NREL is a national laboratory of the U.S. Department of Energy
Office of Energy Efficiency & Renewable Energy
Operated by the Alliance for Sustainable Energy, LLC
This report is available at no cost from the National Renewable Energy
Laboratory (NREL) at www.nrel.gov/publications.
Contract No. DE-AC36-08GO28308
Technical Report
NREL/TP-6A20-76881
July 2020
Current and Future Costs of Renewable
Energy Project Finance Across
Technologies
David Feldman
,
1
Mark Bolinger,
2
and Paul Schwabe
1
1
National Renewable Energy Laboratory
2
Lawrence Berkeley National Laboratory
NREL is a national laboratory of the U.S. Department of Energy
Office of Energy Efficiency & Renewable Energy
Operated by the Alliance for Sustainable Energy, LLC
This report is available at no cost from the National Renewable Energy
Laboratory (NREL) at www.nrel.gov/publications.
Contract No. DE-AC36-08GO28308
National Renewable Energy Laboratory
15013 Denver West Parkway
Golden, CO 80401
303-275-3000 • www.nrel.gov
Technical Report
NREL/TP-6A20-76881
July 2020
Current and Future Costs of Renewable
Energy Project Finance Across
Technologies
David Feldman,
1
Mark Bolinger,
2
and Paul Schwabe
1
1 National Renewable Energy Laboratory
2 Lawrence Berkeley National Laboratory
Suggested Citation
Feldman, David, Mark Bolinger, and Paul Schwabe. 2020. Current and Future Costs of
Renewable Energy Project Finance Across Technologies. Golden, CO: National
Renewable Energy Laboratory. NREL/TP-6A20-76881.
https://www.nrel.gov/docs/fy20osti/76881.pdf
.
NOTICE
This work was authored in part by the National Renewable Energy Laboratory, operated by Alliance for Sustainable
Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. Funding
provided by U.S. Department of Energy Office of Energy Efficiency and Renewable Energy Office of Strategic
Programs and Solar Energy Technologies Office. The views expressed herein do not necessarily represent the
views of the DOE or the U.S. Government.
This report is available at no cost from the National Renewable
Energy Laboratory (NREL) at www.nrel.gov/publications
.
U.S. Department of Energy (DOE) reports produced after 1991
and a growing number of pre-1991 documents are available
free via www.OSTI.gov
.
Cover Photos by Dennis Schroeder: (clockwise, left to right) NREL 51934, NREL 45897, NREL 42160, NREL 45891, NREL 48097,
NREL 46526.
NREL prints on paper that contains recycled content.
iii
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Acknowledgments
This work was authored by the National Renewable Energy Laboratory, operated by Alliance
for Sustainable Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No.
DE-AC36-08GO28308. Funding provided by U.S. Department of Energy Office of Energy
Efficiency and Renewable Energy Office of Strategic Programs and Solar Energy Technologies
Office.
The authors would like to thank the following individuals for their thoughtful reviews and
comments on this work: Paul Donohoo-Vallett (DOE), Rebecca Jones Albertus (DOE), Doug
Arent (NREL), Jay Bartlett (Resources for the Future), Philipp Beiter (NREL), Dan Bilello
(NREL), Elaine Hale (NREL), Parthiv Kurup (NREL), Robert Margolis (NREL), Mike Meshek
(NREL), Gian Porro (NREL), Edward Settle (NREL), Rocio Uria Martinez (Oak Ridge National
Laboratory), Laura Vimmerstedt (NREL), and Ryan Wiser (Lawrence Berkeley National
Laboratory).
iv
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List of Acronyms
ATB Annual Technology Baseline
BNEF BloombergNEF
CSP concentrating solar power
DOE U.S. Department of Energy
DSCR debt service coverage ratio
EEI Edison Electric Institute
EIA US. Energy Information Administration
FRED Federal Reserve Economic Data
GW gigawatt
IOU investor-owned utility
IPP independent power producer
IRR internal rate of return
ITC investment tax credit
LADWP Department of Water and Power
LCOE levelized cost of electricity
LIBOR London Inter-Bank Offered Rate
MACRS modified accelerated cost recovery system
NREL National Renewable Energy Laboratory
OPPD Omaha Public Power District
POU publicly owned utility
PPA power purchase agreement
PSEG Public Service Enterprise Group
PTC production tax credit
ROE return on equity
RoR rate of return
SoBRA Solar Rate Base Adjustment
SMUD Sacramento Municipal Utility District
SOFR Secured Overnight Financing Rate
WACC weighted average cost of capital
v
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Executive Summary
This report documents a consistent set of technology-specific U.S. financing cost benchmarks
for renewable and conventional energy technologies. The benchmarks are intended for use in
the National Renewable Energy Laboratory’s Annual Technology Baseline (ATB), a cross-
technology modeling and analysis framework of current and projected future cost of electric
generation and storage technologies.
1
Renewable energy technologies covered in the ATB
include land-based wind, offshore wind, utility-scale solar photovoltaic (PV), distributed PV,
concentrating solar power (CSP), geothermal, and hydropower; conventional technologies
covered include natural gas, coal, nuclear, and biopower.
2
Because ATB develops independent
projections of the change in renewable energy costs and characteristics of new generating assets
over time—while relying on other sources for conventional electric generation technologies—we
focus our analysis reported here primarily on these renewable energy technologies, estimating
both current and future financing costs to 2030. We also benchmark financing costs for new
natural gas generation facilities, as they represent the vast majority of all recently installed
conventional electricity generation.
3
In all cases, the goal is to portray consistent, representative
financial transactions and financing terms.
While there is a wide variety of financial ownership structures and individual project
characteristics for U.S. electric generation assets, we benchmark current finance costs for assets
owned by independent power producers (IPPs) because this ownership status represents most
new electric generation assets in the United States, particularly for renewable energy plants. IPPs
use tax equity arrangements as the primary financial arrangement for most U.S. renewable
energy assets, without the need for external financial partnerships. We benchmark IPPs primarily
to simplify the complexity of formulating a common set of financial assumptions for a variety of
technologies over time and to reflect that federal renewable tax credits are phasing down over the
next few years.
4
We also estimate future changes to finance costs from the planned expiration of
tax credits and a likely increase in interest rates from current historical lows, as both are assessed
to be fairly certain and easy to quantify. Lastly, we benchmark financial costs for renewable
energy assets assuming these projects sell their electricity through long-term power contracts, or
1
The financing cost benchmarks are used in ATB to calculate levelized cost of energy for each technology over time
and can be more generally used in other analyses that require current or future financing inputs for various
technologies.
2
While biopower can be considered a renewable energy technology, NREL does not perform research in that area;
biopower is treated in the ATB similar to conventional electric generation technologies.
3
Feldman and Margolis (2020) report that from 2010 to 2019, 79% of conventional U.S. electric generation
technology capacity additions (including biomass) were natural gas facilities.
4
Other reasons for not modeling tax equity transactions include that not all owners of electric generating assets enter
into tax equity arrangements, and that far fewer will do so in the future given the current phasedown of federal tax
credits. In addition, despite tax equity having a relatively low internal rate of return (IRR) of 6%–8% according
to Norton Rose Fulbright (2020a) compared to the cost of equity estimated in this report ranging from 7.5% to 10%,
the costs and complexity of tax equity transactions make them more inefficient and also mask the transparency
required for cross-technology comparisons over time, given different emphasis on different metrics. For example, a
tax equity provider may be more interested in its return on investment (ROI)—that is, the total amount of return it
receives in excess of its initial investment, regardless of time—than its rate of return (RoR) or internal rate of return
(IRR; i.e., the annualized return of an investment over a period of time). For example, investors in a solar project
may receive a considerable portion of their initial investment back in the first year in the form of tax credits and
depreciation expense benefits, and nearly all their return in the first five years of an investment, so that the IRR
does not properly convey the amount of money made on a transaction to the same degree as ROI.
vi
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power purchase agreements (PPAs); IPP financing structures in the United States are currently
based primarily on projects obtaining these contracts before receiving construction funding.
Natural gas plants are typically not able to obtain contracts of such a long duration, and so we
benchmark natural gas plants assuming quasi-merchant electricity sales. However, there are
many other factors that could affect financing costs that are less certain to occur and are more
difficult to quantify in terms of their impact; we discuss these additional factors in the report, but
we do not incorporate them into future estimates of financing costs.
We collect data from a variety of sources that have exposure to different renewable and
conventional energy technology financings, both in the United States and abroad. Sources
include confidential industry interviews with renewable energy project developers, owners,
financiers, consultant, and analysts; IPP public filings; public and privately reported project-level
financial data; and government-reported interest-rate data. The vast majority of all research was
performed before the novel coronavirus pandemic and therefore the benchmarks do not capture
any change, now or in the future, caused by it. Table ES-1 (next page) summarizes the identified
financial assumptions by technology during a project’s operation for an IPP-owned electric
generation asset, incorporating our current benchmarks with future changes in financing costs
discussed above. The electricity sales are categorized as power purchase agreements (PPAs) or
quasi-merchant.
We combine these assumptions
5
with the 2020 ATB project cost, operation and maintenance
cost, capacity factor, tax rate, and lifetime assumptions and calculate a projected weighted
average cost of capital (WACC) for the different technologies, as summarized in Figure ES-1
(page viii).
6
Under these assumptions, the initial financing term WACC on technologies with tax credits
decreases as these credits phase out. The after-tax benefit that tax credits provide will—all else
being equal—be replaced by a greater amount of cash revenue (e.g., via higher PPA prices),
which in turn will allow greater leverage. And because debt is typically less costly than equity,
this shift in capital structure toward more debt will lower overall financing costs (i.e., WACC),
thereby partially mitigating the loss of tax benefits. WACC subsequently increases from 2025 to
2030 as interest rates rise. We project an increase consistent with the Congressional Budget
Office (CBO) estimate of the increase in 10-year Treasury bond yields from 2019 (2.1%) to 2030
(3.1%, or a 100 basis point increase) in all-in construction and term debt interest rates by 2030
(CBO 2020). WACC also varies by technology; we estimate that solar PV and wind electricity
generation assets have lower cost of capital, owing to lower equity return expectations and
higher leverage. It is also important to keep in mind that while financing costs can vary by
technology, they currently also vary greatly (1) by project ownership (independent power
producer versus investor-owned utility versus publicly owned utility) and (2) based on the
individual characteristics of a project, its owner, and when and where it is built.
5
We choose 2025 as the starting point for the interest rate increase to simplify calculations and assumptions, given
that 2025 is when all tax credits will have expired or reverted to their lower value. This is a reasonable assumption
given the recent announcement that the Federal Reserve plans to keep interest rates near zero through 2022
(Timiraos 2020).
6
The 2020 ATB also has cases that reflect no consideration of tax credits and no change in interest rate. For these
cases, we ran separate leverage calculations, but input the same cost of equity and debt.
vii
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Table ES-1. Summary of Current and Future Financial Assumptions by Technology
Construction Operation
Technology
Electricity
Sales
After-
Tax
Levered
Equity
Returns
Debt
Interest
Rate:
2018/2030
Leverage
(i.e. debt
fraction)
After-
Tax
Levered
Equity
Returns
18-Year
Term Debt
Interest
Rate:
2018/2030
Leverage:
2018/2030
land-based
wind
power
purchase
agreement
(PPA)
11.0% 4.0%/5.0% 80% 9.0% 4.0%/5.0% 32%/66%
offshore
wind
PPA
12.0% 4.0%/5.0% 80% 10.0% 4.0%/5.0% 48%/67%
utility PV PPA 9.75% 4.0%/5.0% 80% 7.75% 4.0%/5.0% 52%/65%
residential
and
commercial
PV
PPA
10.75% 4.0%/5.0% 80% 8.75% 4.0%/5.0% 54%/67%
CSP PPA 12.0% 4.0%/5.0% 80% 10.0% 4.0%/5.0% 46%/58%
geothermal
PPA pre-
drilling:
15.0%
post-
drilling:
10.0%
4.0%/5.0%
pre-
drilling:
0%
post-
drilling:
75%
10.0% 4.0%/5.0% 58%/59%
hydropower PPA 12.0% 4.0%/5.0% 80% 10.0% 4.0%/5.0% 65%/70%
natural gas
quasi-
merchant
12.0% 5.0%/6.0% 80% 10.0%
5.0%/6.0%
73%
viii
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Figure ES-1. WACC of different technologies, 2018–2030
ix
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Table of Contents
1 Introduction ........................................................................................................................................... 1
2 IPP Ownership .................................................................................................................................... 11
2.1 Construction Financing ........................................................................................................... 11
2.2 Term Financing ....................................................................................................................... 12
2.2.1 Term Debt ...................................................................................................................... 12
2.2.2 Debt Service Coverage Ratio ......................................................................................... 15
2.2.3 Term Equity ................................................................................................................... 17
2.3 Summary of Current IPP costs ................................................................................................ 18
3 Utility Financing .................................................................................................................................. 20
3.1 IOU Financing ......................................................................................................................... 20
3.2 Publicly-Owned and Cooperative Utility Financing ............................................................... 22
3.3 Qualitative Comparison of IPPs, IOUs, POUs ........................................................................ 25
4 Future Financing................................................................................................................................. 27
4.1 Changes in Interest Rate .......................................................................................................... 27
4.2 Changes in Tax Credits ........................................................................................................... 28
4.3 Other Factors that May Influence Future Financing Costs ...................................................... 30
4.4 Summary of Financing Cost Changes Over Time ................................................................... 32
5 Conclusion .......................................................................................................................................... 36
References ................................................................................................................................................. 37
x
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List of Figures
Figure ES-1. WACC of different technologies, 2018–2030 ...................................................................... viii
Figure 1. Financial risk by technology .......................................................................................................... 2
Figure 2. U.S. utilities by number of companies (left) and millions of customers (right), 2017 .................. 3
Figure 3. Percentage of new U.S. electric generation capacity owned, by company type, beginning service
from 2010 to 2018 .................................................................................................................... 4
Figure 4. Percentage of new U.S. hydropower capacity owned, by company type and system size,
beginning service from 2010 to 2018 ....................................................................................... 5
Figure 5. History of debt interest rates and components ............................................................................. 14
Figure 6. Empirical all-in term debt interest rates for loans initiated over time, by technology ................. 15
Figure 7. Empirical DSCR data at different probability of exceedance levels, by technology ................... 16
Figure 8. Empirical data and medians of the after-tax levered cost of equity, by technology .................... 17
Figure 9. IOU’s average ROE and investment grade corporate debt yield, 2010 to 2019 .......................... 21
Figure 10. Characteristics of municipal bonds ............................................................................................ 23
Figure 11. Comparison of 3% tax-exempt debt and equivalent taxable yields ........................................... 24
Figure 12. Revenue bond yields, 2017–2019 .............................................................................................. 25
Figure 13. Tax credit assumptions for electric generating assets, by online date ....................................... 28
Figure 14. Leverage assumed in LCOE modeling as tax credits phase down ............................................ 29
Figure 15. Leverage of global renewable energy projects, by technology ................................................. 29
Figure 16. WACC of different technologies, 2018–2030 ........................................................................... 35
List of Tables
Table ES-1. Summary of Current and Future Financial Assumptions by Technology ............................... vii
Table 1. Top Ten U.S. IPPs, by Technology Capacity (as of February 2020) .............................................. 6
Table 2. Summary of Current IPP Financial Assumptions ......................................................................... 18
Table 3. Capital Structure, Return, and WACC Estimates for IOUs, 2010–2019 ...................................... 22
Table 4. Comparison of 1%–5% Tax-Exempt Debt and Equivalent Taxable Yields ................................. 24
Table 5. Qualitative Comparison of Different Financing Approaches by IPPs, IOUs, and POUs ............. 26
Equation 1. WACC Formula ....................................................................................................................... 32
Table 6. Summary of Current and Future Financial Assumptions by Technology ..................................... 34
1
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1 Introduction
The purpose of the analysis reported here is to develop a consistent set of technology-specific
U.S. financing cost benchmarks for the renewable and conventional energy technologies. The
benchmarks are intended for use in the National Renewable Energy Laboratory’s (NREL’s)
Annual Technology Baseline (ATB),
7
a cross-technology modeling and analysis framework of
current and projected future cost of electric generation and storage technologies.
8
Renewable
energy technologies covered in the ATB include land-based wind, offshore wind, utility-scale
solar photovoltaic (PV), distributed PV, concentrating solar power (CSP), geothermal, and
hydropower; conventional technologies in the ATB include natural gas, coal, nuclear, and
biopower.
9
Because the ATB’s develops independent projections of the change in renewable
energy costs and characteristics of new generating assets over time—while relying on other
sources for conventional electric generation technologies—we focus our analysis primarily on
these renewable energy technologies, estimating both current and future financing costs to 2030.
We also benchmark financing costs for new natural gas generation facilities, as they represent
the vast majority of all recently installed conventional electricity generation.
10
In all cases, the
goal is to portray consistent, representative financial transactions and financing terms.
Various factors influence the financial costs associated with building, owning, and operating
an energy asset. Key factors include the amount of risk associated with achieving the investor’s
desired rate of return, the level of marketplace competition for available projects and sources
of capital (i.e., the balance of supply and demand),
11
and, to a lesser extent, the time and effort
required to arrange a financial transaction. Each technology has its own specific risk factors
during the construction and operation of plant, which may influence the underlying cost of
financing. These “technology risks” relate to the likelihood of completing construction
(including on-time and on-budget), and the likelihood of producing the expected amount of
electricity; such factors that might influence the latter include resource availability, equipment
failure, damage, underperformance, or operational failure. Figure 1, from Fitch Ratings (2015)
demonstrates the indicative risk to fully develop (i.e., “complete”) and operate different
renewable technologies. Solar PV has lower construction and operation risk, as it is modularly
built, involves few moving parts, and offers more predictable resource availability. Wind has
more moving parts, though is still somewhat modular in design, and so it has slightly higher
construction risk; however, because of more uncertainty in resource availability, it has more
operation risk. Geothermal, CSP, and hydropower plants require more engineering in design
7
https://atb.nrel.gov
8
The financing cost benchmarks are used in ATB to calculate levelized cost of energy for each technology over time
and can be more generally used in other analyses that require current or future financing inputs for various
technologies.
9
While biopower can be considered a renewable energy technology, NREL does not perform research in that area;
biopower is treated in the ATB similar to conventional electric generation technologies.
10
Feldman and Margolis (2020) report that from 2010 to 2019, 79% of conventional U.S. electric generation
technology capacity additions (including biomass) were natural gas facilities.
11
Lower perceived risk of cash flows to PV investors also affects the amount of marketplace competition because
it expands the number of investors willing to fund a project, thus increasing the supply of capital.
2
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
and operation, permitting requirements, are more site-specific, and in the case of geothermal
may have less certainty in resource availability.
Figure 1. Financial risk by technology
Source: Fitch Ratings 2015
Sizes of bubbles represents variation in risk.
Beyond technology risk, two other determinants of financing costs among energy projects are
project ownership and electricity sales agreement structure.
Project Ownership
In the United States, grid-tied energy generation assets are primarily owned by electric utilities
and independent power producers (IPPs). Electric utilities can be for-profit (i.e., investor-owned
utilities [IOUs], nonprofits [i.e., cooperatives], or publicly owned [POUs; i.e.; federal, state, or
municipally-owned]). Each owner type typically has different return expectations and faces
different rules and processes in terms of selling electricity and raising capital, which can
influence financing costs.
Additionally, some of these regulatory or organizational strategies may limit the number of
projects that can be owned by specific organizations (e.g., some co-ops may purchase the bulk of
their electricity generation from a third-party, and some public utility commissions discourage
utility ownership of electric generating assets in favor of a more market-based approach).
Ownership type also influences the ability to monetize tax benefits generated by projects. Certain
companies may be limited or even prohibited from using these tax benefits and may need
specific types of financial partners to invest in projects to take advantage of the benefits (i.e., tax
equity investors).
Additionally, though the overall price of electricity is not directly tied to the cost of capital,
it may be influenced by ownership in the case of utility-owned projects with tax attributes,
because of normalization requirements. Normalization accounting requirements diminish the
upfront stimulus of tax benefits by requiring utility owners to account for the benefits over the
High
3
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life of the project. Conversely, IPPs are for-profit corporations, operating within a more market-
based competitive landscape.
Electricity Sales Agreements
IPPs generate revenue by making short-term electricity sales either through wholesale markets or
via long-term contracts (i.e., power purchase agreements, or PPAs). Long-term contracts (e.g.,
10–30 years) are typically far less risky, as the future sale price is known, as long as generation
requirements are met. However, even if selling into the wholesale market, project owners may
also protect against future price uncertainty through financial hedges, which come in several
forms including synthetic PPAs, bank hedges, and proxy revenue swaps (Bartlett 2019). The
longer the hedge or PPA contract, the more certainty in the electricity revenue over the life of
a project. Typically, PPAs with electric utilities have longer terms than financial hedges and
“avoided cost” PPA contracts mandated under the Public Utility Regulatory Policies Act.
Electric utilities typically generate revenue through the sale of electricity to their customers.
What they can charge, and the return they are allowed to achieve, are regulated and are often
dictated by the rate-making process (i.e., the process in which utilities set electricity rates
for customers).
Because of the impact that asset ownership and electricity sales agreements have on financial
costs, we assess which types are most common in the U.S. market through the U.S. Energy
Information Administration (EIA) Form 860 (EIA 2019a) and BloombergNEF’s (BNEF’s) U.S.
Power Plant Stack (BNEF 2020a). As shown in Figure 2, while there are far fewer IOUs than
publicly owned or cooperative utilities, IOUs service the vast majority of customers in the
United States.
Figure 2. U.S. utilities by number of companies (left) and millions of customers (right), 2017
Source: EIA 2019b
4
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Though IOUs represent the majority of U.S. customers, IPPs owned the majority of new U.S.
generating capacity from 2010 to 2018 and therefore represent the majority of recent financial
transactions (excluding refinancing existing electric generation assets and upgrading or
repowering), as shown in Figure 3.
Figure 3. Percentage of new U.S. electric generation capacity beginning service from 2010 to 2018
owned, by company type
Source: EIA 2019a
Additionally, the IPP ownership percentage is significantly higher for renewable energy assets
than fossil assets, with the exception of hydropower facilities. However, as shown in Figure 4,
there is significantly more IPP ownership for new hydropower plants with capacities below 150
MW. From 2010 to 2019, approximately half of all new hydropower installed in the United
States had capacities under 150 MW, with the other half coming from one plant.
12
12
Additionally, the ATB represents hydropower plants of sizes below 150 MW.
5
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Figure 4. Percentage of new U.S. hydropower capacity beginning service from 2010 to 2018
owned, by company type and system size,
Source: EIA 2019a
A significant portion of IPPs are either large companies focused in the energy space—often
an unregulated arm of a regulated utility company—or financial infrastructure investment
institutions, and they often own generating assets of different technologies. Many are also
publicly-traded companies, which typically have access to lower-cost financing than private
companies. Table 1 shows the top ten IPPs by technology capacity within the United States at
the end of February 2020.
6
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Table 1. Top Ten U.S. IPPs, by Technology Capacity (as of February 2020)
(P: energy company with shares traded on a stock exchange; Pr: private energy company; F: financier; D: developer)
Rank
Land-based
Wind
Offshore Wind Utility-scale
PV
CSP Geothermal Hydropower Natural Gas
1 NextEra (P)
14.4 gigawatts
(GW)
Ørsted (P)
30 MW
ConEd (P)
2.1 GW
NRG Energy
(P) 0.7 GW
Energy Capital
Partners (F)
1.7 GW
Brookfield (P)
1.7 GW
Energy Capital
Partners (F)
27.6 GW
2 Iberdrola (P)
7.1 GW
Vineyard Wind
(P)
NextEra (P)
2.0 GW
Atlantica Yield
(F)
0.3 GW
Ormat
Technologies
(D)
0.8 GW
Exelon (P)
1.6 GW
Vistra Energy
(P)
25.7 GW
3 EDP (P)
5.0 GW
Wind Energy
Systems
Technology (D)
Southern Co.
(P)
1.7 GW
NextEra (P)
0.3 GW
Berkshire
Hathaway/
MidAmerican
(P)
0.4 GW
Engie (P)
1.4 GW
NRG Energy
(P) 24.6 W
4 Invenergy (P)
3.4 GW
Fishermen's
Energy (D)
Berkshire
Hathaway/
MidAmerican
(P)
1.3 GW
Energy Capital
Partners (F)
0.2 GW
AltaRock
Energy (D)
0.1 GW
ArcLight
Capital
Partners (F)
0.6 GW
LS Power (Pr)
12.8 GW
5 Enel (P)
3.2 GW
Equinor (D) Dominion
Energy (P)
1.3 GW
US
Renewables
Group (F)
0.1 GW
AES Corp. (P)
0.1 GW
LS Power (P)
0.5 GW
Exelon (P)
9.2 GW
6 Global
Infrastructure
Partners (F)
2.7 GW
— Capital
Dynamics (F)
1.0 GW
Acciona (P)
0.1 GW
EnergySource
(D)
0.1 GW
Emera (P)
0.3 GW
Riverstone (F)
9.0 GW
7 Electricite de
France (P)
2.6 GW
— Global
Infrastructure
Partners (F)
0.9 GW
— Enel (P)
0.1 GW
Riverstone
Holdings (F)
0.3 GW
Southern Co.
(P)
8.8 GW
7
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Rank
Land-based
Wind
Offshore Wind Utility-scale
PV
CSP Geothermal Hydropower Natural Gas
8 BlackRock (F)
2.4 GW
— AES Corp. and
AIM Co. (P)
0.8 GW
— — Enel (P)
0.2 GW
Public Service
Enterprise
Group, or
PSEG (P)
7.5 GW
9 RWE (P)
2.2 GW
— First Solar (D)
0.7 GW
— — JP Morgan (F)
0.2 GW
Tenaska (Pr)
7.2 GW
10 Pattern Energy
(D)
2.0 GW
— Canadian Solar
(D)
0.6 GW
— — Royal Dutch
Shell (P)
0.2 GW
ArcLight
Capital
Partners (F)
7.1 GW
Top-ten U.S.
IPP capacity
as a
percentage of
total U.S.
installed
capacity, by
technology
43% 100% 35% 100% 88% 7% 27%
As of the end of 2019, only one offshore wind facility, Block Island Wind Farm, had been installed; however, several were under active
development; The companies listed in italics are the owners of the offshore wind projects under active development.
Source: BNEF 2020a
8
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Even though many IPPs have large balance sheets, they often partner with additional equity
investors for certain projects, especially those with large tax benefits, such as those associated
with the federal investment tax credit (ITC) or production tax credit (PTC). Though many IPPs
can take advantage of some of (if not all) the tax benefits associated with projects, partnerships
may be more economical in many instances. These partnerships, also called tax equity
arrangements, offer lower-cost capital for a portion of the cost of eligible projects in exchange
for the associated tax benefits. However, tax equity participation also comes with the costs of
structuring, and arranging the complex financial arrangements, and removing them when they
are no longer needed. Norton Rose Fulbright (2020a) reported that approximately $12 billion in
tax equity was raised in both 2018 and 2019 for solar and wind projects, representing
approximately 40% and 55% of total project costs, respectively. Based on pricing data reported
by Lawrence Berkeley National Laboratory for solar (Barbose and Darghouth 2019; Bolinger,
Seel and Robson 2019) and wind (Wiser and Bolinger 2019), and on the notion that financial
closings can precede the commercial operation date of a plant by a year or more, we estimate that
these transactions contributed capital to the vast majority of solar and wind plants in 2018 and
2019.
IPP financing structures in the United States are also currently based primarily on having long-
term contracts. Bolinger, Seel and Robson (2019) report that from 2006 to 2019 there were only
a few IPP solar projects without a long-term contract (i.e., “merchant”); Wiser and Bolinger
(2019) report that 23% of wind projects installed in 2018 were merchant or quasi-merchant;
Uría-Martínez et al. (2020) reported that of the hydropower plants that received Federal Energy
Regulatory Commission licenses from 2007 to 2018 and are now operational or under
construction, none was reported as merchant;
13
and geothermal projects also primarily rely on
PPAs, with Hernandez, Richard, and Nathwani (2016) reporting data on approximately 1
gigawatt (GW) of geothermal PPAs. Natural gas plants are unable to get electricity price
contracts of the same length as renewable energy generation assets because of an inability (or
prohibitive cost) to lock in or hedge fuel prices for more than a few years. According to the EIA,
the average expiration date reported in 2019 for natural gas contracts for electricity generation
plants was October 2021—or a little over two years.
14
Renewable energy projects have little to
no fuel risks and are able to contract electricity for much longer periods —typically 10–30
years.
15
Though we focus on the risks associated with technology, ownership, and electricity sales, it is
important to note that there are a variety of other risks associated with projects, which are large
contributors to the wide variation in financing costs of individual projects. According to Feldman
et al. (2018) and Bartlett (2019), these risks include the:
• Political risk
• Regulatory uncertainty
• Development risk
13
An inability to obtain a PPA was cited as the primary reason for project cancellations.
14
The average expiration date for a coal contract in 2019 was July 2021.
15
Some renewable energy projects have recently contracted shorter-term contracts, increasing the percentage of cash
flow over the lifetime of a project that is uncontracted at the beginning of the contract (Norton Rose Fulbright
2019a).
9
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
• Government support (if any)
• Credit-worthiness of the project owner
• Credit-worthiness of the electricity offtaker
• Length of the contract (if any)
• Whether the electricity price is firm or changes with the market
• Supply and demand of competing electricity
• Underlying inflation rate
• Cost of the underlying base interest rate.
Additionally, financing costs can be influenced by economies of scale (e.g., some investment
sources have minimum investment thresholds), supply and demand of sources of financing, or
preexisting relationships between project developers and financiers. For these reasons, there is
a wide range in financing costs across the United States, even for the same types of project.
In summary, while there is a wide variety of financial ownership and electricity sales structures
and individual project characteristics for U.S. electric generation assets, most of them are owned
by IPPs, and a much higher percentage of renewable assets are owned by IPPs. While IPPs that
own conventional electric generating assets typically sell their power either into wholesale
markets or under short-term contracts, most renewable energy generation assets sell electricity
via long-term contracts. IPPs are typically large companies with big balance sheets (i.e., a
significant amount of assets [including cash] and equity, which can be used to directly fund
projects or raise more capital to fund projects) and access to low-cost capital, often through
public markets. However, the vast majority of renewable energy projects receiving tax credits
also receive a large percentage of funding (~40% for solar, 55% for wind) from tax equity
providers (Norton Rose Fulbright 2020a). Tax equity participation is likely to greatly diminish
as the tax credits phase out (or down), leaving ownership interest to come principally from large
IPPs that likely can raise more funding from debt providers than currently exists today. However,
electric utilities also own a significant share of new electric generating assets, including
renewable energy projects (although not as great a percentage as older, larger plants), and in the
case of hydropower, are the principal form of asset ownership. Utilities sell this power to their
customers via a regulated process, and they receive a regulated return. Looking into the future,
when all tax credits will have expired or reverted to their lower value, utility ownership of
renewable assets may increase as utilities are no longer hampered by normalization accounting
of tax benefits.
Based on this landscape, and on our emphasis on renewable energy, we focus most of our efforts
in benchmarking financing costs for a project owned by an IPP with sales governed by a long-
term electricity contract. For conventional technologies, we benchmark the financing costs of a
natural gas project owned by an IPP, without a long-term contract. While tax equity
arrangements are the primary financial arrangement for most U.S. renewable energy assets,
we benchmark the financing costs of an IPP that is able to use the tax benefits associated with tax
equity directly without the need for external financial partnerships. We do this for a variety of
reasons, but most notably to simplify the complexity of formulating a common set of financial
assumptions for a variety of technologies over time.
16
We also compare the financing costs of
16
Other reasons for not modeling tax equity transactions include that not all owners of electric generating assets
enter into tax equity arrangements, and far fewer will do so in the future given the current phasedown of federal tax
10
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
IPP ownership to the financing costs of IOUs and POUs. The vast majority of all research was
performed before the novel coronavirus pandemic and therefore the benchmarks do not capture
any change, now or in the future, caused by the pandemic.
credits. In addition, the costs and complexity of tax equity transactions make them relatively inefficient and also
mask the transparency required for cross-technology comparisons over time, given different emphasis on different
metrics. For example, a tax equity provider may be more interested in its return on investment (ROI)—that is, the
total amount of return it receives in excess of its initial investment, regardless of time—than its rate of return (RoR,
or IRR)—that is, the annualized return of an investment over a period of time. For example, an investors in a solar
project may receive a considerable portion of their initial investment back in the first year in the form of tax credits
and depreciation expense benefits, and nearly all their return in the first five years of an investment that the IRR
does not properly convey the amount of money made on a transaction to the same degree as ROI.
11
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
2 IPP Ownership
We collected data from a variety of sources that have exposure to different renewable and
conventional energy technology financings, both in the United States and abroad. Sources
include confidential industry interviews with renewable energy project developers, owners,
financiers, consultant, and analysts; IPP public filings; public and privately reported project-level
financial data; and government-reported interest-rate data. Doing so, we endeavored to
accurately represent typical financing costs for each technology as well as the differences, if any,
between technologies. Data points include:
• Construction financing
o After-tax cost of levered equity
17
during the construction of the asset
o Cost and amount of debt during the construction of the asset
• Term financing
o Required debt service coverage ratio (DSCR) that debt providers use to determine the
amount of debt (i.e., leverage) they would provide to a project during the operation of
the asset
o Cost-of-term debt—or a loan with a set payment schedule of interest and principal—
during the operation of the asset
o After-tax cost of levered equity during the operation of the asset.
2.1 Construction Financing
Based on confidential industry interviews, there is a premium of approximately 200 basis points
(2%) on the cost of equity during construction for each renewable energy project, relative to the
cost of equity during plant operation, to account for construction risk. The exception to this is the
construction financing costs for geothermal projects, where the cost of equity during construction
is separated into at least two stages. The first round of equity investment occurs pre-drilling of
site wells, where the resource potential is unknown and there is no long-term site control,
completed permit, or PPA in place. During this period, it is typically not possible to obtain
construction debt to finance development and pre-construction costs, and the cost of equity is
usually higher. Once the wells have been drilled and the geothermal resources found to be viable,
site control is in place, permits have been obtained, and a PPA has been contracted, the risk on
invested capital is greatly reduced, meaning the required equity return is lower and construction
debt can be obtained.
18
While all electric generation technologies have some form of initial
development risk before construction occurs in earnest, geothermal is somewhat unique in the
level of time, risk, and percentage of capital that must be expended before plant construction.
17
The after-tax cost of levered equity is the cash flows—after accounting for taxes—an investor requires to make
an equity investment in a project that is also funded through a loan (i.e., with leverage).
18
As mentioned before, finance varies significantly between projects. Ormat Technologies is a notable exception
to the geothermal construction financing described above. As one of the top two operators of geothermal projects
in the United States, Ormat Technologies finances the construction of its projects from a combination of short-term
corporate bonds, cash flow from operating projects, and lines of credit. Still, Ormat Technologies assesses a higher
cost of capital during construction than during plant operation.
12
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Interestingly, once a plant can proceed to construction, the cost of debt is relatively consistent
across technologies. According to Norton Rose Fulbright (2020a), interest during construction is
approximately 50 basis points lower than term debt. Though there is no operational cash flow on
which debt providers can depend on for payment, construction loans are significantly shorter in
nature than term loans, and construction debt is only provided to projects with guaranteed
financing once a project begins operation (and implements risk-limiting measures)—meaning the
risk is mostly tied to whether a project completes construction. Also, construction debt providers
do not fund the entire portion of construction costs, which motivates project owners to complete
construction or lose the funds they used during construction (typically 10%–25% and
representing the first dollars spent).
Because of the inherently greater construction risk associated with offshore wind, geothermal,
and hydropower technologies, we assume construction debt and term debt are priced the same
(i.e., are not 50 basis points lower than term debt).
2.2 Term Financing
2.2.1 Term Debt
Term debt—which is sourced primarily in the commercial bank market, but sometimes through
the bond market—makes up a significant portion of the capital stack for IPP project owners
using project finance. For deals involving third-party tax equity investors, term debt most often
takes the form of “back leverage,” by which the debt is secured not by the underlying project
assets but instead by the IPP-owner’s equity stake in the project company (i.e., back leverage is
secured and serviced only by the cash allocated by the project company—typically a special-
purpose LLC created solely to own the project—to the IPP sponsor over time). In contrast, under
the simplifying assumption of no third-party tax equity (i.e., that the IPP sponsor can make
efficient use of tax benefits on its own), term debt is typically secured by the project assets.
Historically, back leverage has been priced at a small premium to project-level debt (reflecting
the slightly inferior collateral position), but in recent years, increasing market liquidity (i.e., the
supply of capital outstripping demand) has all but erased this premium, and back leverage and
project-level debt are now widely considered to have essentially the same terms and conditions
(Norton Rose Fulbright 2020a).
The “all-in” or total interest rate charged on term debt is a function of three independent
components: the base rate, the bank spread, and the swap rate (Bolinger 2018). The base rate
is a short-term interest rate that can be thought of as a proxy for the bank’s cost of funds.
Historically, the three-month London Inter-Bank Offered Rate (LIBOR) has served as the base
rate for renewable energy projects using project finance in the United States. However, as a
result of a recent price-manipulation scandal involving LIBOR, the market is in the early stages
of a transition to a new base rate based on the Secured Overnight Financing Rate, or SOFR
(Norton Rose Fulbright 2020b).
13
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
The second component of all-in term debt interest rates, the bank spread, is simply the margin
that banks charge on top of the base rate (whether LIBOR or SOFR). The size of the bank spread
reflects several things, including the bank’s cost of funds (to the extent that the base rate is an
imperfect proxy for cost of funds), the risk of getting repaid (riskier projects typically have larger
bank spreads), market liquidity (more capital flowing typically means lower bank spreads, all
else equal), and profit margin. As such, the bank spread is the only interest rate component
whose magnitude is based, at least in part, on the underlying renewable energy asset being
financed—both the base rate and the swap rate (described below) are generic benchmarks that
are not at all tied to the underlying asset.
Adding the bank spread to the base rate yields a floating debt interest rate that will vary over
time as the base rate—a short-term interest rate—moves around, for example, with changes to
monetary policy (as shown in Figure 5, the three-month LIBOR has closely followed the
overnight federal funds rate over time). This floating interest rate is applicable mostly just for
short-term (e.g., six months to two years) construction debt, where the risk of significant changes
in the base rate are minor, given the short time frame.
For term debt of longer duration, however, most banks require borrowers to swap out the floating
interest rate for a fixed rate over the full term of the loan. This requires consideration of the third
component all-in interest rates—the fixed-for-floating swap rate (or just the “swap rate”) over
the applicable loan term. The swap rate is the fixed interest rate that banks demand be paid in
exchange for paying out the base rate (e.g., three-month LIBOR) over the life of a loan; as such,
it represents banks’ views on future movements in the base rate. Given that the borrower is
simultaneously paying the base rate (i.e., the first component of all-in interest rates) and also
being paid the base rate (as one-half of the swap transaction), the borrower’s base-rate exposure
cancels out altogether and the all-in fixed interest rate is comprised solely of the swap rate plus
the bank spread.
Figure 5 shows the daily history of all three underlying components, as well as the all-in floating
and fixed interest rates, going back to 2005. The overnight federal funds rate is included as well.
Though they do not always move in tandem, since early 2019, both the base rate and the 20-year
swap rate have moved lower, while bank spreads have—until very recently—held steady,
resulting in both floating and 20-year fixed interest rates below 4%. The recent market turmoil
caused by the novel coronavirus has pushed the base rate even lower (as the Federal Reserve has
cut the federal funds rate to 0%), though at the same time, bank spreads have moved higher by at
least 50 basis points, reflecting market uncertainty and liquidity concerns (Norton Rose Fulbright
2020c).
14
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Figure 5. History of debt interest rates and components
Sources: U.S. Federal Reserve Bank 2020; Intercontinental Exchange 2020; Norton Rose Fulbright 2020a
b.p: basis points
Whereas Figure 5 builds up a theoretical history of project finance interest rates from underlying
components, Figure 6 shows some empirical data points on debt interest rates from relatively
recent renewable energy project financings. Though there is clearly some spread depicted—
particularly in 2019, which is perhaps a function of the sharply declining interest rate
environment in that year, as shown in Figure 5—the empirical interest rates shown in Figure 6
are nevertheless roughly consistent with the trends shown above in Figure 5. Though all-in term
debt interest rates have fallen below 4% over the past year, our modeling analysis assumes a 4%
interest rate for all technologies, on the grounds that interest rates are unusually low at present
and that the inclusion of bank closing fees and necessary reserve accounts will likely push a sub-
4% rate up toward the 4% level regardless.
19
We also do not assume technology-specific interest
rates because we could not definitively differentiate each technology, given the limited data
spread. For example, land-based wind and utility-PV, which represent the majority of U.S. (and
global) renewable energy generation loans, overlap considerably in rates. In addition, our data set
appears to suggest geothermal projects tend to have higher rates and distributed PV have lower
rates; however, these technologies have much smaller sample sizes, there is still overlap with
other technologies, and there may be individual project-specific circumstances that push loans
higher or lower.
19
Various costs are associated with securing a loan. Banks often charge fees for arranging a loan, which may range
from 1% to 3% of the principal of the loan (Mendelsohn et al. 2012) estimated bank closing fees of 2.75%);
additionally, they may require that a borrower set aside cash up front into one or more accounts as a reserve to cover
unexpected fluctuations in cash flow. These arrangements effectively push the cost of a loan higher than the stated
interest on a loan.
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
Jan-05
Jan-06
Jan-07
Jan-08
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Jan-16
Jan-17
Jan-18
Jan-19
Jan-20
Fed Funds rate (with 25 b.p. target range since 2009)
20-year fixed interest rate (swap rate+bank spread)
Floating interest rate (LIBOR+bank spread)
20-year fixed-for-floating swap rate
Bank spread
3-month LIBOR
15
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Figure 6. Empirical all-in term debt interest rates for loans initiated over time, by technology
Each data point represents a collected value, which may include the capacity-weighted average rate for a company
or portfolio or an analyst estimated value.
Sources: Berkshire Hathaway Energy 2018; Terraform Power 2019, 2020; Brookfield Renewable Partners 2020;
Bank of America 2020; BNEF 2019; Guillet 2018; Norton Rose Fulbright 2020, 2019b, 2019c; Ormat
Technologies 2019, 2018
Table 2 (page 18) shows our construction and term debt interest rate assumptions for each
technology, in both 2018 and 2030. These assumptions are informed by a bottom-up buildup of
all-in interest rates from the underlying components described above (and shown in Figure 5),
Congressional Budget Office (CBO) interest rate projections (CBO 2020), as well as the
empirical interest rates shown in Figure 6. The modestly higher interest rates in 2030 are
consistent with CBO’s projection of a 100 basis point increase 10-year Treasury bond yields
from 2019 to 2030 (from 2.1% in 2019 to 3.1% in 2030), and reflect that interest rates are
currently at abnormally low levels and are therefore likely to increase in the future. For example,
at its June 2020 meeting, the Federal Reserve Bank’s Federal Open Market Committee projected
the overnight federal funds rate—a benchmark interest rate that is the Federal Reserve’s primary
monetary policy tool—will remain near 0% through 2022 but then increase to ~2.5% over the
longer run, five or six years from now (FOMC 2020). Though changes to the federal funds rate
do not flow through directly one-for-one to term debt interest rates (e.g., see Figure 5, above), in
general, tighter monetary policy (i.e., a higher federal funds rate) is associated with higher
interest rates across the board. This view is further supported by the U.S. Department of the
Treasury (Treasury) yield curve, which currently pegs the 10-year benchmark Treasury bond
yield at roughly 60 basis points above the one-month T-bill yield, implying a slight rise in
interest rates over the coming decade.
2.2.2 Debt Service Coverage Ratio
Though the all-in interest rate determines the cost of the loan, the size of the loan is governed by
the minimum debt service coverage ratio (DSCR) required by the lender. The DSCR is simply a
measure of the amount of net operating income that must be freely available over time to service
16
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
the loan; it both represents and dictates the size of the “cushion” required by the lender to ensure
the loan will be repaid—even under “worst-case” operating conditions.
The required DSCR is largely a function of the uncertainty surrounding future revenue generated
by the project. For renewable energy projects—which may have variable weather-dependent
output but often fixed-price PPAs in place—revenue uncertainty mostly boils down to resource
uncertainty (though it also depends on a host of other factors, including curtailment, availability,
and offtaker credit risk). As a result, lenders typically require a DSCR of 1.0 under a worst-case
or “P99” resource forecast (i.e., a long-term resource forecast that has a 99% probability of
exceedance). In other words, lenders typically require that even in the worst-case or most-
unlikely resource scenario, the project should still generate just enough net free cash to repay
the loan (i.e., a 1:1 ratio between of cash flow and debt service). In turn, this P99 DSCR of
1.0 translates into a P50 DSCR that is higher than 1.0, based on the gap (reflecting relative
uncertainties) between the P99 and P50 (i.e., median) resource projections. For solar PV projects,
P50 DSCRs of ~1.30 are common (Norton Rose Fulbright 2020a). For wind projects, P50
DSCRs tend to be higher (e.g., ~1.40) simply because wind resource projections are more
uncertain than solar resource projections (Norton Rose Fulbright 2020a).
Figure 7 shows empirical DSCR data gathered from various sources (and at different levels of
probability of exceedance), while Table 2 (page 18) shows our benchmark P50 DSCR
assumptions for each technology based on the empirical data in Figure 7. While certain data
points in Figure 7 were gathered from sources with information on one technology’s DSCR,
most data points come from data sources covering multiple technologies (and therefore offer
a comparative perspective).
Figure 7. Empirical DSCR data at different probability of exceedance levels, by technology
Sources: Norton Rose Fulbright 2019c, 2020a; Financier 1 2020; Financier 2 2020; Ormat Technologies 2020;
BusinessWire 2015; Credit Agricole 2018a, 2019b; Fitch Ratings 2015
17
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
2.2.3 Term Equity
While financing for IPP-owned electric generation assets comes from various sources and can
involve multiple owners including tax equity, we focus our analysis on the after-tax equity return
requirements of assets solely owned by IPPs. These large companies typically have access to
significant capital through ongoing operations and public capital markets; however, because debt
is almost always less costly than equity,
20
equity investments in electric generating assets only
cover the portion of the project not funded through debt—thus, representing “levered” returns.
Figure 8 summarizes 31 separate data points gathered from 15 sources for the levered after-tax
cost of equity by technology type. In some instances, unlevered equity returns were provided,
which we convert to levered via a derivation of the weighted average cost of capital (WACC)
formula.
21
For example, we calculate a 7.5% unlevered rate of return to be equivalent to a 10.5%
levered rate of return.
Figure 8. Empirical data and medians of the after-tax levered cost of equity, by technology
Error bars represent estimates given with ranges.
Sources: Bank of America 2020; BNEF 2019; Financier 3 2020; Financier 4 2020; Financier 1 2020; Financier 5
2020; Financier 6 2020; Financier 7 2020; Financier 8 2020; Financier 9 2020; Financier 10 2020; Nextera Energy
2019; Norton Rose Fulbright 2020a;
Ørsted 2018; Ormat Technologies 2020
As shown in Figure 8, utility-scale PV requires the lowest after-tax levered rate of return, with
a median of 7.75%, and is followed by land-based wind at 9.00%. This would seem to follow
the premium in perceived risk between utility-scale PV, with fewer moving parts and lower
predicted resource variability than land-based wind. For example, Fitch Ratings (2020) stated,
“more than a decade of analysis shows that solar resources are consistently more stable and
predictable than wind, resulting in less volatile revenues and generally higher ratings.”
Given the limited data points for the other technologies (i.e., offshore wind, CSP, geothermal,
hydropower, and natural gas), their overlapping data points, and the premium assessed over wind
20
Debt investors lend money for a predetermined period of time and have a legal claim to any assets up to the
amount borrowed, plus the interest, and that right supersedes that of the equity investor. Because there is more
certainty and seniority to their cash flow than equity investors, debt is typically a less expensive form of capital
than equity.
21
levered cost of equity (i.e. WACC) = unlevered cost of equity / equity capital contribution – cost of debt * (1 – tax
rate) * debt capital contribution / equity capital contribution. A 4.0% cost of debt, a combined effective corporate tax
rate of 25.7%, and a debt contribution of 40% were assumed.
18
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
and PV by data sources that provided multiple values, we assume a 100 basis point premium
over land-based wind. This premium is slightly lower than the premium reported by individual
data sources when comparing these technologies to onshore wind (which ranged from 120 to 150
basis points); however, the 100 basis point premium provides values more consistent with their
median data points. We were unable to obtain specific returns for distributed PV, but Norton
Rose Fulbright (2020a) estimates that tax equity rates for distributed PV are approximately 100
basis points higher than utility-scale PV transactions; therefore, we assume a similar premium for
after-tax levered equity returns. Though they are not included in Figure 8, we were also able to
obtain data on equity rates where the PPA offtaker is a corporation or the owner uses a financial
hedge; the data sources indicate a rate of return between 10% and 12% for wind and utility-PV
projects (Financier 11 2020).
2.3 Summary of Current IPP costs
Table 2 summarizes our financial assumptions by technology during the project’s construction
and operation. As noted in the table and above, the electricity sales for natural gas plants are
assumed to come from short-term quasi-merchant plants, unlike the long-term PPA sales
assumed for the renewable energy technologies. This is likely a large contributor to the higher
cost of equity and DSCR shown in Table 2.
Table 2. Summary of Current IPP Financial Assumptions
Construction Operation
Technology
Electricity
Sales
After-Tax
Levered
Equity
Returns
Debt
Interest
Rate
Leverage
After-Tax
Levered
Equity
Returns
18-Year
Term
Debt
Interest
Rate
P50
DSCR
land-based
wind
PPA 11.0% 3.5% 80% 9.0% 4.0% 1.40
offshore wind
PPA
12.0% 4.0% 80% 10.0% 4.0% 1.40
utility PV PPA 9.75% 3.5% 80% 7.75% 4.0% 1.30
residential
and
commercial
PV
PPA
10.75% 3.5% 80% 8.75% 4.0% 1.30
CSP PPA 12.0% 3.5% 80% 10.0% 4.0% 1.45
geothermal
PPA
pre-drilling:
15.0%
post-
drilling:
10.0%
4.0%
pre-
drilling:
0%
post-
drilling:
75%
10.0%
4.0%
1.45
hydropower PPA 12.0% 4.0% 80% 10.0% 4.0% 1.50
natural gas
quasi-
merchant
12.0% 3.5% 80% 10.0% 5.0% 1.45
19
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
These financial assumptions are used as input values to calculate the WACC in the 2020 ATB.
WACC is used in the ATB as the discount rate input to the capital recovery factor for the
levelized cost of electricity (LCOE) formula. There is some incongruity to this method, in that
the variables shown in Table 2 are inputs to project finance cash flow models, and those models
differ from the simple LCOE formula used in ATB. Using these inputs to derive the WACC that
feeds into the LCOE formula might create slightly lower finance costs, and thus lower costs of
electricity, than are warranted. For example, the WACC (and LCOE) formula assumes a steady
debt-to-equity ratio over the project life; however, in project finance, principal is typically paid
down, creating more equity in a project over time. Feldman and Schwabe (2018) examine this
issue.
20
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
3 Utility Financing
This section illustrates financing practices for utility ownership of power generation assets.
Though the ATB uses data under an IPP model, it is also important to characterize and quantify
the cost of financing utility-owned projects because utilities currently own a significant amount
of U.S. electric generating assets, including renewable energy assets, as demonstrated in
Section 1, and utilities may own a larger share of renewable energy assets in the future.
We describe two primary ownership types prevalent in the U.S. marketplace: privately-owned
IOUs and POU organizations such as municipals, power authorities or districts and cooperative
utilities and other variations. Under the utility-ownership model, IOUs or POUs may own some
or all of the electric generation required to serve their customers, as well as the transmission and
distribution infrastructure. In contrast to IPPs, utility financing practices and costs (with some
notable exceptions; e.g., Florida’s Solar Rate Base Adjustment) do not differentiate financing
cost by generation technology type; rather, the main driver for costs are regulatory restrictions
and allowances, availability of capital, and credit rating for each type of utility.
3.1 IOU Financing
IOUs provide electricity services to 72% of utility customers in the United States, which
represents 220 million Americans (EIA 2019b; EEI 2019a). IOUs’ business strategy and
electricity rates are regulated at varying levels by state utility commissions. Like IPPs, IOUs are
for-profit corporations that are taxable at the federal level; they are eligible to receive federal tax
benefits afforded to qualifying renewable energy project owners, including the PTC, ITC, and
modified accelerated cost recovery system (MACRS) benefits. Of the 47 U.S. IOUs tracked by
the Edison Electric Institute in 2018, 42 had directly tradable stock and 5 operated as subsidiaries
of parent corporations or other business variations (EEI 2019).
In the IOU ownership-model, we assume investment in a power generation asset reflects the
capital structuring and cost of capital for the utility overall, as the IOU’s regulatory body permits
it to recover costs from all its capital investments, irrespective of technology, including electric
generation assets.
22
Estimating representative financing costs requires three input parameters
specific to IOUs: (1) the average return on equity (ROE), (2) the average cost of debt, and (3) the
composition of debt and equity in the IOU’s capitalization.
A utility’s ROE is largely determined by its regulator and typically results from a rate case. The
average awarded ROE for IOUs has trended downward since the late 1990s largely because of
steady decreases in the economy-wide benchmark interest rates (see Figure 9). According to EEI
(2019a), the averaged awarded ROE for tracked IOUs fell from 10.54% in 2009 to 9.70% in
2019.
We estimate the cost of debt for IOUs using the range of IOU’s bond credit ratings from the
Edison Electric Institute (EEI) and aggregated corporate bond yields (i.e., stated interest rates)
reported by the Federal Reserve. EEI reports that as of 2019, 43 of the 45 IOUs were rated as
22
As mentioned previously, there are notable exceptions to this assumption where a regulatory authority permits
a utility to achieve a specific return from a specific type of investment. For example, through the use of a Solar Rate
Base Adjustment, or SoBRA, by several Florida utilities, the public service commission can approve the addition of
solar projects of a utility rate base without a full rate case.
21
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
“investment grade,” with two utilities rated BBB- (the lowest investment-grade rating), another
two rated A or higher (the highest investment grade ratings), and the remaining 39 with an
average credit rating of BBB. To construct the cost of debt for IOUs, we average reported yields
for the lowest and highest rated investment grade corporate bonds. The resulting average
corporate yield for 2019 was 3.9%, as noted in Table 3, but by Q4 2019, it had dropped to 3.5%
(EEI 2020; FRED 2020a, 2020b). Figure 9 shows the ROE and average investment grade
corporate bond yields from 2010 to 2019. The 10-year Treasury bond rate is shown to illustrate
the spread of ROE and debt yield relative to the benchmark government interest rate.
Figure 9. IOU average ROE and investment grade corporate debt yield, 2010 to 2019
Sources: EEI 2020; FRED 2020a, 2020b
IOU capital structure held steady from 2010 to 2019. The average capital structure of IOUs over
that period ranged from 43% to 47% equity, with the corresponding 53%–57% made up of debt
(EEI 2019b). Unlike the IPPs, IOUs traditionally do not partner with third-party tax equity
providers and instead may use the tax credit in-house, which is known as “self-sheltering.”
From the estimates of ROE, corporate bond yields, and capital structure, we calculate the annual
WACC for the IOU ownership model. Table 3 presents the estimated WACC for IOUs from
2010 to 2020, which range from 5.8% to 6.4%. The WACC in Table 3 is an after-tax value, as
the interest payments on debt are tax deductible for IOUs.
0%
2%
4%
6%
8%
10%
12%
14%
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
IOU Cost of Capital
Corporate Debt Rate (Spread over Treasury)
10 Year Treasury (Benchmark Interest Rate)
Approved Return on Equity (ROE)
22
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Table 3. Capital Structure, Return, and WACC Estimates for IOUs, 2010–2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Equity capitalization (%) 43.2 43.7 43.3 43.3 46.9 46.4 44.7 44.4 45.0 45.0
Debt capitalization (%) 56.7 56.3 56.8 56.7 53.1 53.6 55.4 55.6 55.0 55.0
Return on equity (%) 10.3 10.3 10.2 10.0 9.9 9.9 9.8 9.7 9.5 9.6
Debt interest rate (%) 5.5 5.2 4.3 4.7 4.5 4.4 4.2 4.1 4.4 3.9
Federal tax rate (%) 35 35 35 35 35 35 35 35 21 21
WACC (%) 6.5 6.4 6.0 6.1 6.2 6.1 5.9 5.8 6.2 6.0
3.2 Publicly-Owned and Cooperative Utility Financing
In addition to IOUs, EIA also classifies utilities as either public or cooperative. Public utilities
may include federal, state, or municipal electric service companies run by governmental entities.
Cooperative utilities are nonprofit organizations owned by their members. Although there are
important but subtle distinctions between public and cooperative utilities, we group these non-
IOUs together for the sake of simplicity as POUs.
POUs collectively serve more than 44 million customers and constitute the greatest number of
utilities by count in the United States. EIA (2019b) lists 812 cooperative utilities and 1,958
public utilities in the United States in 2017. POUs are owned by the community at-large or their
members rather than by equity investors or shareholders. This ownership structure does not
readily allow for capital to be raised through equity investment in the enterprise itself, such as
with IOU stock. Instead, the POU ownership model primarily raises capital through nontaxable
debt issuances with prespecified rates of returns to lenders.
POUs are generally eligible to issue nontaxable debt (also referred to as tax exempt debt)
through issuance of a specific type of bond, known as a municipal bond. The proceeds from a
nontaxable municipal bond issuance fund the costs of infrastructure projects including power
generation and promise a return to the lender (i.e., the bond’s investor) at a specified rate and
maturity date. More than $4.14 trillion dollars of municipal bonds were outstanding at year-end
2019 (SIFMA 2020).
Municipal bonds come in two primary forms—both are typically tax exempt. State and local
governments issue general obligation bonds for projects that do not generate revenue on their
own and require public taxation or voter approval (e.g., funding for schools and education).
In contrast, POUs generally issue revenue bonds to fund infrastructure projects with dedicated
revenue streams, such as power generation assets. The revenue from the project or the POU itself
is pledged to repay the bond costs. For purposes of this report, we focus on revenue bonds as the
main financing vehicle for POUs to raise capital for energy assets. Figure 10 illustrates key
differences between general obligation and revenue bonds.
23
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Distinguishing Characteristics
Issuer State and local
governments
Issuer Electric, gas, water,
and waste utilities,
transportation
authorities, hospitals
Pledged by Taxing authority of
issuer (limited and
unlimited), all legally
available resources
Pledged by Gross or net revenues
of the enterprise or
project
Purchasers/
investors
Retail (46%), mutual
funds (27%), banks
and credit unions (12%),
insurance (12%),
other (3%)
Purchasers/
Investors
Retail (46%), mutual
funds (27%), banks
and credit unions
(12%), insurance
(12%), other (3%)
Voter approval Yes Voter approval No
Tax exempt Interest Yes Tax exempt interest Yes
First issuance New York State
(1812)
First issuance New York State Port
Authority (1926)
Figure 10. Characteristics of municipal bonds outstanding year-end 2019
Sources: SIFMA 2020; Invesco 2019
Interest payments received on revenue bonds are generally exempt from federal income and
some state income taxes. POUs can therefore issue tax-exempt bonds with lower interest rates
and can remain competitive with higher yielding taxable bonds. The bond investor’s return
advantage of tax-exempt debt is illustrated in Figure 11. A tax-exempt bond with a stated interest
rate (i.e., yield) of 3% is equivalent to 4.62% taxable yield at the 35% marginal tax bracket and
5% taxable yield at the 40% marginal tax bracket.
23
Table 4 shows tax exempt yields from 1%
to 5% and the equivalent taxable yields.
23
The marginal tax yields in Figure 11 includes the net investment income tax rate of 3.8% that is applied to
individuals and trusts with income over statutory defined thresholds (Invesco 2019).
Municipal Bonds ($4.1 trillion)
General Obligation Bonds (33%)
Revenue Bonds (~67%)
24
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Figure 11. Comparison of 3% tax-exempt debt and equivalent taxable yields
Table 4. Comparison of 1%–5% Tax-Exempt Debt and Equivalent Taxable Yields
Tax-Free Yield % (Interest Rate) 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0
Equivalent Taxable Yield %
(35% Marginal Tax Bracket)
1.54 2.31 3.08 3.85 4.62 5.38 6.15 6.92 7.69
Equivalent Taxable Yield %
(40% Marginal Tax Bracket)
1.67 2.50 3.33 4.17 5.00 5.83 6.67 7.50 8.33
Source: Invesco 2019
Interest rates offered by revenue bonds vary according to both macroeconomic conditions and
bond-specific factors. Macroeconomic effects may include current interest rates, expectations of
future interest rates, investor demand for bonds or alternative investments, and other factors.
Bond-specific considerations might include service territory characteristics (e.g., condition of
utility assets, area wealth), utility financial strength, management metrics, legal provisions, and
term to maturity to name a few (Moody’s 2014).
POUs typically disclose key financial metrics such as bond issuance amounts and yield in annual
financing statements. We collected revenue bond yields from published financial statements
from 7 of the 20 largest POUs in the United States to construct a representative data sample of
POU bond financing rates (APPA 2019). POUs in the revenue bond data sample include the Salt
River Project, CPS Energy, the Los Angeles Department of Water and Power (LADWP), JEA,
Omaha Public Power District (OPPD), Austin Energy, and the Sacramento Municipal Utility
District (SMUD). Other POUs either did not report or issue revenue bonds during that time, or
they do not generally own power generation assets; or, the bond’s cost data were not easily
3.00% 3.00% 3.00%
1.62%
2.00%
TAX- FREE DEBT
3% INTEREST RATE
TAXABLE DEBT
35% MARGINAL TAX
TAXABLE DEBT
40% MARGINAL TAX
Investor Return Tax Expense
25
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
discernible from other long-term costs. Figure 12 shows the stated yield and maturity for 29
revenue bond issuances during the sample period. The length of term until maturity is denoted by
circle size. The range of interest rates (1.5%–6.5%) is narrow from 2017 to 2019, with maturities
ranging from 2.0 to 27.5 years.
24
The average interest rate and term in 2019 is ~4.1%, with ~16.6
years to maturity.
Due to the absence of equity capital in the POU financing model, proceeds from revenue bond
issuance typically fund 100% of a project’s upfront costs. The WACC under the POU ownership
structure in 2019 is therefore the average value of revenue bond yields in the data sample, or
4.1%.
.
Figure 12. Revenue bond yields, 2017–2019
Sources: Austin 2019; CPS Energy 2020; JEA 2019; LADWP 2020; OPPD 2019 SRP 2019 SMUD 2020
3.3 Qualitative Comparison of IPPs, IOUs, POUs
The preceding sections describe the capital contributions and the variations in costs of capital
from IPP, IOU, and POU financing models. Each of the different financing approaches have both
advantages and disadvantages. These considerations are highlighted in Table 5 (page 26).
As tax-paying entities, IPPs can utilize federal support mechanisms for certain renewables (i.e.,
PTC/ITC and MACRS) and can deduct interest payments from federal taxes, but they must pay
income taxes on profit. The tax treatment of IOUs generally follow IPPs except that IOUs have
difficulty using the federal support mechanisms for renewables to the maximum extent possible
because of tax normalization accounting rules.
25
POUs, by contrast, do not pay federal income
24
Refinancing revenue bonds before their maturity, a practice known as “refunding,” is a common practice.
25
Normalization accounting rules generally require IOUs to spread the value of the ITC over the operating life of
the asset when rate-basing the project, rather than inputting the benefit in the first year. IOUs are also required to
spread the accelerated deprecation benefit over a longer time frame (likely 12 years) than the typical five-year
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
2016 2017 2018 2019 2020
LADWP
SRP
CPS
SMUD
JEA
Austin
OPPD
27.5-year
maturity
2-year
maturity
26
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
taxes on revenue and can issue tax-exempt debt, but they accordingly are ineligible for federal
tax benefits. These differing ownership characteristics lead to different approaches to financing
renewable generation projects, each with different costs.
Table 5. Qualitative Comparison of Different Financing Approaches by IPPs, IOUs, and POUs
Consideration IPPs IOUs POUs
Income subject to federal and
state taxation
Yes Yes No
Can use federal tax benefits for
renewables (ITC or PTC)
Yes
Yes, subject to tax
“normalization”
accounting
No
Can use accelerated depreciation of
qualifying costs
Yes
Yes, subject to tax
“normalization”
accounting
No
Interest payments on taxable debt are
deductible from federal income taxes.
Yes Yes No
May issue debt exempt from federal
and some state income taxes
No No Yes
As shown in 26Table 5, IPPs, IOUs, and POUs have comparative advantages and disadvantages
in financing renewable energy projects. These considerations vary in terms of both magnitude
and direction of impact (i.e., cost advantage and disadvantages). In most cases, the IPP scenario
currently returns the lowest relative costs, owing to (1) inclusion of lower cost tax equity
(relative to shareholder equity assumption) and (2) the ability of IPPs to use the full stated value
of the ITC and five-year MACRS. As we model a future scenario without an ITC, however, we
see a smaller cost advantage between IPP and IOU ownership, as well as scenarios that reflect
POUs with as the lowest financing cost option. However, there are many variations and
combinations on these structures, including a recent Internal Revenue Service private letter that
clarified how IOUs can participate in tax equity financing without the normalization adjustment
that IOUs are exposed to in self-ownership.
The ATB uses an assumed IPP financing structure because the majority of new electric
generation assets, and the vast majority of new renewable energy generation assets, are owned by
IPPs. If the ATB used IOU or POU financing structures, it would likely increase the cost of
financing in the short-term for projects receiving tax credits. As the tax credits phase down, the
difference would likely be reduced and the POU financing structure, assuming 100% tax-exempt
debt financing and no corporate income taxes, might be less expensive. That being said,
individual circumstance, both currently and in the future, may make a specific type of ownership
the most economically viable; additionally, there may be other factors, beyond financial costs,
that would cause one financing type to be the preferred approach for electric generation asset
ownership.
MACRs schedule allows. In combination, these both negatively impact the overall value of these tax benefits to
IOU customers by extending the time to realize the full stated benefits.
27
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
4 Future Financing
A variety of factors will influence future financing costs for electricity generation technologies.
In this section, we estimate future changes to finance costs caused by the planned expiration
of tax credits and a likely increase in interest rates (from current historical lows), as both are
fairly certain and easy to quantify. However, there are many other factors that could affect
financing costs that are less certain to occur and/or are harder to quantify in terms of impact;
we discuss these additional factors below, but we do not incorporate them into future estimates
of financing costs.
4.1 Changes in Interest Rate
All-in interest rates on term debt are abnormally low by historical standards. As shown in Figure 5
(above), 20-year fixed interest rates had fallen to around 3% just prior to the novel coronavirus
outbreak (which has since roiled the markets). These historically low interest rates have been
enabled, in part, by reductions in the three-month LIBOR base rate, which followed the overnight
federal funds rate lower throughout 2019 as the Federal Reserve reversed and then began easing
its monetary policy stance. This monetary easing continued in 2020 in an attempt to combat the
economic decline caused by the novel coronavirus, culminating on March 15, 2020 with a 100
basis point reduction in the federal funds rate to the current target range of 0.00%–0.25%.
Although the Federal Reserve may eventually tighten monetary policy by raising the federal
funds rate once the economy recovers from the current pandemic-induced downturn, the markets
are not expecting that to happen any time soon. For example, trading activity in the federal funds
future contract on the Chicago Mercantile Exchange suggests market participants currently
expect the federal funds rate to remain at its current 0.00%–0.25% target range for at least
another nine months—i.e., through the March 17, 2021 meeting of the Federal Reserve’s Federal
Open Market Committee (CME Group 2020). And, as mentioned earlier, the Federal Reserve’s
Open Market Committee—i.e., the very group that controls the federal funds rate—projects that
it will remain at current levels through 2022 before eventually rising to a median projection of
2.5% over the longer run, in five or six years (FOMC 2020). An even longer period of sustained
easing is certainly possible—for example, Figure 5 shows that the federal funds rate (and with it,
the three-month LIBOR base rate) remained at or near 0% for an unprecedented seven straight
years from 2009 to 2015, in the wake of the Great Recession of 2008. The CBO estimated that
the 10-year benchmark Treasury bond yield will increase from 2.1% in 2019 to 3.1% in 2030—
an increase of 100 basis points (CBO 2020).
Given today’s combination of historically low interest rates coupled with uncertainty over how
long they will last, we project an increase consistent with CBO’s estimate of 10-year Treasury
bond yields from 2019 to 2030 (100 basis points across the board) in all-in construction and term
debt interest rates by 2030. This modest increase is generally consistent with the Federal
Reserve’s view that the federal funds rate will eventually move higher, and also with the
Treasury yield curve, which currently pegs the 10-year benchmark Treasury bond yield at
roughly 60 basis points above the one-month T-bill yield (implying a slight rise in interest rates
over the coming decade).
28
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
4.2 Changes in Tax Credits
Renewable energy project finance will also be significantly impacted by the ongoing phasedown
of federal tax credits. By providing a significant portion of a project’s after-tax return in the form
of a tax credit as opposed to cash revenue that can support and service debt, federal tax credits
like the PTC and ITC restrict the amount of debt that a renewable energy project can support.
Figure 13. Tax credit assumptions for electric generating assets, by online date
We assume eligible projects use the full duration of the "safe harbor" window in order to receive the maximum
tax credit level. We also assume offshore wind projects elect the ITC over the PTC in order to maximize
economic value (though there may, in reality, be a few projects that choose the PTC over the ITC, depending
on installed cost, anticipated capacity factor, and tax equity preferences). We never assume a 40% PTC (or
similar ITC percentage for offshore wind) because of the step back up to 60% in the following year. Eligible
hydropower facilities that receive the PTC include new power dams.
While both the PTC and ITC phase down over the next few years (Figure 13), the after-tax
benefit that each provides will—all else being equal—be replaced by a greater amount of cash
revenue (e.g., via higher PPA prices), which in turn will allow greater leverage. And because
debt is typically less costly than equity, this shift in capital structure toward more debt will lower
overall financing costs, thereby partially mitigating the loss of tax benefits. We use a cash flow
model, with the technology cost and performance input assumptions from the ATB, as well as
the financing assumptions in this report, to calculate project leverage by technology each year,
while maintaining the DSCR requirements. As shown in Figure 14, our modeling accounts for
the greater leverage that is possible as the PTC and ITC phasedown over the next few years.
29
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Figure 14. Leverage assumed in cash flow modeling as tax credits phase down
Because solar and geothermal projects benefit from a permanent 10% tax credit, their respective
leverages tend to be at the lower end of the post-phase-out range (i.e., from 2025 to 2030). In
general, the calculated leverages shown in Figure 14 for all technologies over this post-phase-out
period (i.e., 60%–75% leverage from 2025 to 2030) are fairly consistent with leverages achieved
by 174 global renewable energy projects that also do not receive tax credits, as summarized in
Figure 15.
Figure 15. Leverage of global renewable energy projects, by technology
Sources: BNEF 2020b; Financier 1 2020; World Bank 2014; New Energy Update 2019; Thompson Reuters 2018, 2019
30
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Although leverage varies significantly among individual projects, the median leverage is generally
around 75%, with no clear differences between technologies. The differences are further lessened
when the projects that received more than 80% financing through debt are removed, with the
median dropping to around 70% for all technologies, which roughly matches the approximate
leverage calculated for technologies in the 2020 ATB. Many of these high-levered projects
received government, or quasi-government (e.g., World Bank), assistance in the form of
nonmarket loan terms (e.g., 30-year terms), loan guarantees, or favorable credit guidelines.
Many also received lower interest rates or higher equity returns (e.g., in the mid-teens) than
projects in the United States, both of which allow for greater leverage for a given DSCR.
Beyond the obvious impacts on capital structure, the phasedown of tax credits will likely have
additional—but harder-to-quantify—impacts on project finance, so we have not tried to quantify
them. For example, the equity return on renewable energy investments will likely become more
risky because of the greater amount of leverage at play and the fact that a significant portion of
each project’s after-tax return will no longer be secured by federal tax credits. In addition, the
reduction in tax benefits could encourage more electric utility ownership of renewable energy
projects, which is currently hindered by tax normalization issues that make utility ownership less
competitive than IPP-ownership (Blank and Richardson 2020). That being said, IPP ownership
should also become more competitive than it currently is because of the greater leverage that will
be possible with the decline in tax credits, as noted above.
4.3 Other Factors that May Influence Future Financing Costs
A significant portion of current financial risk to renewable energy generation plants is mitigated
by long-term, fixed contracts, with relatively stable counterparties. Currently, variation in the
length of the contract and the creditworthiness of the offtaker contributes to a range in financing
costs. Additionally, as discussed in Section 1, most new renewable energy generation plants are
owned by IPPs. In the future, several different factors may change electricity sales revenue, and
in turn, financing costs, including the following.
Movement Away from PPAs: Renewable portfolio standards have been major contributors to
the adoption of long-term PPAs for renewable energy generation assets. Because many states
have required an increasing, or at least constant, percentage of utilities’ electricity to sales come
from renewable energy facilities, PPAs have been long-term solutions for both utilities and
project owners. However, IPP electricity sales from conventional electricity generation plants
have not had this benefit for a variety of reasons; instead, they sell into wholesale markets, with
limited future price certainty. To the extent that utilities or other offtakers (e.g., corporations)
no longer feel the need or see an advantage to entering into these long-term contracts, this could
create more price risk for renewable energy projects. Future price uncertainty could also rise if
PPA contract durations shorten, increasing the percentage of cash flow over the lifetime of a
project that is uncontracted at the start of commercial operations. That being said, many states
and corporations in recent years have increased their mandates for carbon free electricity (DSIRE
2020; Domonoske 2020), which could continue to drive the need for purchases of renewable
energy. Given the uncertainties involved, we do not adjust our future financing assumptions to
account for changes in the use of PPAs or their durations.
31
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Increased Curtailment: As the market penetration of renewable energy increases, so too does the
risk of curtailment of variable generation. Most PPAs already anticipate a certain amount of
curtailment, and allocate that risk among counterparties. For example, a PPA might allow the
offtaker to curtail the project for economic reasons during a certain number of hours each year
without having to compensate the project for lost revenue, or it might designate who bears the risk
of reliability-based curtailment ordered when a grid operator exceeds a certain threshold. Going
forward, these considerations are likely to become more important, and could impact the riskiness
of renewable energy PPAs and, hence financing costs. On the other hand, increasing interest in
medium- and long-duration battery storage could at least partly address curtailment risk from a
physical, rather than contractual, angle. We do not adjust our future financing assumptions for
increased curtailment risk, given the uncertainties over how it might affect financing.
Increase in Use of Financial Hedges: As the cost of renewable generation continues to drop
and PPA prices converge with wholesale power prices, financial hedge products are becoming
increasingly common in lieu of traditional PPAs in some markets (Bartlett 2019). These hedges
are typically structured as a “contract for differences,” where the counterparties—the project and
a financial institution (or, increasingly, a corporate offtaker)—agree on a “strike price” that
effectively becomes the de facto price of power locked in by the project.
26
If wholesale power
prices exceed the strike price, the project pays the financial institution the difference (while
selling its energy into the local wholesale power market). If wholesale power prices fall below
the strike price, the project still sells its energy into the local wholesale power market, but the
financial institution makes up the shortfall between the wholesale power price and the strike
price. These types of hedges are common in the power industry, particularly for gas-fired
generation, but they are typically of shorter durations, partly because of the fuel price risk
associated with conventional generation. For wind projects, these types of hedges typically run
10–12 years (i.e., just long enough to cover the 10-year PTC window). For solar projects, they
might be slightly shorter in duration (e.g., 8–10 years). While not as common as with other
renewable projects, these hedges are becoming more common as solar PPA prices continue to
decline. In either case, these hedges lock in prices for much shorter durations than does the
typical wind or solar PPA—which, in turn, means greater market risk, particularly once the
hedge has ended. Going forward, there will be increasing focus on this post-hedge “merchant
tail” period, given that—particularly in high concentrations—wind and solar power tend to drive
down wholesale power prices and thereby erode the incremental value they provide to the grid
(a phenomenon sometimes referred to as “eating their own lunch”). As “merchant tail” risk
grows, project financing might become shorter-term in nature (and/or more expensive), as
investors seek to avoid that risk. On the other hand, as interest rates rise from today’s historically
low levels, the distant cash flows associated with the merchant tail will be more-heavily
discounted, and so will carry slightly less weight than they do when discount rates are low.
Given the uncertainties involved, we do not adjust our future financing assumptions to account
for shorter contract durations or increasing merchant tail risk.
Fewer Creditworthy Regulated Utility Offtakers: A contract with a creditworthy counterparty
can greatly mitigate financial risk, and in the case of renewable energy projects, most
counterparties are regulated utilities with relatively high credit ratings. Investor-owned utility
26
There are several different types of hedges in the marketplace, each with its own risk profile. For more
information, see Bartlett (2019).
32
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
average credit rating at the parent company level in 2019 remained at investment grade BBB+
for a sixth straight year (EEI 2020). However, in 2018, Moody’s Investor Service downgraded its
overall outlook of the U.S. utility sector because of changes in the tax code and the challenges
facing the utility industry (Foehringer Merchant 2018). When PG&E entered bankruptcy, it was
reported that it attempted to renegotiate its long-term renewable energy PPAs, adding more risk
to future long-term PPAs, though most contracts are still in place (Saint John 2019). While the
increased risk of the changing utility landscape and what regulators and the industry are doing to
mitigate these risks is an analysis unto itself, an increase in the future of utility bankruptcy could
increase PPA counterparty risk and increase financing costs for renewable energy assets. Given
the uncertainties involved, we do not adjust our future financing assumptions to account for a
change in creditworthiness of PPA offtakers.
Changes in Regulation: Regulatory risk can be significant, particularly in other parts of the
world. The United States has provided a relatively stable regulatory environment for operating
renewable energy plants. Though regulatory changes have sometimes adversely affected future
projects, existing projects have most often been grandfathered or shielded from such changes.
To the extent that this unwritten compact changes going forward such that adverse regulatory
changes affect existing projects as well, this risk could increase the financing costs of future
projects.
Changes in Perceived Technology Risk: The industry is actively working on reducing the
perceived risks to the construction and operation of renewable energy generation projects.
Research and development is being funded for better resource forecasting, improved siting for
better performance, improved operation and maintenance procedures, and lower hardware failure
rates. These improvements can create more certainty in electricity generation over the expected
life of an asset. On the other hand, an increase in maintenance or quality issues might increase
the future perceived risk. We did not incorporate any of these changes in risk into future
financing costs.
4.4 Summary of Financing Cost Changes Over Time
Table 6 (page 34) summarizes our financial assumptions by technology during the project’s
operation for an IPP-owned electric generation asset, incorporating our current benchmarks with
the future changes in interest rates and tax credits discussed above.
We input these assumptions,
27
the leverage calculations summarized in Figure 14 (page 29),
along with other technology-specific inputs from the 2020 ATB, to calculate WACC for the
different technologies, according to the following formula:
Equation 1. WACC Formula
= – ×
(
1 −
)
+ × × (1 − )
27
We choose 2025 as the starting point for the interest rate increase to simplify calculations and assumptions,
given that is when all tax credits will have expired or reverted to their lower value.
33
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
These WACC estimates are shown in Figure 16 (page 35) as well as the ATB as a ‘Market +
Policies’ financial case.
28
Under these assumptions, the WACC on technologies with tax credits decreases as these credits
phase out. WACC subsequently increases from 2025 to 2030 as interest rates rise.
28
The 2020 ATB also has cases that reflect no consideration of tax credits and no change in interest rate. For these
cases, we ran separate leverage calculations but input the same cost of equity and debt. WACCs for both cases are
shown in the ATB: https://atb.nrel.gov/electricity/2020/images/financials/2020-supporting-financials-WACC.png.
34
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Table 6. Summary of Current and Future Financial Assumptions by Technology
Construction Operation
Technology
Electricity
Sales
After-Tax
Levered
Equity
Returns
Debt Interest
Rate:
2018/2030
Leverage
After-Tax
Levered
Equity
Returns
18-Year Term
Debt Interest
Rate:
2018/2030
Leverage:
2018/2030
land-based wind PPA 11.0% 4.0%/5.0 80% 9.0% 4.0%/5.0 32%/66%
offshore Wind
PPA
12.0% 4.0%/5.0 80% 10.0% 4.0%/5.0 48%/67%
utility PV PPA 9.75% 4.0%/5.0 80% 7.75% 4.0%/5.0 52%/65%
residential and
commercial PV
PPA
10.75% 4.0%/5.0 80% 8.75% 4.0%/5.0 54%/67%
CSP PPA 12.0% 4.0%/5.0 80% 10.0% 4.0%/5.0 46%/58%
geothermal
PPA pre-drilling:
15.0%
post-drilling:
10.0%
4.0%/5.0
pre-drilling:
0%
post-drilling:
75%
10.0% 4.0%/5.0 58%/59%
hydropower PPA 12.0% 4.0%/5.0 80% 10.0% 4.0%/5.0 65%/70%
natural gas Quasi-merchant 12.0% 5.0%/6.0 80% 10.0% 5.0%/6.0 73%
35
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
Figure 16. WACC of different technologies, 2018–2030
It is important to keep in mind that financing costs are one piece of the overall competitiveness of
a project. Though projects receiving tax credits may have lower leverage, and thus a higher
WACC, they benefit from the tax credits, which reduce the LCOE on net. For example, because of
the benefits of receiving PTCs, the LCOE of land-based wind is lower in 2018 than its up-front
capital expenditures, meaning there is not a lot of project operational cash flow in the model
(received from the cost of energy) that can go toward paying off debt over the life of the project;
thus, the DSCR dictates that it has a lower level of debt causing a higher WACC. As the PTC
phases down, land-based wind’s cost of energy goes up (relative to its capital expenditures) and it
can now service more debt, and so has a lower WACC. Natural gas has the highest calculated
leverage, yet it also has the highest WACC because it faces a higher cost of debt and equity
(owing, in part, to it being the only technology analyzed to not have fully contracted cash flows).
However, in 2018, natural gas still has some of the lowest LCOEs in the ATB, does not depend on
long-term fixed contracts, and may be more competitive in markets for reasons not captured by
LCOE (e.g., capacity credit). Some might argue that the financing cost for a new CSP plant would
be even higher than reported in Figure 16 because no new CSP projects are under active
development in the United States and therefore they represent a risk investment. However,
financing is not holding CSP development back in the United States; it is the lack any CSP
projects with long-term PPAs, permitting, and environmental approvals that are needed to receive
financing.
29
Globally, several gigawatts of CSP projects, including the newer technology “power
tower” projects with storage, have received financing in the past few years at rates lower than the
those assumed in this report; however it would undoubtedly be easier to finance a plant using
trough technology, all other things being equal, because of its longer track record. These projects
were financeable because long-term power agreements were made available at rates that could
support the upfront and ongoing costs of a CSP plant. The U.S. market has not as of yet realized
such agreements for CSP, instead opting for lower LCOE PV, wind, and batteries projects.
29
One could argue that financing is holding-up merchant CSP plants from entering operation, but the same holds
true for most U.S. renewable energy projects.
36
This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
5 Conclusion
In the analysis, we attempted to estimate financing costs over time across a broad range of
renewable electric generation technologies to inform the Annual Technology Baseline (ATB).
Several types of corporate structures have access to different kinds of equity and debt, which
they use to finance electric generation assets. A project’s construction, operation, and contract
risk are important factors in determining these costs and the capital structure used. However,
there are also political and regulatory considerations (e.g., the availability and size of tax credits,
normalization accounting rules for utilities) and macroeconomic factors (e.g., supply and demand
of capital, and the federal funds rate) that also determine overall financing costs. These vary by
energy technology, by project ownership (IPP versus IOU versus POU), and also over time.
Variation in project finance costs also exists based on the individual characteristics of a project,
its owner, and when and where it is built. Looking forward, many other factors may change the
underlying risk to project cash flows.
Because renewable energy projects tend to be capital-intensive and have lower operating costs,
financing costs often can be a more important contributor to LCOE than for conventional electric
generation plants. NREL’s ATB LCOE projections have historically been affected primarily by
its projections of technology cost and performance over time. Going forward—and as a result of
the work described in this paper—the cost of finance can be used in the ATB, or for other
analyses that require current or future financing inputs for various technologies, as another
important distinguishing variable both across technologies and over time. Potential future work
that progresses this analysis could include quantifying the range in financing costs across
technologies depending on the project risk profiles and availability of capital in the marketplace.
Additionally, it could be useful to perform a more in-depth quantitative comparison of the cost of
financing between IPPS, IOUs, and POUs.
37
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