumed to be 5% less than building a nearby greenfield site based on semi-structured interviews with 

developers/owners.

b For the West Coast case study, interviews with owners/operators indicated that finding a nearby greenfield site with as strong a wind resource as the existing 

wind site was unlikely given the large number of wind plants that have already been installed in this location.
17

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Table 5. Financial Modeling Constants Across Case Study Scenarios

Inflation 2.5%

Discount rate (nominal) 9%

Cost of financing (nominal) 9%

PPA escalation rate (nominal)a 1%

O&M escalation rate (nominal)b 4.5%

a

The Midwest plant PPA’s escalation rate was assumed to be 0.2% for the existing plant, and 0% escalation for the 

greenfield and repower scenarios per guidance from semi-structured interviews. Moreover, as reported by Bolinger 

(2013) there are many PPAs signed today that are consistent with this approach and are constant in nominal terms 

with time.

b O&M escalation rate for the existing West Coast wind plant was assumed to be 5.5% given its earlier 

commissioning date.

3.2 Results

For the Northeast wind plant, which has 15–20 years of operation, both building a new 

greenfield site and repowering would increase the NPV of projected after-tax cash flows (Figure 

6). Moreover, these two possible investment opportunities result in very similar NPVs, within 

1%. Thus, although repowering does appear to be a viable option, one cannot conclude it is 

clearly favorable to building a new greenfield site.

For the West Coast plant, which is 20–25 years old, both building a new greenfield site and 

repowering also increase the NPV of projected cash flows above and beyond those resulting 

from simply maintaining the existing plant. However, in this case, repowering the existing wind 

plant was notably more lucrative than building a new greenfield site (Figure 6). In part, this is a 

result of the slightly lower net capacity factor assumed for a nearby greenfield site relative to a 

repowered facility. This assumption was applied in this specific case as a result of interviewees 

observing that the West Coast plant would have difficulty acquiring land to build an adjacent 

greenfield site with a similar high-quality wind resource.

9 However, the more critical factor is 

likely the overall age of the facility and its relatively low remaining cash flow. Under these 

conditions, the incremental cost savings from use of a portion of the existing infrastructure 

coupled with the slightly better wind resource at the repowered site result in repowering being 

the most attractive investment opportunity.

As in the previous two cases, building a new greenfield site and repowering the existing wind 

plant both resulted in an increase in the NPV of projected after-tax cash flows for the Midwest 

wind plant. However, as this facility has been in operation for only 10–15 years, and there are

presumably many years of substantial profitability from this plant, building a new greenfield site 

is more lucrative than repowering the existing plant. 

 9 This location is already extensively developed, making it relatively difficult to acquire adjacent land.
18

This report is available at no cost from the 

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at www.nrel.gov/publications.

Figure 6. Value added to each case study wind plant as a result of 

investing in a new greenfield or full repowering 

Note: Comparing the NPV across the three case studies is not appropriate. The absolute magnitude of the NPV is 

highly correlated with the size of the wind plant, as larger wind plants require higher levels of investment. Within 

each case study, it was always assumed that both greenfield and repowering decisions would be of the same size 

(i.e., same rated capacity) and thus can be fairly compared.

The results of these case studies support the findings generated by the economic analysis 

summarized in Section 2. Only after a wind plant has been in operation for more than 20 years 

does repowering provide a clear financial advantage relative to building a nearby greenfield site. 

Interestingly, the simulated results compiled here appear to align relatively well with current 

owner/operator financial assessments. Only one of these three plants—the West Coast plant—

has been repowered to date.

$0

$10

$20

$30

$40

$50

$60

$70

Existing +

Green

Repower Existing +

Green

Repower Existing +

Green

Repower

Change in NPV vs. Continuing to Operate 

Existing Wind Plant (Millions of $2012)

West Coast: 

Existing plant - 

20-25 yrs old

Midwest:

Existing plant 

- 10-15 yrs old

Northeast: 

Existing plant –

15–20 yrs old
19

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at www.nrel.gov/publications.

4 Market Opportunity

Both the general economic assessment and the more specific regional case study analysis suggest 

repowering is likely to become attractive after 20–25 years of operation.

10 An anticipated plant 

life of 20–25 years is generally consistent with the typical contract life for wind facilities.

Historically, wind power contracts have been 20 years in length with 15- and 25-year contracts 

signed as well (Bolinger 2013). Having identified the expected timeframe in which projects will 

consider repowering, the next element of this analysis is to quantify the market opportunity 

provided by repowering activity through 2030. 

4.1 Methods

The market opportunity was quantified in terms of annual repowered capacity and expected 

value in constant 2012 dollars. Estimates are premised on 25% of existing facilities repowering 

after 20 years of operation and 50% repowering after 25 years of operation. The remaining 25% 

of the existing fleet is assumed to either continue to operate after 25 years or be 

decommissioned. As empirical data on actual repowering behavior are extremely limited, these 

estimates are intended for hypothetical purposes only. Given this timeframe, only existing plants

will be making repowering decisions by 2030. Accordingly, this task relied on installations 

contained in the U.S. industry projects database (American Wind Energy Association 2012) to 

determine the potential installed capacity that might be repowered on an annual basis over the 

next two decades. Annual installed capacity estimates are calculated assuming a 1:1 replacement 

of capacity. However, if repowering results in increased capacity at a given site, as has been 

observed in Germany and Denmark, additional demand could result. The total repowering 

market value is estimated based on the calculated plant lifetime, projected turbine pricing, and

installed cost estimates. 

This approach represents a high-level estimate of the potential repowering opportunity. The 

actual magnitude of the repowering market will likely vary; nevertheless, the results presented 

here are anticipated to capture the general order of magnitude of the market segment in terms of

both installed capacity and dollar value.

4.2 Results

The estimated plant life applied here suggests that repowering could be considered for about 

40 gigawatts (GW) of the operating wind power fleet within the next two decades (i.e., plants 

commissioned by year-end 2010). Moreover, it suggests that there will be a substantial increase 

in repowering activity in the early 2020s as turbines installed in the late 1990s and early 2000s 

begin to approach the 20- to 25-year threshold where repowering begins to be attractive. 

Assuming 25% of the existing fleet repowers at or around year 20 of operation and 50% 

repowers at or around year 25 of operation, annual repowering activity in terms of megawatts

repowered through 2030 are highlighted in Figure 7. With these conditions the effect is that 75% 

of the fleet does not repower before 25 years of operation; accordingly, the cumulative 

repowered capacity by 2030 is estimated to be slightly less than 14 GW.

 10 If technological advances are more rapid, costs for repowering are substantially lower relative to a new greenfield 

plant, or if capacity factors at new greenfields are notably lower than at repowered facilities, repowering could occur 

earlier than projected in Section 2 and Section 3.
20

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Figure 7. Estimated annual capacity repowered by year

Note: Results assume 1 MW of existing capacity is replaced by 1 MW of repowered capacity.

The total future value of repowering activity through 2030 is estimated at $20–$25 billion. Once 

repowering begins to take an active foothold in the market around 2023, the annual value of the 

market segment is anticipated to be roughly $1 billion per year through 2025 and increases to 

about $5 billion per year in 2028.

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2013 2015 2017 2019 2021 2023 2025 2027 2029

Estimated Annual Repowering Demand (MW)

Estimated Cumulative Repowering Demand (MW)

Annual MW Repowered - Left Axis

Cumulative MW Repowered - Right Axis
21

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5 Supply Chain Impacts

Based on the potential range of incremental new demand resulting from repowering activities,

impacts to the supply chain are calculated in terms of demand for new blades, drivetrains, and 

turbines. As a result of the uncertainties noted above—in terms of the percentage of eligible sites 

that actually repower and the percentage of partial versus full repowering—this analysis seeks 

simply to provide a basic order of magnitude estimate for changes in demand, given the 

estimated levels of repowering and assuming that all repowering activity is full repowering. 

5.1 Methods

Projected technological advancement11 is coupled with anticipated repowering activity to 

estimate total repowering demand and demand for specific component sizes. Given the relatively 

strong wind resource areas where those facilities projected to repower over this timeframe are 

located (Wiser and Bolinger 2012), the majority of demand is expected to be for International 

Electrotechnical Commission (IEC) Class II turbines. The results are briefly compared with the 

existing U.S. wind manufacturing base to inform the ability of the current supply chain to serve 

the repowering market.

5.2 Results

Total turbine demand is estimated from the installed capacity estimates presented in Section 4. 

Assuming 2- to 3-MW turbines constitute the bulk of capacity during the late 2010s and early 

2020s, an average of approximately 60 turbines per year will be needed to serve repowering 

investment from 2018 to 2021. Assuming that 3- to 4-MW turbines become more prevalent after 

2021, an average of approximately 230 turbines per year will be needed to serve the repowering 

demand from 2022 to 2027. From 2028 to 2030, an average of about 730 turbines per year will 

be needed (Figure 8).

Figure 8. Estimated turbine demand by nameplate capacity 

resulting from potential repowering activity

 11 Based on extrapolation of historical trends as well as analysis and research summarized by Cohen et al. (2008) 

and Chapman et al. (2012).

0

100

200

300

400

500

600

700

800

900

2014 2016 2018 2020 2022 2024 2026 2028 2030

Estimated Turbine Demand

3-4 MW Turbines

2-3 MW Turbines
22

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Blade and tower demand by size are presented in Figure 9 and Figure 10, respectively. Based on 

the technology projections applied here, the majority of blades could be on the order of 50–60 

meters (m) with some IEC Class III turbines being utilized in the late 2020s and subsequently 

requiring longer 70- to 80-m blades. Similarly, the majority of towers required for sites that are 

repowered (i.e., Wind Power Class 5 and above wind resource sites) are expected to be 80- to 

100-m towers with some 120- to 130-m towers in the later years.

Figure 9. Estimated blade demand by length (meters) resulting from potential repowering activity

0

500

1,000

1,500

2,000

2,500

3,000

2014 2016 2018 2020 2022 2024 2026 2028 2030

Estimated Blade Demand

70-80m Blades

50-60m Blades
23

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Figure 10. Estimated tower demand by height (meters) resulting from potential repowering activity

U.S. wind installations topped 13 GW per year in 2012. With incremental demand from 

repowering expected to be below 500 MW through the early 2020s and only about 3 GW by the 

late 2020s, supply chain constraints are not expected to be a major impediment to repowering. 

Were partial repowering to become more viable than observed here, production capacity for 

somewhat smaller components geared toward refurbishing older equipment might need to be 

developed. However, as this analysis suggests that repowering will be dominated by full 

repowering efforts utilizing the same state-of-the-art technology being installed on greenfields,

such additional investment is not foreseen. At the same time, repowering cannot be expected to 

create notable supplemental demand in the U.S. supply chain until at least the early to mid2020s. Were the U.S. supply chain forced to downsize dramatically between today and the mid2020s, supply chain constraints could emerge as repowering demand picks up once again in the 

latter half of the 2020s. Assuming a 20- to 25-year life suggests that repowering demand will 

jump again in the early 2030s. Nevertheless, as these increases can be anticipated and predicted,

they are not expected to result in significant supply chain hurdles.

0

100

200

300

400

500

600

700

800

900

2014 2016 2018 2020 2022 2024 2026 2028 2030

Estimated Tower Demand

120-130m Towers

80-100m Towers
24

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

6 Policy and Other Relevant Considerations

The analyses conducted here suggest that repowering activity will remain modest in the United 

States through the early to mid 2020s; however, repowering decisions are not often driven by 

economic considerations alone. The following discussion highlights the perspectives of wind 

industry professionals with regard to the impacts of current policy on repowering decisions as 

well as areas where future policy may be applied to facilitate or discourage repowering.

Semi-structured interviews indicated that current federal policy has only a modest impact on 

repowering decisions. In some instances, repowering investment may be accelerated to take 

advantage of the PTC or accelerated depreciation provisions similar to other wind power 

development activity, but generally, no substantial impact was observed. Similarly, 

Environmental Protection Agency rules under development that may encourage the retirement of 

existing generation capacity could create more demand for wind power generally but are unlikely 

to directly affect decisions specific to repowering.

Multiple interview respondents observed that repowering could offer the possibility for 

expedited permitting because development is occurring at a previously permitted site and these 

sites have a much longer track record of historical environmental data. Existing plants also tend 

to have increased local familiarity, which might also facilitate the permitting process. The ability 

to expedite the permitting process would suggest, perhaps, that repowering could take place

somewhat sooner than envisioned by the financial analyses above. However, development costs,

including permitting, are low relative to the total capital expenditures associated with modern 

wind facilities (Tegen et al. 2011) suggesting that this effect may be relatively modest. It was 

also observed that where endangered species live or other environmental damage has occurred,

permitting would likely be more complex and drawn out, with the likely effect of postponing 

repowering activity. Repowering activity was also noted to be likely to occur later in a plant’s 

life if local siting requirements become more stringent over time. 

Along with more general policy considerations, respondents noted that the contractual language 

around an existing PPA could potentially raise a number of red flags when considering 

repowering. For example, wind professionals expressed concern about potential outage clauses

and minimum generation thresholds as the physical act of repowering would likely involve 

substantial plant downtime. Respondents were also concerned about the contractual implications 

resulting from potential changes in production associated with putting new more productive 

technology at a specific site or from the potential addition of more capacity at a site. It was also 

noted that past PPAs tended to be more generous, so project owners are hesitant to take any

action that would jeopardize an existing set of terms, conditions, and payments. Such a condition 

is comparable to that described earlier as the “California Fix,” whereby repowered plants that 

take the federal PTC are anticipated to result in the loss of relatively generous standard offer 

contracts for many California wind projects built in the 1980s. 

Within this context, if the various attributes of repowering are valued, repowering activities

could be accelerated. However, encouraging and accelerating repowering investment is likely to 

require a shift in policy. Policy changes would likely need to address the current economic 

incentives around repowering, but may also consider the various permitting, regulatory, and 

contractual risks associated with repowering.
25

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

7 Summary and Conclusions

In line with prior work, this report’s principal conclusion is that wind power plants that continue 

to generate a positive after-tax cash flow are unlikely to pursue repowering in the immediate 

future. Based on the analysis completed here, it is estimated that existing plant viability remains

strong up until 20–25 years of operation, at which point repowering becomes more attractive 

than a new greenfield addition. Before this time, the continuing revenue stream from the existing 

plant augments any new greenfield site’s future revenue stream, making repowering less viable. 

This timeframe for repowering was supported both by our aggregated representative wind plant 

financial analysis and by our case studies. Once the after-tax cash flow falls below a given 

threshold (after 20–25 years), the installed cost savings associated with repowering and resulting 

from the ability to use existing infrastructure, including roads, buildings, and electrical 

equipment, shifts the balance in favor of repowering.

As defined here, partial repowering appears to offer less value than full repowering. Estimated 

cost savings of approximately 10% relative to full repowering that result from reusing the 

existing tower and foundations did not offset the reduction in energy generation due to the lower 

hub height and smaller rotor anticipated for the partially repowered turbine. Accordingly, partial 

repowering is unlikely to be pursued unless innovations emerge that can boost plant productivity 

or reduce operating costs with less investment than was anticipated here.

In brief, wind industry investors looking to expand their profitability over the next decade are 

likely to see a greater increase in NPV from developing adjacent new greenfield sites than from 

repowering.

12 Nevertheless, there is an array of variables that could affect the attractiveness of 

repowering and either extend or shorten operating plant life including:

• Technological advancement: More rapid advancement will encourage repowering while 

slower advancement will reduce the viability of repowering.

• Wind resource regime for greenfield plants: A wind resource that is lower quality than 

that of existing facilities will encourage repowering while higher-quality wind resource 

areas potentially opened up by new transmission will encourage further greenfield

investment.

• PPA prices: Both higher prices for future repowered plants and, alternatively, lower PPA 

prices for existing plants would encourage repowering to occur earlier.

• Operation expenditures: More rapid cost escalation as facilities age will make 

repowering more attractive earlier.

• Repowering cost savings (relative to a greenfield project): The ability to capture > 5% 

cost savings from repowering activities will encourage repowering; potentially higher 

costs (than modeled here) for repowering will discourage repowering investment.

 12 Assuming, of course, that new greenfield plants are viable investments independent of the repowering 

considerations.
26

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Assuming a plant life of 20–25 years, repowering demand is expected to be low over the next 

decade, reach a few hundred megawatts per year in the early 2020s, and achieve 1–3 GW by the 

late 2020s. The total estimated value of the repowering market segment is estimated at $25 

billion through 2030 with the vast majority of this investment occurring in the latter half of the 

2020s. Turbine demand is anticipated to range from well below 100 turbines per year in the early 

2020s to slightly more than 700 turbines per year by the late 2020s. Tower and blade demand is 

anticipated to be concentrated on the state-of-the-art IEC Class II turbine designs suggesting that 

repowering could support an incremental increase in supply chain activity.

Policy support in the form of financial incentives, as well as solutions to potential regulatory and 

contractual hurdles, is likely to be necessary if there is value placed on the acceleration of 

repowering investment.
27

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

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at www.nrel.gov/publications.

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This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Appendix A: Interview Guide for Wind Owner 

Operators

Semi-structured interviews with plant owners and operators provided insights into their reasons 

for having repowered or not, as well as an opportunity to acquire feedback on earlier modeling 

inputs and results. This appendix includes the interview template and summarizes the themes that 

emerged from these discussions. In total, extended interviews were completed with eight wind 

power professionals, representing the financial community, owner/operator/developer firms, and 

utility owners.

Template

Part 1: Experiences and Perspective on Repowering 

1. Project Overview

A. Explanation of our project

B. Why we are calling

C. What we mean by repowering

2. Have you been involved in any projects involving repowering of older wind plants? (if 

no, move down to #3) 

(If yes), please describe what was done in the repowering process.

A. How many turbines were removed? Rated capacity of each? 

B. How many new ones were installed? Rated capacity of each? 

C. Was the plant’s total rated capacity increased? How much?

D. Were the towers replaced?

E. What other components, if any, of the balance of plant was modified?

F. Which of the following, if any, were reasons supporting this repowering decision? 

You may choose more than one response.

i. Increasing total plant rated capacity

ii. Lowering O&M costs

iii. Increasing net capacity factor

iv. Adhering to environmental regulations

v. Technology was outdated

vi. Equipment was at the end of its useful life

G. Was a new environmental impact study conducted before the repowering was 

approved?

H. What was done with the old nacelle, rotors, and towers when the plant was 

repowered?

i. Refurbished and sold?
30

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National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

ii. Recycled?

iii. Landfill?

3. What are the primary benefits of repowering an existing wind plant?

4. What major obstacles, if any, should a wind plant owner consider when evaluating the 

feasibility of repowering?

5. When evaluating the decision whether to invest in a new nearby greenfield site versus

repowering an existing wind plant, what are the major factors that an owner/operator 

should consider? 

I. Describe the advantage of repowering an existing wind plant relative to investing 

in a new greenfield site.

J. Conversely, describe the advantage to investing in a new nearby greenfield site 

relative to repowering an existing wind plant.

6. At what age do you think it is most appropriate to repower a wind plant?

7. Please discuss what impact, if any, the structure of current government incentives 

supporting wind energy have on the decision to repower an older wind plant?

8. What impact, if any, does a wind plant’s current PPA agreement for an existing wind 

farm have on the decision to repower?

9. What should be done with older wind plant equipment (nacelle, rotors, and tower) when 

taken down?

Part 2: Case Study Examples 

Now we would like to hear your perspective on the three case studies we prepared. We compared 

the financial projections for three possible investment decision paths for each case study: 

1. Maintaining an existing wind plant

2. Building a new greenfield site in addition to maintaining the existing plant

3. Repowering an existing site.

We created three case studies (Northeast, West Coast, Midwest), all of which were run with 

these three investment decision paths. If we could not find publicly available information for key 

inputs, we used industry averages described in the Wind Technology Market Report 2011 (Wiser 

and Bolinger 2012). Modeling was performed with SAM. 

4. Have you had a chance to review our preliminary results of the case studies file we sent 

you on Friday evening? (if no, ask them to review it)

K. What are your initial thoughts?

L. Do these results match what you would expect? Why or why not?

5. In the case study results we highlighted three important input assumptions that drove 

repowering’s NPV advantage over building a new greenfield site. Please consider each of 

these three assumptions and describe whether you feel they are reasonable or not and why 

you feel that way.
31

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National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

M. 5% better wind resource for repowered sites versus greenfield 

N. 5%–10% lower installation costs due to already existing infrastructure for 

repowering

O. Costs of removal of old equipment can be offset by selling it.

6. Does your company have any employees devoted to assessing the market potential of 

repowering? Please describe.

7. What other thoughts do you have on the feasibility of repowering that you would like to 

share?

8. What questions would you like answered to help your company make informed decisions 

concerning repowering older wind plants?

9. Is there anything else you would like to tell us to inform this project?

10. Are there any other wind energy professionals, either within or outside of your company, 

that you would recommend we speak with on this topic? Request specific contact 

details.