A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

National Renewable Energy Laboratory 

Innovation for Our Energy Future 

Solar Photovoltaic Financing: 

Deployment on Public Property 

by State and Local Governments 

Karlynn Cory, Jason Coughlin, and 

Charles Coggeshall 

Technical Report 

NREL/TP-670-43115 

May 2008 

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 
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by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337

Technical Report 

NREL/TP-670-43115 

May 2008 

Solar Photovoltaic Financing: 

Deployment on Public Property 

by State and Local Governments 

Karlynn Cory, Jason Coughlin, and 

Charles Coggeshall 

Prepared under Task No. PVC7.8501 
NOTICE

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Acknowledgments 

This work was funded by the U.S. Department of Energy’s (DOE) Solar Program; therefore, the 

authors wish to thank participating DOE staff—Tom Kimbus and Charles Hemmeline—for 

providing useful insights and overall direction to this project. The authors are also grateful for 

the guidance and helpful input of the project manager, Robert Margolis of the National 

Renewable Energy Laboratory (NREL). We would also like to thank the individuals who 

reviewed various drafts of this report, particularly Charles Jennings of Financial Analytics 

Consulting Corporation; his comments were invaluable for improving the overall organization 

and the content of the report. Other reviewers that provided useful insights include Douglas 

Arent, Maggie Mann, and Robert Margolis of NREL; and Mark Bolinger and Ryan Wiser of the 

Lawrence Berkeley National Laboratory. Finally, the authors thank Jennifer Josey of NREL for 

providing editorial support. 

The authors would also like to thank our interviewees for their time, for reviewing our 

descriptions of their programs and activities in the market, and for providing additional 

clarifications. Thank you to representatives from the public sector for their useful input, 

including: the Energy Information Administration, the Massachusetts Technology Collaborative, 

the Massachusetts Division of Energy Resources, the New York State Energy Research and 

Development Authority, the Montana Public Service Commission, Ohio Department of 

Development, the Connecticut Clean Energy Fund, the California Energy Commission, Boulder 

(Colorado) County's Office of Sustainability, and the U.S. Department of Energy (DOE). 

Additionally, we would like to thank the nonprofit organizations such as the Clean Energy States 

Alliance (CESA), the Community Office for Resource Efficiency (CORE), and Vote Solar for 

their input. We also want to thank the law firm of Nixon Peabody, Hudson Valley Clean Energy 

(a solar design and installation company), and the utilities Xcel Energy and Northwestern 

Energy. Finally, we thank third-party power purchase agreement (PPA) providers MMA 

Renewable Ventures, and SunEdison for their input and guidance. 

 iii
List of Acronyms 

ACUA Atlantic County Utilities 

Authority 

AEI Advanced Energy Initiative 

BETC Business Energy Tax Credit 

CCEF Connecticut Clean Energy 

Fund 

CCSE California Center for 

Sustainable Energy 

CEC California Energy Commission 

CESA Clean Energy States Alliance 

CL&P Connecticut Light & Power 

CORE Community Office for 

Resource Efficiency 

COSRE Customer On-Site Renewable 

Energy 

CPUC California Public Utilities 

Commission 

CREB Clean renewable energy bonds 

CSI California Solar Initiative 

DG Distributed generation 

DIA Denver International Airport 

DOE U.S. Department of Energy 

DOER Division of Energy Resources 

(Massachusetts) 

DPUC Department of Public Utilities 

Control (Connecticut) 

DSIRE Database of State Incentives 

for Renewables and Efficiency 

EIA Energy Information 

Administration 

EPA Environmental Protection 

Agency 

EPBB Expected performance-based 

buy-down 

GHG Greenhouse gas emissions 

H.R. 5351 Renewable Energy and Energy 

Conservation Tax Act of 2008 

HB. 32 Energy Efficiency and 

Renewable Energy Bonding 

Act 2005 

HVCE Hudson Valley Clean Energy 

IREC Interstate Renewable Energy 

Choices 

IRS Internal Revenue Service 

ITC Investment tax credit (federal) 

kW Kilowatt 

LED Light emitting diode 

LEED Leadership in Energy and 

Environmental Design 

LSE(s) Load-serving entity(ies) 

MACRS Modified Accelerated Cost 

Recovery System (federal) 

MassDev MassDevelopment 

MECA Mayor's Energy Conservation 

Account (San Francisco) 

MTC Massachusetts Technology 

Collaborative 

MW Megawatt 

MWh Megawatt-hour 

NJBPU New Jersey Board of Public 

Utilities 

NJCEP New Jersey’s Clean Energy 

Program 

NMFA New Mexico Finance Authority 

NREL National Renewable Energy 

Laboratory 

NYSERDA New York State Energy Research 

and Development Authority 

O&M Operating and maintenance 

OEE Office of Energy Efficiency 

(Ohio Department of 

Development) 

PBI Performance-based incentive 

PG&E Pacific Gas & Electric 

PPA Power purchase agreement 

PTC Production tax credit 

PV Photovoltaics 

R&D Research and development 

REC Renewable energy certificates 

REPI Renewable energy production 

incentives (federal) 

RFP Request for proposals 

RFQ Request for qualifications 

RPS Renewable portfolio standard 

SAC Solar America Cities 

SAI Solar American Initiative 

SAS Solar America Showcase 

SB1 Million Solar Roofs Bill 

SBC Systems benefit charge 

 iv
SCE Southern California Edison 

SDG&E San Diego Gas & Electric 

SFPUC San Francisco Public Utilities 

Commission 

SMUD Sacramento Municipal Utility 

District 

SPE Special purpose entity 

SREC Solar renewable energy 

certificates 

UI United Illuminating 

USBP Universal Systems Benefit 

Program 

VEPCO Virginia Electric Power 

Company 

 v
Executive Summary 

State and local governments have grown increasingly aware of the economic, environmental, and 

societal benefits of taking a lead role in U.S. implementation of renewable energy, particularly 

distributed photovoltaic (PV) installations. Recently, solar energy's cost premium has declined as 

a result of technology improvements and an increase in the cost of traditional energy generation. 

At the same time, a nationwide public policy focus on carbon-free, renewable energy has created 

a wide range of financial incentives to lower the costs of deploying PV even further. These 

changes have led to exponential increases in the availability of capital for solar projects, and 

tremendous creativity in the development of third-party ownership structures. 

As significant users of electricity, state and local governments can be an excellent example for 

solar PV system deployment on a national scale. Many public entities are not only considering 

deployment on public building rooftops, but also large-scale applications on available public 

lands. The changing marketplace requires that state and local governments be financially 

sophisticated to capture as much of the economic potential of a PV system as possible. 

Therefore, a key issue facing policy makers at the state and local level is how to most efficiently 

allocate public dollars and leverage incentives to develop a significant amount of energy 

generation from public-sector PV. This report examines ways that state and local governments 

can optimize the financial structure of deploying solar PV for public uses. 

A number of revenue streams, incentives, and financial structures can be utilized by state and 

municipal governments who want to support solar projects. PV systems produce two main 

products that can be sold in the marketplace: electricity and the green attributes of this electricity. 

For any particular solar PV project, the revenue will depend on its geographic location, the 

quality of the resource, and access to purchasers that place a high value on solar renewable 

energy certificates (SRECs). For state and local governments, several methods of financing the 

production of these goods are available, including systems benefit charge (SBC) funds, issuance 

of energy bonds, clean renewable energy bonds (CREBs) approved by the Internal Revenue 

Service (IRS), and federal renewable energy production incentives (REPI). Additionally, private 

sector financiers are able to take advantage of another set of incentives, which include the federal 

investment tax credit (ITC) and accelerated depreciation under the federal Modified Accelerated 

Cost Recovery System (MACRS). Finally, there may be additional state, local, or utility 

incentives available to further reduce the installed costs of PV. The primary vehicle that has 

emerged to finance public-sector PV is the third-party ownership model because it allows the 

public-sector systems to take advantage of federal tax incentives without a large up-front outlay 

of capital. Under this structure the government entity hosts, but does not own, a solar PV system 

and is able to secure, on average, 15- to 25-year fixed-price power at or below current retail 

rates. The combination of these options has led to the installation of many PV systems with the 

transactions increasing both in terms of size and complexity. In this paper, the mechanisms 

underlying these transactions are analyzed in detail, and their specific relevance to state and local 

governments is explored. 

Based on the research and analysis conducted, several themes emerged that highlight the 

opportunities and challenges with deploying PV on public-sector buildings and lands: 

• Reduce electricity bills. State and local governments can reduce electricity bills by 

producing electricity on-site with a solar PV system. However, the savings are not 

 vi
currently enough to justify deployment solely based on these savings, even over a 20-year 

payback period. 

• Value of green attributes. Where available, SRECs offer an additional revenue stream 

that can be combined with incentives to offset the high cost of PV deployment. The value 

of an SREC is highest in states with solar tiers in their renewable portfolio standard 

(RPS) requirements; voluntary SRECs command a smaller, but sizable premium as well. 

• Use state incentives. SBC funds provide a significant source of capital to lower the upfront costs of installing PV, including public-sector applications. There is significant 

flexibility in how SBC-funded programs can be designed and administered. 

• Take advantage of third-party ownership.

o Capture federal incentives. As many state and local governments pursue 

aggressive PV expansion programs, the third-party ownership model will be a key 

financing structure to take advantage of federal tax incentives like the ITC and 

MACRS. However, unless significant rebates are available or if the system is 

being installed in or near a state with a solar tier in its RPS, the economics of onsite solar in many states may still be marginal when compared to average retail 

electric rates, even with the federal incentives. 

o Consider an option for ownership. Two relatively new structures, the saleleaseback and partnership flip, create the financing mechanism for third-party 

ownership model. Both of these structures allow an option for the public entity to 

ultimately own the project in six years, before the power purchase agreement 

(PPA) or lease expires. However, each structure has complicated tax issues that 

must be addressed. 

o Defray up-front costs. In certain states, the transition to performance-based 

incentive programs and away from up-front incentives may change the nature of 

how PV projects are financed. This may encourage a greater reliance on thirdparty structures, especially for the public sector and residential markets. 

• Own and finance public-sector solar PV. For those state and local governments that 

desire to own the PV system on their site, there are several options for structuring the 

financing: 

o Issue bonds. Securing up-front capital through general obligation bonds is how 

public renewable energy projects have traditionally been financed, though they do 

require voter approval.

o Issue energy bonds. Issuing state or municipal energy revenue bonds that are 

repaid with energy savings is an attractive concept; however bringing these bonds 

to market can be challenging. 

o Apply to the IRS for a CREBs allocation. For approved applicants, the federal 

incentive CREBs can be a valuable source of low-cost financing, if steps are taken 

to reduce the high transaction costs associated with their issuance. 

o Use REPI. While the REPI is designed to provide a production incentive to 

public projects like the production tax credit (PTC), the incentive is consistently 

underfunded by annual congressional appropriations; therefore, it is difficult to 

depend on it for supporting significant public deployment of solar PV. 

• Understand insurance requirements. Utility insurance requirements for PV systems, 

including general liability and property, can be onerous. Their cost can significantly 

negatively impact the economics of solar PV projects and can be large enough to derail 

public-sector PV projects. 

 vii
Table of Contents 

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

List of Acronyms........................................................................................................................................iv 

Executive Summary...................................................................................................................................vi 

List of Figures ...........................................................................................................................................ix 

List of Tables ...........................................................................................................................................ix 

1.0 Introduction ...........................................................................................................................................1 

2.0 PV System Revenues............................................................................................................................2 

2.1 Electricity Revenues ......................................................................................................... 2 

2.2 REC and Solar REC Revenue........................................................................................... 4 

 2.2.1 RECs Overview and Background .................................................................. 4 

 2.2.2 SREC Revenue............................................................................................... 6 

3.0 State and Local Financing....................................................................................................................9

3.1 System Benefit Charge Programs ..................................................................................... 9 

3.2 State and Local Government Bonds ............................................................................... 11 

 3.2.1 Issuing Energy Bonds .................................................................................. 11 

4.0 Federal Incentives for Public-Sector PV...........................................................................................14

4.1 Overview of CREBs ....................................................................................................... 14 

4.2 Basic Principles of CREBs ............................................................................................. 15 

4.3 Barriers to Using CREBs................................................................................................ 17 

 4.3.1 Transaction Costs......................................................................................... 17 

 4.3.2 Interest Rates................................................................................................ 17 

 4.3.3 Early First Payment...................................................................................... 18 

4.4 The Future of CREBs...................................................................................................... 18 

4.5 Federal Renewable Energy Production Incentive (REPI) .............................................. 19 

5.0 Federal and State Tax Incentives ......................................................................................................21

5.1 Investment Tax Credit..................................................................................................... 21 

5.2 Modified Accelerated Cost Recovery System (MACRS) and Bonus Depreciation....... 21 

5.3 State Tax Credit Incentives............................................................................................. 22 

6.0 Third-Party Financier Model in the Public Sector............................................................................23

6.1 Public-Sector Hosts, but Does Not Own PV .................................................................. 23 

6.2 The Benefits of Third-Party Ownership ......................................................................... 24 

6.3 Caveats with Third-Party Ownership.............................................................................. 26 

6.4 Who is Using Third-Party Ownership in the Public Sector............................................ 28 

6.5 Sale-Leaseback and the Partnership-Flip Models........................................................... 28 

 6.5.1 Sale-Leaseback Structure............................................................................. 28 

 6.5.2 Partnership-Flip Structure............................................................................ 29 

7.0 Insurance and the Impact on PV Deployment..................................................................................31

7.1 Self-Insuring Publicly Owned PV Systems .................................................................... 31 

7.2 Massachusetts: Umbrella Insurance Policy Decreases Costs ......................................... 31 

7.3 Insurance and Third-Party PPB Providers ...................................................................... 32 

8.0 Conclusions.........................................................................................................................................34 

Appendix 1. Examples of Public-Sector PV Deployment, by State and Project.................................36 

Appendix 2. Critical Steps when Issuing a CREBs Bond .....................................................................50 

Appendix 3. Critical Steps in the Structure of Third-Party Ownership Model....................................51 

Appendix 4. Critical Steps to Issue a Tax-Exempt Bond ......................................................................53 

Appendix 5. The Department of Energy’s Solar America Cities and Showcases ..............................56 

Appendix 6. Useful Reference Documents and Internet Resources ...................................................58 

Appendix 7. Useful Contacts ...................................................................................................................59 

 viii
List of Figures 

Figure 1. On-site generation and net metering................................................................................ 2 

Figure 2. Retail price of electricity for commercial customers averaged for July 2007 (in cents 

per kW hour).................................................................................................................... 3 

Figure 3. Solar/DG provisions in state RPS policies ...................................................................... 7 

Figure 4. System benefit charge funding of renewables by 2017, by state .................................. 10 

Figure 5. Allocation of 610 Round 1 CREBs projects: Distributed by the number of projects per 

technology...................................................................................................................... 15 

Figure 6. Allocation of 312 Round 2 CREBs projects: Distributed by the number of projects per 

technology...................................................................................................................... 15 

Figure 7. Clean renewable energy bonds...................................................................................... 16 

Figure 8. Contracts and cash flow in third-party ownership model.............................................. 23 

Figure 9. Third-party ownership model details (one variation).................................................... 24 

Figure 10. Sale-leaseback structure with PPA.............................................................................. 29 

Figure 11. Partnership-flip structure with PPA............................................................................. 30 

Figure 12. Tax-exempt bonds ....................................................................................................... 53 

List of Tables 

Table 1. REC and SREC Prices in Voluntary and Compliance Markets........................................ 5 

Table 2. Examples of Public-Sector PV Deployment, by State and Project................................. 36 

Table 3. 2007 Solar America Cities.............................................................................................. 56 

Table 4. 2008 Solar America Cities.............................................................................................. 56 

 ix
1.0 Introduction

The opportunity to deploy PV on public buildings is tremendous. According to the Energy 

Information Administration’s (EIA) Commercial Buildings Energy Consumption Survey, there 

were approximately 574,000 state and local government-owned buildings in the United States in 

2003.1

 This represents 12% of the total number of all nonresidential buildings in the country. In 

2003, these buildings consumed approximately 178 billion kW hours of electricity.2 If only 1% 

of their total demand were provided by solar PV (assuming a capacity factor of 14%), 

approximately 1,450 MW of solar PV capacity would be needed. This is 10 times the annual 

U.S. grid-tied PV capacity installed in 2007 of 150 MW-dc.3 Clearly, state and local government 

electricity consumption is significant and represents an opportunity to increase small- and largescale distributed solar PV power generation. 

Many state and local governments are already pursuing PV installations on public property. To 

do this successfully, sound public policy, financial incentives, and committed program 

administrators are required. While each state and local government will have its own reasons for 

pursuing PV, the most common benefits associated with public-sector solar programs include the 

following: 

• PV can reduce current utility expenses; 

• PV offers predictability of future utility expenses; 

• PV reduces public-sector greenhouse gas (GHG) emissions; 

• Public-sector PV motivates other sectors to deploy solar; 

• PV promotes the creation of local jobs; and 

• PV can provide emergency power benefits for critical municipal services during and 

directly after a disruption to the electrical grid. 

Under a basic revenue analysis, PV systems produce two saleable commodities: 1) electricity and 

2) the green attribute of that electricity. The production of these commodities can be financed by 

state and local incentive programs, utility incentives, federal incentives, or by third parties who 

can monetize federal and state tax incentives available for solar energy generation. The details of 

the main financing options for solar PV on state and local buildings and lands are identified and 

discussed in this report. Research was conducted, including interviews with state and local 

officials and other industry professionals actively engaged in the deployment of PV on public 

buildings. The goal was to identify creative structures of public-sector PV financing, industry 

trends, and continued barriers to implementation. Individual examples from state and local 

government deployment of solar PV are captured in Appendix 1. The critical steps for 

structuring a few of the more complicated financing structures (CREBs, third-party ownership, 

and tax-exempt bond issuance) are described in Appendices 2-4. 

 

1

 “2003 CBECS Detailed Tables- Table C-13- Total Electricity Consumption and Expenditures, 2003,” accessed 

January 2008, at http://www.eia.doe.gov/emeu/cbecs/cbecs2003/detailed_tables_2003/2003set10/2003pdf/c13.pdf 

2

 Ibid. 

3

 “U.S. Solar Industry Year in Review: 2007,” Solar Energy Industry Association and Prometheus Institute for 

Sustainable Development, released April 21, 2008, at http://www.seia.org/Year_in_Review_2007.pdf 

 1
2.0 PV System Revenues 

There are two main revenue streams that are derived from the operation of solar PV systems: 

electricity and the SRECs that represent the environmental attributes of the electricity generated. 

This section details how the value of these revenue streams can be analyzed. 

2.1 Electricity Revenues4

A PV system located on a customer’s site is typically located “behind-the-meter” and therefore 

produces electricity that offsets retail electricity purchased from the local utility, or load-serving 

entity (LSE).5 As shown in Figure 1, the on-site generation is fed directly to the customer for its 

use. The advantage is that generation produced behind-the-meter ultimately reduces the demand 

from the customer’s local utility, and thus the utility electricity bill. 

Figure 1. On-site generation and net metering

In addition to avoiding the utility’s retail rate, the majority of U.S. states allow customers to have 

on-site generation and to sell the excess renewable power to their utility, also known as net 

metering.6

 The amount the utility purchases will allow depends on how much excess generation 

is created, above what is used by the customer. Depending on the state, the utility may pay for 

this excess generation at their retail rate (the highest rate, as it includes transmission and 

distribution), at the utility’s avoided generation cost, or at the utility’s wholesale generation rate. 

Net metering can also allow excess generation in any given month to be carried over to the next 

 

4

 Municipalities that own and operate their own electric utilities are not considered. 

5

 A load-serving entity includes (1) investor-owned utilities in regulated electricity markets, (2) default/standard 

offer utilities in restructured electricity markets (or deregulated generation markets), and (3) competitive retail 

electricity suppliers in restructured electricity markets. 6

 For more information, see “State Energy Alternatives: Net Metering,” U.S. Department of Energy Web site, EERE 

State Activities and Partnerships, at http://www.eere.energy.gov/states/alternatives/net_metering.cfm 

 2
billing month, typically for up to one year. In states that do not have net metering, rather than 

having the meter spin backwards, the customer is usually required to install a second meter and 

the utility may pay for excess generation at the avoided or wholesale generation rate. 

Government entities that wish to learn more about net metering in their state should access the 

Database of State Incentives for Renewables and Efficiency (www.dsireusa.org). 

The actual retail rate avoided will depend on the geographic location and season, and could 

depend on the time of day (for customers with time-of-use rates). Over an average month, retail 

electricity will sell in the continental United States for $0.05 – $0.16 per kWh, with the lower 

price representing Idaho and the higher price representing New York State.7 Figure 2 shows the 

average electricity price by state for July 2007. However, there are many congested areas in the 

country that have higher peak prices during particular hours, especially during the summer. 

Some examples include the cities of New York, Los Angeles, Chicago, and Boston. For 

example, in 2007 the Long Island day-ahead electricity market reached more than $0.24 per kWh 

on August 3 at 3 p.m. and the real-time dispatched spot market (hour-ahead for 5- to10-minute 

intervals) reached more than $2.14 per kWh on August 8 at 3:20 p.m., nearly 10 times the dayahead peak.8

 Note that these peak prices occur during certain hours and days during the summer 

peak period and may be significantly higher than average rates. 

Source: EIA Electric Power Monthly — Table 5.6.A — Average Retail Price of Electicity to Ultimate Customers by EndUser Sector, by State for July 2007

15.2

6.5

7.2

14.4

10.1

12.0

22.4

8.9 7.6

6.8 7.1

6.2

5.4

8.3 6.9

6.8

6.9

7.6

8.0

10.1

9.2

7.0

7.5

8.0

8.4

9.0

8.9

8.5 7.4 9.0

6.9

8.0

8.7 8.5 8.1

7.9

9.5

7.6

6.4 5.7

9.5

16.7

12.4

13.4

12.3

15.3

12.9

11.3

12.2

15.1

Source: EIA Electric Power Monthly — Table 5.6.A — Average Retail Price of Electicity to Ultimate Customers by EndUser Sector, by State for July 2007

15.2

6.5

7.2

14.4

10.1

12.0

22.4

8.9 7.6

6.8 7.1

6.2

5.4

8.3 6.9

6.8

6.9

7.6

8.0

10.1

9.2

7.0

7.5

8.0

8.4

9.0

8.9

8.5 7.4 9.0

6.9

8.0

8.7 8.5 8.1

7.9

9.5

7.6

6.4 5.7

9.5

16.7

12.4

13.4

12.3

15.3

12.9

11.3

12.2

15.1

Figure 2. Retail price of electricity for commercial customers averaged for July 2007 (in cents per 

kW hour)

 

7

 “Electric Power Monthly – Table 5.6.A – Average Retail Price of Electricity to Ultimate Customers by End-User 

Sector, by State” for July and December 2007, from October 2007 and February 2008 monthly reports, respectively.. 

http://www.eia.doe.gov/cneaf/electricity/epm/epmxlfile5_6_a.xls 

8

 “Day-Ahead Market LBMP” and “Real-Time Market LBMP” zonal information from the New York Independent 

System Operator’s Web site, for the “LONGIL” zone, representing Long Island. Data for the month of August 2007 

was examined. http://www.nyiso.com/public/market_data/pricing_data.jsp 

 3
Reducing annual expenditures on electricity may free up cash for other purposes, and the pursuit 

of lower electricity bills can be a factor in the decision to pursue a public-sector PV system. 

However, in the absence of other incentives, it is unlikely that simply offsetting a percentage of a 

facility's retail electricity purchases with PV-generated electricity will be sufficient to make the 

economic case for solar energy, given the high up-front capital costs. As a result, additional 

revenue streams, like the sale of renewable energy attributes and other incentives, are critical to 

making a project economically attractive. 

2.2 REC and Solar REC Revenue 

SRECs are increasingly critical for structuring the financing of new solar PV projects. This 

section explains why renewable energy certificates (RECs) were developed, how they can be 

used in the marketplace, and the importance of SRECs in financing solar installations. 

2.2.1 RECs Overview and Background 

RECs9 have become the dominant mechanism for compliance with renewable portfolio standard 

(RPS) policies and voluntary green power purchases. The RPS is a state-level mechanism, which 

requires LSEs in a given state to meet a certain percentage of its customer electricity demand 

with renewable energy sources. While RECs are not used for RPS compliance everywhere, the 

manner in which RECs are defined and treated in RPS policies varies by state and region, and 

can vary between the different utilities and green power marketers operating in the voluntary 

market. 

RECs are tradable commodities, separate from the electricity produced, that bundle the 

“attributes” of renewable electricity generation. Because they are unbundled from the electricity, 

RECs are not subject to transmission constraints. One REC typically represents the attributes of 

1 megawatt-hour (MWh) of renewable electricity generation. The definition of "attributes" can 

vary across contracts, but will likely include any future carbon trading credits, emission 

reduction credits, and emission allowances. Once the REC is separated from the underlying 

electricity and sold to another party, claims to the attributes can only be made by the REC owner, 

and not by the electricity owner or the owner of the project. For example, the host of a solar 

system may not be able to claim they are using “green power” if they are selling the RECs 

generated by the project to another entity. This concept will be revisited when the third-party 

ownership model is discussed in Section 6. 

RECs are currently used by 1) LSEs to demonstrate compliance with regulatory requirements, 

such as renewable energy mandates ("the compliance market"), and 2) green power marketers 

and utilities to supply renewable energy products to end-use customers who voluntarily purchase 

RECs ("the voluntary market"). When an LSE is required to meet a certain level of electricity 

demand with renewable energy as part of a RPS, RECs are typically, but not always, used to 

demonstrate compliance with such a mandate. California provides an exception, where the 

attributes must be bundled with the power in the same contract with the utility. However, the 

state utility regulators are considering the use of tradable RECs for compliance with their RPS.10

 

9

 Also called renewable energy credits, tradable renewable certificates, or green tags. 

10 For more information, please see the California Public Utility Commission Web site: 

http://www.cpuc.ca.gov/PUC/energy/electric/RenewableEnergy/ongoing.htm 

 4
In addition, RECs are becoming the dominant mechanism for marketing renewable power into 

the voluntary market.11 When companies like Intel12 or Pepsico13 announce that they are 

offsetting a percentage of electricity use with renewable energy, more often than not, the 

companies have purchased RECs in the voluntary market rather than installing wind turbines or 

PV systems on-site. To put these two large purchases into context, the Intel purchase of 1.3 

billion kWh equates to the generation from 450 MW of wind (33% capacity factor), and the 

Pepsico purchase of 1.1 billion kWh equates to the generation from approximately 150 MW of 

baseload landfill gas or biomass (85% capacity factor).14 The advantage of RECs is that 

corporations and government agencies can support renewable energy without having to develop 

or support their own project, allowing them to focus on their core business. And because RECs 

are not subject to transmission constraints, voluntary green power customers can purchase RECs 

from a variety of projects from across the country to match some or all of their electricity 

demand. Voluntary RECs are created by entities that are producing renewable power beyond 

what is needed to demonstrate legal compliance with RPS requirements or by renewable energy 

generators that are not located in or near markets with RPS policies. 

The value of a REC depends on a number of factors, including whether it is sold into a 

compliance or voluntary market, where in the U.S. the REC is sold, whether there is a shortage 

of RECs, and whether the REC was derived from a solar resource. Table 1 shows the different 

values of RECs, depending on these factors. 

Table 1. REC and SREC Prices in Voluntary and Compliance Markets 

* Not counting biomass 

RPS (shortage) $48-56/MWh ??? ($711 NJ 2009)

RPS $3-22/MWh $205-265/MWh

Voluntary $1-7*/MWh $18-21/MWh

RECs Solar RECs

RPS (shortage) $48-56/MWh ???

RPS $3-22/MWh $160-265/MWh**

Voluntary $1-7*/MWh $18-21/MWh

RECs Solar RECs

RPS (shortage) $48-56/MWh ??? ($711 NJ 2009)

RPS $3-22/MWh $205-265/MWh

Voluntary $1-7*/MWh $18-21/MWh

RECs Solar RECs

RPS (shortage) $48-56/MWh ???

RPS $3-22/MWh $160-265/MWh**

Voluntary $1-7*/MWh $18-21/MWh

RECs Solar RECs

NJ SREC cap:

$711/MWh

As shown in the table, RECs used for RPS compliance have significantly more value than RECs 

in the voluntary market. However, in both cases, SRECs have higher value than generic RECs. 

Finally, REC values are highest in markets with a supply shortage. 

 

** New Jersey and Colorado only. 

Sources: Evolution Markets, NREL, Xcel, NJ Clean Energy Program 

11 Bird, Lori, Leila Dagher, and Blair Swezey, “Green Power Marketing in the United States: A Status Report (Tenth 

Edition), National Renewable Energy Laboratory technical report NREL/TP-670-42502, December 2007, 

http://www.nrel.gov/docs/fy08osti/42502.pdf 

12 “Intel Becomes Largest Purchaser of Green Power in the U.S.,” Intel News Release, January 28, 2008, 

http://www.intel.com/pressroom/archive/releases/20080128corp.htm 

13 “Pepsico Makes Largest Corporate Purchase of Renewable Energy Certificates,” Pepsico News Release, April 30, 

2007, http://phx.corporate-ir.net/phoenix.zhtml?c=78265&p=irol-newsArticle&ID=992341 

14 Note that, in reality, the two purchases by Intel and Pepsico are from a variety of renewable resources, such as 

geothermal, wind, solar, biomass, and potentially others. A simplifying assumption about technologies and capacity 

factors was made to put these large purchases into context. 

 5
2.2.2 SREC Revenue 

SRECs are a separate commodity in most REC markets because their value is higher than other 

RECs. This is true for a variety of reasons. First, several states encourage solar or distributed 

generation (DG) through a specific solar/DG tier in their RPS. The goals of creating such a tier 

include increased deployment of solar and DG technologies, diversified electricity generation, 

and in-state economic development benefits. By separating solar and DG into their own tier, the 

RPS protects these higher-cost technologies from competing against more cost competitive, 

renewable technologies like wind and landfill gas. Second, for states with solar tiers in their RPS, 

the penalty price for non-compliance is often set higher than for standard RPS compliance. 

Higher penalty prices encourage LSEs to support new development, by accounting for the higher 

cost of solar and the lack of economies of scale with smaller projects. Third, SRECs tend to be 

quite desirable in the voluntary market and customers are willing to pay much more for SRECs 

than for wind or biomass RECs, as shown in Table 1. 

SRECs have the most value in markets with a separate solar tier in their RPS (also called a 

“carve-out”) and a high penalty price for non-compliance above what the owner/developer needs 

to make project economics work. Examples of the significant project revenues from SREC setasides can be found in Colorado and New Jersey, where SREC prices have ranged from 

$160/MWh to $265/MWh.15 Note that SREC values in New Jersey are expected to increase, 

because the state increased its SREC cap from $300/MWh to $711/MWh starting in 2009 

(ramping down over time).16 This is the highest solar price cap in the nation. A higher SREC 

price cap, in conjunction with phasing out their up-front rebates, is expected to lead to 

significantly higher SREC prices going forward. 

RPS programs that include solar/DG RPS set-asides include Arizona, Colorado, Delaware, 

Maryland, Nevada, New Hampshire, New Jersey, New Mexico, New York, North Carolina, 

Ohio, Pennsylvania, Washington, and Washington D.C. As shown in Figure 3, of these: 

• Ten states and the District of Columbia specify a certain quantity or percentage of the 

RPS must be met with solar resources; 

• Three RPS programs have set-asides for customer-sited or distributed systems, which 

tend to favor solar; and 

• Five policies offer extra credit to either solar or distributed generation. 

Collectively, these provisions could result in the installation of several thousands of MW of solar 

electric capacity by 2025. For example, if it is met, Maryland’s solar set-aside is expected to 

result in 1,500 MW of new solar capacity.17 A recent report by the Lawrence Berkeley National 

Laboratory calculates that if compliance is achieved with the various state-level solar RPS set-

 

15 NREL estimate based on Xcel Energy’s “2008 Renewable Energy Standard Compliance Plan” Section 5 – 

Acquisition Plans at http://www.xcelenergy.com/docs/Section5-Acquisition_Plans_Final.pdf and New Jersey’s 

Clean Energy Program “SREC Pricing: SREC Trading Statistics,” Web site at 

http://www.njcleanenergy.com/renewable-energy/programs/solar-renewable-energy-certificates-srec/pricing/pricing 16 “New Jersey Approves Solar REC-Based Financing Program: Frequently Asked Questions,” New Jersey Clean 

Energy Program, December 17, 2007, 

http://www.njcleanenergy.com/files/file/SOLARTransitionFAQs121707%20fnl2(2).pdf 17 Parker, S. “Maryland Expands RPS: 1,500 MW Solar by 2022,” Renewable Energy Access, April 12, 2007, at 

http://www.renewableenergyaccess.com/rea/news/story?id=48102 

 6
asides (in place as of early 2008), they could result in roughly 6,700 MW of additional solar 

capacity by 2025.18 

Solar/DG Provisions in RPS Policies

NM: 4% solar electric by 2020

0.6% DG by 2015

AZ: 4.5% DG by 2025

NV: 1% solar by 2015;

2.4 to 2.45 multiplier for PV

MD: 2% solar electric in 2022

CO: 0.8% solar electric by 2020

DC: 0.386% solar electric by 2022

1.1 multiplier for solar

NY: 0.1542% customer-sited by 2013

DE: 2.005% solar PV by 2019;

Triple credit for PV

Solar water heating counts 

towards solar set-aside

WA: double credit for DG

NH: 0.3% solar electric by 2014

NJ: 2.12% solar electric by 2021

PA: 0.5% solar PV by 2020

NC: 0.2% solar by 2018

OH: 0.5% solar by 2025

Figure 3. Solar/DG provisions in state RPS policies 

SRECs can be a very important revenue stream for developing new projects. State and local 

governments may decide to sell the SRECs to nearby LSEs that must comply with solar setasides in RPS programs. If the SRECs are sold (into either voluntary or mandatory markets), 

then the site host also sells the right to claim that it uses solar power. At the same time, the SREC 

cash-flow stream may very well determine whether or not a particular project is economically 

viable. According to 3 Phases Energy Services, SREC cash flows in Colorado account for 

roughly 40% of total project cash flows.19 Personal interviews with developers structuring deals 

have noted that SRECs can account for 40%-80% of the total revenue stream of a project, in 

particular states.20 However, as explained earlier, not every state has SREC prices high enough 

to provide solar projects with this kind of suppor

Source: Database of State Incentives for Renewables and Efficiency (www.dsireusa.org) 

t. 

 

In states without solar rebates and/or a specific solar RPS carve-out, it can be very difficult to 

structure economically viable solar projects that provide payback periods acceptable to public 

entities, given the capital costs involved. This explains why most of the PV installations are 

taking place in states such as California, Colorado, and New Jersey. California has a state-wide 

18 Wiser, Ryan, Galen Barbose, et al. “Renewables Portfolio Standards in the United States: A Status Report with 

Data Through 2007,” Lawrence Berkeley National Laboratory technical report LBNL-154E, April 2008, at 

http://eetd.lbl.gov/ea/EMS/reports/lbnl-154e.pdf 

19 3 Phases, 2007. “Selling Solar with RECs,” Presentation by 3 Phases Energy Services, January 31, California 

Solar Forum, http://www.californiasolarcenter.org/pdfs/forum/2007.1.31_SolarForum_TDerrick3PhasesEnergy_SellingSolarRECs.pdf 

20 Cory, Karlynn, Jason Coughlin, et al., “Innovations in Wind and Solar PV Financing,” National Renewable 

Energy Laboratory technical report NREL/TP-670-42919, February 2008, at 

http://www.nrel.gov/docs/fy08osti/42919.pdf 

 7
solar rebate program although it does not have an RPS with a specific solar tier. In Colorado, 

Xcel Energy, the state's largest utility, administers a program to purchase SRECs from end-users 

as part of its compliance activities with the solar tier of the state’s RPS. Additionally, the Xcel 

program also includes an up-front solar rebate. New Jersey's SBC fund also provided a rebate to 

defray the up-front cost of PV installations, in conjunction with the sale of SRECs to the local 

utility. In December 2007, the state put a schedule in place to eliminate its up-front rebates in the 

hope that developers could rely on the SREC market (in addition to federal incentives). Note that 

while each program is structured differently, they have all been successful. 

Specific examples of the role that SRECs play in structuring the financing of new solar PV 

projects can be found in several of the examples in Appendix 1. 

 8
3.0 State and Local Financing 

In most cases, avoided electricity costs and the sale of SRECs will not be sufficient to structure a 

public-sector PV project with a payback period that is acceptable to the public entity. Therefore, 

state and local governments usually try to take advantage of the various incentives that exist in 

the marketplace to reduce the up-front cost of installing a PV system. This section explores the 

mechanisms that state and municipalities use to provide incentives and structure financing for 

new solar PV projects that they own. At the end of the paper, Appendix 1 provides additional 

detail and examples, including the SBC programs referenced below. 

 

3.1 System Benefit Charge Programs 

The primary source of incentives in many states derives from programs that are funded by a 

SBC, also called a public benefit fund. Since the mid 1990s, 17 states, including the District of 

Columbia, have implemented some variation of SBC funds21 to support renewable energy.22 The 

implementation of these SBC programs has generally been the result of electric utility 

restructuring legislation approved over the past 10 years.23 The SBC is a required fee added to 

electricity bills, usually in the form of a usage charge (per kWh basis), or as a monthly flat fee. 

While the fee is usually modest to the consumer, in aggregate, significant funds are generated 

using this mechanism, as shown in Figure 4. According to the North Carolina Solar Center, 

between 1997 and 2017, $6.8 billion dollars will be raised via the system benefit charge 

mechanism.24 On its own, California will collect $331 million just in 2008.25

A standard stipulation for securing SBC incentives is that beneficiaries must be utility ratepayers. 

Therefore, if state and local governments are customers of utilities that collect an SBC, they are 

eligible to participate in SBC-funded programs. 

SBC funds are used to support a variety of renewable energy-related activities through grants, 

loans, rebates, performance based incentives, and free technical assistance. A few examples of 

state SBC programs (further detailed in Appendix 1) include: 

• California. The California Solar Initiative (CSI), funded by an SBC, aims to deploy 

3,000 MW of new solar by 2017. Currently, public PV projects (<50 kW) will receive an 

up-front incentive of $2.65/watt. This incentive will ramp down as target solar capacity 

levels are reached within each utility’s territory. Public systems greater than 50 kW will 

receive periodic payments (performance-based incentives) based on actual production. 

 

21 “Public Benefit Funds for Renewable Energy,” Database of State Incentives for Renewables and Efficiency 

(DSIRE), latest review depends on the state, accessed April 6, 2008, at 

http://www.dsireusa.org/library/includes/seeallincentivetype.cfm?type=PBF¤tpageid=7&back=regtab&EE=0

&RE=1 

22 In addition to renewables, some states use SBC funds to target energy efficiency, energy R&D, weatherization, 

and low-income customer assistance. 

23 “State Energy Alternatives: System Benefit Charges,” U.S. Department of Energy Web site, accessed April 6, 

2008, at http://www.eere.energy.gov/states/alternatives/system_benefits.cfm 

24 “Public Benefit Funds for Renewables (Estimated Funding).” Report by Interstate Renewable Energy Council 

and North Carolina Solar Center. Accessed April 6, 2008, at 

http://www.dsireusa.org/documents/summarymaps/PBF_Map.ppt 

25 Ibid. 

 9
Figure 4. System benefit charge funding of renewables by 2017, by state 

Funded by Voluntary Contributions

IL: $99 ($5.5)

1998-2015

NY: $159 

($26.8)

1999-2011

PA: $63.2 ($1.9)

1999-2010

WI: $96.6 ($5.5)

2001-2017

MN: $264 ($16)

1999-2017

CA: $4,149 

($330.9) 

1998-2016

OR: $182 ($12)

2001-2017

MT: $8.3 ($0.75)

1999-2009

OH: $63 

($3.15)

2001-2010

RI: $38.3 ($2.2)

1997-2017

MA: $525 ($25)

1998-2017

NJ: $637 ($102)

2001-2012 

DE: $49.3 ($3.5)

1999-2017

CT: $435 ($24)

2000-2017

Cumulative 1997-2017 and Annual (2008) in Million $

17 State Funds + DC

$6.8 B by 2017

D.C.: $5.1 ($0.4)

2004-2017

MI: $25 

($1.7)

2001-2017

VT: $34.3 ($6.6)

2004-2011 ME: $2.1 ($0.75)

2002-2008

NOTE: Cumulative values (1997-2017) 

appear first, followed by annual values 

(2008). The dates refer to the period for 

which cumulative values were calculated, 

not necessarily fund expiration dates. 

Source: Database of State Renewable and Efficiency Incentives (www.dsireusa.org)

• Ohio. The Advanced Energy Fund in Ohio typically uses grants to offset a portion of the 

cost of systems purchased by local municipalities. For nonresidential customers, rebates 

start at $3.50/watt and decrease to $1.50/watt for systems up to 75 kW. 

• New York. New York’s PV System Incentive Program provides $5.00/watt for the first 

25 kW of a public system and $4.00/watt, up to 100 kW. 

• Connecticut. A portion of Connecticut’s SBC funds are used to challenge cities and 

towns to a Clean Energy Campaign, whereby participation in green power programs 

leads to free PV systems for the community. New Haven has already earned 20 kW of 

new solar installations as a result of this program. 

• Montana. Montana’s SBC funds have been used by one local utility to install PV 

systems and battery packs in to provide back-up power at fire stations, in case of a power 

outage. 

Overall, SBC funds provide an important source of funding for public-sector PV. As illustrated 

above and in Appendix 1, a state can be creative in how it decides to manage its SBC funds. 

Certain programs provide across-the-board incentives whereas others focus on specific sectors. 

Some provide up-front grants and rebates while others create low-interest loan funds. In this 

sense, no two programs are exactly the same. 

 10
Specific examples in Appendix 1 explore in greater detail some of the ways that SBC funds are 

used to promote PV for the benefit of public entities. Programs and financing structures for a 

variety of projects are included from California, Connecticut, Montana, New York, and Ohio. 

These states were selected because their SBC funds are administered by different agencies, 

including state government (California, Ohio), a third party (New York, Connecticut), and the 

utility imposing the surcharge (Montana). 

3.2 State and Local Government Bonds26, 27, 28

Public entities can also issue bonds to secure capital for PV projects. In conjunction with, or 

instead of SBC funds, municipal bonds (also called securities) can be issued by state and local 

governments to finance capital expenditures, including PV installations. In Appendix 5, a 

description of the critical steps necessary to issue a tax-exempt bond is provided for public 

entities that are unfamiliar with the process. 

There are two types of municipal bonds: 

1. General obligation bonds. The principal and interest are secured by the full faith and 

credit of the issuer, and are usually supported by the issuer’s taxing power. These bonds 

are voter approved, the rules of which differ by state and can range from a simple 

majority to complex formulas for taxpayer approval. The municipality is generally 

limited in the amount of debt that can be incurred, either as a percentage of a 

jurisdiction’s assessed valuation (sometimes as a multiplier of revenues, like in 

Connecticut) or based on the type of project. Sometimes the bond issue is indirectly 

restricted through limitations based on annual revenue growth, the overall tax rate, or on 

the rate of spending (e.g., cannot outpace inflation).29

2. Revenue bonds. These bonds are often issued by special authorities created for specific 

purposes, usually infrastructure related such as a toll road, bridge, airport, water and 

sewage treatment plants, hospitals, or low income housing. Principal and interest are 

secured from revenues derived from fees and/or charges paid by the users of the facility. 

For example, toll roads collect fees from motorists for their usage; the initial capital was 

secured through revenue bonds in anticipation of repayment through fees. 

3.2.1 Issuing Energy Bonds 

As an alternative to traditional municipal bond issuances, local governments can also consider 

issuing energy bonds whose proceeds may be used to finance renewable energy installations. 

 

26 Note that some municipal bonds are taxable at the federal level, because the government has determined that 

certain activities (e.g., sports stadium) do not provide a public benefit. These types of federally taxed bonds are not 

considered in this document. 

27 Much of the information in this section is taken from the Web site of The Securities Industry and Financial 

Markets Association, from the menu “Learn More > Types of Bonds > Municipal Bonds,” found at: 

http://www.investinginbonds.com/learnmore.asp?catid=5&subcatid=24, unless otherwise noted 

28 Also see “Municipal Bond Basics,” on the Web site of the Corporate Research Project of Good Jobs First, at 

http://www.publicbonds.org/bond_basics/municipal_bonds.htm 

29 Wandschneider, Philip, Ronald Faas, and Douglas Young, “How a Community Decides to Issue Bonds,” from the 

Municipal Bonds Series by the U.S. Department of Education, December 1982. 

http://www.eric.ed.gov/ERICDocs/data/ericdocs2sql/content_storage_01/0000019b/80/2e/c6/53.pdf. 

 11
However, obtaining the authorization to issue these bonds to finance renewable energy projects 

may be easier than actually getting the bonds to market. 

Four examples of public bond programs that have been approved specifically for renewable 

energy (including PV) can be found in San Francisco in 2001,30 Honolulu31 and New Mexico32

in 2004, and Delaware in 2007.33 Of these four, however, only Honolulu has successfully issued 

its energy bond. 

In the cases of Honolulu and New Mexico, general obligation bonds for renewable energy 

projects were authorized by the respective authorities. As mentioned earlier, with general 

obligation bonds, the taxing authority of the issuing entity supports the repayment of the debt. 

Conceptually, however, the energy savings from the renewable energy and energy efficiency 

investments would be expected to pay for the bonds over time, backed up by the taxing authority 

of the issuer, if necessary. 

In the cases of San Francisco and Delaware, revenue bonds for renewable energy were approved. 

As noted, the repayment of revenue bonds comes from revenue generated (or saved) by the 

specific projected financed with the bond proceeds. Because revenue bonds do not add to a 

government's general debt burden and are not supported by tax revenues, they do not require 

voter approval and do not technically add to the government’s tax burden. However, these bonds 

may be more complicated to bring to market. Energy savings are used as the sole source of 

repayment and might be viewed as a less certain revenue stream when compared to more 

traditional revenue bonds with easily identified cash flows available for debt repayment (i.e., 

tolls from a toll road). 

Here are some more specific details of each of these four bond authorizations: 

• Honolulu. The city issued $7.85 million in solar general obligation bonds in FY05 and 

used the proceeds for solar powered parking lots, energy retrofits, and LED streetlamps.34

• New Mexico. The New Mexico Finance Authority (NMFA) has approval to issue up to 

$20 million in general obligation bonds. The proceeds would go toward the Public 

Project Revolving Fund to make loans to state agencies, universities, and public schools 

to fund energy efficiency and renewable energy investments. It is expected that 90% of 

 

30 DeLonge, Danielle. “Solar Bond Will Help City Focus on Renewable Energy,” Pacific Business News, June 18, 

2004. Accessed April 6, 2008, at http://www.bizjournals.com/pacific/stories/2004/06/21/focus3.html 31 “Energy Efficiency and Renewable Bonding Act,” New Mexico Finance Authority Web site, accessed April 6, 

2008, at http://www.nmfa.net/loan/?t=State%20Building%20Automation%20Project%20Financing 

32 Energy Efficiency and Renewable Energy Bonding Act 2005 (HB. 32), at 

http://legis.state.nm.us/Sessions/05%20Regular/final/HB0032.pdf 

33 McDowell, Harris B., and John Byrne, “A Sustainable Energy Future for Delaware,” as chair and co-chair of the 

Sustainable Energy Utility Task Force, presented to the Delaware General Assembly on April 16, 2007. Accessed 

April 6, 2008, at http://www.seu-de.org/docs/fina_report_brief.pdf 

34 E-mail communication with Lori Goropse Winguard, chief of staff to Honolulu City Council Member Charles K. 

Djou on 10/16/2007. 

 12
the energy savings would be “captured” from the participating agencies to fund debt 

service.35 As of January 2008, no bonds have been issued under this authorization.36

• San Francisco. Proposition B was approved by San Francisco voters in 2001; it gave the 

city the authority to issue up to $100 million of revenue bonds for renewable energy 

projects, including PV. In the same election, Proposition H was passed giving the City 

authority to issue additional revenue bonds with greater flexibility as to the issuer and the 

amount. To date, these bonds have never been issued for a number of reasons, including 

net metering issues between PG&E and the City of San Francisco,37 and apparent 

creditworthiness concerns at Hetch Hetchy Water and Power.38 

• Delaware. In 2007, Delaware announced the creation of a Sustainable Energy Utility to 

promote energy efficiency, weatherization, and distributed renewable energy generation, 

including PV. Proposed funding for the Sustainable Energy Utility would come from a 

number of sources, including the issuance of special purpose, tax-exempt bonds up to the 

amount of $30 million.39 Energy savings are expected to generate funds to repay these 

bonds. 

 

35 “Annual Report 2005,” New Mexico Finance Authority, 2005, page 24, at 

http://www.nmfa.net/uploads/document/Annual%20Report%202005.pdf 

36 “Invested in New Mexico: 2007 Annual Report,” New Mexico Finance Authority, 2007, at 

http://www.nmfa.net/uploads/document/NMFA_2007_Report.pdf 

37 “Electricity: Hetch Hetchy Water and Power Solar Generation,” California Assembly Committee on Utility and 

Commerce, Lloyd E. Levine, chair, California Assembly AB 2573, hearing date: April 17, 2006. See page 7. 

 http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_2551-2600/ab_2573_cfa_20060414_120324_asm_comm.html 38 “1/27/05 & 1/28/05 Minutes SFPUC Commission,” San Francisco Public Utilities Commission meeting minutes 

published 3/10/2005, updated 3/14/2005, accessed March 2008, at 

http://sfwater.org/detail.cfm/MC_ID/18/MSC_ID/113/MTO_ID/369/C_ID/2422/Keyword/Proposition%20B 39 McDowell, Harris B., and John Byrne, “A Sustainable Energy Future for Delaware,” as chair and co-chair of the 

Sustainable Energy Utility Task Force, presented to the Delaware General Assembly on April 16, 2007. Accessed 

April 6, 2008, at http://www.seu-de.org/docs/fina_report_brief.pdf 

 13
4.0 Federal Incentives for Public-Sector PV 

Among the programs that have been created by the federal government to promote renewable 

energy development, at least two are targeted to help state and local governments finance new 

renewable projects: the IRS' clean renewable energy bonds (CREBs) and DOE’s Renewable 

Energy Production Incentives (REPI). The CREBs program is attracting significant interest from 

local governments. In contrast, REPIs are subject to annual congressional appropriations and to 

date have been unable to meet the total requests each year. These two factors mean that REPIs 

are not bankable in project financing. 

4.1 Overview of CREBs 

To participate in CREBs, a state or local government must apply to the IRS for a CREBs 

allocation. Upon receiving an allocation, the public entity can issue CREBs to finance a solar PV 

project.40, 41 Originally created in the 2005 Energy Tax Incentives Act, CREBs provide a federal 

tax credit to the bond owners in lieu of interest payments from the issuer.42 Because the issuer 

(in theory) does not have to make interest payments and only has to pay off the bond principal, 

this feature is attractive compared to tax-exempt municipal bonds. 

 

The initial allocation for the CREBs program was $800 million in 2005; legislation in 2006 

increased this amount to $1.2 billion dollars.43 In total, the amount of CREBs allocations that can 

be awarded to public-sector projects can be up to 62.5% of the total allocations. In the first 

round, $800 million of CREBs allocations went to 610 projects.44 Figure 5 shows that 433 of 

these projects were for PV; of these, 93% were in the public sector.45 

The second round of CREBs applications were due in July 200746 and project awards were 

announced on February 8, 2008.47 312 projects received allocations totaling $477 million dollars. 

Similar to the 2006 allocations, public-sector PV projects were awarded a significant percentage 

of the total allocations. In 2008, 55% of the total funds allocated were for public-sector PV.48 As 

illustrated in Figure 6, 44% of the total number of allocations were for PV projects (includes 

both governments and cooperatives). 

40 Other qualified entities that can borrow money using CREBs include cooperatives, any political subdivision that 

can issue tax-free bonds, and tribal governments. All of these entities, including states and local governments, can 

actually issue the CREBs; in addition, qualified cooperative lenders can issue bonds. 

41 CREBs can be used to help finance a number of renewable technologies, including wind, closed-loop biomass, 

open-loop biomass, geothermal, solar energy, irrigation power facilities, landfill gas, MSW, and hydropower 42 Section 1303 of the Energy Tax Incentives Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005) (the “2005 

Act”) added section 54 to the Internal Revenue Code. 

43 IRS Bulletin No. 2007-14. April 2, 2007. pp. 870, at http://www.irs.gov/pub/irs-irbs/irb07-14.pdf 

44 “Clean Renewable Energy Bond Volume Cap Allocation Information,” IRS News Release IR-2006-181, 

November 20, 2006, at http://www.irs.gov/newsroom/article/0,,id=164423,00.html 

45 Ibid. 

46 “Clean Renewable Energy Bonds- July 13, 2007: Deadline for Second Round Allocation Applications and 

Updated IRS Guidance”. Client Advisory by Hunton and Williams, March 2007, at 

http://www.hunton.com/files/tbl_s10News%5CFileUpload44%5C14044%5CCREB_Alert_March2007.pdf 47 “IRS Announces Energy Bond Allocations,” IRS News Release IR-2008-016, February 8, 2008, at 

http://www.irs.gov/pub/irs-news/ir-08-016.pdf 

48 Ibid. 

 14
Wind

Biomass

Geothermal

Solar

Small Irrigation

Landfill Gas

Trash Combustion

Refined Coal

71%

Solar PV

Hydroelectric

Figure 5. Allocation of 610 Round 1 CREBs projects: 

Distributed by the number of projects per technology 

Source: Internal Revenue Service 2006 

PV

Wind

Landfill Gas

Hydroelectric 

Closed-loop biomass

Trash Combustion

Open-loop Biomass

44%

Solar PV

Figure 6. Allocation of 312 Round 2 CREBs projects: 

Distributed by the number of projects per technology 

Source: Internal Revenue Service 2008 

Currently, the CREBs application process to apply for an IRS allocation is closed. Therefore, 

states and municipalities should not count on CREBs unless they currently have an allocation 

from the first or second rounds. There are legislative proposals to further expand the program, 

however, which are discussed in Section 4.4. At the end of the paper, Appendix 4 provides 

additional information on the critical steps necessary to apply for and issue a CREBs bond. 

4.2 Basic Principles of CREBs 

CREBs allocations are made by the Internal Revenue Service (IRS). The two times that Congress 

allocated money for the program, the IRS put out an announcement asking for applications from 

qualified projects. As shown in Figure 7, the structure is essentially the same as for the issuance 

 15
of a tax-exempt bond described in Appendix 5, except that the federal government provides the 

investor with a tax credit in lieu of interest payment from the project to the investor. 

Figure 7. Clean renewable energy bonds

Challenges: 

• Not truly equivalent to an interest-free bond issue. 

• Assumes bond issuer can issue bonds equivalent to AA corporate credit; public 

entities without such strong credit must either make supplemental interest payments, 

or sell the bond at a discount. 

• Limits transaction costs that can be financed by proceeds from the CREBs to 5%. 

• First principal payment is due in December of the year the CREBs is issued. 

Principal 

Investor 

Upfront capital 

Project/Issuer 

• Provides investor 

with a tax credit 

• Investor buys CREBs, thus 

lending money to the project. 

• Investor receives a tax credit 

from federal government in lieu 

of interest payments. 

• May discount the CREBs, 

depending on the level of the tax 

credit and familiarity with the 

debt instrument. 

• Applies to IRS for 

CREBs allocation 

• If received, issues a bond 

to secure capital for a 

renewable project. 

Tax credit, in 

lieu of interest 

Federal 

government 

• Outlay: Principal repaid 

to investor annually in 

December, starting in the 

year in which the CREB is 

issued. Ideally, no interest 

payment. 

If a state or municipality has a CREBs allocation, specific requirements must be met. First, the 

bond must be issued before the end of 2008, or else the public entity forfeits the ability to secure 

the CREBs tax credits.49 Second, the first payment for a CREB issued in 2008 must be 

considered in the financial planning as it will be due in December 2008. 

There are several distinctions that should be understood with how CREBs are structured. For a 

typical bond issue, the shorter the term the lower the applicable interest rate. With CREBs, the 

longer the term, the longer the investor gets to benefit from the tax credit which increases the 

cost to the U.S. Treasury. As a result, the IRS limits the term of the bond; this limit is currently 

on the order of 15-16 years. In addition, the IRS uses the market rate for AA-rated corporate 

bonds to determine the tax credit to be offered investors. However, this can be challenging 

because not all public entities can borrow at this rate (this is explored in detail in section 4.3.2). 

Finally, each annual principal payment is treated as a separate bond with its own tax credit rate, 

rather than a single bond with one tax credit rate. This is different than how bonds are typically 

structured and it is taking some time for the market to get comfortable with this method. 

 

49 This deadline could be pushed back if the CREBs program receives an extension from Congress, but this should 

not be counted on. 

 16
4.3 Barriers to Using CREBs 

Despite the significant number of CREBs allocations for PV projects, initial evidence indicates 

that the program has some significant challenges. When speaking to a few state and local 

officials, it was clear that the CREBs process is a frustrating one. The IRS awards allocations to 

projects from the smallest to the largest, which ends up maximizing the transaction costs per 

project. Additional issues include the fact that CREBs is often not true interest-free financing 

(based on federal government assumptions), and the challenging requirement to make the first 

bond principal payment in the same year the CREBs award was issued,50 even if the system is 

not yet in service. 

4.3.1 Transaction Costs 

Administrative costs for CREBs are particularly problematic for smaller cities and towns that 

secure their own financing and tend to issue debt in modest amounts. As noted, to date the IRS 

has awarded allocations to projects going from the smallest qualified requests to the largest. 

While this ensures smaller projects are included, it can increase costs on a per-project basis since 

these are essentially fixed and not highly dependent on the size of the project. 

In addition, the CREBs allocation has specific rules regarding how the proceeds can be spent. At 

least 95% of the CREBs allocation must be invested in capital expenditures on qualified project 

costs.51 Up to 5% of the proceeds can be used to cover non-qualified project costs, including 

transaction costs and a debt service reserve fund (which might be required by investors). The IRS 

requires that 95% of the net proceeds be used in the first five years of the project; if not, the IRS 

may require that the bond be redeemed early. 

One interviewee (who wished to remain anonymous), in charge of managing renewable energy 

projects at a particular municipality, performed an analysis on CREBs to determine if it made 

sense to apply for an allocation. The results showed that a $10 million allocation would cost $3 

million when transaction costs, the cost of getting voter approval, and the expected discount to 

par were taken into account. As such, this particular entity decided against applying for a CREBs 

allocation. 

Bundling projects and issuing larger CREBs bonds can help reduce these transaction costs on a 

per-project basis. The state of Massachusetts bundled CREBs issuances together and were able to 

achieve notable transaction cost savings, as explained in Appendix 1. 

4.3.2 Interest Rates 

The combination of the term and the tax credit rate are not quite sufficient for the bonds to be 

truly equivalent to interest-free instruments. According to Bruce Serchuk at Nixon Peabody, to 

date most bonds have been issued at either a discount to par or with a supplemental interest 

payment. The tax credit earned by a buyer of a CREBs bond is based on the current market rate 

for AA corporate bonds.52 However, issuers are not assured of issuing at this rate for a number of 

reasons, including: 

 

50 “Part III – Administrative, Procedural, and Miscellaneous: Clean Renewable Energy Bonds,” Internal Revenue 

Service notification 2005-98, at http://www.irs.gov/pub/irs-drop/n-05-98.pdf 

51 Ibid, pg 4. 

52 “Part III – Administrative, Procedural, and Miscellaneous: Clean Renewable Energy Bonds,” Internal Revenue 

Service notification 2007-26. p14. http://www.irs.gov/pub/irs-tege/n-07-26a.pdf 

 17
• The state/municipality may not be able to borrow at a rate equivalent to the current AA 

corporate borrowing rate; 

• Investor demand for CREBs may be limited given a lack of familiarity with the 

instrument. This may complicate the ability to sell the bonds at par; and/or 

• The amount of the bond issue is small. 

In 2006, Carbondale, Colorado, received a CREBs allocation of $1.6 million to help finance 250 

kW of solar electricity. On November 6, 2006, 80% of the voters in Carbondale approved a 

ballot initiative (2F) for the town to issue up to $1.8 million in Energy Bonds to construct and 

operate two large-scale solar systems.53 Xcel Energy agreed to provide $1.5 million in the form 

of rebates and SREC purchases to lower the installed cost of the systems. The bonds were 

approved by voters as interest-free debt. Electricity sales and energy savings from the proposed 

solar projects would cover the amortization of the principal. Unfortunately, Carbondale would 

have had to issue the bonds at a discount to par, since their municipal borrowing rate is higher 

than an AA corporate borrowing rate. This discount to par, plus the transaction costs associated 

with issuing the debt, made the proposed Energy Bonds more expensive than initially expected 

and the town of Carbondale decided to abandon using CREBs.54 The town is now pursuing other 

options to finance its solar projects, including partnering with private capital to take advantage of 

federal tax incentives. 

4.3.3 Early First Payment 

The requirement to make the first CREBs payment in the calendar year that the CREBs are 

issued can also be problematic. For example, if a CREB is issued in October, the first principal 

payment is due in December of the same year. Note that the principal payment is due whether the 

PV system begins to produce electricity or not. This structure is distinct from how the principal 

is typically repaid on bonds, where the interest might be paid annually, but the principal is 

usually paid fully at maturity (unless repaid early, as in the case of a callable bond). 

Consequently, the issuer may need to be prepared to tap into other funds to make the first 

payment. 

4.4 The Future of CREBs

Given the uncertainty surrounding the extension of the program, state and local governments 

should evaluate their proposed PV projects with the assumption that additional CREBs funding 

will not be available. However, if a new CREBs allocation is approved by Congress and signed 

by the President before a particular project is financed, and if the project meets eligibility 

requirements, an application can then be submitted to the IRS for a CREBs allocation. If the 

project has already been financed using other financial instruments, public entities should 

investigate whether or not the reauthorized CREBs program continues to allow for project 

refinancing. If so, depending on the current interest rate environment, it may make economic 

sense to consider refinancing outstanding debt with a CREBs issuance. 

 

53 Guarascio, Gina. “Carbondale pursues solar power, but unsure how much,” Post Independent of Glenwood 

Springs, Colorado, January 19, 2007, at www.postindependent.com/article/20070119/VALLEYNEWS/101190052 

54 Personal communication with the Community Office for Resource Efficiency with Gary Goodson (new director) 

and Randy Udall (former director, as of April 2008, no longer with CORE), October and December 2008. For more 

information, see http://www.aspencore.org/. 

 18
There are proposals in the House and Senate to expand the CREBs program, often grouped with 

the reauthorization of production and investment tax credits. For example, the proposed 

Renewable Energy and Energy Conservation Tax Act of 2008 (H.R. 5351), which the House of 

Representatives passed in early 2008, was referred to the United States Senate. If passed and 

signed by the president, the bill would establish an additional $2 billion for new CREB 

allocations.55 If the CREBs program is expanded, an additional round of CREBs would likely be 

issued by the IRS soon thereafter, and applicants would have a few months to put together an 

application. It is also worthwhile to note that the second round of CREBs also included 

allocations that had been turned-in to the IRS from first-round awardees who decided to not use 

their CREBS allocation. A third round of CREBs allocations could include additional allocations 

that have since been surrenders to the IRS. 

The proposed legislation may address a few other issues as well. For municipalities, the proposal 

shifts from making awards to the smallest projects first to issuing awards at a pro-rata share of 

the total funds available across all eligible projects that apply. It also proposes to eliminate the 

requirement to make the first principal repayment in the year that the bond is issued and to either 

allow for a grace period of some duration or a lump sum payment at maturity. 

4.5 Federal Renewable Energy Production Incentive (REPI)

A second federal program, which was designed to assist municipalities finance new renewable 

energy projects, is called the Renewable Energy Production Incentive (REPI) Program. 

Authorized under the Energy Policy Act of 1992 and amended under the 2005 Energy Policy 

Act, REPI provides financial incentive payments as renewable electricity is generated. In other 

words, it is a production-based incentive program.56 

It is difficult for public entities to count on the availability of full REPI payments to help finance 

renewable projects for two main reasons. First, while the REPI program provides qualifying 

projects with incentives over a 10-year period, funding is subject to annual federal appropriations 

and is therefore uncertain every year.57 This uncertainty is unacceptable to lenders, who will 

attribute no value to potential REPI payments, to reduce their risk of investment. Additionally, 

funding has been insufficient to meet 100% of the qualified REPI payments. For example, in 

2007, only 25% of the amount requested by qualified producers was paid out (based on 2006 

electricity production). Approximately $20 million worth of REPI credits were requested in 

2006, yet only $4.9 million were allocated by Congress for the program.58 Given that REPI 

payouts are production based, the amount can still be considerable for large producers of 

electricity. In 2007, a Nebraska wind project received a $1.1 million REPI payment and a 

Washington wind project received a REPI payment of $585,000.59 

 

55 “Renewable Energy and Energy Conservation Tax Act of 2008 (Engrossed as Agreed to or Passed by House)” 

United States Congress proposed legislation [H.R.5351.EH], Title I, Subpart I, Section 54B New Clean Renewable 

Energy Bonds, at http://thomas.loc.gov/cgi-bin/query/F?c110:4:./temp/~c110Z35Iae:e32849: 

56 “Renewable Energy Production Incentive,” U.S. Department of Energy Web site, accessed April 6, 2008, at 

http://www.eere.energy.gov/repi/ 

57 “Renewable Energy Production Incentive: About the Program,” U.S. Department of Energy Web site, accessed 

April 6, 2008, at http://www.eere.energy.gov/repi/about.cfm 

58 Personal communication with Christine Carter and Chico Gonzalez, REPI program managers of the U.S. 

Department of Energy Golden (Colorado) Field Office in December 2008. 

59 Ibid. 

 19
However, for many projects, particularly solar, the REPI payout is very modest. The average 

allocation for the 25 solar projects that received REPI funds in 2007 was $898.52.60 Given this 

data and the fact that REPI rewards electricity already generated, it is not a significant driver of 

financing new public-sector PV. One local government REPI beneficiary (who did not wish to be 

cited), viewed REPI as an added bonus but not something to include in a project's justification or 

economic analysis. In this particular case, only 10% of the incentives earned by this district's 

qualifying projects had actually been paid out over the years. 

 

60 Ibid. 

 20
5.0 Federal and State Tax Incentives 

The emergence of the third-party ownership model (described in Section 6) has created a 

mechanism whereby renewable projects on government property can benefit from federal and 

state tax incentives. These incentives provide tremendous value to the system owner, which can 

be passed on to the public host. For example, the federal investment tax credit (ITC) and 

Modified Accelerated Cost Recovery System (MACRS) can account for 40-60% of the installed 

cost of a PV system,61 which can dramatically alter the economic viability of installing solar. 

State tax incentives also provide benefits to tax paying entities. The value of these incentives can 

be passed on to public entities through the price of the power purchase agreement (PPA), which 

is typically at or below the utility’s retail rate in the first year. This section explains the two 

primary federal tax incentives for solar, the ITC and MACRS, and also describes certain state tax 

incentives. 

5.1 Investment Tax Credit (ITC) 

For commercial entities, the federal government currently offers a 30% investment tax credit to 

partially offset the up-front installed cost of a PV system.62 This credit will revert back to 10% as 

of January 1st, 2009, if Congress does not reauthorize it. The system owner can use this credit to 

reduce his tax burden. For example, a PV system with an installed cost of $1 million will qualify 

for a $300,000 tax incentive. The rules associated with the ITC are complex and a tax lawyer 

should review its application. Certain incentives can reduce the ITC’s value and can impact the 

depreciable basis of the underlying asset as well. The Solar Energy Industry Association's Guide 

to Federal Tax Incentives for Solar Energy provides good background information and incentive 

detail.63

5.2. Modified Accelerated Cost Recovery System (MACRS) and Bonus 

Depreciation64 

As defined by the IRS, “depreciation is an income tax deduction that allows a taxpayer to 

recover the cost or other basis of certain property. It is an annual allowance for the wear and tear, 

deterioration, or obsolescence of the property.”65 Depreciation schedules can range from 3-50 

years, depending on the asset.66 It is a non-cash charge recorded as a depreciation expense for 

tax purposes, and most property today is depreciated using MACRS.67 The IRS allows 

 

61 Cory, Karlynn, Jason Coughlin, et al. “Innovations in Wind and Solar PV Financing,” National Renewable Energy 

Laboratory technical report NREL/TP-670-42919, February 2008, at http://www.nrel.gov/docs/fy08osti/42919.pdf 62 See Section 48 (a) (3) (Investment Credit: Energy Credit) in the IRS tax code. 

63 Chadbourne & Parke, LLP. “Guide to Federal Tax Incentives for Solar Energy: Version 1.2,” Solar Energy 

Industries Association, version 1.2 released May 26, 2006, at http://seia.org/taxmanualdownload.php 

64 “Modified Accelerated Cost-Recovery System (MACRS) + Bonus Depreciation,” Database of State Incentives for 

Renewables and Efficiency (DSIRE), last reviewed February 27, 2008, accessed March 2008, at 

http://www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=US06F&State=federal¤tpageid=1

&ee=1&re=1

65 “A Brief Overview of Depreciation,” Internal Revenue Service Web site, accessed April 2008, at 

http://www.irs.gov/businesses/small/article/0,,id=137026,00.html 

66 “Modified Accelerated cost-Recovery system (MACRS) + Bonus Depreciation,” Database of State Incentives for 

Renewables and Efficiency (DSIRE), last reviewed February 27, 2008, accessed March 2008, at 

http://www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=US06F&State=Federal¤tpageid=1 

67 “Chapter 4. Figuring Depreciation Under MACRS,” Internal Revenue Service publication 946, accessed March 

2008, at http://www.irs.gov/publications/p946/ch04.html 

 21
commercial owners of PV systems (and most renewable systems) to use a five-year MACRS 

schedule.

 

Depreciation reduces an entity's taxable income and subsequently, its tax burden. The sh

depreciation schedule, the greater the percentage of the asset that can be depreciated each 

So in the case of PV, five-year M

orter the 

year. 

ACRS is more advantageous than longer depreciation 

hedules because shorter schedules allow businesses to accelerate the tax benefits of 

ets 

e 

improving the return characteristics of the project. The 

quirement that the depreciable basis of the underlying asset be reduced by 50% of the federal 

of 

orate entities purchasing PV systems. According to the North 

arolina Solar Center, more than 10 states offer some form of local tax relief to encourage 

2002, 

ol District in Oregon's Central Cascade Mountains sold its tax credits to 

e Nike Corporation and received $129,000 to assist with the capital costs of its energy 

fficiency upgrades.71

 

sc

depreciating a particular asset. 

The Economic Stimulus Act of 2008 (ESA08) contains bonus depreciation for qualifying ass

placed in service in 2008. Renewable energy installations, including PV systems, may qualify for 

this bonus depreciation if certain criteria are met. Instead of the standard five-year MACRS 

schedule described in the preceding paragraph, under the ESA08, 50% of the installed cost of th

PV system can be depreciated in the first year, with the remaining 50% to be depreciated over

the original schedule. By accelerating the amount of depreciation in the first year, tax benefits 

will accrue more rapidly to investors, 

re

investment tax credit did not change. 

5.3 State Tax Credit Incentives 

Individual states have a number of mechanisms at their disposal to support the development 

renewable energy within their jurisdictions. The aforementioned RPS is one such mechanism, 

and state tax credits, sales tax exemptions, and property tax exemptions are three additional 

incentives that create value for corp

C

renewable energy development.68 

The Oregon Business Energy Tax Credit (BETC) is noteworthy given its relevance to publicsector entities. The BETC is a state income tax credit up to 50% of the installed costs of a 

renewable energy system. The tax paying entity can apply the tax credit pro-rata over five years 

to lower its state income tax bill.69 In recognition of the non-tax-paying status of governments 

and nonprofits, the Oregon Department of Energy created a “Pass-Through Option” where a 

government agency or a school, for example, can sell the present value of its tax credit to a tax 

paying entity and use the proceeds to defray the cost of its PV project.70 For example, in 

the North Santiam Scho

th

e

68 “Corporate Tax Incentives for Renewable Energy,” Database of State Incentives for Renewables and Efficiency 

(DSIRE), last review depends on the state, accessed April 2008, at 

http://www.dsireusa.org/library/includes/seeallincentivetype.cfm?type=Corporate¤tpageid=7&back=fintab&

EE=0&RE=1 

69 Ibid. 

70 “Business Energy Tax Credit Pass-Through,” Oregon Department of Energy – Conservation Division, accessed 

April 2008, http://egov.oregon.gov/ENERGY/CONS/BUS/tax/pass-through.shtml 

71 “Case Study: North Santiam School District: Homework pays off for North Santiam Schools, “ Oregon 

Department of Energy – Conservation Division, February 2008 at 

http://egov.oregon.gov/ENERGY/CONS/SB1149/Schools/docs/NorthSantiam.PDF 

 22
6.0 Third-Party Financier Model in the Public Sector 

Now that the tax incentives have been described, this section turns to how public entities can 

finance on-site PV by working with partners to monetize the federal tax incentives. 

6.1 Public-Sector Hosts, but Does Not Own PV 

In the public-sector PV marketplace, public entities are moving away from direct ownership of 

PV systems and toward the use of partnering with third-party owners. While common in the 

private sector, the use of third-party ownership structures is still a relatively new phenomenon in 

the public sector. According to Greentech Media, in 2007, 50% of the growth in the commercial 

and institutional market for solar in the United States was carried out using the third-party owner 

model compared to just 10% in 2006.72 State and local governments see the third-party 

ownership model as a potential way to effectively monetize federal tax benefits, avoid paying the 

up-front cost of solar, more efficiently allocate public funds, and accelerate the deployment of 

solar PV. 

Instead of owning the PV system, a public entity hosts a system that is paid for and owned by a 

taxable entity. The public entity enters into a long-term contract (the “PPA”) with a third party to 

purchase the electricity generated on its property. The electricity price is typically set at or below 

the host's current retail rate for the first year, and then will typically increase at a fixed 

percentage over time. The developer manages all aspects of system financing, installation, and 

maintenance, and bears all operating risks as illustrated in Figure 8. 

Figure 8. Contracts and cash flow in third-party ownership model 

Source: Department of Energy Solar Program 

Benefits of the third-party ownership structure include no up-front capital costs, known 

electricity prices purchased from the system for 20-25 years, no responsibility if the system does 

not perform over time (except to purchase more power from their utility), and a shift in the 

operating and maintenance (O&M) responsibility onto a qualified party. The details of the roles 

and responsibilities of different parties for one variation of the third-party ownership model are 

 

72 Guice, Jon, and John D.H. King, “Solar Power Services: How PPAs are changing the PV Value Chain,” 

Greentech Media Inc., February 14, 2008. 

 23
shown in Figure 9. Examples of the third-party ownership structure in place in the public sector 

include PV facilities at an airport,73 a water treatment plant,74 and a port,75 to name a few. These 

examples are explored in detail in Appendix 1. 

Figure 9. Third-party ownership model details (one variation) 

• Outlay: Nothing up front 

• Hosts system, but does not own it 

• Provides the developer with access 

to the system on own property 

• May receive fixed-price power at or 

below current retail price in the first 

year. Typically escalates annually. 

• Signs 20-30 year PPA to provide 

critical annual revenues 

• Can purchase replacement RECs 

(e.g., wind) 

Host/customer 

(e.g. big retailer)

Project 

Developer Electricity income 

• Designs, builds, and 

maintains system 

• Arranges transaction 

and financing 

• Signs PPA with host 

• Receives income 

from the sale of 

RECs 

• Provides capital 

• Owns equipment 

• Receives state and 

federal tax benefits

• Receives income 

from electricity 

sales to Host

Investor 

Upfront capital 

Tax Credits 

20-25 yr PPA 

Predetermined 

Power Price 

While the third-party owner model is attractive, there are some important caveats—most notably, 

if the SRECs are sold, then the municipality cannot claim it is consuming green power unless it 

buys replacement RECs.76 A second issue is that despite the fact that the public entity is hosting 

on-site PV, it still pays for all of its electricity needs. In addition to paying a fixed (and 

escalating) price for power generated on-site through the PPA, the public entity purchases its 

remaining electricity needs from the LSE at the current retail rate. Thirdly, the partners in the 

third-party ownership model must have access to the site where the PV system is located. 

Finally, transaction costs can be significant and there are some specific contracting issues that 

require attention. These challenges are explored in Section 6.3. 

6.2 The Benefits of Third-Party Ownership 

There are several key reasons why more state and local governments are considering the thirdparty PPA an integral component of their PV financing strategy. 

• Ability to Monetize Federal Tax Incentives. As noted above, the federal ITC for 

commercial solar projects is 30% of the installed capital cost. In addition, businesses can 

accelerate the depreciation of the cost of a solar system using a five-year MACRS. 

Together, these two tax incentives have a tremendous impact on both the cost of and the 

financial returns on a project. However, as non-tax paying entities, state and local 

 

73 Denver International Airport 

74 San Diego's Alvarado Water Treatment Plant 

75 Port of Oakland, California 

76 When a renewable generation owner sells the RECs, it also sells the right to claim they are using renewable 

power. This is discussed in more detail in Section 6.3. 

 24
governments cannot benefit from these attractive incentives if they own PV systems. The 

third-party ownership model introduces a taxable entity into the structure that can benefit 

from the federal tax incentives, lowering the overall cost to the non-taxable entity. 

• Low/No Up-front Costs. At $9-10 per installed watt in parts of California,77 publicsector PV systems (above 100 kW) can easily cost hundreds of thousands of dollars. 

Even with rebates and incentives to reduce this amount, the up-front cost is significant. 

Given budget constraints, committing to such a large initial investment is not always 

feasible, even if the long-run economics make sense. The third-party ownership structure 

pushes this initial cost on to the solar developer and its investors. 

• Predetermined Electricity Price for 20-25 years. In today's volatile energy markets, a 

fixed-priced PPA (with a predetermined escalation rate) offers predictable electricity 

pricing for the portion of the entity's load served by the PV system. To make the thirdparty ownership model work, the price of electricity is usually set at or below the 

customer’s current retail rate for the first year, and then escalates annually for 20-25 

years. This structure provides a price hedge against the potential volatility of both fossil 

fuel and electricity markets. An annual price escalator of 3-3.5% is common in today's 

marketplace,78 although smaller escalators are possible. For example, San Francisco's bus 

company, AC Transit, has signed a 20-year PPA with MMA Renewable Ventures with a 

2.5% price escalator.79

• Shift O&M Responsibility to Qualified Third Party. Owning a large PV system 

implies a certain degree of oversight and maintenance that a public entity may not want 

to be responsible for or have the expertise to carry out. One of the attractive features of 

the third-party ownership structure is the ability to assign the operation and maintenance 

of the PV system to more qualified counterparties. The third-party ownership model 

streamlines the number of counterparties that the public entity has to deal with down to 

basically one, the PPA provider/developer. 

• Path to Ownership. It is possible for a local government to include a buyout option in 

the PPA. From a financial perspective, this option would likely take place after year six 

so that the original investors are able to capture all of the tax incentives. This buyout will 

likely represent a mutually agreed upon fair market value for the PV system. For 

example, the Denver International Airport (DIA) has entered into a 25-year PPA with 

MMA Renewable Ventures for a 2 MW PV system at the airport. This PPA contains an 

estimated $8.1 million dollar buyout option after year six that will allow DIA to take 

ownership (the actual payment will be based on the fair market value of the system at the 

 

77 Phillips, Roy. “Solar Technology,” presentation at the Solar Power Project Development and Finance Tutorial in 

San Diego, California, by the president of Marin Solar on November 14, 2007. 

78 Horsey, Ed. “Modeling Solar Projects,” presentation at the Solar Power Project Development and Finance 

Tutorial in San Diego, California, by a principal of Enselle LLC on November 15, 2007. 

79 “Solar’s Newest Resource: MMA Renewable brings together energy users, builders, and financiers to build miniutilities,” BusinessWeek article from www.businessweek.com, published December 12, 2007, at 

http://www.businessweek.com/magazine/content/07_49/b4061074.htm?chan=technology_technology+index+page_t

op+stories&chan=innovation_architecture_top+stories 

 25
time of purchase).80 If a buyout option is not exercised prior to the end of the original 

PPA term, at the end of the term, the three likely scenarios for the host would be to: 1) 

extend the PPA agreement, 2) purchase the system, or 3) ask that the system be removed.

81 

6.3 Caveats with Third-Party Ownership 

While the third-party ownership model can be attractive for state and local governments, it is not 

perfect. There are nuances to PPA agreements which must be understood before moving ahead 

with the third-party ownership structure. 

• Green versus Brown Energy. It is common in third-party PPA agreements that 

ownership of the SRECs be transferred to the owner of the system (i.e., not the state/local 

government). If this is the case, state and local governments must be careful how they 

advertise the solar PV systems that they host. In the absence of REC ownership, it is not 

accurate to claim that the public agency is powered by clean or green energy. The owner 

of the SREC is the only entity that can claim the environmental attributes of the solar 

power. In essence, the host has sold the clean attributes of the system in the form of 

SRECs. Instead, what may be permissible is to say that the agency “hosts” solar panels 

on its property.82 The rationale is to avoid double-counting of renewable energy credits 

by more than one entity.83 Therefore, if a particular agency wants to claim that they are 

powered by solar energy, it must either own the system or negotiate to retain ownership 

of the SRECs within the PPA. However, by retaining SREC ownership, the negotiated 

price of electricity plus SRECs in the PPA will be higher to compensate the third-party 

PPA provider for the loss of the SREC revenue stream. An alternative option is to replace 

the SRECs sold to the owner with lower-cost wind or biomass RECs purchased in the 

voluntary green market to claim they are supporting green power (but again, not solar 

power). 

• Ownership and Facility Access. In some cases, ownership is important.

o One of the concepts that can attract public entities to solar PV is the concept of a 

permanent reduction in electricity bill payments to their LSE. However, when the 

third-party ownership model is used, the host must still pay for the power 

generated on-site during the term of the PPA (albeit at a known rate that will not 

change with fossil fuel and electricity prices). While a third-party PPA can allow 

for system buyout options (generally after tax incentives are exhausted), in most 

 

80 Vuong, Andy. “Solar-energy system to land at DIA in 2008,” The Denver Post, October 1, 2007, at 

http://www.denverpost.com/ci_7056394?source=rss 

81 Guice, Jon, and John D. H. King. “Solar Power Services: How PPAs are Changing the PV Value Chain,” 

Greentech Media, February 14, 2008. 

82 The Federal Trade Commission (FTC) is currently investigating renewable energy certificates and carbon offsets 

(among other topics) and held a workshop on January 8, 2008, to discuss advertising claims. The FTC is planning to 

issue guidance in late 2008 or early 2009 that clarifies the claims that parties can make (as of early 2008), and they 

plan to include guidance about REC claims in the third-party ownership model. More information can be found at 

http://www.ftc.gov/bcp/workshops/carbonoffsets/index.shtml, or by contacting Hampton Newsome at 202-326-

2889. 

83 Holt, Ed, Ryan Wiser, and Mark Bolinger, “Who Owns Renewable Energy Certificates? An Exploration of Policy 

Options and Practice,” Lawrence Berkeley National Laboratory technical report LBNL-59965, April 2006, at 

http://eetd.lbl.gov/ea/emp/reports/59965.pdf 

 26
cases, permanently lower electric bills must wait until the PPA expires and the 

host exercises the ownership option (during which the host will have to pay the 

fair market value of the system). 

o Some government agency staff, particularly plant/facility managers and security 

staff, may not be comfortable with a third party having access to and installing 

equipment on their property. Ongoing site access is critical to the performance of 

the system and if that is not acceptable, the third-party ownership model will 

unlikely be a viable option. 

• Transaction Costs. The third-party ownership model requires knowledgeable lawyers to 

assist with implementing the appropriate contracts so that the various federal tax 

incentives can be monetized. While the host is not involved with all of the contracts that 

need to be signed, it is involved with the PPA itself and must be ready to allocate 

resources to ensure its interests are represented in the final contract. 

• Municipal-Specific Contractual Issues. Most state and local governments approve the 

funding of their operating obligations on an annual basis, so there is a question about the 

enforceability of a long-term PPA. This is typically addressed through two mechanisms: 

o Non-appropriation clause: A non-appropriation clause permits the hosting 

customer to terminate the PPA at the end of any appropriation period without 

further obligation or payment of any penalty, if and only if, the host was unable to 

obtain appropriation for funds to meet future scheduled payments and a formal 

resolution or ordinance is passed. Often, this type of clause will contain a "best 

efforts" requirement, i.e., the customer promises to use its best efforts to seek and 

obtain the necessary appropriation for payment. This provision is common in taxexempt leases and is designed to enable the customer to account for the PPA 

obligation as a current expense instead of debt. 

o Non-substitution clause: In today’s fast-evolving solar industry, non-substitution 

clauses are used to protect a project’s viability. If a PPA is canceled due to nonappropriation, the clause prohibits the customer from replacing the hosted 

equipment supported by the PPA with equipment that performs the same or 

similar function. A non-substitution period of 365 days is common, and shorter 

time periods are also used. Decisions regarding the length of the non-substitution 

period are based partly on the perceived essential nature of the equipment. 

Generally, the more essential the equipment is, the shorter the non-substitution 

period will be. Given the host’s right to cancel under the non-appropriation 

clause, the non-substitution clause is intended to provide some comfort to the 

investor and the project developer. 

• Legality Concerns. In Nevada, there may be some question about the legality of using 

the third-party model for on-site projects. The argument is that by selling power to a host 

facility, the third-party PPA provider might be illegally competing with the utilities. The 

 27
Public Utilities Commission of Nevada is investigating these concerns and is expected to 

make a ruling later in 2008.84

In the end, city and state program administrators will determine how best to tailor third-party 

ownership and the PPAs to meet their PV program goals and to capitalize on any incentives. 

Certainly, the promise of stable and predictable electricity prices for 20-25 years has value. 

However, the economic value can only be measured retroactively when the contracted PPA 

prices can be measured against actual market prices. While any realized electricity savings (or 

additional costs) can be calculated over time, the total net economic benefit (or cost) can only be 

determined at the end of the PPA. 

6.4 Who is Using Third-Party Ownership in the Public Sector? 

While there are many examples of individual public-sector projects that use a third-party 

ownership structure (many of which are in California), comprehensive programmatic approaches 

to third-party financing are relatively new. States such as Massachusetts85 and Hawaii,86 and 

local governments such as Boulder County, Colorado,87 are among those pursuing more 

comprehensive third-party ownership models. In 2007, the San Francisco Public Utilities 

Commission88 (SFPUC) and the Sacramento Municipal Utility District89 (SMUD) issued a 

request for information and a request for offer, respectively, seeking PPA proposals for PV 

deployment. This trend is continuing into 2008; more cities have indicated an interest in issuing 

requests for proposals for solar PV PPAs. Recent examples of public-sector third-party owner 

projects are included in Appendix 1. 

6.5 Sale-Leaseback and the Partnership-Flip Models90

It is important for state and local governments to understand the dynamics between the solar 

developer and its tax-equity investors, because the agreement between these two parties will 

influence elements of the PPA, including the timing and the cost of any potential buyout options. 

Common system ownership structures include the sale-leaseback model and the partnership-flip 

model. 

6.5.1 Sale-Leaseback Structure 

The sale-leaseback structure is shown in Figure 10. Under the sale-leaseback arrangement, the 

tax-equity investor buys the PV system and leases it to the third-party PPA provider. The third-

 

84 Lacey, Stephen. “Nevada Debates Third-Party Ownership of Renewable Energy Systems,” Renewable Energy 

World, March 24, 2008, at http://www.renewableenergyworld.com/rea/news/story?id=51908. 85 Personal communications with Jon Abe of the Massachusetts Technology Collaborative, December 2008. 

86 “Governor Lingle Announces Historic Plan to Utilize Solar Power at 12 Locations Around State: Plan highlights 

commitment to renewable energy, leading by example,” Hawaii governor's news release, January 9, 2008, at 

http://hawaii.gov/gov/news/releases/2008/news_item.2008-01-09.3842330405 

87 “Boulder County Envisions Expansion of Solar Power on County Buildings,” Boulder County Colorado, 

November 16, 2007, at http://www.co.boulder.co.us/newsroom/templates/?a=976&z=1

88 “Request for Information: development of renewable power facilities within the city,” San Francisco Public 

Utilities Commission, February 22, 2007, at http://www.fypower.org/pdf/SFPUC_Solar_RFI.pdf 

89 “SMUD to Release 2007 Renewable Energy RFO,” Sacramento Municipal Utility District, news release on March 

8, 2007, at http://www.smud.org/news/releases/07archive/03_08RenewableRFO.pdf 

90 Most of the information in this section was provided through several personal communications with Charles 

Jennings, of Financial Analytics Consulting Corporation, in February and March 2008. Additional input was 

provided from Mark Bolinger, Lawrence Berkeley National Laboratory, on March 30, 2008. 

 28
party PPA provider, in turn, signs a PPA with the state or local government agency that will host 

the PV system. At the end of the lease period, which likely will be after “year six” when the tax 

benefits have been exhausted, the third-party PPA provider can purchase the system. At that 

time, and at predetermined times throughout the remainder of the PPA, the municipality may 

have the option to purchase the system and take full ownership, if this was contractually arranged 

in the PPA. The sale-leaseback structure is subject to the same rules of any capital equipment 

lease, in that the tax investor must show a before-tax profit on the lease, net of the investment tax 

benefit. Therefore, the transaction must be structured so that it shows an economic benefit to the 

tax investor, other than merely the tax incentives. 

Figure 10. Sale-leaseback structure with PPA

Tax-Equity 

Investor 

• Purchases PV system 

• Leases PV system to 

developer 

• Monetizes federal tax 

incentives 

• Installs system 

• Operates system 

• Maintains system 

• Signs PPA with Host 

• Delivers electricity to Host 

Lease agreement 

Lease payments 

Tax credits 

Solar Developer and 

PPA Counterparty 

6.5.2 Partnership-Flip Structure 

The partnership-flip structure is borrowed from the wind industry and is shown in Figure 11. The 

solar developer and tax-equity investor(s) can form a partnership for the express purpose of 

installing and operating that system, usually in the form of a limited liability corporation or 

special purpose entity (SPE). The SPE then purchases the PV system and enters into a PPA with 

the public-sector host of the system. The SPE, or its affiliates, will install, operate, and maintain 

the PV system. The tax-equity investor will own a majority stake (nearly 100%) in the SPE in the 

early years of the project (through year six) to monetize the federal tax incentives. When these 

tax benefits are exhausted, majority ownership “flips” from the tax investor to the developer. At 

that time, and at predetermined times throughout the remainder of the PPA, the municipality may 

have the option to purchase the system and take full ownership, if the option was contractually 

arranged in the PPA. 

 29
Figure 11. Partnership-flip structure with PPA 

Tax-Equity 

Investor 

• Purchases PV system 

• Monetizes federal tax incentives 

• Installs system 

• Operates system 

• Maintains system 

• Signs PPA with Host 

• Delivers electricity to Host 

Solar Developer and 

PPA Counterparty 

Tax credits Partnership 

(SPE) 

While the ownership requirements are not clear for solar facilities using the ITC, at the end of 

2007, the IRS clarified the rules of the production tax credit (PTC) for wind energy deals under 

Revenue Procedure 2007-65.91 In this ruling, the IRS created a “safe harbor,” whereby if the 

ownership structure meets the entire set of key requirements, investors can be certain about the 

allocation of wind tax credits.92 While the IRS made it clear that this procedure does not apply 

to other technologies or other tax credits, the solar industry is using it as a guideline for how ITC 

ownership should be structured. 

 

91 “Part III: Administrative, Procedural, and Miscellaneous: 26 CFR 601.105: Examination of returns and claims for 

refund, credit or abatement; determination of correct tax liability,” Internal Revenue Service, Revenue Procedure 

2007-65, 2007, at http://www.novoco.com/energy/resource_files/irs_guidance/rulings/proc_07-65.pdf 

92 “IRS Establishes Safe Harbor Provision for Investors Claiming Section 45 Wind Energy Credits,” Bracewell & 

Guiliani Update, October 29, 200, at http://www.bracewellgiuliani.com/index.cfm/fa/news.advisory/item/0d77e273-

7527-4f00-90d1-

dc105955d58d/IRS_Establishes_Safe_Harbor_Provisions_for_Investors_Claiming_Section_45_Wind_Energy_Cred

its.cfm 

 30
7.0 Insurance and the Impact on PV Deployment 

Insurance requirements can complicate the installation of PV systems on public buildings and 

lands. Depending on the state, utility companies, as part of the interconnection agreement, can 

require owners of PV systems to obtain additional general liability insurance whose cost can 

reduce the economic viability of the project.93 Under the third-party PPA ownership structure, it 

is the third party that must obtain property insurance for the PV systems hosted by the public 

agency; but, as with other costs associated with the PPA, the customer/host will bear this cost. 

This insurance can be expensive and has the potential to result in higher-than-expected costs—

and could potentially result in abandoning potential projects. 

7.1 Self-Insuring Publicly Owned PV Systems 

An issue for public entities in certain states is the insurance requirement mandated by the local 

utility as a prerequisite to interconnect a PV system to the grid.94 Public entities traditionally 

self-insure property they own. However, local utilities in certain states might require that pub

entities obtain a separate policy, prior to interconnection. While utility interconnect agreements 

allow for self-insurance options,

lic 

 

95 minimum coverage requirements may exceed self-insurance 

levels. Depending on the cost of coverage, this insurance premium could materially impact the 

feasibility of the project. If insurance costs are high enough, it is possible that a PV system will 

be downsized or abandoned to avoid insurance requirements, instead of optimizing it for the 

host's load profile. 

7.2 Massachusetts: Umbrella Insurance Policy Decreases Costs96

If additional liability insurance requirements are unavoidable, anecdotal evidence from 

Massachusetts indicates that an umbrella policy may be a more cost-effective approach than oneoff policies for each project. Net-metering laws in Massachusetts apply to systems up to 60 

kW.97 Additional insurance requirements are triggered for projects greater than 60 kW.98 Of the 

12 CREBs projects for public-sector PV installations that the state's Division of Energy 

Resources (DOER) is involved in (described in Appendix 1), nine of them are larger than 60 kW 

and, thus, require additional insurance. Of those, two already have policies for other powergenerating assets, but the rest must obtain additional insurance. According to utility regulations, 

for projects in the 60-100 kW range, the insurance requirement is $500,000 per project. Projects 

93 “Freeing the Grid: 2007 Edition,” Network for New Energy Choices, Report No. 02-07, November 2007, at 

http://www.newenergychoices.org/uploads/FreeingTheGrid2007_report.pdf 

94 Shirley, Wayne. “Survey of Interconnection Rules,” prepared for the Florida Public Service Commission 

Workshop on Interconnection of Distributed Generation, The Regulatory Assistance Project, August 27, 2007, at 

http://epa.gov/chp/documents/survey_interconnection_rules.pdf 

95 Ibid. 

96 Information in this section that is not attributed to other sources comes from various e-mail conversations with 

Meg Lusardi, Division of Energy Resources, Commonwealth of Massachusetts in October, November, and 

December 2007. (http://www.mass.gov/doer/) 

97 “Massachusetts Incentives for Renewables and Efficiency: Massachusetts – Net Metering,” Database of State 

Incentives for Renewables and Efficiency (DSIRE), last reviewed 04/25/2007 and accessed April 2008, at 

http://www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=MA01R&state=MA&CurrentPageID=1&

RE=1&EE=1 

98 Shirley, Wayne. “Survey of Interconnection Rules,” prepared for the Florida Public Service Commission 

Workshop on Interconnection of Distributed Generation, The Regulatory Assistance Project, August 27, 2007, at 

http://epa.gov/chp/documents/survey_interconnection_rules.pdf 

 31
greater than 100 kW but less than 1 MW require $1 million. Finally, for systems between 1 MW 

and 5 MW, the insurance requirement is $2 million. Utility interconnection agreements in the 

state permit self-insurance if it is established in accordance with commercially acceptable risk 

management practices.99 However, in the case of the aforementioned CREBs projects, the level 

of self-insurance does not meet the minimums stipulated by the insurance requirements listed 

above. 

As a result, the DOER is exploring the concept of an umbrella policy for public-sector PV 

facilities as a way to lower insurance costs on a per-project basis. To provide a data point, one 

particular 425 kW PV project in Massachusetts triggered the need for a $1 million insurance 

policy, which carries an annual premium of $14,000 ($33/kW). However, according to 

conversations that the DOER has had with various insurance agencies, if additional PV projects 

are aggregated under an umbrella policy, costs will decrease on a $/kW basis.100 

7.3 Insurance and Third-Party PPA Providers 

In conversations with two of the largest third-party PPA providers, MMA Renewable Ventures 

and SunEdison, there are "under-the-radar" issues such as insurance, property taxes, sales taxes, 

and other costs that impact project economics and the feasibility of entering into third-party 

ownership agreements. Some states waive certain taxes and fees, such as California, which 

waives property taxes for solar PV.101 A comprehensive list of these exemptions can be found 

on the Solar Energy Industries Association Web site.

102 

However, insurance appears to be a particular issue for third-party PPA providers. From the 

interviews, it is apparent that insurance costs can stop a deal from moving forward. MMA has 

been quoted annual insurance rates as high as 0.5% of the installed project costs, or $50,000 per 

year on a $10 million dollar PV system. Insurance can be costly for a number of reasons, 

including: 

 

o PV equipment and system integration is not well understood by the insurance industry. 

o There is insufficient historical data on losses in the PV industry to appropriately price 

risk. Anecdotally, actual losses in the United States appear to be very minimal. However, 

the operating history for the majority of PV systems in the United States is not long 

enough to fully document what appear to be modest levels of risk. 

o Insurance companies are being asked to provide coverage on expensive electrical 

equipment that is installed on someone else's property. This is not typical and can cause 

some concerns. 

 

99 Ibid. 

100 Personal communication with Meg Lusardi, Division of Energy Resources, Commonwealth of Massachusetts in 

October, November, and December 2007. (http://www.mass.gov/doer/) 

101 “California’s Incentives for Renewables and Efficiency: Property Tax Exemptions for Solar Systems,” Database 

of State Incentives for Renewables and Efficiency (DSIRE), last DSIRE review on 03/05/2008, accessed April 2008, 

at 

http://www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=CA25F&state=CA&CurrentPageID=1&R

E=1&EE=1 

102 Herig, Christy, and Susan Gouchoe. “State by State Incentives for Photovoltaic Projects,” Seague Energy 

Consulting under subcontract to the National Renewable Energy Laboratory, August 2007, at 

http://www.seia.org/PV_Incentives_Aug07.doc 

 32
In addition to the initial premium, the PPA provider must also absorb the risk of annual premium 

increases despite locking in a fixed-price, 20-plus-year contract with the PV host. Annual 

premiums are most likely to fluctuate in markets where there is a greater potential for system 

damage due to issues outside of the project owner’s control. For example, California has the 

potential for seismic activity, and the Gulf Coast has the potential for damaging hurricane 

activity. Floods, fires, and heavy winds are other weather-related risks that the insurance industry 

will severely scrutinize. Florida appears to be particularly problematic. While the state has 

recently announced an aggressive renewable energy plan, which includes promoting the use of 

PV,103 it is unclear whether high insurance rates will be a major barrier for third-party providers 

and their ability to offer PPAs to public entities—and for PV deployment, in general. 

One approach to lowering the cost of insurance on a project basis is for PPA providers to 

establish master policies (often on a state-by-state basis) that moderate the risk profile of PV 

systems in aggregate. Both third-party providers interviewed are doing this. The interviewees 

also suggested three specific activities that could begin to address the insurance challenges, 

including: 

• Collaborate with the U.S. solar industry to compile actual loss data and demonstrate the 

true risks involved in PV. An agency such as the Department of Energy could work with 

solar associations to collect information from industry on a confidential basis and publish 

an annual report on claims made against insurance companies for damage to PV systems. 

• Work with Europe and Japan to secure loss-history data because their systems have been 

operating longer than the systems in the United States. Provide an analysis of this data to 

educate U.S. insurance companies about actual PV risks. 

• Conduct policy roundtables with representatives from the PV industry and the insurance 

industry, to bridge any existing knowledge gap and, potentially, reduce insurance 

premiums that currently inhibit PV deployment in certain instances. 

 

103 Crist, Charlie. “Establishing Immediate Actions to Reduce Greenhouse Gas Emissions within Florida,” State of 

Florida: Office of the Governor, Executive Order Number 07-127, July 13, 2007, 

http://www.fsec.ucf.edu/en/media/enews/2007/pdf/07-127-emissions.pdf 

 33
8.0 Conclusions 

Given the recent changes in the marketplace, many state and local governments are evaluating 

new strategies to deploy solar PV on public property. With payback periods longer than most 

public entities consider reasonable, state incentive programs have proven necessary to help 

support additional solar PV deployment. Appropriate policies and adequate financial incentives 

can motivate public-sector agencies to consider implementing PV on their sites. The goal of this 

report is to gauge the progress of public-sector PV deployment in select states and cities 

throughout the country, and determine what policies and programs are working and where there 

are barriers to deployment. 

A significant source of funding for PV on public and private buildings comes from SBC funds. 

Enacted on a state-by-state or utility-specific basis, SBC funds can successfully support new PV 

projects on public buildings and lands in several ways. Rebates and subsidies can significantly 

reduce the up-front capital costs of a PV system. Funds also can be used to challenge the public 

to take in-kind action, as in Connecticut. Nonetheless, the remaining costs are large enough that 

SBC incentives are often bundled together with other financial incentives. 

RECs have emerged as an important revenue stream for deploying renewables. The 

environmental attributes of renewable energy generation are captured in this tradable commodity 

and are critical to the success of many PV projects. SRECs provide the most revenue in states 

with specific RPS set-asides for solar. In Colorado, Xcel Energy purchases SRECs from the 

owners of qualified PV systems, in addition to providing an up-front cash rebate. New Jersey 

used to provide rebates, in combination with market-based SREC sales, but recently enacted 

changes to phase out those rebates. In the near future, developers must depend solely on SREC 

sales to utilities to get projects financed. The elimination of the up-front solar rebate may create 

additional financing hurdles for new PV projects, particularly for small projects. 

In states with significant support for PV, state and local governments have recently been able to 

use the third-party ownership structure to monetize federal tax credits. Given their non-tax 

paying status, government agencies are traditionally unable to benefit from the generous federal 

tax incentives for PV such as the ITC and accelerated depreciation schedules. However, under a 

third-party PPA, the public entity hosts rather than owns the PV system. The host secures stable 

and predictable electricity prices over a 20- to 25-year period. The up-front capital investment 

and the ongoing operations and maintenance requirements of the PV system are transferred to the 

tax investor and developer, respectively, in exchange for the tax credit benefits. As a result, the 

third-party ownership model offers great promise to those state and local governments looking to 

install a significant number of PV systems in the most cost-efficient manner. Third-party 

ownership is not necessarily the solution for all public entities, especially those who want to 

reduce their annual electricity bills by taking immediate ownership of the PV system, or those 

who are reluctant to provide third parties access to their facilities. 

In addition to tax incentives, there are other federal programs that provide subsidized financing 

for renewable energy owned by public entities. CREBs offer a new source of affordable 

financing for qualifying PV projects. CREBs provide a federal tax credit to investors in lieu of 

interest payments. Massachusetts successfully navigated the CREBs process by pooling together 

several projects to minimize transaction costs. However, in general, transaction costs appear to 

 34
 35

be a significant barrier for local governments who want to finance small PV projects with 

CREBs. In addition to CREBs, the renewable energy production incentive (REPI) also provides 

a 10-year financial incentive for public renewable energy projects. However, it is apparent that 

this particular program does not promote significant new PV deployment because it is subject to 

annual congressional appropriations and has been unable to support a majority of eligible 

projects in the past. 

At the state and local level, governments continue to explore bond-related instruments to finance 

PV projects with mixed success. General obligation bonds supported by a government’s taxing 

authority provide greater security to investors, but revenue bonds repaid by energy savings 

appeal to local governments managing their debt burden. During the past several years, voters, 

city council representatives, and state legislatures have approved solar PV bonds in several states 

and one city. However, of the four cases examined, only Honolulu has successfully issued these 

bonds. It appears that getting approval to issue renewable energy bonds, in general, may be 

easier than issuing them to finance projects. 

The third-party ownership structures are financed using either the sale-leaseback structure or the 

partnership-flip model. While these structures are independent from the PPA that is signed by the 

host and the project developer, they do influence the language in the PPA, in particular, the 

buyout clauses. Both of these third-party structures have complex tax issues associated with their 

use. To the extent the tax issues can be addressed efficiently, these innovative financing 

structures may begin to propagate in the public sector. 

Insurance can be a “below-the-radar” issue in the PV industry. For public agencies accustomed 

to self-insuring their facilities, it is important to determine whether they need to contract for 

third-party insurance to comply with interconnection requirements. It can be costly to insure PV 

systems on a one-off basis. Therefore, Massachusetts is exploring an umbrella insurance policy 

to cover multiple systems and, ultimately, reduce costs on a per-project basis. Aside from new 

insurance requirements for public systems, third-party PPA providers also grapple with the high 

cost of insuring the large-scale systems they own as they pursue PPA opportunities. In certain 

states such as Florida, the high cost of insurance may actually prevent a project from going 

forward. 
 36

AppendicesAppendix 1. Examples of Public-Sector PV Deployment, by State and Project Note: This page provides an overview of the public-sector PV project examples detailed in this appendix and shows which aspects our 

not intended to be comprehensive, and the authors recognize that each state/city may offer many more programs and other states/cities 

included here. 

Table 2. Examples of Public-Sector PV Deployment, by State and Project 

Examples by State and Project*

RECs CREBs SBC

Energy 

Bonds PPA

Energy 

Efficiency 

Emergency 

Power 

State

California

X

Santa Rita Jail X XMoscone Center X XAlvarado Water Treatment Facility X XPort of Oakland X XFresno State University X XSan Francisco X**

Colorado X X

Denver International Airport XXXBoulder County

X

Connecticut

X

Clean Energy Campaign

X

Delaware X**Hawaii

X

Honolulu X**

Massachusetts X X

Montana X XNew Jersey

X

Atlantic County Utilities Authority X X

New York 

X

New Paltz

X

Ohio 

X

Center for Nature Photography

X

New Mexico 

Finance Authority X**

* The examples highlight particular aspects of each state's programs - that each program may offer more than what is listed in the table.X** - These four examples are found in the text in Section 4.2.2.
California

California Solar Initiative104

California is a leader when it comes to public-sector PV programs. San Francisco, Sacramento, 

Berkeley, Los Angeles, and San Jose are just a sample of the many California cities that have 

taken a progressive attitude toward public-sector PV deployment for a number of years. As a 

result, many of the public-sector PV examples are in California. Generous state and utility 

incentives and widespread public support have contributed to the state's impressive demand for 

PV systems. From 1981-2006, 198 MW of grid-connected PV was installed in California.105 In 

2007, 7,541 applications, requesting $558 million in incentives, were submitted for a total of 209 

additional MW of PV.106 Out of these totals, the government and nonprofit sector (the two 

sectors are reported on a combined basis) accounted for 197 applications for 33.4 MW.107 18 

MW of new PV was actually installed in the state in 2007, partly financed by $46 million in 

rebates.108 

In January 2006, the California Public Utilities Commission (CPUC) approved the landmark 

California Solar Initiative (CSI), which authorizes the state to invest $3.2 billion in small-scale 

solar electric systems.109 The California Solar Initiative, funded by a system benefit charge, is 

tasked with developing 3,000 MW of new solar generated electricity by 2017. The CPUC and 

the California Energy Commission (CEC) have joint oversight over the CSI, whereas the utilities 

administer the program. The initiative was complimented in August 2006 when Gov. Arnold 

Schwarzenegger signed the Million Solar Roofs Bill (SB1). The bill created state-level policies 

that reinforced the California Solar Initiative, something that the CPUC was unable to establish 

on its own.110 CSI was officially launched on January 1, 2007, and it is currently administered 

by the utilities in their respective service territories.111 

 

104 “The California Solar Initiative – CSI: About the California Solar Initiative,” Go Solar California Web site, 

accessed April, 2008, at http://www.gosolarcalifornia.ca.gov/csi/index.html 

105 “California Solar Initiative: California Public Utilities Commission: Staff Progress Report,” California Public 

Utilities Commission, September 2007, at http://www.energy.ca.gov/2007publications/CPUC-1000-2007-

011/CPUC-1000-2007-011.PDF 

106 “California Solar Initiative: California Public Utilities Commission: Staff Progress Report,” California Public 

Utilities Commission, January 2008, at http://www.cpuc.ca.gov/NR/rdonlyres/5C9DDC79-3E96-4241-BEEC46D3F34254F4/0/080117_Jan_ED_CSI_Staff_Progress_Report.pdf 

107 “California Solar Initiative Public Forum,” presentation for a meeting hosted by PG&E on January 17, 2008, at 

http://www.cpuc.ca.gov/NR/rdonlyres/ADF0C249-959A-4D17-A242-

58C51E499C4C/0/080117_CSIForummaster.pdf 

108 “California Solar Initiative: California Public Utilities Commission: Staff Progress Report,” California Public 

Utilities Commission, January 2008, at http://www.cpuc.ca.gov/NR/rdonlyres/5C9DDC79-3E96-4241-BEEC46D3F34254F4/0/080117_Jan_ED_CSI_Staff_Progress_Report.pdf 

109 “The California Solar Initiative – CSI: About the California Solar Initiative,” Go Solar California Web site, 

accessed April 2008, at http://www.gosolarcalifornia.ca.gov/csi/index.html 

110 Ibid. 111 The three California utilities are Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San 

Diego Gas & Electric (SDG&E). Note that SDG&E hired a contractor, the California Center for Sustainable Energy 

(CCSE), to manage its program. 

 37
Similar to other states with SBC-funded programs, California initially developed a system of 

capacity-based incentives.112 This capacity-based incentive program was labeled an expected 

performance-based buy-down (EPBB), resulting in an up-front payment based on the expected 

performance of the PV system.113 However, in 2007, with the implementation of the CSI, the 

state began the transition away from up-front EPBB payments to a performance-based incentive 

(PBI) program.114 Under the PBI system, monthly payments based on actual performance are 

paid out over a five-year period. 

In 2007, PV systems that were greater than 100 kW were required to participate in the PBI 

program. As of January 1, 2008, PV projects that are 50 kW or greater will be included in the 

PBI program. This threshold will drop to 30 kW in 2010. Therefore, state and local governments 

currently contemplating PV systems of less than 50 kW can still benefit from up-front incentives 

at a rate of $2.30/watt to $2.65/watt (depending on the utility).115 Public PV systems that exceed 

50 kW can earn $0.32/kWh – $0.37/kWh generated under the new PBI program.116 California 

does provide a higher per watt rebate to non-tax-paying entities to compensate for their inability 

to take advantage of tax incentives. However, both of these incentives step down over time as 

more solar projects are installed and megawatt milestones are achieved. 

Using Energy Efficiency with Solar Projects 

Energy efficiency should not be forgotten when a public agency is considering PV. In addition to 

the cost savings from energy efficiency retrofits, which can have very attractive payback periods 

on their own, there are direct benefits related to the installation of a PV system. If the energy 

consumption of a facility is reduced as a result of energy efficiency investments, the PV system 

can offset a larger portion of the total load of the facility, or the size of the PV facility (and the 

cost) can be reduced. In addition, energy savings resulting from energy efficiency investments 

can help defray the cost of owning and maintaining a PV system. The California Solar Initiative 

now requires that all existing customers applying for a solar incentive must first conduct an 

energy audit, unless 1) they have done an acceptable energy audit in the past three years, 2) have 

proof of Title 24 Compliance,117 or 3) have either Leadership in Energy and Environmental 

Design (LEED) or Energy Star certification.118 Even prior to the introduction of the California 

Solar Initiative, California was paying attention to energy efficiency as the following two 

examples illustrate. 

 

112 “Performance-Based Incentives and New Incentive Levels Starting in 2007,” Go Solar California! Web site, 

accessed April 2008, at http://www.gosolarcalifornia.ca.gov/csi/performance_based.html 

113 “California Solar Initiative: Program Handbook,” California Public Utilities Commission, January 2008, at 

http://www.gosolarcalifornia.ca.gov/documents/CSI_HANDBOOK.PDF 

114 Ibid. 115 “California Solar Initiative: Statewide Trigger Point Tracker,” developed by PG&E, Southern California Edison 

and the Center for Sustainable Energy California, last accessed on April 18, 2008, at http://www.sgip-ca.com/. . . . . 

The price will ramp down as the next trigger point is reached. 

116 Ibid. 117 “California’s Energy Efficiency Standards for Residential and Nonresidential Buildings,” California Energy 

Commission, Title 24, Part 6, of the California Code of Regulations, October 1, 2005, as amended September 11, 

2006, at http://www.energy.ca.gov/title24/ 

118 “California Solar Initiative: Program Handbook,” California Public Utilities Commission, January 2008, at 

http://www.gosolarcalifornia.ca.gov/documents/CSI_HANDBOOK.PDF 

 38
Santa Rita Jail 

Alameda County installed a 1.18 MW system on the Santa Rita Jail in 2001-2002. The system 

produces 2.4 million kWh of annual electricity, meeting approximately 30% of the jail’s daytime 

energy needs.119 The project cost approximately $9 million but was offset by nearly $5 million 

in incentives from the following sources:120

• California Energy Commission's Emerging Renewable Buy-down program 

• California PUC Self Generation Program (through PG&E) 

• Energy efficiency incentive programs 

• Low interest-rate energy efficiency loan from CEC that will be repaid using the 

project's energy savings. 

This project occurred in tandem with an elaborate energy efficiency retrofit. The combined 

savings from this retrofit and the solar installation was $400,000 in the first year of operation, 

and it’s expected to save $15 million during the 25-year life of both projects.121 

Moscone Center122

At the end of 2001, the San Francisco Mayor's Energy Conservation Account (MECA) funded an 

$8.1 million solar and energy efficiency project at the Moscone Center. The project consisted of 

$4.5 million for a 675 kW solar installation and $3.6 million for investments in energy 

efficiency. These costs were offset by the public utility commission’s “self-generation” subsidy 

of $2.3 million, as well as a California Energy Commission (CEC) Incentive for energy 

efficiency of $186,000. As with the Santa Rita Jail, the success of the Moscone project is 

attributed to the energy efficiency upgrades that were executed in connection with the solar PV 

installation. It is estimated that the efficiency measures taken, including upgrades to lighting 

equipment, and building controls, reduces the annual energy needs for the center by more than 

20%. 

California Third-Party Ownership Examples

San Diego’s Alvarado Water Treatment Plant123

San Diego's Water Department has entered into a PPA with SunEdison for 1 MW of solar PV at 

its Alvarado Water Treatment Plant. According to the city's news release, $6.5 million in upfront installation costs were avoided by signing the PPA with SunEdison (as opposed to buying 

the system). Once installed, the PV system will cover 20% of the plant's power needs. 

Port of Oakland124

On November 8, 2007, the Port of Oakland inaugurated its 4,000-panel, 756 kW, groundmounted PV system. SunEdison financed, built, and will own and operate the system. The Port 

 

119 Gouchoe, Susan, Lynne Gillette, and Christy Herig. “Solar Cities: Local Government & Utility Leaders in Solar 

Deployment,” Seague Energy Consulting and Million Solar Roofs Program, March 15, 2004, page 6, at 

http://www.dsireusa.org/documents/PolicyPublications/Solar_Cities_Report_fnl1_3_22_04.pdf 

120 Ibid. 121 Ibid. 122 “Moscone Featured at World Environment Day,” Moscone Center news release, June 1, 2005, at 

http://www.moscone.com/site/do/news/view?id=6 

123 “Mayor Sanders Unveils Solar Power System At Alvarado Water Treatment Plant,” City of San Diego news 

release, March 1, 2007, at http://www.sandiego.gov/environmental-services/energy/news/pdf/070301.pdf 

124 “Port of Oakland and SunEdison Flip the Switch on New Zero Emission Solar Power System,” Port of Oakland 

news release, November 7, 2007, at http://www.portofoakland.com/newsroom/pressrel/view.asp?id=82 

 39
of Oakland signed a PPA with SunEdison to purchase “clean and predictably priced electricity” 

for 20 years at a cost of approximately $4.1 million.125

Fresno State University126

On November 9, 2007, Fresno State University and Chevron Energy Solutions completed the 

installation of a 1.1 MW PV system that will provide the university with 20% of its annual 

electricity needs. The project cost approximately $12 million; an amount that was partly offset 

by a $2.8 million rebate from PG&E under California’s Self-Generation Incentive Program. 

Chevron Energy Solutions installed the PV system and Fresno State signed a 20-year PPA with 

MMA Renewable Ventures. MMA financed and will own the system. The university expects to 

save $13 million in avoided electricity costs over a 30-year period. 

Colorado

Colorado RECs: Meeting Xcel Energy’s RPS Requirement 

Colorado's Renewable Energy Standard requires that investor-owned utilities of a certain size 

meet 20% of their energy sales with renewable sources by 2020.127 Four percent of this 20% 

must be solar, and 50% of this solar requirement (or 2%) must be generated on their customers' 

sites.128 Additionally, renewable energy that is generated in Colorado receives a 1.25x multiplier 

toward their RPS, so that for every 1 kWh generated, 1.25 may be claimed toward 

compliance.129 Community-based systems in the service territory of Colorado electric 

cooperatives and eligible municipal utilities that are less than 30 MW receive a 1.5x credit 

toward RPS compliance purposes. Community-based system refers to a system owned 

collectively by residents of a community, by a local nonprofit organization, by a cooperative, by

a local government agency, or by a tribal council. s) may 

 energy producers. 

 

130 Renewable energy certificates (REC

be used to satisfy compliance with the renewable standard. Utilities that do not generate the 

required amount of electricity from renewable energy sources may purchase RECs from other 

utilities that exceed the requirement or from independent renewable

As an example, Xcel Energy, Colorado’s largest electricity provider, has established the Xcel 

Energy Solar*Rewards program. Xcel will provide a rebate for the installation of a PV system 

and also purchase the RECs generated by the system. A 20-year contract is signed with Xcel 

when the REC agreement is negotiated.131 These REC purchases help Xcel meet its solar 

125 “Oakland Board of Port Commissioners Authorized Port of Oakland’s First Solar Energy Agreement,” Port of 

Oakland news release, June 6, 2006, at http://www.portofoakland.com/newsroom/pressrel/view.asp?id=28 

126 “Fresno State, Chevron Energy Solutions Complete Solar Parking Project Largest at US University,” Fresno 

State News article, November 9, 2007, at http://www.fresnostatenews.com/2007/11/solarwrapup2.htm 127 Subject to an overall retail rate cap of 1.7% on Colorado ratepayers. 

128 “Colorado Incentives for Renewable Energy: Renewable Energy Standard,” Database of State Incentives for 

Renewables and Efficiency (DSIRE), accessed April 2008, at 

http://www.dsireusa.org/library/includes/incentivesearch.cfm?Incentive_Code=CO24R&state=CO¤tpageid=

2&search=State&EE=0&RE=1 

129 Ibid. 130 Ibid. 131 “Solar*Rewards,” Xcel Energy Web site, accessed April 2008, at 

http://www.xcelenergy.com/XLWEB/CDA/0,3080,1-1-2_41004_43476-23075-2_171_256-0,00.html 

 40
obligations under the renewable energy standard while lowering the cost of the system for the 

end user. 

The manner in which the contract with Xcel is structured, as well as the price paid for RECs, 

depends on the size of the system. Small systems (0.5 kW to 10 kW) located on Xcel’s Colorado 

customers’ sites132 get an installation rebate (currently $2/watt) and an up-front REC payment 

equal to $2.50/watt as a way to defray installation costs. Mid-sized systems (10 kW to 100 kW) 

get an up-front installation rebate of $2/watt as well as a monthly REC payment of $115/MWh. 

Large systems (100 kW to 2 MW) must bid for monthly REC payments based on the economics 

of the projects involved. Successful bidders receive their monthly REC price over a 20-year 

period, based on actual generation as well as a $200,000 up-front rebate. For those paid monthly 

for their RECs, there are financial penalties if their PV systems do not generate the expected 

amount of electricity. For the large systems, the winning REC bids (and hence the average REC 

price) are not publicly available. However, NREL calculated an approximate range of $205-

265/MWh based on data from the Xcel 2008 RPS compliance filing, as well as a number of 

assumptions (see footnote).133 

Colorado Third-Party Ownership Examples

Denver International Airport (DIA) 134

In 2007, the Denver International Airport (DIA) announced that it had signed a 25-year PPA 

with MMA Renewable Ventures for a 2 MW solar PV system, which will produce 3.5 million 

kWh per year. The total cost of power to be purchased under the PPA was reported to be $10.9 

million or roughly 12.5c/kWh. Xcel Energy will provide a $200,000 rebate to partially offset the 

project's initial costs. While not stated in the news release, it is also reasonable to assume that 

MMA sold solar RECs to Xcel Energy as part of the project's financing. The system is expected 

to begin producing electricity in 2008. Built into the agreement is an $8.1 million buyout option 

after five years, allowing DIA to assume ownership of the system. The structure of this project is 

creative and should be of interest to municipalities interested in owning PV systems on their 

property. First, it allows the city to leverage the federal tax incentives through a third party, thus 

reducing the need to secure up-front capital for the system. And yet, once the tax incentives are 

fully monetized by the original investors, the City of Denver has the option to ultimately 

purchase the system. 

 

132 Including residences, businesses, and public buildings. 133 See Section 5 of “Renewable Energy Standard Compliance Plan,” Xcel Energy filed with the Colorado Public 

Utilities Commission on November 23, 2007, at: http://www.xcelenergy.com/XLWEB/CDA/0,3080,1-1-

1_41994_45696-27104-2_171_282-0,00.html. In particular, see Table 1 in Section 5, on page 14 

(http://www.xcelenergy.com/docs/Section5-Acquisition_Plans_Final.pdf). This table shows that their 2008 

installations are expected to produce 16,129 MWh annually and cost $8.4 million. To find the REC price, subtract 

out the $200,000 rebate for each of the 20 installations ($4 million), as well as an assumed 9% administrative costs 

($760,000 – which is less than the 10% required by law), there is $3.7 million remaining. Divide by the expected 

generation (16,129 MWh) to get an estimated approximate average REC price of $230/MWh. Xcel states that they 

assume large projects will have an estimated 16% capacity factor. If the PV systems have 14-18% capacity factors, 

then the range is between $205/MWh and $265/MWh. 

134 Vuong, Andy. “Solar-energy system to land at DIA in 2008,” The Denver Post, October 1, 2007, at 

http://www.denverpost.com/ci_7056394?source=rss 

 41
Boulder County Buildings, Colorado135

Boulder County has set an aggressive goal to reduce GHG emissions 7% below 1990 levels by 

2012. PV will play an important role in meeting this target. In August 2007, Boulder County 

installed a 10 kW system on its courthouse, which will initially offset electricity consumption at 

the building. However, the ultimate goal is to use it to power four plug-in hybrids that the county 

plans to purchase in 2008. Xcel Energy, the utility serving Boulder County, provided a rebate of 

$44,500 for this project, roughly 50% of the total cost of the system. On November 16, 2007, the 

county announced a plan to expand PV on public buildings using the PPA structure.136 The 

Boulder County Office of Sustainability has hired a solar consulting firm, Bella Energy, to 

analyze the feasibility of third-party, PV deployment on public buildings as a way to limit the 

up-front costs of solar installations and to leverage tax incentives unavailable to the county on a 

stand-alone basis. 

Connecticut

Connecticut: Challenges to Create Clean Energy Communities 

In 1998, Connecticut passed electric-utility restructuring legislation that included the creation of 

the Connecticut Clean Energy Fund (CCEF) to support the growth of renewable energy in the 

state. Investor-owned utilities—Connecticut Light & Power (CL&P) and United Illuminating 

(UI)—within the state are required to add a surcharge to ratepayers’ utility bills of no less than 

$.001 per kilowatt hour.137 The CCEF receives approximately $20 million annually as a result of 

this charge. The CCEF develops and administers programs that provide grants, rebates, and other 

financing mechanisms to promote and subsidize the expansion of renewable energy technologies. 

One such program is the Connecticut Clean Energy Communities Program, under which the 

CCEF provides solar PV systems to qualifying municipalities who encourage resident 

participation in voluntary “green power” programs, and who meet the following requirements: 

• The city or town must commit to the SmartPower 20% by 2010 Clean Energy Campaign. 

The 2010 Campaign is a voluntary pledge by local governments to obtain 20% of the 

electricity for all municipal facilities (including schools) from clean, renewable sources 

by 2010. A town may satisfy the goal by enrolling in the CT Clean Energy Options 

program, purchasing renewable energy certificates, or installing on-site renewable power 

systems. 

• A certain minimum number of local residents, schools, and businesses must sign up for 

CT Clean Energy Options,138 a green power program approved by the Department of 

Public Utilities Control (DPUC). It allows any CL&P or UI customer to support clean 

energy produced from approved renewable resources such as wind, small hydro, and 

landfill gas. Customers who enroll in the program continue to receive electric delivery 

 

135 “Boulder County Envisions Expansion of Solar Power on County Buildings,” Boulder County, Colorado, news 

release, November 16, 2007, at http://www.co.boulder.co.us/newsroom/templates/?a=976&z=1 

136 Ibid. 137 “Connecticut Incentives for Renewable Energy: Connecticut Clean Energy Fund,” Database of State Incentives 

for Renewables and Efficiency (DSIRE), last reviewed August 29, 2007, accessed April 2008, at 

http://www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=CT03R&state=CT&CurrentPageID=1&R

E=1&EE=1 

138 “Connecticut Clean Energy Communities,” Connecticut Clean Energy Fund, accessed April 2008, at 

http://www.ctcleanenergyoptions.com/ 

 42
service from their utility and pay a small clean energy surcharge. The surcharge is either 

$0.011 (Community Energy) or $0.0115 (Sterling Planet) per kWh for 100% clean 

energy (customers may also choose to offset 50% of their electricity use at 50% of the 

aforementioned rates, respectively). The average Connecticut home uses 700 kWh per 

month, which would result in an additional cost of approximately $8 per month for the 

100% renewable option. 

• The city or town must make a municipal clean energy purchase using the electricity 

savings generated by any systems they received for free from the program. 

When these obligations have been met, the city or town will receive a 1 kW solar PV system 

(towns located in the southwest Connecticut congested grid zone receive a 2 kW system.). Each 

system is accompanied by Fat Spaniel’s monitoring software that enables students and residents 

to log on to the Internet and examine electricity generation, emissions avoided, and costs saved 

in real time. There is no limit to the number of systems that a town or city can earn. A town can 

secure additional PV systems for each threshold met, if the funding is available. Bob Wall, of the 

CT Clean Energy Fund, said that 62 out 169 eligible towns and cities in the state have committed 

to the program, and that at least 23 have met the requirements for receiving a solar installation. 

New Haven was the first city to commit to 20% by 2010. Since joining the Clean Energy 

Communities Program, New Haven has recruited more than 900 customers to sign on to the 

Clean Energy Options program, and has earned 20 kW of solar installations for the city. The first 

system New Haven installed was 2 kW on the Common Ground Environmental High School. 

The city announced that it will put some of the additional systems on low-income “green” 

housing projects. 

The town of West Hartford is approaching 900 participants and has earned 11 kW of free solar. 

West Hartford installed a 3 kW system on its Town Hall. The city has plans to put 3 kW systems 

on each of the two local high schools. 

Hawaii 

Hawaii Department of Transportation139

On January 9, 2008, the Governor of Hawaii, Linda Lingle, announced that the state was issuing 

a request for proposals for up to 34 MW of PV on 11 Department of Transportation sites as well 

as one downtown Honolulu site. According to the governor's news release, the plan is to finance 

these PV systems using the PPA model. 

Massachusetts

Successfully Addressing CREBs Transaction Costs in Massachusetts 

Despite the barriers involved with CREBs, there are success stories. Massachusetts was one state 

that successfully navigated the CREBs process.140 Of the 13 CREBs projects that were awarded 

 

139 “Governor Lingle Announces Historic Plan to Utilize Solar Power at 12 Locations Around State: Plan highlights 

commitment to renewable energy, leading by example,” Hawaii governor's news release, January 9, 2008, at 

http://hawaii.gov/gov/news/releases/2008/news_item.2008-01-09.3842330405 

 43
to the State of Massachusetts for solar PV installations in 2006, 12 of them were creatively 

bundled together into one financing package to streamline project costs. The state’s “Leading by 

Example” program in collaboration with MassDevelopment (MassDev) and the Massachusetts 

Technology Collaborative (MTC), assembled 1 MW worth of PV projects at state colleges, 

prisons, a water treatment facility, and a veterans home, creating a critical mass for CREBs 

funding. By bundling the projects together, Massachusetts was able to minimize overall 

transaction costs. 

Once installed, these 12 projects will represent a fivefold increase in PV-generated electricity at 

public facilities throughout Massachusetts.141 The 1 MW of new capacity also will represent 

a 20-25% increase in the total amount of PV in the entire state, and is part of an expanded solar 

PV program, whose goal is to achieve 250 MW of new capacity installed by 2017.142

Together, the 12 projects will cost approximately $8,500,000. The total CREBs allocation was 

$3,129,300. The MTC and the state provided the remaining funds in the form of grants. While 

each project received its own CREBs allocation, only by bundling the projects into one MassDev 

bond issuance of $3,129,300, was it cost-effective. Not only did bundling the 12 projects lower 

the transaction costs related to the CREBs financing, it also lowered procurement costs. To 

facilitate repayment of the debt, the CREBs financing for each project was intentionally sized so 

that expected annual energy savings was at least equivalent to the annual bond payment. The 

following excerpt from the MassDev news release summarizes the achievement: 

Given the comparatively small bond amounts and unique funding structure, many 

states around the country are finding it difficult to bring CREB issues to market 

and realize the benefit of zero-interest financing for their solar power projects," 

said Robert L. Culver, MassDevelopment president/CEO. "That’s why it made 

sense for the state’s multi-agency energy team to partner with MassDevelopment 

– one of the Commonwealth’s primary bonding authorities – to unify these twelve 

important projects and get the critical mass needed to attract investor interest and 

reduce issuance costs.143

The structure of CREBs can present some particular challenges that may seem daunting. 

However, creative bundling of projects can help capture the value of CREBs. 

Montana

Backup Emergency PV Power for Montana’s Fire Stations 

Montana restructured its legislation in 1997 to include a Universal Systems Benefit Program 

(USBP). The USBP requires all of the state’s utilities, including cooperative utilities, to 

contribute an amount equivalent to 2.4% of their 1995 revenues each year to the program. This 

 140 Personal communications with Ian Finlayson at the Massachusetts Division of Energy Resources in October and 

November 2008. 

141 “$3.1 Million MassDevelopment Bond Supports Twelve Solar Power Projects Across Massachusetts,” 

MassDevelopment news release, November 13, 2007, at http://www.massdevelopment.com/press/11132007-01.aspx

142 Ibid. 143 Ibid. 

 44
amounts to a combined annual contribution of $14.9 million.144 The utilities are required to 

invest these funds in “cost-effective energy conservation, low-income customer weatherization, 

renewable-energy projects and applications, research and development programs related to 

energy conservation and renewables, market transformation designed to encourage competitive 

markets for public purpose programs, and low-income energy assistance.”145 

Will Rosquist, of the Montana Public Service Commission, states that the only mandate for 

spending the money is that at least 17% of each utility’s fund has to be allocated to programs 

assisting low-income families. The utilities can spend the remaining 83% as they want, as long 

as it falls into the categories listed above. The largest Montana utility, Northwestern Energy 

(which meets two-thirds of the state's electricity demand), is the only energy provider in the state 

that has used these funds for renewable energy projects. Northwestern Energy has implemented a 

$.001/kWh surcharge to meet its USBP requirement. When interviewed, John Campbell, of 

Northwestern Energy, stated that $1 million of the $9 million generated by the USBP went 

toward renewable energy projects in 2005. In 2006, this figure declined to $850,000. 

Northwestern Energy has used some of the USBP fund for solar PV projects on fire stations. The 

principle reason for the fire station focus is to provide emergency backup power. As of October 

2007, 20 fire stations within the state have been outfitted with emergency power backup PV 

installations (including battery storage). Total capacity for these 20 systems is 47.5 kW. This 

represents 8 percent of total solar PV capacity in the state of Montana.146 Campbell explained 

that 100% of the costs of these projects were covered by Northwestern Energy’s USBP. 

New Jersey 

New Jersey’s On-Site Rebate Program 

New Jersey’s Clean Energy Program (NJCEP) is consistently highlighted as an example of a 

successful program that has encouraged significant solar PV deployment. New Jersey has a 2% 

solar RPS set-aside that must be met in 2020, which could result in 1,500 MW of new solar 

capacity. To help meet that goal, NJCEP created the Customer On-Site Renewable Energy 

(CORE) Program to provide an up-front rebate for PV in New Jersey, on the order of $3-5/watt. 

The remaining costs of the system are recovered by a combination of attractive net-metering 

retail rates, avoided energy costs, and solar RECs (SRECs) sales to utilities with solar RPS 

obligations. New Jersey SREC prices started out in the range of $160-$200/MWh and have 

increased to as much at $230/MWh at the end of 2007 and beginning of 2008.147

 

144 “Public Benefits Fund: Universal System Benefits Program for Montana,” Database of State Incentives for 

Renewables and Efficiency (DSIRE), last reviewed March 14, 2007, accessed April 2008, at 

http://www.dsireusa.org/library/includes/incentivesearch.cfm?Incentive_Code=MT01R&Search=Type&type=PBF&

CurrentPageID=2&EE=0&RE=1 

145 Rickerson, William, and Christopher Colson. “Montana Firefighters See Benefit of PV,” Renewable Energy 

Focus, November/December 2007, page 51, at http://www.rickersonenergy.com/pdfs/renewableenergyfocus.pdf 146 Ibid. 147 “SREC Pricing: SREC Trading Statistics,” New Jersey Clean Energy Program Web site, showing data through 

February 2008, accessed April 11, 2008, at http://www.njcleanenergy.com/renewable-energy/programs/solarrenewable-energy-certificates-srec/pricing/pricing 

 45
Demand for solar rebates was so tremendous that it exceeded the state's CORE budget. As of 

August 2007, all funding for the CORE solar electric rebate program had been allocated, and 

new projects were placed into a queue to wait for additional funding.148 In late December 2007, 

the New Jersey Board of Public Utilities (NJBPU) approved another funding allocation that will 

include CORE, but it won’t fully fund the projects in the queue. This same NJBPU order 

mandated that no additional private-sector applications will be accepted as of December 20, 

2007, and that public-sector applications will be accepted only through April 1, 2008.149 It is 

unclear whether projects remaining in the queue will receive any funding in the future. 

As of August 2007, only 40.9 MW had been installed in the state,150 and more solar generation is 

needed to meet the state's aggressive solar RPS requirement in 2020. However, the state does not 

want to increase the customer’s Clean Energy Fund rate to secure the necessary funds to achieve 

the 1,500 MW requirement, which could be billions of dollars (estimated to be $500 million each 

year).151 Therefore, New Jersey decided to implement a system that relies entirely on marketbased SRECs, rather than a combination of up-front state rebates and SRECs.152 On September 

12, 2007, the New Jersey PUC voted to transition to a system without state-provided rebates and 

where LSEs with a solar RPS requirement pay the market rate for SRECs.153 The expectation is 

that the cost the state would have had to pay through rebates will now be rolled into the price of 

SRECs. To accommodate higher SREC prices, the state raised the effective price cap for SRECs 

(called the alternative compliance payment), up to $711/MWh in 2009. The solar alternative 

compliance payment declines at an annual rate of approximately 2.5%, down to $594/MWh by 

2016. The regulators hope that the market will be able to cover the total above-market cost using 

SRECs.154

This new structure means that solar PV projects in the state will need to finance more of the 

project’s costs up-front. While this new structure may not impact the installation of solar on large 

commercial, industrial, and public sites who use the PPA model, it could have a significant 

 

148 “Customer On-Site Renewable Energy (CORE) Program,” New Jersey Clean Energy Program Web site accessed 

April 7, 2008, at http://www.njcleanenergy.com/renewable-energy/programs/core-rebate-program/incentives/corerebate-program 

149 “Clean Energy Order: Suspension of Acceptance and Processing of New Solar Applications in CORE Rebate 

Program,” State of New Jersey Board of Public Utilities, Docket No. EO07100773, accessed April 7, 2008, at 

http://www.njcleanenergy.com/files/file/Core-Suspension-12-20-07-8E.pdf 

150 “Core Activity: Renewable Energy Systems Completed,” New Jersey Clean Energy Program Web site, accessed 

April 7, 2007, at http://www.njcleanenergy.com/renewable-energy/program-updates/core-activity/core-activity 

151 “Frequently Asked Questions: New Jersey’s Solar Market: Transition to Market-based REC Financing System,” 

New Jersey Clean Energy Web site, estimated to be written in 2006, accessed April 7, 2008, at 

http://www.njcleanenergy.com/files/file/FINALSolarTransitionFAQ4.pdf

152 Wobus, Nicole, Kevin Cooney, and John Anderson. “Preliminary Review of Alternatives for Transitioning the 

New Jersey Solar Market from Rebates to Market-Based Incentives,” prepared for the New Jersey Board of Public 

Utilities by Summit Blue Consulting and the Rocky Mountain Institute, March 15, 2007, at 

http://www.njcleanenergy.com/files/file/NJ-BPU_Market_Transition_Interim_Report_0315076.pdf 

153 “New Jersey Board of Public Utilities Approves Transformation of New Jersey’s Solar Market,” Statement of the 

New Jersey Board of Public Utilities, September 12, 2007, at 

http://www.njcleanenergy.com/files/file/STATEMENT%20On%209%2012%2007%20BPU%20Statement%20Sola

r%20Transition%20FINAL.pdf 

154 “New Jersey’s Solar Financing Program: as Approved by the Board September 12, 2007,” New Jersey Clean 

Energy Program frequently asked questions, September 12, 2007, at 

http://www.cleanenergyfunds.org/library/nj/NJ_SOLAR-Transition_FAQs_091207.pdf 

 46
impact for small solar systems (residential and public) that would have to bear the burden of 

increased up-front, capital costs. 

SRECs for Atlantic County Utilities Authority (New Jersey) 

The Atlantic County Utilities Authority (ACUA) in New Jersey owns a wastewater treatment 

facility, on which 500 kW of solar PV was installed at five locations. Both the solar rebate and 

SRECs were important revenue streams to help the project be economically viable. The total 

initial capital cost of the project was $3.25 million and was funded by a 57% CORE rebate and a 

$1.5 million, 20-year low-interest loan from the New Jersey Environmental Infrastructure Trust 

Program.155 Revenue from the SREC is assumed to start at $238/MWh and decline 3% annually 

to $114/MWh by the 25th year. This revenue is expected to exceed the cost of debt service, 

periodic replacement of the solar inverters, and system insurance. Combined with the avoided 

electricity costs (at the utility’s retail rate), the total net present value of savings are expected to 

be more than $1.8 million over a 25-year period.156

New York 

NYSERDA Funding for Municipal PV Systems 

The New York State Energy Research and Development Authority (NYSERDA) was established 

in 1975, initially as a research and development organization focused on reducing New York 

State's fossil fuel consumption.157 In 1996, the New York system benefit charge was created and 

the funds were directed to NYSERDA for a wide range of energy-related programs. 158

Municipal projects in New York are often financed with straightforward structures. Generally, a 

municipality receives an incentive from NYSERDA and covers the remaining costs out of local 

funds. For example, the Village and Town of New Paltz installed a 14.85 kW PV system with a 

solar battery backup at a cost of $143,380. NYSERDA provided an incentive of $96,200 and 

New Paltz covered the difference.159 

NYSERDA has also created the New York Energy SmartSM Program,160 which is a portfolio of 

initiatives designed to promote energy efficiency products and services, and renewable energy 

technologies.161 One of these initiatives is the PV System Incentive Program, which provides 

 

155 “Solar Array Project: Fact Sheet,” Atlantic County Utilities Authority, August 2007, at 

http://www.acua.com/files/Solar%20Array%20Project1.pdf 

156 “Solar Generation System 500 kW: project details,” Atlantic County Utilities Authority, accessed April 18, 2008, 

at http://www.acua.com/files/chartsmall06o6.pdf 

157 “About NYSERDA,” New York State Energy Research and Development Authority (NYSERDA) Web site, 

accessed April 7, 2008, at http://nyserda.org/About/default.asp 

158 In 2004, NYSERDA received additional funding from the settlement of a lawsuit with the Virginia Electric 

Power Company (VEPCO), according to “PV for Peak Load Reduction on Municipal Buildings,” New York State 

Energy Research and Development Authority (NYSERDA), Program Opportunity Notice No. 843, at 

http://www.nyserda.org/Funding/843PON.html 

159 “Village and Town of New Paltz,” New York State Energy Research and Development Authority (NYSERDA), 

case study for the New York Energy $mart program, accessed April 7, 2008, at 

http://www.powernaturally.com/About/documents/newPaltz.pdf

160 Ibid. 161 “New York Energy $martSM Program,” New York State Energy Research and Development Authority 

(NYSERDA) Web site, accessed April 7, 2008, at http://www.nyserda.org/ny_energy_smart.asp 

 47
incentives for PV systems up to 50 kW per site and 100 kW per customer for nonresidential 

beneficiaries, including municipal governments.162 The incentive is $5/watt for the first 25 kW 

and $4/watt for the balance of the system up to 100 kW.163 

Many municipalities have taken advantage of the EnergySmartSM programs. One PV design and 

installation firm, Hudson Valley Clean Energy (HVCE), has installed at least five municipal PV 

projects itself.164 According to the company’s president, Jeff Irish, because these systems are 

often in highly visible areas of town, there are important educational and marketing benefits to 

PV system designers and installers who work on such projects. HVCE can trace numerous 

residential projects directly back to its public-sector projects. Public systems lend credibility to 

both the installer and to the concept of "going solar". However, there are elements of municipal 

projects in New York that increase the cost of installed PV systems. 

o Prevailing Wages: Hourly wages on a residential job may be in the $18-25/hour range. 

Prevailing wage rules for municipal projects can be as high as $90/hour when social 

security and liability insurance are included. 

o The Bid Process: Projects that require municipalities to spend $10,000 or more trigger a 

bid process. This process often includes the need to hire an engineering consulting firm to 

review the bids, which adds to project costs. A project often will be scaled down so that 

the municipal portion is less than $10,000 to avoid the costs involved in the bid process. 

o Performance Bonds and Paperwork: Municipal projects may require both bid bonds and 

performance bonds. In addition, notarized forms, manuals, and drawings are required, 

none of which is standard in the residential sector. 

These nuances of installing municipal PV systems in the State of New York can have a 

significant impact on costs. According to Jeff Irish, a residential PV project may cost $8/watt, 

whereas a municipal project of the same size can cost 25% more or $10/watt. 

Ohio 

Ohio’s Advanced Energy Fund 

In 1999, Ohio authorized the creation of the Advanced Energy Fund, to be managed by the Ohio 

Department of Development's Office of Energy Efficiency (OEE) during a restructuring of the 

state’s electric utility sector. 

The fund is designed to generate $100 million over 10 years. To achieve this goal, investorowned utilities (participation by municipal utilities and electric cooperatives is voluntary) are 

 

162 “PV Incentives: PON 1050 Solar Electric Incentive Program,” New York State Energy Research and 

Development Authority (NYSERDA), Program Opportunity Notice 1050, accessed April 7, 2008, at 

http://www.powernaturally.com/Programs/Solar/incentives.asp 

163 Ibid. 164 Based on e-mail and phone conversations with Jeff Irish, president of Hudson Valley Clean Energy on December 

3, 2008. 

 48
required to generate $15 million per year from 2001-05 and $5 million per year from 2006-11.165

The utilities collected .00010758 per kWh for the first five years to meet the annual $15 million 

target, and now collect a flat fee of 9 cents per monthly bill to raise $5 million per annum. 

The fund supports both the Advanced Energy Program and the Energy Loan Fund's low-interest 

loan program. State and local governments in Ohio use a combination of the grant program and 

their own bonding authority to finance solar PV. Participation in the loan fund is not common. 

Recently, the Metropolitan Park District of Toledo, Ohio, took advantage of a grant offered by 

the Advanced Energy Program to install a 6.48 kW solar PV system on the Center for Nature 

Photography. The total cost of the installation was $63,400. The Metropolitan Park District paid 

the total cost of the system and then received a rebate of $31,700 from the Advanced Energy 

Program. The 6.48 kW system generates nearly 100% of the electricity consumed at the center. 

 

165 “Public Benefits Funds: Advanced Energy Fund of Ohio,” Database of State Incentives for Renewables and 

Efficiency (DSIRE), last reviewed September 12, 2007, accessed April 7, 2008, at 

http://www.dsireusa.org/library/includes/incentivesearch.cfm?Incentive_Code=OH11R&Search=Type&type=PBF&

CurrentPageID=2&EE=0&RE=1 

 49
Appendix 2. Critical Steps when Issuing a CREBs Bond 

Applying for and issuing a bond supported by a clean renewable energy bonds (CREBs) 

allocation involves a number of steps. The key tasks and information regarding the CREBs 

process are summarized below. 

Step 1 – Application to IRS

The IRS application must include the entity that will issue the bond, the borrower if distinct from 

the issuer, the nature of the project (size, technology, location, etc.), the regulatory approvals 

needed, and a financing plan. Unlike tax-exempt financing, CREBs also require certification 

from an independent licensed engineer that the project will meet the requirements and is 

technically viable (an additional step that adds to transaction costs). 

CREBs allocations can be used only for projects that meet specific criteria. CREBs are primarily 

intended to finance the deployment of new facilities and cannot be used for existing facilities, 

except for renovation activities. The allocations also can be used to refinance a new project for 

which debt incurred after August 8, 2005. CREBs can be used for jointly owned projects, where 

the municipality or a cooperative uses it as their ownership contribution to the partnership with a 

utility, a municipality, or cooperative not using CREBs. The CREBs allocation is for a 

designated project at a specific location; if there is a change in the use of the project, or a change 

in ownership, the project may lose its qualified status forcing the issuer to undertake remedial 

action, which could include redeeming the bond. 

For the first round, it took the IRS approximately five-six months to qualify projects and make 

allocations. The second round took six months and was announced on February 12, 2008. As of 

April 2008, all CREBs allocations have been made. If the CREBs program is expanded, it is 

expected that future allocations would go more quickly because the IRS can benefit from 

previous experience. 

Step 2 – IRS makes allocations 

In the first two rounds, CREBs were allocated using a simple process. The IRS would take all of 

the municipal projects that met the qualifications and put them in rank order from smallest to 

largest. The allocations were given to the smallest projects first, and then given out to 

increasingly larger projects until the allocations were exhausted. Therefore, many municipalities 

that wanted to do larger projects did not secure a CREBs allocation. 

Step 3 – Work with the financial team to issue the CREBs 

The process is the same as for the tax-exempt bond, except that the federal government provides 

a tax credit to the investor instead of the issuer making interest payments. The tax credit from the 

federal government and the tenor are predetermined using data published by the U.S. Treasury 

on a daily basis, at its Web site, http\\www.TreasuryDirect.gov. For example, if a CREB had 

been issued on April 18, 2008, the maximum allowable tenor would have been 15 years with an 

allowable tax credit in the first year equivalent to 5.83%. 166 

 

166 “Clean Renewable Energy Bonds Rates,” U.S. Department of Treasury Web site, accessed April 18, 2008, at 

https://www.treasurydirect.gov/SZ/SPESRates?type=CREBS 

 50
Appendix 3. Critical Steps in the Structure of Third-Party Ownership Model 

In Section 6.1, Figure 8 shows one variation of how a third-party ownership model can be used 

to help public entities own renewable projects—there are many others. To execute this model 

using a PPA for the power (and/or SRECs), the steps listed below are recommended. These were 

adapted from a report by GreenTech Media167 and from conversations with Bob Westby at 

NREL, who has been actively involved in the PPA negotiations for several NREL PV projects. 

While the steps are presented in linear fashion, many are concurrent activities. 

Steps to executing a third-party ownership model 

Step 1 – Identify potential location(s) 

Identify the buildings or land on which to install a solar PV system. In preparation for the next 

step, it is a good idea to characterize the site or sites that you would like to consider developing 

by gathering and providing detailed information. Characterizing the potential solar resource 

using PVWatts168 also is recommended; you will be required to enter longitude and latitude, the 

PV technology of interest, and the tilt and azimuth angles. It also would be useful to characterize 

other site-specific characteristics, including potential for shading (e.g., buildings, trees, and other 

structures), distance to nearest substation, overall site load, average electricity prices paid, etc. 

Using available information, including expected REC prices and rebates, do a “back of the 

envelope” calculation to see if the economics make sense. 

Determine whether an environmental impact assessment is going to be necessary, especially as it 

relates to ground-mounted systems. Finally, address both safety and security issues with the 

appropriate internal parties to make sure these two topics do not present barriers later in the 

process. 

Step 2 – Identify developer 

States and municipalities must comply with local and state rules of procurement. If the site is big 

enough (can support a project of a minimum size of approximately 1 MW), consider releasing a 

request for qualifications (RFQ) followed up with a request for proposals (RFP) once the number 

of potential vendors has been narrowed. If the site can only support a smaller system, developers 

may not respond to a formal RFP and might have to be contacted individually to gauge potential 

interest. 

The potential developers will request the information developed in Step 1 so that they can make 

their own initial assessment of the feasibility of the project. Additional information that the 

developers may require include the utility's interconnection requirements, confirmation of access 

to the site, and information on the soil if the system is a ground-mounted one. 

Step 3 – Site assessment and term-sheet development 

Based on the preliminary information provided by the state/municipality and its own research, 

the developer will conduct a high-level site assessment that will include electricity needs, solar 

 

167 Guice, Jon, and John D.H. King, “Solar Power Services: How PPAs are changing the PV Value Chain,” 

Greentech Media Inc., February 14, 2008. 

168 “PVWATTS: A Performance Calculator for Grid-Connected PV Systems,” National Renewable Energy 

Laboratory Web site, accessed April 2008, at http://rredc.nrel.gov/solar/codes_algs/PVWATTS/ 

 51
generation potential, financial incentives, and engineering issues. This will be an initial proposal 

to determine the feasibility of the project. Based on this assessment, a term sheet will be drafted 

that will include the estimated output of a solar project, the price of electricity and term. If a 

tentative agreement can be reached on the term sheet, then the project can move forward. 

Step 4 – Contract development 

The contracts are negotiated and signed. There are multiple contracts involved in the PPA 

process. There is the PPA agreement between the public entity and the PPA provider. There may 

be a separate agreement between these same two parties related to the easement or lease which 

provides access to the property. The PPA provider and the utility may sign a separate agreement 

for the solar RECs. 

Step 5 – Rebate processing 

If the state or utility offers incentives, the application to request them should be filed at this 

point. Note that in some states, there might be a limited window when incentives are awarded to 

qualifying projects. Depending on the state, in some cases, the rebate may go to the host who 

must endorse it over to the PPA provider. The utility will pay the PPA provider directly for the 

RECs. 

Step 6 – Project design and financing 

A detailed project engineering analysis is performed and the system is designed, based on more 

precise measurements that are specific to the site. Using the term sheet and the intent to enter 

into a contract, project financing also is arranged. 

Step 7 – Permitting 

Local regulatory agencies require appropriate documentation to receive a building permit. It 

might be useful to see whether there is a backlog of permits and when the project needs to be in 

the queue for this step to be completed, aiming for approximately the same time that the contract 

is signed. 

Step 8 – Procurement, construction, and commissioning 

The developer will arrange for the components and equipment to be supplied to the site, at which 

point the system is installed and tested. At commissioning, there is a final confirmation test to 

prove system performance to the utility, so that it will interconnect the system and allow for 

system activation. 

Step 9 – Monitoring and maintenance 

The host must allow the developer and the owner access to the site for maintenance activities for 

the life of the project. The system is monitored through a combination of automatic (and remote) 

readings of power performance and other indicators, and can include manual readings (on-site) 

of performance indicators as well. If there is an anomaly, then the system is accessed on the 

host's site for repair and any equipment replacement that is needed. 

 52
Appendix 4. Critical Steps to Issue a Tax-Exempt Bond 

The information in this section is largely taken from “Anatomy of a Bond” by David Unkovic of 

Saul Ewing, LLP,169 “The Basics of Municipal Bonds,” by Jim McWhinney on Investopedia,170

and “Basics of Federal Bond Issues” by Jason Van Bergen on Investopedia171

This section explains the players and steps needed to issue a municipal tax-exempt bond. The 

roles and activities of each participant are described in detail, including how the participants 

interact and work together. Following this description, the steps for issuing a municipal security 

are described sequentially. 

Figure 12. Tax-exempt bonds 

Participants in Issuing a Bond 

As with all bond issues, a bond to finance a renewable energy project will involve a number of 

different partners who must work together. Figure 12 shows the roles and describes the cash flow 

between the primary participants. The full list of participants and their roles are described below: 

1. Issuer of the bond. The bond issuer needs capital to invest in a renewable energy project. 

2. Investment banker/underwriter. Buys the bonds from the issuer at a discount, markets 

them to the public and resells them to investors. Often helps structure the bond issue and 

prepare the disclosure document. Sometimes purchases the entire bond issue without 

 

169 Unkovic, David. “Anatomy of a Bond Issue,” copyright Saul Ewing, posted on the Web site FindLaw for Legal 

Professionals in March 2000, accessed February 15, 2008, at http://library.findlaw.com/2000/Mar/1/130778.html 170 McWhinney, Jim. “The Basics of Municipal Bonds,” posted on Web site of Investopedia: A Forbes Media 

Company, in February 2005, accessed February 15, 2008, at 

http://www.investopedia.com/articles/bonds/05/022805.asp 

171 Van Bergen, Jason. “Basics of Federal Bond Issues,” posted on Web site of Investopedia: A Forbes Media 

Company, in May 2004, accessed February 15, 2008, at http://www.investopedia.com/articles/basics/04/052104.asp 

Principal and Interest 

Up-front capital 

Federal 

government 

Investor/bond 

purchaser 

Project issuer 

• Works with an investment 

bank to issue a bond and 

secure upfront capital. 

• Outlay: Interest usually 

repaid to investor semiannually and principal 

usually repaid at maturity 

• Variation: Zero-coupon 

bonds are sold at a deep 

discount and pay principal 

and interest at maturity.

• Buys tax-exempt bonds from the 

bank, thus lending money to the 

project. 

• Does not pay federal taxes on 

interest earned. Might be exempt 

from state and local taxes, if located 

in the state where the bond was 

issued. 

• Given tax-exempt status, interest 

rate will be lower than a 

comparable taxable bond, generally 

by about 30%. Interest typically 

paid annually; principal at maturity.

• No active role 

in this structure. 

• Permits tax 

exemption. 

 53
proceeding to a public offering to resell it (e.g., for its own account or on behalf of its 

own clients). 

3. Financial adviser. Participates in some bond issues to help the issuer structure the bond, 

prepare the disclosure document, and solicit bids from various investment bankers. 

Sometimes the investment bank/underwriter plays this role. 

4. Lawyers. Each lawyer delivers an opinion at the bond issue closing 

a. Solicitor. Validates the issuer and the bond issue. 

b. Bond counsel. Focuses on the legal aspects of financing and helps structure the 

transaction with regard to state law approvals and compliance with federal tax 

laws related to bond issues. For funding of a capital project, the funds must serve 

the purpose of taxpayers and the greater good. 

5. Trustee/paying agent. Bond issuer will choose a bank that will make debt service 

payments on its behalf to the bondholders and represent the bondholders in the event of 

default. 

6. Bond guarantor. Provides credit enhancement to the bond issuer, either through an 

insurance policy secured from an insurance company (guaranteeing payment) or a letter 

of credit from a bank. A guarantor is not always included in transactions. 

7. Ratings agency. Municipal bonds are rated by an independent ratings agency to provide 

guidance to potential investors as to the creditworthiness of the bond. 

8. Investor/bond purchaser. Ultimate investor in the bond issue. 

Steps for Issuing a Bond

Step 1 – Select financial team 

The bond issuer selects a bond counsel and an underwriter/financial adviser to work with the 

issuer and the solicitor to structure financing. 

Step 2 – Work with financial team to address details 

Some basic questions must be answered: 

1. What are the legal parameters that must be addressed (e.g., can debt be refunded under 

the federal tax rules?) 

2. Should bonds be sold to one underwriter, or competed among multiple underwriters (e.g., 

does a relationship already exist with a single firm, and is the denomination small enough 

that it would be less hassle and cost to deal with one underwriter)? 

3. Is the cost of credit enhancement (insurance or letter of credit) less than the resulting debt 

service savings to the issuer? 

Step 3 – Select trustee and credit enhancer 

The trustee is selected and possibly a counterparty to provide additional support for the issue if it 

makes sense to secure credit enhancement. Given the current creditworthiness concerns of the 

primary municipal bond insurance companies, credit enhancement may be less valuable than in 

the past. 

Step 4 – Prepare required documentation 

The underwriter prepares the disclosure document (also called the preliminary official statement) 

that provides the details of the bond issue. Bond counsel prepares legal documentation that is 

 54
specific to the bond issue. During the documentation phase, the lawyers make sure that state and 

federal legal procedures are followed. 

Step 5 – Marketing 

The bond is marketed to one or more potential purchasers, usually for about a week. During this 

time, the disclosure document is scrutinized by the potential purchaser(s). 

Step 6 – Bond sale at public meeting 

At the end of the marketing period, the bonds are sold at a public meeting. Terms of the purchase 

proposal include the principal amount of the bond, interest rates, amortization schedule, and 

details about prepayment provisions. 

Single underwriter/negotiated offer 

The underwriter that was preselected will come to the public meeting with a firm purchase 

proposal, containing the specific terms of the bond issue. These details can be negotiated further 

at the public meeting and approval by both sides at the meeting results in confirmation of the 

terms. 

Multiple underwriters/competitive offer 

If several underwriters were invited, the multiple bids are collected by the financial adviser the 

day of the bond sale and public meeting. The auction proceeds until all the bonds are distributed. 

Step 7 – Prepare for Closing 

Once agreement has been reached on the terms, the bond counsel prepares a package to be filed 

with the state, which approves the bond issue. The closing takes place about a month after the 

bond sale. Prior to the closing, the bond counsel distributes the necessary draft legal documents. 

Step 8 – Closing 

At the closing, all parties of the bond issue execute the various closing documents. The 

underwriter(s) wires the approved purchase price for the bonds to the trustee. The trustee ensures 

that funds are properly distributed according to the intended purpose of the bond issue. At the 

direction of the bond issuer, the trustee pays the cost of issuance and applies the balance to the 

construction project’s accounts. After the closing, the bond counsel distributes copies of the 

executed documents to the bond participants. 

 55
Appendix 5. The Department of Energy's Solar America Cities and Showcases 

The U.S. Department of Energy is supporting two significant developments at the local 

government level: Solar America Cities and the Solar America Showcases. In the 2006 State of 

the Union Address, President Bush announced the creation of the Advanced Energy Initiative 

(AEI). Within the AEI, the Department of Energy launched the Solar America Initiative (SAI) 

with the goal of making solar energy cost-competitive with conventional forms of electricity 

production by 2015. 

One of the projects for the Solar America Initiative is Solar America Cities (SAC) (details can be 

found at http://www.solaramericacities.org/). The DOE initially offered approximately $2.5 

million to the Solar America Cities initiative in support of 13 cities (population must be at least 

100,000). The cities approved to participate were judged on their “plans to build a sustainable 

solar infrastructure, streamline city-level regulations, and promote the adoption of mainstream 

solar technology among residents and businesses.”172 In addition to the combined $2.5 million 

in federal financing to the 13 cities, the DOE will offer on-site technical and policy assistance fo

implementation of solar deployment. The 2007 Solar America Cities are: 

r 

Table 3. 2007 Solar America Cities 

Ann Arbor, Michigan Pittsburgh, Pennsylvania 

Austin, Texas Portland, Oregon 

Berkeley, California Salt Lake City, Utah 

Boston, Massachusetts San Diego, California 

Madison, Wisconsin San Francisco, California 

New Orleans, Louisiana Tucson, Arizona 

New York, New York 

A second group of Solar America Cities was announced on March 27, 2008, bringing the total to 

25.173 The 2008 Solar America Cities are: 

Table 4. 2008 Solar America Cities 

Denver, Colorado 

Philadelphia, 

Pennsylvania 

Houston, Texas Sacramento, California 

Knoxville, Tennessee San Antonio, Texas 

Milwaukee, Wisconsin San Jose, California 

Minneapolis-St. Paul, 

Minnesota Santa Rosa, California 

Orlando, Florida Seattle, Washington 

In addition to Solar America Cities, the DOE also offers the Solar America Showcase (SAS). 

The DOE selects individual public projects that involve large-scale solar installations as 

additional support for the Solar America Initiative. SAS does not provide financial assistance for 

 

172 “The 2007 Solar America Cities Awards,” U.S. Department of Energy Solar America Initiative Fact Sheet, June 

2007, at http://www1.eere.energy.gov/solar/solar_america/pdfs/41760.pdf 

173 “U.S. Department of Energy to Provide up to $2.4 Million to Advance Solar Energy in 12 U.S. Cities,” U.S. 

Department of Energy news release, March 28, 2008, at http://energy.gov/news/6099.htm 

 56
these projects; instead, it provides technical assistance to approved applicants through teams of 

DOE-funded solar experts. As of October 2007, the following five projects had been identified: 

174, 175

• “Residential Hybrid Solar Electric and Thermal Systems in Hawaii” – Forest City 

Military Communities are seeking DOE assistance for the feasibility of incorporating 

hybrid solar-thermal electric systems into a large military residential project in Oahu, 

Hawaii. 

• “Photovoltaic Demonstration and Research Facility and Family Learning Center” – 

Orange County, Florida, is seeking DOE assistance in evaluating the technical feasibility 

of placing an 800 kW photovoltaic system on the Orange County Convention Center. 

• “Smart Solar Initiative” – City of San Jose, California, is seeking DOE assistance in 

evaluating the potential of multiple large buildings and complexes in San Jose for solar 

photovoltaic and thermal applications. 

• Northeast Denver Housing Center – DOE will assist in overcoming barriers to the 

installation of solar photovoltaics on 80 permanently affordable housing units in Denver, 

Colorado. 

• Montclair State University will receive technical assistance in support of a 280 kW “solar 

farm” at its New Jersey School of Conservation. 

 

174 “Solar America Initiative: Solar America Showcases,” accessed April 2008, at 

http://www1.eere.energy.gov/solar/solar_america/solar_america_showcases.html 175 “DOE Announces Solicitation for 2008 Solar America Cities,” U.S. Department of Energy Progress Alert, 

October 30, 2007, accessed April 2008, at 

http://www1.eere.energy.gov/news/progress_alerts/progress_alert.asp?aid=252 

 57
Appendix 6. Useful Reference Documents and Internet Resources 

California Solar Initiative Handbook 2007 

http://www.gosolarcalifornia.ca.gov/documents/CSI_HANDBOOK.PDF 

Database of State Incentives for Renewables and Efficiency (DSIRE) 

http://www.dsireusa.org/ 

Energy Information Administration. 2003. 

Commercial Buildings Energy Consumption Survey 

http://www.eia.doe.gov/emeu/cbecs/ 

EPA. 2004. "Guide to Purchasing Green Power." 

http://www.epa.gov/greenpower/documents/purchasing_guide_for_web.pdf 

Interstate Renewable Energy Choices (IREC) and the North Carolina Solar Center. 2007 

“Connecting to the Grid: A Guide to Distributed Generation Interconnect Issues,” 5th Edition. 

http://www.irecusa.org/fileadmin/user_upload/ConnectDocs/IC_Guide.pdf 

Network for New Energy Choices, Interstate Renewable Energy Choices, Vote Solar Initiative 

and the Solar Alliance. 2007. “Freeing the Grid” Net Metering and Interconnection Report 

http://www.newenergychoices.org/uploads/FreeingTheGrid2007_report.pdf 

Shirley, W. 2006. “Survey of Interconnection Rules.” 

The Regulatory Assistance Project 

Prepared for the Florida Public Service Commission 

http://epa.gov/chp/documents/survey_interconnection_rules.pdf 

Solar Energy Industry Association. 2006. “Guide to Federal to Federal Tax Incentives for Solar 

Energy (Version 1.2)” 

http://www.seia.org/SEIAManualversion1point2.pdf 

State Solar Power Rebates, Incentives, and Tax Credits 

http://www.solarpowerrocks.com/solar-politics/solar-cities/ 

Wiser, R. and M. Bolinger. 2006. “Federal Tax Incentives for PV: Potential Implications for 

Program Design.” Lawrence Berkeley National Laboratory. 

http://repositories.cdlib.org/lbnl/LBNL-60193/ 

 58
Appendix 7. Useful Contacts 

State and Local Governments 

California 

• California Energy Commission 

http://www.energy.ca.gov/ 

o Virginia Lew 

 Vlew@energy.state.ca.us 

• Department of General Services 

http://www.dgs.ca.gov/default.htm 

o Pat McCoy 

 Patrick.McCoy@dgs.ca.gov 

• New Solar Home Partnership 

http://www.gosolarcalifornia.ca.gov/nshp/ 

o Sanford Miller 

 Smiller@energy.state.ca.us 

Colorado 

• The County of Boulder 

http://www.co.boulder.co.us/ 

o Ann Livingston 

Sustainability Coordinator 

alivingston@co.boulder.co.us 

• Public Utilities Commission 

http://www.dora.state.co.us/PUC 

o Richard Mignogna 

 richard.mignogna@dora.state.co.us 

Connecticut 

• The Connecticut Clean Energy Fund 

www.ctcleanenergy.com 

o Lise Dondy 

President 

lise.dondy@ctinnovations.com 

o Dale Hedman 

Director of Project Development 

dale.hedman@ctinnovations.com 

o Bob Wall 

Bob.Wall@ctinnovations.com 

 59
Massachusetts 

• Massachusetts Division of Energy Resources 

http://www.mass.gov/doer/ 

o Ian Finlayson 

Ian.Finlayson@state.ma.us 

o Meg Lusardi 

Meg.Lusardi@state.ma.us 

• Massachusetts Technology Collaborative 

http://masstech.org/ 

o Jonathan Abe 

Sr. Project Manager, Renewable Energy Trust 

abe@masstech.org 

Montana 

• Montana Public Service Commission 

http://www.psc.state.mt.us 

o Will Rosquist 

 wrosquist@mt.gov 

 

New Jersey 

• New Jersey Board of Public Utilities

http://www.bpu.state.nj.us 

o Scott Hunter 

benjamin.hunter@bpu.state.nj.us 

New York 

• New York State Energy Research and Development Authority 

http://www.nyserda.org/ 

o Adele Ferranti 

 Sr. Project Manager 

 af1@nyserda.org 

o Heather Hammond 

Project Coordinator - Loan Fund 

hsh@nyserda.org 

Ohio 

• Ohio Department of Development 

http://www.odod.state.oh.us/cdd/oee/ 

o Judy Pacifico 

jpacifico@odod.state.oh.us

 60
Nonprofit Organizations 

CESA – Clean Energy States Alliance 

http://www.cleanenergystates.org/ 

o Mark Sinclair 

 MSinclair@cleanegroup.org 

Community Office for Resource Efficiency (CORE) 

http://www.aspencore.org/ 

o Gary Goodson 

gary@aspencore.org 

The Vote Solar Initiative 

http://www.votesolar.org/ 

o Adam Browning 

 abrowning@votesolar.org

U.S. Department of Energy 

Golden Field Office 

Golden, Colorado 

• REPI Program Administration 

o Christine Carter 

christine.Carter@go.doe.gov 

o Chico Gonzalez 

chico.gonzalez@go.doe.gov 

 61
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Solar Photovoltaic Financing: Deployment on Public Property by 

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State and local governments have grown increasingly aware of the economic, environmental, and societal benefits of 

taking a lead role in U.S. implementation of renewable energy, particularly distributed photovoltaic (PV) installations. 

Recently, solar energy's cost premium has declined as a result of technology improvements and an increase in the 

cost of traditional energy generation. At the same time, a nationwide public policy focus on carbon-free, renewable 

energy has created a wide range of financial incentives to lower the costs of deploying PV even further. These 

changes have led to exponential increases in the availability of capital for solar projects, and tremendous creativity in 

the development of third-party ownership structures. As significant users of electricity, state and local governments 

can be an excellent example for solar PV system deployment on a national scale. Many public entities are not only 

considering deployment on public building rooftops, but also large-scale applications on available public lands. The 

changing marketplace requires that state and local governments be financially sophisticated to capture as much of 

the economic potential of a PV system as possible. This report examines ways that state and local governments can 

optimize the financial structure of deploying solar PV for public uses. 

15. SUBJECT TERMS

NREL; innovative financing; renewable energy certificates; RECs; renewable portfolio standard; RPS; power 

purchase agreements; PPAs; solar PV; photovoltaics; analysis; Karlynn Cory; Jason Coughlin; Charlie Coggeshall 

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