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.

Contract No. DE-AC36-08GO28308

Renewable Energy Finance 

Tracking Initiative (REFTI)

Solar Trend Analysis

Ryan Hubbell, Travis Lowder, 

Michael Mendelsohn, and Karlynn Cory

Technical Report

NREL/TP-6A20-53531

September 2012
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.

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Renewable Energy Finance 

Tracking Initiative (REFTI)

Solar Trend Analysis

Ryan Hubbell, Travis Lowder, 

Michael Mendelsohn, and Karlynn Cory

Prepared under Task No. SM12.3050

Technical Report

NREL/TP-6A20-53531

September 2012
NOTICE

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iii

Acknowledgments

The production of this report hinges on a large amount of data collected over a multiyear 

timeline. Both the gathering and processing of this data involved contributions from many 

people, including Paul Scharfenberger, Andrew Martinez, Paul Schwabe, Bethany Speer, Claire 

Kreycik, David Feldman, and Ron Koenig. In addition, the authors would like to thank Jeff 

Logan, David Kline, Dan Bilello, Robin Newmark, Scott Gossett, and Mary Lukkonen for 

editorial support.
iv

Preface

This report presents trend analyses of various financial terms for solar photovoltaic (PV) 

projects and concentrated solar power (CSP) projects as reported in the National Renewable 

Energy Laboratory’s (NREL) Renewable Energy Finance Tracking Initiative (REFTI). REFTI 

delineates PV systems into two sizes: small (<1 MW) intended to capture residential and 

commercial systems, and large (≥1 MW) intended to capture utility-scale systems. 

The data were collected from industry stakeholders over seven analysis periods from the fourth 

quarter (Q4) of 2009 through the second half (2H) of 2011. All REFTI data are provided 

voluntarily with respondent confidentiality of paramount importance. Although these limit the 

scope and granularity of the project, REFTI is still the only publicly available resource for 

renewable energy project financial terms. It offers renewable energy stakeholders a set of

information upon which project terms can be benchmarked.
v

Table of Contents

Acknowledgments ..................................................................................................................................... iii

Preface ........................................................................................................................................................ iv

Table of Contents........................................................................................................................................ v

List of Figures ............................................................................................................................................ vi

List of Tables .............................................................................................................................................. vi

1 The Renewable Energy Finance Tracking Initiative.......................................................................... 1

2 A Word on the Data .............................................................................................................................. 2

3 Overview of Solar Projects in REFTI .................................................................................................. 3

3.1 Solar Project Information........................................................................................................... 3

3.2 Solar Project Development Barriers .......................................................................................... 3

3.3 Impact of Solar Development Barriers ...................................................................................... 5

4 Energy Costs......................................................................................................................................... 6

4.1 Solar Installed Costs.................................................................................................................. 6

4.2 Power Purchase Agreement...................................................................................................... 7

4.3 Levelized Cost of Energy........................................................................................................... 8

5 Equity Structure.................................................................................................................................. 10

5.1 Tax Equity................................................................................................................................ 10

5.2 Developer Equity ..................................................................................................................... 11

5.3 Financial Structure................................................................................................................... 11

6 Debt...................................................................................................................................................... 14

6.1 Debt-to-Capital Ratio and Cost of Debt................................................................................... 14

6.2 Cost of Debt Versus Cost of Tax Equity.................................................................................. 15

6.3 Debt Term and Coverage Ratio............................................................................................... 16

7 Soft Costs............................................................................................................................................ 17

8 Summary ............................................................................................................................................. 18

References................................................................................................................................................. 19
vi

List of Figures

Figure 1. Proportion of REFTI respondents and their roles in RE industry ....................................1

Figure 2. Ranges for total solar projects and megawatt capacity financially closed .......................3

Figure 3. PV <1 MW barriers to development ................................................................................4

Figure 4. PV <1 MW barrier impacts..............................................................................................4

Figure 5. PV ≥1 MW barriers to development ................................................................................4

Figure 6. PV ≥1 MW barrier impacts ..............................................................................................4

Figure 7. CSP barriers to development............................................................................................5

Figure 8. CSP barrier impact ...........................................................................................................5

Figure 9. PV <1 MW weighted averages for installed costs versus PV module prices...................6

Figure 10. PV ≥1 MW weighted averages for installed costs versus PV module prices.................6

Figure 11. PV <1 MW PPA price, escalation rate, and term weighted averages............................7

Figure 12. PV ≥1 MW PPA price, escalation rate, and term weighted averages ............................8

Figure 13. Weighted average LCOE (after incentives) for both PV scales versus average retail 

and commercial electricity prices (from U.S. EIA) ........................................................9

Figure 14. PV <1 MW weighted average tax equity percent and expected returns.......................10

Figure 15. PV ≥1 MW weighted average tax equity percent and expected returns.......................10

Figure 16. Weighted average expected solar developer and tax equity returns.............................11

Figure 17. PV <1 MW aggregate financial structure.....................................................................12

Figure 18. PV <1 MW financial structure trend ............................................................................12

Figure 19. PV ≥1 MW aggregate financial structure.....................................................................12

Figure 20. PV ≥1 MW financial structure trend ............................................................................12

Figure 21. CSP aggregate financial structure ................................................................................13

Figure 22. PV <1 MW weighted average debt-to-capital ratio, all-in cost of debt, and Baa 

corporate bond yields (St. Louis Federal Reserve).......................................................14

Figure 23. PV ≥1 MW weighted average debt-to-capital ratio, all-in cost of debt, and Baa 

corporate bond yields (St. Louis Federal Reserve).......................................................15

Figure 24. PV <1 MW weighted average cost of debt and tax investor equity .............................15

Figure 25. PV ≥1 MW weighted average cost of debt and tax investor equity .............................16

Figure 26. Total project “soft costs” as a percentage of total project costs...................................17

List of Tables

Table 1. DSCR Weighted Averages for Solar Technologies.........................................................16
1 

1 The Renewable Energy Finance Tracking Initiative

Successful policy design, financing, and development of renewable energy (RE) projects require

information to guide the decision-making process. Much of this information, however, is not 

widely available. Project financial terms are especially difficult to come by as many of these 

terms are often negotiated between two or more private entities. This lack of transparency may 

impede effective policy design, competition, and potentially industry growth if important 

information is known by only a few market participants.

To improve project finance term transparency and assist public and private RE participants, the 

National Renewable Energy Laboratory (NREL) created the Renewable Energy Finance 

Tracking Initiative (REFTI). REFTI data participants include new and existing developers, 

financiers, insurance companies, policymakers, and market research participants. REFTI data is 

used by NREL and the U.S. Department of Energy (DOE) and is publicly available for use in 

financial models and pro formas. 

A total of 831 participants disclosed their role in the RE industry during REFTI reporting periods 

Q4 2009 to 2H 2011.1

 Almost 40% of respondents described themselves as Developers, 

Installers, or Integrators of RE projects (Figure 1). The second- and third-largest classes of 

participants were Counsel/Consultants (15%) and those involved in Government, Research, or 

Advocacy (12%). Equity and Debt Financiers together accounted for a modest 6% of 

respondents. Information and data constitute competitive advantage for financiers, and it is likely 

that the seeming risk of compromising that advantage through disclosure limited participation 

from this group. About 14% of participants selected the “Other” category when asked to disclose 

their role in the RE industry.

Figure 1. Proportion of REFTI respondents and their roles in RE industry

Total number of respondents: 831

 

1 The REFTI questionnaire was administered once per quarter from Q4 2009 through Q4 2010. Beginning in 2011, 

only two questionnaires were administered: one in the first half of the year and the other in the second half.
2

2 A Word on the Data

The principal method of data collection for REFTI was an online questionnaire distributed to 

those reporting to be RE stakeholders. All responses are assumed to be faithful reporting from 

market participants and the analyses should therefore be viewed accordingly. NREL did not 

confirm the accuracy of participants’ responses for a number of reasons, including the assurance 

of confidentiality. Much of the data collected is considered proprietary and complex in nature. 

NREL reports the questionnaire responses and conducts various trend and comparative analysis 

on the data. Although the online questionnaire restricts participation to once per IP address, it is 

possible for more than one respondent (e.g., a financier, a developer, and an insurer) to submit 

data on the same project without NREL’s knowledge of the duplication, which could result in an 

unequal weighting of certain projects over others.

2

To ensure respondent confidentiality and facilitate questionnaire completion, numerical answer 

choices were formatted as range-bound, multiple choice questions. To then perform comparative,

trend, and aggregate analyses, median values were assigned to each bin range answer choice in 

order to calculate weighted averages.3 Unless otherwise indicated, all numerical values 

contained in the report are weighted average calculations.4

The granular level of detail reported in REFTI may render some sample sizes too low to be 

considered statistically significant in comparison to the total number of projects closed in a given 

time period. Sample size limitations also prevent concentrated solar power (CSP) data from 

appearing in every section of the report. 

A more complete dataset is available for review at: financere.nrel.gov/finance/refti. 

 2 All REFTI data is provided confidentially unless the participant opts to disclose specific information about his/her 

project, company, etc.

3 Weightings applied by response count. Highest answer choice assigned a median value of its numerical value plus 

the difference between its value and the prior median value. For example, if the answer choice was “10+” and the 

previous bin range value was “8–10,” then a median value of 11 was assigned. 4 As with all weighted average calculations, the fewer number of responses will increase the influence each response 

has on the final weighted average. 
3 

1,401 

1,176 

3,193 

3,632 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

3 Overview of Solar Projects in REFTI

3.1 Solar Project Information

Between 1,400 and nearly 3,200 

projects were reported to have reached 

some form of financial closure5

through the REFTI process (Figure 2). 

Not surprisingly, over 75% of these 

projects were reportedly below 1 MW 

in size and can likely be assumed to 

be small-scale residential systems. Of 

the remaining larger-scale systems, 

approximately nine were reported to 

be CSP. As illustrated, these projects 

accounted for a slightly higher range 

of capacity.6

 Given that 1,076 MW of 

solar capacity was added in the United 

States between 2009 and 2011 (SNL 

Financial), it is likely much of the REFTI-reported capacity will be installed in 2012. 

3.2 Solar Project Development Barriers

Although solar projects can experience numerous development barriers, the largest reported 

barriers for REFTI participants were financial in nature. Both small- and large-scale PV reported 

raising capital and tax equity to be top barriers to development (Figures 3, 5, and 7). Since the 

investment tax credit (ITC) would likely have been taken in the form of an upfront 1603 

Treasury grant payment, it is presumed raising tax equity was primarily utilized to monetize 

accelerated depreciation benefits. This may not be the case going forward following the 

expiration of the grant program. 

No CSP respondents indicated finding tax equity investors as a top barrier but instead identified 

the inaccessibility of government incentive programs as the chief development hurdle. This is 

likely due to CSP projects not yet reaching a level of maturity to consider how best to monetize 

the tax benefits and heavy reliance on the 1703 federal loan guarantee program. Altogether, 

power purchase agreements (PPA), finding tax equity investors, raising capital, and accessing 

government incentives accounted for over 38% of the top barriers reported by CSP respondents 

and over 50% of both small and large PV respondents. 

 

 

5 Note, the above numbers include projects that closed financing and do not include projects that came online or 

were in the pre-financing stages of development. 6 Because of limitations in the dataset having to do with the confidentiality concerns, no direct correlation can be 

drawn between projects reported and megawatt-capacity development in REFTI.

Figure 2. Ranges for total solar projects and 

megawatt capacity financially closed

(“X” indicates NREL’s weighted average estimates)

Total # of Projects Closed Total Capacity of Projects (MW)

X X
4

Figure 3. PV <1 MW barriers to development

Total responses: 159

Figure 4. PV <1 MW barrier impacts

Total responses: 143

Figure 5. PV ≥1 MW barriers to development

Total responses: 128

Figure 6. PV ≥1 MW barrier impacts

Total responses: 113

11% 2%

5%

4%

13%

15% 13%

11%

18%

8%

Project economics

Technological hurdles

Environmental

permitting

Transmission

PPA / creditworthiness

of power purchaser

Finding tax equity

investor

Raising capital

Accessing government

incentive programs

Other

None

10%

45% 19%

6%

10%

4%

6%

None

Delayed project(s) ≤ 1 

year

Delayed project(s) > 1

year

Required reduced

project size(s)

Abandoned the Project

Raised Energy Price

Other (pls explain)

13% 1%

5%

16%

16%

20%

11%

2%

12%

4%

Project economics

Technological hurdles

Environmental

permitting

Transmission

PPA / creditworthiness

of power purchaser

Finding tax equity

investor

Raising capital

Accessing government

incentive programs

Other

None

11%

34%

27%

4%

11%

7%

7%

None

Delayed project(s) ≤ 1 

year

Delayed project(s) > 1

year

Required reduced

project size(s)

Abandoned the Project

Raised Energy Price

Other (pls explain)
5

Figure 7. CSP barriers to development

Total responses: 34

Figure 8. CSP barrier impact

Total responses: 27

3.3 Impact of Solar Development Barriers

Figures 4, 6, and 8 show the impacts these barriers had on project development by technology. 

Project delays accounted for well over a majority of responses across all three categories;

however, the majority of PV project delays were less than one year. Although project 

abandonment occurred for roughly 10%–15% of reported solar projects, this figure could be 

understated as it is possible some long-term delayed projects may transition to abandonment in 

the future.

Not surprisingly, CSP projects showed a high percentage (41%) of long-term delay (>1 year) 

given the capital intensity, siting, and permitting requirements of many CSP projects. Also 

notable was the significantly higher number of responses to the “Barriers” section (36) in relation 

to other sections of the questionnaire (6 for most others), which seems to indicate a low track 

record for project completion from CSP respondents.

Also of note is the considerable portion of large-scale solar respondents that opted for the

“Other” category when selecting development barriers. Further explanations ranged but were

mostly centered on high upfront capital costs, limited investor pools, and legal and regulatory 

challenges. Three respondents did specify difficulties raising equity in the earlier project phases, 

which could have been categorized under the “Raising Capital” category.

12%

12%

3%

6%

12%

9%

20%

20%

6%

Project economics

Technological hurdles

Environmental

permitting

Transmission

PPA / creditworthiness

of power purchaser

Finding tax equity

investor

Raising capital

Accessing government

incentive programs

Other

None

4%

26%

41%

7%

15%

7%

None

Delayed project(s) ≤ 1 

year

Delayed project(s) > 1

year

Required reduced

project size(s)

Abandoned the

Project

Other (pls explain)
6

4 Energy Costs

4.1 Solar Installed Costs

Figures 9 and 10 illustrate a general decline in installed costs for PV projects with the exception 

of the most recent REFTI reporting period. This overall trend is consistent with declines in 

global average PV module prices; however, the recent upticks reported in small-scale PV 

installed costs is much more pronounced than the slight increases reported by GTM in Q4 2011, 

by comparison.

7 It should be noted that installed system prices can range significantly; REFTI 

2H 2011 data still falls within the range reported by GTM a full six months later in Q2 2012. 

Survey results also appear to indicate module price declines are outpacing balance-of-system 

(BOS) cost declines.8 As margins get squeezed, industry consolidation may have a significant 

impact on future installed cost reductions.

Figure 9. PV <1 MW weighted averages for installed costs versus PV module prices

Total responses: 80

Figure 10. PV ≥1 MW weighted averages for installed costs versus PV module prices

Total responses: 61

 7 Only three respondents reported 2H 2011 data, one of which reported a very high $7/W, increasing the weighted 

average significantly. 

8 For purposes of this paper, BOS costs are defined as installed costs minus module prices

0

1

2

3

4

5

6

7

Q4 09 Q1 10 Q2 10 Q3 10 Q4 10 1H 11 2H 11

$/W

Installed Costs

Module Price

0

1

2

3

4

5

6

Q4 09 Q1 10 Q2 10 Q3 10 Q4 10 1H 11 2H 11

$/W

Installed Costs

Module Price
7

Installed costs for CSP averaged $3.70/W over the five quarters (this calculation includes an 

“outlier” of $1.80/W in Q4 2009). Because of limited data, CSP installed costs could not be 

trended.

4.2 Power Purchase Agreement

Similar to installed costs, reported PPA terms and price escalation for both PV scales generally 

declined until substantial rebounding was reported in 2H 2011 (Figures 11 and 12). First-year 

PPA prices for small-scale projects were variable throughout the analysis time period with the 

lowest levels reported in 2H 2011 of $0.07/kWh. The PPA term, price, and escalation rates—

combined—represent the ability of the project to ensure sufficient cash flows. It is possible the 

longer PPA terms and lower prices are a reflection of the effects of reduced installation costs.

Figure 11. PV <1 MW PPA price, escalation rate, and term weighted averages

PPA responses: 53

Escalation rate responses: 55

All three large-scale PPA metrics tracked declined through 1H 2011, then both prices and 

contract term years subsequently increased in 2H 2011 (Figure 12). This indicates some shortterm revenue challenges for large PV as lower electric demand and future economic uncertainties 

may be tempering off-takers’ willingness to guarantee future price increases. Rapid renewable 

portfolio standard (RPS) compliance and cost curve reductions (including natural gas generation) 

is also likely driving down solar PPA terms. Despite these trends, the duration of PPA terms

have remained relatively stable in the 15–20 year range. 
8

Figure 12. PV ≥1 MW PPA price, escalation rate, and term weighted averages

PPA responses: 52

Escalation rate responses: 52

Weighted average first-year PPA prices for CSP were $0.079/kWh with escalation rates of 1.6%. 

These figures are based on seven responses during the REFTI analysis period.

4.3 Levelized Cost of Energy

Levelized cost of energy (LCOE) weighted averages for small- and large-scale PV display 

opposite trend lines (Figure 13), suggesting that the cost advantage of larger systems has been 

gradually realized over the REFTI analysis period. This could be the function of several market 

conditions including the realization of economies of scale and/or centralized procurement via 

utilities or large commercial entities driving competition and cost reductions. In total, declining 

module prices and nascent BOS cost reductions are registering more perceptibly in larger-scale 

systems. 

Small-scale PV roughly tracks average U.S. residential electricity rates, suggesting that overall 

(excluding regional variations in power prices), PV is a competitive option for residential rate 

payers. However, despite one dip below commercial electricity rates in Q1 2010, smaller PV 

systems registered less competitive for lower-tiered commercial rate off-takers.

0.0

0.5

1.0

1.5

2.0

2.5

3.0

0

5

10

15

20

25

Q409 Q110 Q210 Q310 Q410 1H11 2H11

Escalation (%)

Terms (yrs)

Price (¢/kWh)

PPA Term Yr 1 PPA Price Price Escalation
9

Figure 13. Weighted average LCOE (after incentives) for both PV scales versus average retail and 

commercial electricity prices (from U.S. EIA)

PV <1 MW responses: 57

PV ≥1 MW responses: 46

The weighted average LCOE estimate for CSP projects during the timeframe was $0.093/kWh.9

Because only four CSP projects came online between the last quarter of 2009 and end of 2011

(SEIA 2011), it is likely the projects reported were still in the development phase. Responses 

from the same project across multiple timeframes are also possible.

 9 Based on 10 responses.

4

6

8

10

12

14

16

Q409 Q110 Q210 Q310 Q410 1H11 2H11

¢/kWh

Avg Residential

Electric Rate

Avg Commercial

Electric Rate

LCOE (PV≥1 MW)

LCOE (PV<1 MW)
10

5 Equity Structure

5.1 Tax Equity

Expected tax equity returns for both small and large PV projects rose higher in the back half of 

2011 (Figures 14 and 15). Returns on both small- and large-scale projects rebounded from their 

2011 first-half lows, reaching 10% and almost 14%, respectively. In aggregate, larger PV 

exhibited a higher expected return rate. This trend could reflect the expectation that required tax 

equity yields (minimum return a tax equity partner would require) would increase as a result of

the 1603 Treasury grant expiration or the growing incorporation of debt into the project financial 

structure, which raises yields because tax equity partners take a subordinate position to creditors.

Figure 14. PV <1 MW weighted average tax equity percent and expected returns

Tax equity responses: 63

Return responses: 58

Figure 15. PV ≥1 MW weighted average tax equity percent and expected returns

Tax equity responses: 55

Return responses: 52

0

5

10

15

20

0

10

20

30

40

50

60

Q409 Q110 Q210 Q310 Q410 1H11 2H11

Expected Return (%)

Tax Equity (%)

Tax Equity / Total Equity Expected Return on Tax Equity

0

5

10

15

20

0

10

20

30

40

50

60

70

80

Q409 Q110 Q210 Q310 Q410 1H11 2H11

Expected Return (%)

Tax Equity (%)

Tax Equity / Total Equity Expected Return on Tax Equity
11

5.2 Developer Equity

In aggregate, expected developer returns exceeded tax equity returns by roughly 1%–2% over the

REFTI timeframe (Figure 16). This evidence seems to run counter to many developer claims that 

tax equity partner yields are excessive or well above developer yields. It also indicates risk 

alignment between the investor parties is most equitable at the smaller PV project investment 

level. Results may be skewed slightly lower due to question design.10

Figure 16. Weighted average expected solar developer and tax equity returns

5.3 Financial Structure

The variance in reported financial structures between small- and large-scale solar is 

representative of market conditions. Smaller PV projects—mostly commercial and residential 

installations—typically do not have the size or scale of projects sufficient to attract large tax 

equity investors. As third-party ownership models (from solar lease companies such as SunRun 

and SolarCity) have grown, however, so have residential and commercial installers’ abilities to

achieve larger scales and thus attract more capital. In contrast, larger PV projects are more 

attractive to tax equity investors due to the transactional costs associated with the investment as 

well as the projects greater need and ability to support these costs. 

Figures 18 and 20 illustrate project finance structure trends across the REFTI timeframe. Most 

notable is the increased reporting of “other” financing structures, indicating project financial 

structure innovation continues.11 Through the first half of 2011, the proportion of tax equity to 

total equity declined for both small- and large-scale PV (not pictured); large PV was more 

variable across the analysis period and the general trend was downward. This apparent decline in 

 10 Until 2H 2011, the answer choices did not allow respondents to select “N/A” or “None” for tax equity percentages 

or returns. Approximately 13% of PV respondents reported 0%–10% tax investor equity to total equity before 2H 

2011, and NREL expects that some portion of this 13% would have opted for the “N/A” category had it been 

available. Because these responses were included into quarterly weighted averages as 5% tax equity (instead of not 

counted at all, as would have been the case if there were an “N/A” option), REFTI’s tax equity calculations may be 

skewed low.

11 The “Other” answer category was added in Q3 2010.

0

5

10

15

PV (< 1 MW) PV (≥ 1 MW) Solar - CSP

Expected Return (%)

Developer Equity Expected Return

Tax Equity Partnership Expected Return
12

tax equity partnership percentages could reflect an increasing reliance on the 1603 Treasury 

grant instead of the ITC during the REFTI timeframe (Mendelsohn and Harper 2012).12

The majority of CSP respondents leveraged their balance sheets to finance projects (Figure 21), 

implying the projects either had well-capitalized sponsors or experienced difficulties tapping the 

tax equity market.13 Additionally, it may indicate the utilization of the 1603 Treasury grant (an 

incentive that does not require a tax equity partner to monetize).

 12 The 1603 Treasury grant allows developers to monetize the value of the ITC, effectively reducing the need for 

tax equity. 13 CSP is regarded as a higher risk technology with more capital intensive project costs than PV.

Figure 17. PV <1 MW aggregate financial 

structure

Total responses: 78

Figure 18. PV <1 MW financial structure trend

Total responses: 78

Figure 19. PV ≥1 MW aggregate financial 

structure

Total responses: 48

Figure 20. PV ≥1 MW financial structure trend

Total responses: 48

Balance 

Sheet

60%

Tax Equity 

Partnership

23%

Lease

10%

Other

7%

0%

20%

40%

60%

80%

100%

Q409 Q110 Q210 Q310 Q410 1H11 2H11

Other

Lease

Tax Equity

Partnership

Balance

Sheet

Balance 

Sheet

21%

Tax Equity 

Partnership

41%

Lease

21%

Other

17%

0%

20%

40%

60%

80%

100%

Q409 Q110 Q210 Q310 Q410 1H11 2H11

Other

Lease

Tax Equity

Partnership

Balance

Sheet
13

Figure 21. CSP aggregate financial structure

Total responses: 5
14

6 Debt

6.1 Debt-to-Capital Ratio and Cost of Debt

As shown in Figure 22, debt-to-capital ratios and cost-of-debt trends for smaller-scale PV have 

been in decline since Q1 2010. This chart seems to indicate that the third-party ownership model, 

which does not utilize debt to finance PV systems, has grown to a significant share of the market. 

In fact, out of the four participants that responded to the debt-to-capital ratio and cost-of-debt 

questions for small-scale PV in the latter half of 2011, all four indicated that no debt was used to 

finance their systems (hence, 2H 2011 data is not displayed).

Figure 22. PV <1 MW weighted average debt-to-capital ratio, all-in cost of debt, 

and Baa corporate bond yields (St. Louis Federal Reserve)

Debt ratio responses: 44

Debt cost responses: 40

Debt-to-capital ratios for large-scale PV varied, ranging from 70% to 30% (Figure 23). The costof-debt trend is more telling in Q1 2010, reaching a high of 8.8% before gradually settling just 

above 6%. This declining cost of debt could indicate the increasing use of one or more of the

incentives authorized in the American Recovery and Reinvestment Act of 2009, such as the 1703 

loan guarantee program.

14

The cost-of-debt trends for smaller-PV categories generally tracked above Baa bond yields until 

Q4 2010 when both small and large PV reported declines in debt interest rates.15 This could 

reflect improved financial market conditions or a reduction in perceived project risk from the 

financial community as more solar projects come online.

 14 Debt ratios may be skewed as projects receiving loan guarantees from DOE might have supplemented tax equity 

investment with debt given the more favorable terms.

15 Moody’s Baa-rated corporate bonds were chosen to illustrate debt spreads because of their comparable level of 

perceived risk. Baa is the lowest rating still considered to be “investment grade.”

0

1

2

3

4

5

6

7

8

0

10

20

30

40

50

60

70

Q409 Q110 Q210 Q310 Q410 1H11

Debt, Bond Rate (%)

Debt to Capital (%)

Debt / Total Capital All-in Cost of Debt Baa Corp Bond Rate
15

Figure 23. PV ≥1 MW weighted average debt-to-capital ratio, all-in cost of debt, 

and Baa corporate bond yields (St. Louis Federal Reserve)

Debt ratio responses: 47

Debt cost responses: 45

6.2 Cost of Debt Versus Cost of Tax Equity

Figures 24 and 25 illustrate debt is a less-expensive financing option for developers. 

Interestingly, tax equity yields for the two project scales appear to be trending in opposite 

directions. This could be occurring for a number of reasons: tax equity investors are becoming 

more comfortable with the risk profiles of smaller-scale pooled projects, transactional costs are 

declining (likely due to increased standardization), and/or competition is increasing among the 

investment community.

The gradual decline from Q1 2010 and rebound in later time periods will be interesting to follow 

for small-scale PV going forward, especially if panel prices continue to get squeezed and project 

sizes decline after the expiration of the 1603 grant and the loan guarantee program. (No smallscale PV respondents indicated debt load in 2H 2011.)

Figure 24. PV <1 MW weighted average cost of debt and tax investor equity

Debt responses: 40

Equity responses: 58

0

2

4

6

8

10

0

10

20

30

40

50

60

70

80

Q409 Q110 Q210 Q310 Q410 1H11 2H11

Debt to Capital (%)

Debt, Bond Rate (%)

Debt / Total Capital All-in Cost of Debt Baa Corp Bond Rate

0

2

4

6

8

10

12

14

16

Q409 Q110 Q210 Q310 Q410 1H11 2H11

Percent (%)

Expected Tax Equity Investor Return Cost of Debt
16

Figure 25. PV ≥1 MW weighted average cost of debt and tax investor equity

Debt responses: 45

Equity responses: 52

6.3 Debt Term and Coverage Ratio

Response limitations prevented trend analysis on debt service coverage ratios (DSCR), so 

weighted averages for the entire REFTI timeframe (by technology) are presented in Table 1. The 

lower debt terms for small-scale PV and CSP are interesting to note. Shorter debt terms usually 

imply higher perceived risk; thus, the similarity in debt terms between small PV and CSP 

projects would seem to indicate similar project risk—both of which are higher than large PV.

The shorter terms may also be a reflection of the lower credit quality of the off-takers for nonutility-scale PV (typically commercial entities or homeowners) and/or the increased technology 

risk in the case of new CSP projects. While CSP off-takers (typically utilities) mostly have 

investment-grade ratings and can borrow for longer tenors, they still must contend with 

technology risks.

Table 1. DSCR Weighted Averages for Solar Technologies

Project 

Type

Debt Term 

(yrs) DSCR

PV <1 MW 12.1 1.3

PV ≥1 MW 18.3 1.3

CSP 12.1 1.4

0

2

4

6

8

10

12

14

16

Q409 Q110 Q210 Q310 Q410 1H11 2H11

Percent (%)

Expected Tax Equity Investor Return Cost of Debt
17

7 Soft Costs

In 2H 2011, REFTI began collecting data on “soft costs” (i.e., project costs deriving from

engineering, construction, and legal fees—not module costs). For small PV, soft costs totaled 6% 

of all project costs; engineering and legal fees accounted for almost three-quarters of this

(Figure 26). Larger PV projects reported higher soft-cost ratios around 10%, on par with biomass 

electric. “Interest During Construction” registered as the highest cost at 3.7% of total project 

costs. Higher project soft costs can also increase the potential for cash leakages to occur if the 

project is delayed or takes longer than originally planned.

Figure 26. Total project “soft costs” as a percentage of total project costs

Small PV responses: 6

Large PV responses: 14

0.5 1.3 1.7

3.0

1.5

2.5

3.3

0.9

3.0

0.5 3.5

0.5

2.2

2.5

2.5

0.5

0.5

3.7

3.5

1.5

0.5

0.5

1.8

3.0

1.5

0

2

4

6

8

10

12

14

16

Wind PV (< 1 MW) PV (≥ 1 MW) Geothermal Biomass -

Elec

Percent of Total Project Costs

Construction

Insurance

Interest During

Construction

Debt Set-up Fees

Engineering Fees

Legal Fees
18

8 Summary

The goal of REFTI has been to increase the transparency of the RE project finance realm through 

the requisition and voluntary reporting of market participants. REFTI has collected a significant 

amount of non-publicly available RE project finance information since Q4 2009. The majority of 

participants have been from the solar market. Respondents to the questionnaires that eventually 

feed into the REFTI dataset provide their information on a confidential and voluntary basis and 

responses are not validated by NREL. 

The following are some of the key solar project finance metrics and trends recorded since REFTI 

began in late 2009. A much larger dataset can be reviewed at financere.nrel.gov/finance/refti.

• An estimated 2,300 projects reported closing financing in REFTI from Q4 2009–

2H 2011, accounting for 2,400 MW of capacity additions.

• Financing-related challenges (e.g., PPA issues, tax equity, raising capital, and access 

to government incentives) accounted for the majority of reported barriers to solar 

development for all projects. Innovations in project financial structure continue to 

occur, inferably as a response to these barriers.

• LCOE for small-scale systems appear to be tracking U.S. average retail electricity 

rates. Large-scale systems exhibit declining LCOE (perhaps realizing cost advantages 

as the market matures) on a course to grid parity with commercial electricity rates. 

• REFTI shows installed cost reductions falling at a faster rate than module price 

decline; this may indicate BOS cost reductions at work.

• The proportion of tax equity for both large- and small-scale PV rebounded 

significantly in 2H 2011. Expected returns trend higher for large PV and remain 

above debt costs on a comparative basis.
19

References

Federal Reserve Bank of St. Louis. “Federal Reserve Economic Data.” Accessed August 1, 

2011: http://research.stlouisfed.org/fred2/.

Mendelsohn, M. (2010). “A Chicken in Every Pot? Is There Enough Tax Equity to Sustain the 

RE Market.” NREL. Accessed August 25, 2011:

http://financere.nrel.gov/finance/content/chicken-every-pot-there-enough-tax-equity-sustain-remarket.

SEIA. (2012). U.S. Solar Market Insight Report: Q2 2012. Solar Energy Industries Association 

and GTM Research. 

SEIA. (2011). Solar Market Insight: 2010 Year in Review Executive Summary. Solar Energy 

Industries Association and GTM Research. 

U.S. Energy Information Administration. (EIA 2012). Electricity Data. Average Retail Price of 

Electricity to Ultimate Consumers (By End Use Sector). Available at:

http://www.eia.gov/electricity/data.cfm#sales.

For a glossary of project finance terms used in this report, please visit the NREL Renewable 

Energy Project Finance website at https://financere.nrel.gov/finance/content/glossary.