Technical Report

NREL/TP-6A2-46397 

July 2009

Solar Photovoltaic Financing: 

Deployment by Federal 

Government Agencies 

Karlynn Cory, Charles Coggeshall, 

Jason Coughlin, and Claire Kreycik
National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393

303-275-3000 • www.nrel.gov

NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency and Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

Contract No. DE-AC36-08-GO28308

Technical Report

NREL/TP-6A2-46397 

July 2009

Solar Photovoltaic Financing: 

Deployment by Federal 

Government Agencies 

Karlynn Cory, Charles Coggeshall, 

Jason Coughlin, and Claire Kreycik

Prepared under Task No. PVB9.4210
NOTICE

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iii

Acknowledgments

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

authors wish to thank participating DOE staff—Tom Kimbis 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 managers, Robert Margolis and Selya Price of the 

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

who reviewed various drafts of this report, particularly Kevin DeGroat of Antares Group, Inc; 

Douglas Dahle, Chandra Shah, Michael Mendelsohn, and Brian Levite of NREL; and Matthew 

Gray of DOE. Other reviewers that provided useful insights and comments to various sections 

include: Robert Westby, Karen Thomas, Andy Walker, Alicen Kandt, Nate Blair, and Otto Van 

Geet of NREL; and Randy Manion, John Kral, and Melanie Reed of the Western Area Power 

Administration (WAPA). The authors also thank Jim Leyshon, Ray David, and Bryan Bechtold 

for providing fantastic graphics. And finally, we are deeply grateful to Lisa J. Teman of All the 

Right Words and 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: New Jersey’s Clean Energy Program, New Jersey Board of Public Utilities, 

Massachusetts Technology Collaborative, New York State Energy and Research Development 

Authority, Environmental Protection Agency, National Park Service, U.S. Air Force Facility 

Energy Center, U.S. Army, General Services Administration, U.S. Department of Energy, and 

Lawrence Berkeley National Laboratory. We would also like to thank the utility, Xcel Energy. 
iv

List of Acronyms

AWC Area-wide contracts

BETC Business Energy Tax Credit

CESA Clean Energy States Alliance

CEQ Council on Environmental Quality 

CORE Customer On-Site Renewable Energy Program (New Jersey)

DESC Defense Energy Support Center 

DG Distributed generation

DOD Department of Defense

DOE Department of Energy 

DSIRE Database of State Incentives for Renewables and Efficiency

EA Environmental assessment 

EPBB Expected Performance-Based Buy-Down

ECM Energy conservation measure 

EESA 2008 Emergency Economic Stabilization Act of 2008 

EIS environmental impact statement

EISA 2007 Energy Independence and Security Act of 2007 

EO Executive order 

EPA U.S. Environmental Protection Agency 

EPAct 2005 Energy Policy Act of 2005 

ESA08 Economic Stimulus Act of 2008 

ESCO Energy services company

ESPC Energy savings performance contract 

FAR Federal Acquisition Regulations 

FEMP Federal Energy Management Program 

FES Firm electric service

FONSI Finding of no significant impact 

FRESA Federal Renewable Energy Screening Assistant

FY Fiscal year

GSA U.S. General Services Administration

IA Interagency agreement

IDIQ Indefinite delivery indefinite quantity 

IOU Investor-owned utility 

IPP Independent power producer 

IRR Internal rate of return

IRS Internal Revenue Service

ITC Investment Tax Credit

kW Kilowatt

kWh Kilowatt hour

LCOEG Levelized cost of electricity generation

LEED Leadership in Energy and Environmental Design 

LIBOR London Interbank Offered Rate 

LSE Load-serving entity

MACRS Modified Accelerated Cost-Recovery System 
v

MW Megawatt

MWh Megawatt hour 

NDA Non-disclosure agreement

NEPA National Environmental Policy Act 

NHPA National Historic Preservation Act

NREL National Renewable Energy Laboratory 

NYSERDA New York State Energy Research and Development Authority 

OPUC Oregon Public Utilities Commission

PEIS Programmatic environmental impact statement

PMA Power marketing administration

PPA Power purchase agreement

PSE&G Public Service Electric & Gas

PV Photovoltaic 

R&D Research and development

REC Renewable energy credit

RET Renewable-energy and energy-efficient technology 

RFP Request for proposal 

RFQ Request for qualifications

RPS Renewable portfolio standard

RReDC NREL’s Renewable Resource Data Center

SACP Solar alternative compliance payment 

SAM Solar Advisor Model 

SBC System benefits charge

SBIC Sustainable Building Energy Council 

SEIA Solar Energy Industry Association

SI Statement of interest

SREC Solar renewable energy credit

SSA Social Security Administration

TEAM Transformational Energy Action Management 

UESC Utility energy service(s) contract 

USPS U.S. Postal Service 

WAPA Western Area Power Administration 
vi

Executive Summary

Opportunities for the deployment of distributed photovoltaic (PV) systems at federal government 

facilities in the United States are increasing significantly as a result of supportive government 

policies, innovative financing mechanisms, and the rapid development of the solar industry. Yet 

many federal agencies still lack the information and know-how to overcome the challenges 

associated with making on-site solar PV projects economically viable. This report examines the 

renewable energy and energy intensity standards and goals federal agencies must meet, assesses 

the array of financing structures and tools available to federal agencies to finance on-site PV 

projects, and analyzes the economics of federal PV projects in various locations based on locally 

available incentives and payments.

We describe and evaluate a diverse array of incentives and financing tools that are available to 

federal agency PV projects, including: 

• Federal appropriations,

• State- and utility-level cash incentives,

• Revenues from renewable energy certificates (RECs) or the more-specific solar RECs 

(SRECs), depending on state renewable portfolio standards (RPS), 

• Energy cost savings (and the use of performance contracting to help fund projects), 

• Innovative financing structures in which federal agencies partner with private entities that 

utilize federal tax incentives and other tools to deploy on-site PV. These partnerships can 

take advantage of: 

o Federal investment tax credits (ITCs) via a third tax-paying party, 

o Federal Modified Accelerated Cost-Recovery System (MACRS), or accelerated 

depreciation including bonus depreciation, and 

o Federal loan guarantees.1

In addition to these approaches, federal agencies can use contracts with private entities in one of 

three general formats: 1) energy savings performance contract (ESPC); 2) Super ESPC (in which 

agencies can take advantage of general contract parameters and prequalified contractors without 

executing a full competitive bidding process); 3) and utility energy service contract (UESC). 

Although these structures mostly focused on deployment of energy efficiency (EE) measures, a 

few have included PV-system deployment. 

New financing structures also have emerged, including the third-party ownership power purchase 

agreement (PPA) model. This model, either alone or in conjunction with an ESPC, provides 

several benefits to the federal agency. Under this structure, the government entity hosts—but 

does not own—a PV system. By partnering with a third-party owner, the agency does not pay 

anything up front and is able to secure, on average, 20-year fixed-price power for the output of 

the system at or below current retail rates (in the first year). Private-sector financiers own the 

projects so as to secure federal tax credits and, in exchange, pass on their tax credit advantage to 

the federal agency through lower power prices. Such public-private partnerships are expected to 

 

1 The eligibility and application process for the federal loan guarantee program must be finalized in a Guidance 

document to be issued by the U.S. Department of Energy.
vii

continue, as entities that pay taxes likely will be needed to secure U.S. Department of Treasury 

grants (a temporary option in lieu of tax credits and included in the Recovery Act). 

In some cases, a contractual intermediary can help federal agencies that are unable to sign longterm power contracts (longer than 10 to 15 years).2

Our analysis of market opportunities and financing structures available to federal PV projects 

highlights a number of key strategies and opportunities for federal energy managers: 

The Western Area Power Administration 

(WAPA) has the ability to sign 20-year contracts, and has offered to sign such long-term 

contracts for federal agencies located in its service territory, even those which are not customers 

of WAPA. By signing the 20-year contract with the developer, WAPA provides an important 

service, helping the private developer secure financing because the costs can be amortized over a 

longer period of time. This helps to lower the electricity price in the PPA with the federal 

agency. 

Consider a third-party ownership PPA to take advantage of federal tax credits/grants. As 

federal agencies pursue PV deployment programs, the third-party ownership model (including 

partnering with utilities) will be a key financing structure to take advantage of an array of federal 

incentives like the ITC and MACRS. This model can be used as a component of an ESPC as well

as a UESC, now that utilities are eligible for the ITC.3

Consider bundling PV with energy efficiency activities. In addition to helping meet federal 

energy intensity reduction mandates, bundling PV with EE improves the payback–cost 

effectiveness through the total package of activities.

Private partners will be most interested in 

this model in states with significant PV rebates or in or near a state with a solar tier in its RPS, 

because the rebates and SREC revenues can help complete the PV project economically (as 

compared to average retail electric rates). Importantly, the Recovery Act also enables taxable 

entities to recover the ITC in the form of a grant. Given the economic downturn and the 

reduction of corporate tax liabilities, the option to take the ITC in the form of a grant will 

broaden the applicability of this benefit. 

Use federal and state cash incentives. Federal and state cash incentives can provide federal 

agencies with a significant source of capital to lower the costs of deploying PV. The Recovery 

Act offers appropriations to federal agencies for energy efficiency and renewable energy 

investment. At the state level, system benefit funds and other funds generally are available to 

federal agencies for deployment of PV and other renewables.

Reduce electricity bills. Federal agencies can reduce utility electricity bills by producing 

electricity on-site with a PV system. These savings are not guaranteed due to the uncertainty of 

electricity prices, and generally are not sufficient to economically justify the deployment of a PV 

system. However, historical data shows a consistent upward trend in annual conventional 

electricity prices over the past decade. Further, the Energy Information Administration (EIA) 

forecasts price increases over the next several years, despite the current economic downturn. 

 

2 It is important to note that as of July 2009, draft federal legislation in the U.S. House of Representatives and the 

U.S. Senate include a provision that would allow all federal agencies to use either 20-year or 30-year contracts 

(respectively) for renewable electricity procurement, according to Kevin DeGroat of Anteres group (personal e-mail 

communication on July 17, 2009). Readers should check to see if this legislation was passed.

3 The Emergency Economic Stabilization Act of 2008 clarified that utilities are eligible to take the ITC.
viii

Finally, there is a significant likelihood a federal response to climate change will increase 

electric utility bills over time; thus, deployment of PV or EE should capture this greater benefit. 

Benefit from the value of green attributes. Where available, SRECs offer an additional 

revenue stream that can be combined with incentives to offset the cost of PV deployment. The 

value of an SREC is greatest in states with solar tiers (or set asides) in their renewable portfolio 

standard requirements. In certain markets, voluntary SRECs also command a smaller—but 

sizable—premium. It is important to note that selling a project’s SREC denies the owner the 

right to claim environmental benefits, including counting them toward the federal renewable 

energy requirements. These SRECs, however, can be replaced by the purchase of less expensive 

landfill gas or wind renewable energy certificates (REC) to receive full credit for the project 

toward federal goals and mandates.

When using an ESPC, Super ESPC, and UESC, require consideration of PV deployment.

Presidential goals for increasing federal government use of renewables encourage a holistic site 

evaluation that considers the optimal project portfolio to both reduce fossil-fuel energy 

consumption and increase renewable energy generation. In turn, federal agencies are successfully 

using ESPCs, Super ESPCs and UESCs, to help finance EE and sometimes on-site renewables 

like PV.

Work with a contractual intermediary.4

Throughout this report, specific project examples explain how the different incentives, cost 

savings, and revenues actually are used to deploy PV in the federal sector. The examples also 

examine the various financing structures in greater detail. Appendix A provides an index of all 

the examples presented, and shows which components contribute to successful project financing 

of federal projects.

 For those agencies that are limited and cannot sign 

power-procurement contracts for the necessary period of time (generally 20 years), consider 

working with an intermediary in the contracting process. Those federal agencies located in 

WAPA’s service territory should speak to WAPA authorities about potential opportunities to 

collaborate on solar PV projects.

 

4 It is important to note that as of July 2009, draft federal legislation in the U.S. House of Representatives and the 

U.S. Senate include a provision that would allow all federal agencies to use either 20-year or 30-year contracts 

(respectively) for renewable electricity procurement, according to Kevin DeGroat of Anteres Group (personal e-mail 

communication on July 17, 2009). Readers should check to see if this legislation was passed.
ix

Table of Contents

List of Figures .............................................................................................................................. xii

List of Tables ............................................................................................................................... xii

1 Federal Sector Background: Energy and Electricity Use ................................................... 1

1.1 Introduction ..................................................................................................................... 1

1.2 Overview of Federal Energy Use .................................................................................... 1

1.3 Federal Renewable Energy Requirements ...................................................................... 2

1.3.1 Energy Policy Act of 2005 .......................................................................................... 3

1.3.2 Executive Order 13423 ............................................................................................... 3

1.3.3 EISA 2007 ................................................................................................................... 4

1.3.4 Agency Goals .............................................................................................................. 4

1.4 Federal Renewable Energy Consumption ....................................................................... 5

1.5 Federal Leadership: DOD and DOE ............................................................................... 7

1.5.1 DOD 25% Renewable Energy Goal by 2025 ............................................................. 8

1.5.2 The DOE’s Transformational Energy Action Management Initiative ........................ 8

1.6 Barriers to PV Deployment in the Federal Government ................................................. 9

2 State and Utility Cash Incentives......................................................................................... 11

2.1 Cash Incentives—SBC Funds ....................................................................................... 11

2.2 Use of SBC Funds--Examples ...................................................................................... 14

2.2.1 State Rebate Program Example: Trapelo Road facility, Massachusetts ...................... 14

2.2.2 State Rebate Program Example: Trenton Courthouse, New Jersey ............................. 14

2.2.3 State Rebate Program Example: New Windsor & Jamaica Bay, New York ............... 14

2.2.4 Public Benefit Fund Example: Corvallis, Oregon ....................................................... 14

3 Photovoltaic Cost Savings and System Revenues .............................................................. 16

3.1 Electricity Cost Savings ................................................................................................ 16

3.2 Net Metering Revenues................................................................................................. 17

3.3 Solar REC Revenue ...................................................................................................... 18

3.3.1 RECs Overview and Background ............................................................................. 18

3.3.2 SREC Revenue.......................................................................................................... 20

3.3.3 SRECs Example: General Services Administration Project, Colorado .................... 22

4 Federal and State Tax Credits ............................................................................................. 24

4.1 Investment Tax Credit................................................................................................... 24

4.2 Modified Accelerated Cost-Recovery System and Bonus Depreciation ...................... 25

4.3 Appropriations to Federal Agencies ............................................................................. 25

4.4 State Tax Incentives ...................................................................................................... 26

4.4.1 Corporate Tax Incentives .......................................................................................... 26

4.4.2 Sales Tax Incentive ................................................................................................... 26

4.4.3 Production Tax Incentives ........................................................................................ 26

4.4.4 Federal Agency Use of State Tax Credit: Oregon Business Energy Tax Credit ...... 26
x

5 Federal PV Financing Models.............................................................................................. 28

5.1 Energy Efficiency and PV ............................................................................................ 28

5.1.1 EE and PV Example: U.S. Postal Service Processing Center................................... 28

5.2 Third-Party Ownership/Power Purchase Agreement Model ........................................ 29

5.2.1 Third-Party/PPA Example: Nellis Air Force Base ................................................... 31

5.2.2 Third-Party Ownership/PPA Example: GSA Federal Building (CA) ...................... 31

5.3 PPA Contracting Intermediary: Western Area Power Administration ......................... 32

5.3.1 WAPA Example: Fort Carson .................................................................................. 34

5.3.2 WAPA Example: National Renewable Energy Laboratory ...................................... 34

5.4 Energy Savings Performance Contracts and Utility Energy Service Contracts 

Financing Models.................................................................................................................... 36

5.4.1 Energy Services Companies ..................................................................................... 37

5.4.2 Utility Energy Service Contracts .............................................................................. 38

5.4.2.1 Utility Energy Service Contract PV Example: Camp Pendleton ........................ 38

5.4.2.2 Utility Energy Service Contract PV Example: Chicago Social Security Center 38

5.4.3 Super ESPC Contracts .............................................................................................. 39

5.4.3.1 Super ESPC PV Example: Coronado Naval Base .............................................. 40

5.4.3.2 Super ESPC PV Example: Sher man Indian High School .................................. 40

5.4.4 ESPC in Conjunction with Energy Services Agreement .......................................... 40

5.5 Additional Information on ESPCs and Super ESPCs ................................................... 41

5.6 Multi-Year Construction for Federal System Ownership ............................................. 41

5.7 Summary of Federal PV Financing Models .................................................................. 42

6 Federal Agency PV Revenue and Incentive Analysis ........................................................ 44

6.1 Solar Advisor Model Background ................................................................................ 44

6.2 PV Financing Analysis—Methodology and Assumptions ........................................... 45

6.2.1 System Size and Performance ................................................................................... 45

6.2.2 System Capital Costs ................................................................................................ 45

6.2.3 Financing Assumptions ............................................................................................. 46

6.2.4 Federal Tax Incentives .............................................................................................. 48

6.2.5 State-Specific Cash Incentives .................................................................................. 48

6.2.6 State-Specific Solar Renewable Energy Credit Prices .............................................. 49

6.2.7 Summary of Available Incentives and Assumed SREC Market Prices .................... 50

6.3 Federal PV Analysis Results ......................................................................................... 50

6.3.1 LCOEG of a 500-kW System ................................................................................... 50

6.3.1.1 Benefit of Third-Party Ownership/PPA Financing ............................................. 51

6.3.1.2 The Importance of Federal Tax Incentives ......................................................... 52

6.3.1.3 The Importance of Cash Incentives .................................................................... 52

6.3.1.4 The Importance of SREC Revenue ..................................................................... 53

6.3.1.5 Comparison of LCOEG With and Without Incentives and SREC Revenue ...... 53

6.3.1.6 Impact of Debt .................................................................................................... 54

6.3.1.7 Final 500-kW PV Analysis Results .................................................................... 55

6.3.1.8 The Utility Third-Party Investor ......................................................................... 56

6.3.2 LCOEG of a 100-kW System ................................................................................... 57

6.3.2.1 Benefit of Third-Party Ownership/PPA Financing ............................................. 58

6.3.2.2 The Importance of Federal Tax Incentives ......................................................... 59
xi

6.3.2.3 The Importance of Cash Incentives .................................................................... 59

6.3.2.4 The Importance of SREC Revenues ................................................................... 59

6.3.2.5 Comparison of LCOEG With and Without Incentives and SREC Revenue ...... 59

6.3.2.6 Final 100-kW PV Analysis Results .................................................................... 60

6.4 Federal PV System Analysis Conclusions .................................................................... 61

7 Conclusions ............................................................................................................................ 63

8 References .............................................................................................................................. 66

Appendix A. Federal Sector PV Deployment ........................................................................... 80

Appendix B. Federal-Sector Eligibility for Net Metering ....................................................... 81

Appendix C. Critical Steps in Executing the Third-party Ownership/PPA Model .............. 83

Appendix D. Critical Steps Using WAPA as a Contractual Intermediary ............................ 86

Appendix E. Critical Steps for Assessing Federal Project Potential ...................................... 88

Appendix F. History of Relevant Legislation and Executive Orders ..................................... 96

Appendix G. Energy Intensity Reductions and Renewable Energy’s Role ........................... 99

Appendix H. Useful Reference Documents and Internet Resources .................................... 101

Appendix I. Useful Contacts .................................................................................................... 102
xii 

List of Figures

Figure 1. Federal renewable energy purchases and on-site generation .......................................... 7

Figure 2. System benefit charge funding of renewables by 2017, by state .................................. 12

Figure 3. On-site generation and net metering.............................................................................. 16

Figure 4. Retail price of electricity for commercial customers averaged for August 2008 (in 

¢/kWh) ........................................................................................................................... 17

Figure 5. Solar/distributed generation provisions in state RPS policies ....................................... 21

Figure 6. Contracts and cash flow in third-party ownership/PPA model ..................................... 30

Figure 7. Third-party ownership/PPA model details (one variation) ........................................... 31

Figure 8. WAPA contracting agent model details ........................................................................ 33

Figure 9. Dynamics of Mesa Top PV Project ............................................................................... 35

Figure 10. The LCOEG of 500 kW projects for federal agencies using different financial 

structures and incentives ............................................................................................. 56

Figure 11. LCOEG after federal tax incentives for a 500 kW system in Colorado ...................... 57

Figure 12. The LCOEG of 100 kW projects for federal agencies using different financial 

structures and incentives ............................................................................................. 61

List of Tables

Table 1. Site Delivered Federal Agency Energy and Electricity Usage Data for FY 2006 ............ 2

Table 2. Summary of Policy Drivers Influencing PV Deployment by Federal Agencies .............. 5

Table 3. Federal Agency Renewable Energy Generation and Purchases Data for FY 2006 .......... 6

Table 4. State and Utility PV Incentive Programs for Federal Agencies ..................................... 13

Table 5. REC and SREC Prices in Voluntary and Compliance Markets ...................................... 20

Table 6. Total Installed Costs per Capacity ($/Wdc) .................................................................... 46

Table 7. Federal and State Tax Assumptions................................................................................ 47

Table 8. State-Specific PV Cash Incentive and SREC Price Assumptions .................................. 50

Table 9. An LCOEG Comparison of Financing Structures and Average Retail Rate .................. 51

Table 10. Comparison of LCOEG With and Without Incentives, for a 500 kW System ............. 54

Table 11. LCOEG Comparison of Financing Structures and Average Retail Rate ...................... 58

Table 12. Comparison of LCOEG With and Without Incentives for a 100 kW System .............. 60

Table A-1. Select Examples of Federal Sector PV Deployment, by State and Project ................ 80

Table B-1. Federal-Sector Eligibility for Net Metering, by State ................................................. 81

Table E-1. Optimal Sizes of Each Technology in Zoo Example .................................................. 93

Table E-2. Life-Cycle Cost of Business-as-Usual Case as Compared to the Zero-Energy Zoo 

Case ............................................................................................................................. 94

Table E-3. Cost-Effective Opportunities for Photovoltaics at Job Corps Centers ........................ 94

Table G-1. Federal Building Energy Intensity (Btu Energy Use per Gross Square Foot) ............ 99

Table G-2. Renewable Energy Purchase Contributions Toward Meeting Energy Intensity 

Requirements ............................................................................................................ 100
1

1 Federal Sector Background: Energy and Electricity Use

1.1 Introduction

The goal of this report is to help federal agencies understand how to finance photovoltaic 

systems deployed at their sites. Given the diverse range of financial and contractual options 

available in the marketplace, federal agencies must make sophisticated choices in order to 

capture as much of the economic potential of a PV system as possible. The first section of the 

report examines federal energy and renewable electricity use, reviews key federal goals and 

requirements, and highlights Department of Defense (DOD) and DOE renewable energy 

programs. Section 2 analyzes the state-based incentives for which federal agencies are eligible. 

Section 3 describes the cost savings and revenues (including SRECs) that result from on-site PV. 

State and federal tax incentives that can be utilized when working with or partnering with a 

private entity are covered in Section 4. Section 5 explores the various options for structuring the 

financing of PV on federal facilities and land including the ESPC, Super ESPC,5

As background, this section explains the overall energy use by the federal government, the 

energy intensity goals and requirements expected of federal agencies in existing and new 

buildings, and the current consumption of and requirements pertaining to renewable energy 

usage. Unless otherwise noted, data in this section is based on fiscal year (FY) 2006 information. 

 UESC, and the 

third-party PPA ownership model. Finally, Section 6 explores the results from a quantitative 

analysis of the economics of PV projects, under various financing structures. The analysis shows 

how revenues and incentives combine to improve a project’s economics. 

This information is presented to explore the importance of the federal government as a U.S. 

energy user, and the potential opportunity for federal-sector PV deployment in general. Specific 

attention is paid to the Department of Defense (DOD) and the Department of Energy (DOE), 

because these agencies are committed to increasing their on-site renewable energy usage 

(described in Section 1.5). Although the federal government could wield significant purchasing 

power in the United States, there are a number of barriers to on-site PV deployment at federal 

facilities, which are briefly explored. If the barriers are not addressed, then the opportunity for 

significant PV deployment in the federal sector might not be realized.

1.2 Overview of Federal Energy Use6

The United States federal government is the largest single energy consumer in the nation. In FY 

2006, the federal government accounted for approximately 1.5% of total primary7 energy 

consumption in the United States. Federal site-delivered8

 

5 A Super ESPC loosens the contracting requirements whereby project specifics are not necessary.

 energy consumption totaled nearly 1.06 

quadrillion British thermal units (Btu) in FY 2006, 7.8% less than in FY 2005. [1] The DOD 

alone accounted for nearly 80% of total federal sector site-delivered energy consumption in 

FY 2006, or 844 trillion Btu. [2] Conversely, the DOE accounted for only about 3.1% of total 

federal sector site-delivered energy consumption. Although DOE energy consumption is much 

6 Useful conversion rates for electricity: 3,412 Btu/kilowatt hour and one quad is one quadrillion Btu (10^15 or 

1,000,000,000,000,000 Btu).

7 “Primary energy consumption” includes all energy consumed to produce, process, and transport the energy.

8 “Site-delivered energy” only includes energy delivered to the point of use, and does not account for energy 

consumed in the production and delivery of energy products. Unless otherwise noted, data in this report uses sitedelivered energy.
2

less than DOD, it is second only to the U.S. Postal Service (USPS) for civilian agencies. 

Government energy purchases cost approximately $17.7 billion and accounted for 0.7% of total 

federal expenditures ($2.655 trillion) in FY 2006. [3] Of this, the DOD spent nearly $13.8 billion 

on energy, accounting for 77.8% of the entire federal energy sector spending. [4] 

Total energy consumption includes a variety of fuels used in various ways. Although more than 

60% of energy consumption for the federal sector is attributed to vehicles and equipment 

(particularly fuel), nearly all of the electricity consumption is used in buildings. In FY 2006, 

electricity accounted for 17.6% of the total federal site-delivered energy consumption, and 

24.1% of the total energy cost. [5] “Goal buildings,” which include federal buildings that are 

subject to Energy Policy Act of 2005 (EPAct 2005) performance requirements, comprise 94.9% 

of the total 3.2 billion square feet of federal space and present the greatest opportunities for PV 

development. “Excluded buildings,” accounting for the remaining 5.1% of federal space, “are 

comprised of structures and processes that are not qualified as federal buildings, buildings under 

construction or renovation, and certain types of leased space.” [6]

As shown in Table 1, in FY 2006 the DOD consumed 29,793 GWh of electricity, which was 

more than 54% of the total federal government electricity consumption for the year. The DOE 

was the second-largest electricity consumer of all civilian federal agencies (trailing the U.S. Post 

Office), consuming 4,901 GWh in 2006. [7] 

Table 1. Site Delivered Federal Agency Energy and Electricity Usage Data for FY 2006

Federal Agency

Total Energy Use 

(Billion Btu)

% of Federal 

Energy Use

Total 

Electricity Use 

(GWh)

% of Total 

Federal 

Electricity Use

DOD 843,708 79.6% 29,793 54.4%

DOE 32,939 3.1% 4,901 9.0%

Other agencies 182,875 17.3% 20,037 36.6%

Federal Government 1,059,522 100% 54,731 100%

Source: “Annual Report to Congress on Federal Government Energy Management and Conservation Programs, Fiscal 

Year 2006,” Department of Energy Federal Energy Management Program, Table 4 and A-2 on page 16 and 72, 

http://www1.eere.energy.gov/femp/pdfs/annrep06.pdf.

1.3 Federal Renewable Energy Requirements

Federal agencies are interested in pursuing on-site PV projects for a number of reasons. Two of 

the main reasons—extending across all federal agencies—are the goals set by executive orders 

and the requirements set by legislation.9

 

9 Note that a detailed description of the laws and regulations over federal renewable energy use is provided in 

Appendix F and Appendix G.

Some federal agencies also have established goals. 

There are three main policies that encourage new PV deployment by federal agencies: (1) EPAct 

2005, (2) Executive Order 13423 (EO 13423), and (3) the Energy Independence and Security Act 

of 2007 (EISA 2007). These policies have established and clarified targets that either directly or 

indirectly pertain to federal agency deployment of renewable energy. Note that, although EPAct 

2005 and EISA 2007 constitute congressional laws, EO 13423 is a presidential executive order. 
3

1.3.1 Energy Policy Act of 2005

Section 203 of EPAct 2005 requires that, to the extent economically feasible and technically 

practicable, federal government agencies use renewable electricity10

• Not less than 3% in fiscal years 2007 through 2009 

 (relative to total electricity 

consumption) at the following levels: 

• Not less than 5% in fiscal years 2010 through 2012 

• Not less than 7.5% in fiscal year 2013 and each fiscal year thereafter. 

EPAct 2005 (§ 203) also provides a bonus to federal agencies for qualifying, on-site renewable 

electricity used directly at a federal facility. For every kWh generated on-site, the agency 

receives double credit. This includes power used at a federal facility that is produced on-site, 

produced on federal lands, or produced on Indian land. [8] Note that if agencies use this bonus 

for the full EPAct 2005 requirement, then only 3.75% of electricity use must be renewable in 

fiscal year 2013. If PV with a capacity factor of 17% is used to provide this on-site generation, 

this would equal 1,580 MW by 2013. Lastly, EPAct 2005 indicates that Congress believes that 

the Department of the Interior should approve at least 10,000 MW of non-hydro renewable 

electricity generation, for deployment on public lands. 

1.3.2 Executive Order 13423

Executive Order 13423 was issued in January 2007, and clarified several expectations for 

meeting the EPAct 2005 federal renewable requirement. Specifically, EO 13423 explains that 

agencies should: 

[E]nsure that (i) at least half of the statutorily required renewable energy 

consumed by the agency in a fiscal year [under EPAct 2005] comes from new 

renewable sources, and (ii) to the extent feasible, the agency implements 

renewable energy generation projects on agency property for agency use. 

It is important to note that most of the renewable energy provisions in EO 13423 are 

complementary to EPAct 2005, but there are two exceptions. First, the EO clarifies that at least 

half of the renewable energy used to meet the EPAct 2005 requirement should be new, or on-line 

after January 1, 1999. Second, both electrical renewable energy and non-electrical11

Finally, EO 13423 specifies, “to the extent feasible, the agency [shall implement] renewable 

energy generation projects on agency property for agency use.” Accordingly, federal agencies 

renewable 

energy are eligible to qualify for EO 13423, whereas non-electrical renewable energy procured 

or produced to meet EO 13423 will not qualify for EPAct 2005. 

 

10 The “2007 FEMP Renewable Energy Requirement Guidance for EPAct 2005 and EO 13423” defines ‘‘renewable 

energy’’ for EPAct 2005 as electric energy generated from solar, wind, biomass, landfill gas, ocean (including tidal, 

wave, current, and thermal), geothermal, waste to energy, hydrokinetic, or new hydroelectric generation capacity 

achieved from increased efficiency or additions of new capacity at an existing hydroelectric project. Note also that 

purchased renewable energy certificates (RECs) and some non-energy attributes apply. Found at “2007 FEMP 

Renewable Energy Requirement Guidance for EPAct 2005 and EO 13423,” U.S. Department of Energy Federal 

Energy Management Program, pgs. 3–5, at http://www1.eere.energy.gov/femp/pdfs/

epact05_fedrenewenergyguid.pdf. 11 “Non-electric” renewable energy generally uses the same definition for applicable fuel sources as used for electric 

renewable energy in Footnote 10. The Guidance offers qualifying examples such as: thermal energy from solar 

ventilation pre-heat systems; solar heating and cooling systems; solar water heating; ground source heat pumps; 

biomass heating and cooling; and thermal uses of geothermal and ocean resources. 
4

will likely try to procure an increasing quantity of self-generated renewable electricity. As such, 

many federal agencies are likely to consider on-site PV deployment as a key method for meeting 

the renewable electricity requirement, particularly because agencies receive double credit toward 

EPAct 2005 renewable electricity requirements.

1.3.3 EISA 2007

Additional provisions affecting federal sector renewable energy deployment are established in 

EISA 2007. The Act codified into law an EO 13423 requirement that federal agencies reduce the 

energy intensity of their buildings 3% per year from FY 2003 through FY 2015, to culminate in a 

30% total reduction. [9] Although the ability to use renewable energy to meet this target is 

rapidly diminishing (to zero by 2012), the “Renewable Energy Requirement Guidance for EPAct 

2005 and EO 13423,” states that an exception is made for “small on-site renewable generation 

projects that do not incur fuel costs, are un-metered, and are located on the customer side of a 

facility’s energy meter.” [10] Therefore, in addition to energy efficiency activities, some federal 

agencies could choose behind-the-meter PV as one way to help meet energy intensity mandates.

For additional background on federal energy intensity and renewable energy’s role with energy 

intensity targets, see Appendix 8. 

Lastly, in EISA 2007 § 433 (“Federal Building Energy Efficiency Performance Standards”), the 

DOE is directed to revise federal building standards so that the fossil energy use in new buildings 

(compared to 2003) be reduced [11] as indicated below. 

• 55% by 2010 

• 65% by 2015 

• 80% by 2020 

• 90% by 2025 

• 100% by 2030 

Energy efficiency and renewable energy offer the best means for reducing the fossil-fuel demand 

currently required by federal agencies.

1.3.4 Agency Goals

The National Defense Authorization Act of 2007 sets a goal for the Department of Defense to 

produce or procure at least 25% of total electricity consumption from renewable sources. This 

Act is discussed further in Section 1.5 (below). Note that, aside from the Defense Act, the 

policies outlined in this section are discussed in greater detail in Appendix F and Appendix G. 

Table 2 provides a brief summary of the goals and requirements which either directly or 

indirectly promote PV deployment in the federal sector. 
5

Table 2. Summary of Policy Drivers Influencing PV Deployment by Federal Agencies

EPAct 2005

Federal government is required to increase its use of electricity from 

renewable sources as a fraction of total electricity use, by:

• 3% or more from FY 2007 through 2009,

• 5% or more from FY 2010 through 2012, and

• 7.5% or more by 2013.

Bonus equivalent to doubling the amount of RE used or purchased so long 

as the energy is used by a federal facility, and is produced on-site, on 

federal lands, or on Indian lands (defined by title XXVI of the Energy Policy 

Act of 1992 (25 U.S.C. § 3501 et seq.).

“It is the sense of the Congress that the Secretary of the Interior should, 

before the end of [2015], seek to have approved [10,000 MW of] nonhydropower renewable energy projects located on public lands. . . .”

EO 13423

Clarified that at least half of the EPAct 2005 RE requirement must be met 

with energy from new renewable sources placed in service after January 1, 

1999.

Allows non-electric renewable resources to count toward the requirement 

for new renewable energy.

EISA 2007

Reduce fossil-fuel energy use of new federal buildings (compared to 2003) 

by:

• 55% by 2010; 

• 65% by 2015;

• 80% by 2020;

• 90% by 2025; and

• 100% by 2030.

RE Requirement 

Guidance for 

EPAct 2005 and 

EO 13423

Declining qualification (to zero by 2012) of renewable energy toward 

meeting EISA 2007 energy intensity reduction requirements, with 

exception of small, behind-the-meter applications.

National 

Defense 

Authorization 

Act of 2007

DOD requirement “to produce or procure not less than 25% of the total 

quantity of electric energy it consumes within its facilities and in its 

activities during fiscal year 2025 and each fiscal year thereafter from 

renewable energy sources.

Sources: “2007 FEMP Renewable Energy Requirement Guidance for EPAct 2005 and EO 13423,” U.S. 

Department of Energy Federal Energy Management Program, at 

http://www1.eere.energy.gov/femp/pdfs/epact05_fedrenewenergyguid.pdf; “Energy Independence and 

Security Act of 2007,” Enacted December 2007. Found at http://frwebgate.access.gpo.gov/cgibin/getdoc.cgi?dbname=110_cong_bills&docid=f:h6enr.txt.pdf; United States Code Service: National 

Defense Authorization Act 2007—Energy Performance Goals and plan for Department of Defense. Pg. 2. 

Found at http://www1.eere.energy.gov/femp/pdfs/ndaa_2007.pdf. 

Federal agencies have been challenged with an array of targets concerning an increase in 

renewable energy, improved energy intensity, and decrease in fossil-fuel consumption. The 

deployment of solar PV clearly meets the demands of renewable energy and fossil-fuel reduction 

goals, and even could play a small role in achieving energy intensity targets. 

1.4 Federal Renewable Energy Consumption

Overall, federal renewable energy consumption in FY 2006 comprised 6.9% of total electricity 

consumption in federal buildings—greatly exceeding the 3% EPAct 2005 target for 2007. [12] 

Less than half of all federal agencies, however, individually have been able to meet or exceed the 

EPAct 2005 renewable energy requirements (specific compliance with EO 13423 is not known 
6

as this program began in FY ’07). The DOD in particular has contributed significantly to the 

federal government’s renewable energy mandates. In FY 2006, the DOD accounted for 

2,823 GWh of used or purchased renewable energy. This was 9.5% of the DOD’s total electricity 

consumption, and 75% of the total renewable energy reported by the entire federal 

sector. [13] [14] Table 3 provides the statistics of self-generated and purchased renewable 

energy, total electricity use, and the associated percentage for DOD, DOE, and the remaining 

federal agencies.

Table 3. Federal Agency Renewable Energy Generation and Purchases Data for FY 2006

Federal 

Agency

Self-Generated 

Renewable 

Energy (GWh)

Purchased 

Renewable 

Energy 

(GWh)

Total 

Renewable 

Energy 

(GWh)

Total 

Electricity 

Use (GWh)

Percentage of 

Renewable Energy to 

Total Electricity Use

DOD 1,140 1,683 2,823 29,793 9.47%

DOE 4 138 142 4,901 2.91%

Other 

agencies 37 343 813 20,037 4.06%

Federal 

Government 1,181 2,597 3,778 54,731 6.90%

Source: “Annual Report to Congress on Federal Government Energy Management and Conservation Programs, 

Fiscal Year 2006,” Department of Energy Federal Energy Management Program, Table 4 on page 16 

http://www1.eere.energy.gov/femp/pdfs/annrep06.pdf.

In FY 2006, 68.7% of federal agency renewable energy use was from purchased renewable 

electricity (bundled with RECs), unbundled RECs (without associated power), and landfill gas. 

Self-generated energy, including electricity, solar thermal applications, and geothermal heat 

pump installations comprised the remaining 31.3% of renewable energy use. Note that, of the 

federal government’s total renewable energy use, only 8.8% comes from on-site electricity 

generation from photovoltaics, wind, and other renewable sources. [15] Total federal renewable 

energy purchases and on-site renewable energy generation is shown in Figure 1. It is important to 

note that on-site renewable electricity generation is not differentiated in this figure.
7

Figure 1. Federal renewable energy purchases and on-site generation

Although this report highlights activities of the DOD and DOE in particular, other federal 

agencies have an important role to help the government achieve its goal of renewable 

deployment. In fact, in parts of the country that have greater than average electricity prices, other 

federal agencies might have a better opportunity for PV development. In many regions the DOD 

and DOE have leveraged their buying power to reduce their electricity rates to below the 

average. The result is that the price of electricity from a PV unit can seem relatively greater, 

because there is a bigger disparity between the cost of the system compared to negotiated utility 

electricity rates. Additionally, the energy-efficiency programs at the DOD already have taken 

advantage of many of the low-cost, simple energy conservation measures (ECMs) that pay for 

themselves in just a few years. Federal agencies that have not yet performed a full-scale site 

energy audit and are located in areas that have higher electricity prices, could combine energy 

efficiency efforts with PV deployment, pay a smaller incremental amount, and enjoy a shorter 

payback period. 

1.5 Federal Leadership: DOD and DOE

The aggressive programs of DOD and DOE and the individual agency efforts in pushing 

renewable energy—such as PV—are examined more closely below. To meet the energy 

requirements successfully requires creative policies, financial incentives, and committed 

program administrators. Federal agencies interested in meeting their own requirements and goals 

can learn valuable lessons from DOD and DOE activities.

Source: DOE 2006 Annual 

Report to Congress 
8

1.5.1 DOD 25% Renewable Energy Goal by 2025

In 2006, the U.S. Senate approved a measure creating a goal for the DOD to get 25% of its 

electricity from renewable sources by 2025. A year later, the National Defense Authorization Act 

of 2007 turned the DOD goal into a requirement “to produce or procure not less than 25% of the 

total quantity of electric energy it consumes within its facilities and in its activities during fiscal 

year 2025 and each fiscal year thereafter from renewable energy sources (as defined in section 

203(b) of the Energy Policy Act of 2005).” [16] [17] As explained above, the DOD consumes 

more than 50% of total federal electricity consumption. This 25% requirement is above and 

beyond the EPAct 2005 requirement of achieving a 7.5% renewable energy contribution to 

overall federal energy use by 2013. 

The DOD has a history of surpassing the clean-energy mandates and goals; therefore it is likely 

that DOD also will meet the 25% goal. The EO 13423 goal (later codified by EISA 2007) 

requested federal agencies to reduce their energy intensity by at least 6% from 2003 to 2007, for 

example, and the DOD reduced its energy intensity by 10.1%. Similarly, the DOD surpassed the 

EPAct 2005 requirement that at least 3% of total electricity usage be renewable in FY 2007–

2009 by supplying 5.5% of its electricity needs with renewable purchases or self-generation. [18] 

Further, EO 13423 set the target that at least half of the 3% renewable energy (1.5%) be from 

new sources (installed in 1999 or later). The DOD used 3.3% new renewable energy, well 

exceeding that goal.

The Department of Navy and the Air Force are leaders within the DOD in pursuing selfgenerated renewable energy projects. The Navy operates the largest wind/diesel hybrid plant in 

the world, as well as the some of largest federal PV systems in the United States. [19] Nellis Air 

Force Base operates the largest solar PV system in the United States as of mid-2008. Several of 

these projects are described in more detail elsewhere in this report.

1.5.2 The DOE’s Transformational Energy Action Management Initiative

In 2007, the Department of Energy launched the Transformational Energy Action Management 

(TEAM) Initiative, in response to EO 13423. The TEAM Initiative is driven by the DOE’s desire 

to be the nation’s leader in energy efficiency, renewable energy generation and use, and 

petroleum reduction and alternative fuel use. Among its numerous goals, the underlying initial 

target is “to have all of its national facilities reduce their energy consumption by 30% and water 

consumption by 16% by the end of fiscal year 2009.” [20] Further, all new construction must 

meet or exceed a LEED Gold standard.12

The goals established in EO 13423 and by the TEAM Initiative are captured in DOE Order 

430.2B. The Order required the DOE sites to submit executable plans for achieving the DOE and 

TEAM goals by December 31, 2008. [21] Also, by the end of 2008, the TEAM Initiative set a 

goal for the DOE to have renewable energy agreements in place at as many sites as are needed to 

fulfill and exceed the EPAct 2005 requirements and EO targets for renewable energy consumption. [22] For the DOE, 7.5% of its electricity consumption is equivalent to roughly 370 GWh. 

With the doubling credit (or bonus) for on-site generation, DOE would need to secure 185 GWh 

 

12 More information about the Leadership in Energy and Environmental Design (LEED) Green Building Rating 

System can be found at http://www.usgbc.org/Displaypage.aspx?categoryID=19 (accessed June 5, 2009).
9

of renewable energy by 2013 to meet the EPAct 2005 mandate. [23] Assuming an average 

capacity factor of 18%, this would require the equivalent of nearly 120 MW of PV. 

The DOE TEAM Initiative recommends six strategies for achieving the renewable energy 

consumption goal, including [24] the following: 

1. Develop life-cycle cost-effective on-site projects that will meet the goal using private 

financing. 

2. Maximize direct purchases which facilitate new renewable energy projects.

3. Incorporate renewable technologies into new construction where feasible. 

4. Minimize reliance on REC purchases. 

5. Maximize DOE land for new renewable energy projects.

6. Initiate legislative and policy changes for implementation.

To achieve the aggressive goals laid out by the TEAM Initiative, the DOE will utilize private 

sector financing, such as ESPCs, UESCs, and third-party owned systems with PPAs. Energy 

savings performance contracts enable the government to avoid up-front costs by contracting out 

the financing, installation, and maintenance of energy equipment. The private companies that 

own and operate the asset are repaid over time by the agency from the cost savings produced by 

the new equipment. [25] This strategy enables the government (and therefore taxpayers) to avoid 

the burden of paying the up-front costs. A UESC uses a similar process as does the ESPC, 

however it is the utility that covers the financing for the capital costs of the project and, in turn, 

is paid back by the energy savings. A more detailed discussion of ESPCs, UESCs, and thirdparty owned PPAs is included in Section 5. 

The Department of Defense and DOE strive to be federal leaders in clean energy implementation. Congress established a DOD goal of 25% renewable energy by 2025 and the DOD has a 

history of surpassing its targets. DOE has the TEAM Initiative geared to reduce energy and water 

consumption, as well as exceed renewable energy mandates and goals. These two agencies take 

advantage of state incentives and new financing structures to deploy PV at their sites. The next 

few sections describe the incentives and market mechanisms that federal agencies can use to help 

pay for on-site PV systems.

1.6 Barriers to PV Deployment in the Federal Government

If all of the 2,890 GWh of federally purchased renewable electricity was replaced with on-site 

PV (at an 18% capacity factor), the federal government would need to deploy 1,833 MW. To put 

this in perspective, this is more than 6 times the 292 MWDC annual grid-tied PV capacity 

installed in the nation in 2008. [26] Additionally, if 10% of the federal government’s electricity 

were to come from on-site PV, the federal government could deploy 4,490 MW. 

There are, however, a number of barriers that the federal government faces to deploying PV on a 

large scale. Some common barriers to PV deployment are shared with the private sector and 

some are unique challenges that are more government specific. Some of the obstacles federal 

agencies have experienced include the following. 

Up-Front Cost. Although PV costs have been reduced significantly in recent years, the cost still 

is substantially greater than most ECMs, and (in most of the United States) also is more than 

electric utility rates. Lawrence Berkeley National Laboratory reported 2007 national average 
10

installed PV prices of $7.60/kW and a real long-term decline in prices of 3.5% per year. [27] It 

generally is challenging for federal agencies to secure such capital in their budgets, however the 

Recovery Act has set aside $5.55 billion in appropriations to make federal buildings more energy 

efficient.

13

Limited Contract Authority. Most federal agencies have limited contract authority that could 

prohibit them from entering into contracts with PV developers or investors. In particular, many 

agencies cannot enter contracts that extend 10 or more years, yet most PV contracts in 2008 had 

durations of 20 years or longer. 

The mechanism to access these funds, however, still is unclear—some could be 

allocated directly to federal agencies, some will be available competitively, and there might be 

other rules. Federal agencies should make efforts now to secure funding available under the 

Recovery Act.

Space Limitations. Not all agencies have rooftop space or land that is suitable for hosting PV 

systems. Trees, other buildings, and other roof-top equipment can shade PV, rendering it 

ineffective for many hours a day and, thus, impractical. 

Resource Limitations. Not all federal agencies are located in areas that have a great solar 

resource for harnessing electricity from a PV system. Note that, although the solar resource is a 

consideration, it should not be the only one. Increased incentives can compensate for a reduced 

solar resource, as evidenced in (1) New Jersey, a state having unremarkable solar resources, but 

which has deployed much PV capacity in recent years due to the state-level incentives.

Declining Bundling Opportunities. Many PV projects are more financially feasible when 

bundled with other ECMs. Some of the best ECM opportunities, however, already might have 

been tapped, leaving fewer remaining energy conservation projects to combine with on-site PV.

Military Housing and Other Building Privatization. Private ownership of a building that the 

federal government rents can present a challenge. The private landlord must be convinced of the 

value of deploying PV on the site (and typically entering a commitment of 20 years or longer), 

despite the fact that the government’s lease might not extend for the same length of time.

Lack of Information. Many agencies lack information on their facilities which can be important 

to help projects attain financing. Site characteristics such as roof age are needed to know if a 

project is feasible. Additionally, the federal infrastructure is aging—to the extent that old 

facilities will be replaced with new ones; this could mean that deploying solar on the old facility 

does not make economic sense.

In summary, the federal sector is large and subsequently spends a significant amount of money 

on energy, particularly electricity. As such, the federal government has the opportunity to deploy 

significant levels of PV in the coming years. There are numerous challenges, however, that must 

be addressed for successful federal PV deployment.

 

13 See “Key Provisions Benefiting the Solar Energy Industry in the American Recovery and Reinvestment Act,” 

Solar Energy Industries Association, at http://seia.org/galleries/pdf/exec_summary_of_final_bill_2_17_09.pdf

(accessed June 5, 2009).
11

2 State and Utility Cash Incentives

This section explores state- and utility-level incentives for federal agencies that promote PV. 

Because of the high up-front cost, on-site PV projects at federal agencies are not likely to meet 

purchasing and payback requirements unless the project can secure additional incentives. Some 

states and utilities offer sizable cash incentives to federal projects, either as up-front incentives 

(at the time of installation), or as performance-based incentives that are paid out as the system 

generates power.

Generally, federal agencies are eligible for these state or utility incentives so long as the 

programs are based on customer class or tariff regulation. This is supported by the legislative 

authority of the National Energy Conservation Policy Act, 42 U.S.C. § 8256, which states under 

section c(2), “Each agency may accept any financial incentive, goods, or services generally 

available from any such utility to increase energy efficiency or to conserve water or to manage 

electricity.” [28] Potential exceptions to this rule are interconnection and net-metering standards 

which are created through a state’s independent laws.

2.1 Cash Incentives—SBC Funds

The primary source of cash incentives for on-site federal PV in many states comes from 

programs that are funded by a system benefits charge (SBC), sometimes called a public benefit 

fund.14

Since the mid 1990s, 16 states and the District of Columbia have implemented some variation of 

SBC funds [29]

The sources of these programs often are mandated through state legislation, but also can 

be created by regional utility and or municipal programs. A standard stipulation for securing 

SBC incentives is that beneficiaries must be utility ratepayers. Therefore, federal agencies that 

are customers of utilities with SBC programs typically are eligible to participate in SBC-funded 

programs, as they pay the same surcharge on their electricity bill as all other customers pay.

15 to support renewable energy.16

Cash incentives are available for PV projects located at federal sites in several states. If a federal 

agency owns the PV system, then it directly receives the incentive. If the agency has partnered 

with a third-party owner, then the owner usually receives the incentive and passes the economic 

benefit through a lower electricity PPA price over the length of the contract. Table 4 provides a 

list of state and utility cash incentive programs for which federal agencies are eligible, including 

The implementation of these SBC programs 

originated as a result of state-specific electric utility restructuring legislation.[30] The SBC is a 

required fee that is added to electricity bills—usually in the form of a usage charge (per kWh basis) 

or as a monthly flat fee. Although the fee usually is modest to the consumer, in aggregate 

significant funds are generated using this mechanism, as shown in Figure 2. According to the 

North Carolina Solar Center, between the years 1997 and 2017, $7.3 billion dollars will be raised 

for renewable energy programs via the system benefit charge mechanism. On its own, California 

will collect nearly $364 million just in 2009. [31] PV is one of several renewable energy 

technologies (in addition to energy-efficiency technologies) eligible for these funds in most states. 

The amount allocated to each technology is state-specific and depends on the program’s goals.

 

14 Other state incentives exist that are funded using other mechanisms, which are not described in detail. 15 Latest review depends on the state. 16 In addition to renewables, some states use SBC funds to target energy efficiency, energy research and 

development, weatherization, and low-income customer assistance.
12

their various stipulations. This is not a comprehensive list for all programs of which federal 

agencies are eligible.

Figure 2. System benefit charge funding of renewables by 2017, by state

Source: Database of State Renewable and Efficiency Incentives (http://www.dsireusa.org) 
13

Table 4. State and Utility PV Incentive Programs for Federal Agencies

Examples of Incentives for which Federal Agencies are Eligible

State Program Watt Parameters Incentive $/W Max Limit Notes

CA California Solar 

Initiative

< 50 kW

$3.25/W AC, 

adjusted based 

on expected 

performance

Under 50kW can opt into 

performance-based incentive 

(PBI), but all systems above 

50kW must use PBI ≥ 50 kW $0.50/kWh for 

first 5 years 

CO Xcel Energy: 

Solar*Rewards

.5 kw to 10 kW $2 per Watt DC $35,000 Rebate program includes 

REC pymts: <10kW = 

$1.50/W; 10.1-100kW = 

$.115/kWh; 100.1kW-2MW = 

RFP process

10.1 kW to 100 kW $2 per Watt DC $200,000 

100.1 kW to 2 MW

Determined 

through RFP 

process $200,000 

CT CT Clean 

Energy Fund

≤ 10 kW $4.75/Watt > 10 kW Varies by system 

DC

Renewable 

Energy 

Demonstration 

Project 

Res. ≤ 3 kW $3/Watt $9,000 Completed fourth round 

solicitations in 08/08'. Will 

soon announce fifth round for 

2009 Non-res. ≤ 8 kW $2.50/Watt $20,000 

FL

Solar Energy 

Systems 

Incentives 

Program

≥ 2kW $4/W $100,000 

MA

MTC - 

Commonwealth 

Solar Rebates

> 1 kW ≤ 500 kW 

$1.50 - $5.50/W, 

depending on 

size 

$1.6 million per 

calendar year for 

non-residential 

applicants

Public buildings receive 

additional $1/W in rebate

MN 

Solar Electric 

Rebate 

Program

≥ 0.5 kW ≤ 10 kW

$2-$2.25/W, 

depending on 

installer

$20,000-22,000, 

though larger 

systems considered 

case by case

Administered by the MN 

Office of Energy Securities, 

funded by Xcel

NJ Clean Energy 

Fund

Up to 1 MW; incentives 

are disbursed only for 

the first 700 kW. 

Effective March 1, 2008, 

projects that use only 

private-sector PPA 

receive rebates for first 

100 kW of rated capacity

$1.85 - $4.10/W 

DC (varies by 

technology, 

capacity and 

applicant type)

$245,000 

As of Dec. 2007, applications 

are no longer accepted. It is 

anticipated that rebates for 

≤20 kW systems will continue 

in some form during 2009-

2012; rebates for larger 

systems will be discontinued

NY

NYSERDA: 

PV Incentive 

Program

up to 25 kW $3-5/W : 

dependent on 

size and res. vs. 

non-res

Systems may not 

exceed 110% of 

demonstrated energy 

demand

Rebate is highest for public 

projects > 25 kW and ≤ 50 kW

OR

Solar Electric 

Buy-Down 

Program

Pacific 

Power

< 30 kW $1.25/W

$150,000 Note: The per-watt incentive 

rate declines linearly for 

systems sized between 30 

and 100 kW 

> 100 kW $1/W for 1st 

100kW

PGE 

< 30 kW $2/W

$175,000 

> 100 kW $1.25/W for 1st 

100kW

WI Focus on 

Energy > .5 kW ≤ 20 kW 35% of project 

costs, or $35,000 $35,000 

As of July 1, 2008, federal 

agencies are eligible for this 

program

Sources: DSIRE, Connecticut Clean Energy Fund, Massachusetts Technology Collaborative (MTC) Renewable Energy Trust, Minnesota Solar 

Electric Rebate Program, New York State Energy Research and Development Authority (NYSERDA), Energy Trust of Oregon, Inc. 
14

2.2 Use of SBC Funds — Examples

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 that directly resulted in federal PV facilities include the following.

2.2.1 State Rebate Example: Trapelo Road facility, Massachusetts

Two federal PV projects were funded in Massachusetts and one is currently operational. [32] 

First, the U.S. General Services Administration (GSA) installed 378 kW of PV at its Trapelo 

Road facility in February of 2007. The project cost a total of $5 million. GSA applied for and 

received a $50,000 grant from the Massachusetts Renewable Energy Trust (Trust), under its 

Small Renewables Initiative, which is a rolling rebate program. According to Trust project 

managers, this was thought to have been done as part of a Super ESPC contract and was 

interconnected through the local utility, NSTAR. The second project is an 11-kW system at the 

Lowell National Historic Park. The project had been stalled for 4 years as the park managers 

attempted to secure matching federal funds. In May 2008, these funds were obtained and the 

project is moving forward towards installation. The construction cost is estimated at $99,172, 

and the project also should be eligible for a $50,000 grant from the Trust. 

2.2.2 State Rebate Example: Trenton Courthouse, New Jersey 

One federal PV project was funded and completed in Trenton, New Jersey, at another GSA 

facility. A 41-kW system was installed at the Trenton Courthouse Annex. The cost of this project 

was approximately $347,000, but a rebate of nearly $150,000 was received from the New Jersey 

Clean Energy Fund. [33] The rebate covered about 43% of the up-front system costs.

2.2.3 State Rebate Example: New Windsor & Jamaica Bay, New York

Two federal PV projects were completed in New York with funding from the renewable 

portfolio standard (RPS) surcharge, administered by the New York State Energy Research and 

Development Authority (NYSERDA). The first system, with 15.84 kW of PV capacity, was 

installed at a United States Army facility in New Windsor. The total cost of the system was 

$114,793 and the incentive received was in the amount of $63,360 (more than 55% of system 

cost). A second installation (total system size of 5.824 kW) was installed at Jamaica Bay 

Wildlife Refuge’s Gateway National Recreation Area in Far Rockaway, New York. This 

installation cost $109,750 and received an incentive of $23,296 (although as of 12/15/2008, the 

final incentive invoice had not yet been submitted). [34] 

2.2.4 State Rebate Example: Corvallis, Oregon

One federal PV project was funded and completed at an U.S. Environmental Protection Agency 

(EPA) building in Corvallis, Oregon. The system is 9 kW and had an initial cost of $74,900. 

However, the project received the maximum commercial incentive of $15,000 from the Energy 

Trust of Oregon, Inc, thereby lowering the total costs for the installation to $59,000. [35] The 

Energy Trust is a state-mandated non-profit corporation and is funded by a 3% “public purposes 

charge” included on energy customer bills. This Trust, together with the Oregon Public Utilities 

Commission (OPUC), guides the Energy Trust’s electric energy programs.

2.2.5 State Rebate Example: U.S. Postal Service Processing and Distribution 

Center, California. 

The USPS West Sacramento Processing & Distribution Center installed an on-site 403-kW PV 

solar system in September 2004. The 2,120 photovoltaic panels provided by PowerLight 

Corporation (now SunPower) cover a surface area of 28,000 square feet. The array is mounted 
15

on a parking lot carport that provides shade for 180 vehicles. The PV carport system was part of 

a larger energy retrofit by the USPS, which also included energy-efficient measures for lighting, 

heating, cooling, ventilation, air compressors, and energy-management control systems. The 

result of the entire energy project was a reduction in energy consumption of more than 33%. [36] 

The cost of the project was about $6.2 million; of that, $1.6 million (about 26%) was covered by 

the Pacific Gas & Electric Company’s Self Generation Incentive Program, and $250,000 came 

from Standard Performance Contracting and Express Efficiency programs. [37] The remaining 

cost was financed through a Northern California Shared Energy Savings (SES) contract with 

Chevron Energy Solutions (subsidiary of ChevronTexaco). The USPS created the SES, which 

basically is a version of an ESPC contract (discussed in Section 5), in part because the USPS is 

not governed by the Federal Acquisition Regulations (FAR) (described in greater detail in 

Appendix C). By reducing the annual electricity purchases for the Processing & Distribution 

Center by $615,000, the entire project was estimated to pay for itself in 10 years through utilitybill savings. [38]

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

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

provide up-front grants and rebates and others create low-interest loan funds. In this sense no two 

programs are exactly the same. These incentives can be important for helping federal agencies 

achieve the required payback on a PV system and receive higher-level approval for the project. 
16

3 Photovoltaic Cost Savings and System Revenues

A PV system installed on federal property for a federal agency might generate a stream of cost 

savings and revenues which contribute to repaying the initial capital cost, installation, operation, 

and maintenance of the system. This section examines these savings and revenues and identifies 

the situations in which they contribute to the economic benefits of a federal PV project. 

3.1 Electricity Cost Savings

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

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

entity (LSE).17 As shown in Figure 3, 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 

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

Figure 3. On-site generation and net metering

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

on the time of day (for customers with time-of-use rates). As shown in Figure 4, during August 

of 2008, retail electricity sold to commercial users in the continental United States averaged 

between $0.08/kWh and $0.21/kWh. Federal agencies often can negotiate lower rates, 

however—particularly at large sites having multiple operations—thanks to the high level of 

demand from their LSE. Therefore, even though the avoided electricity cost savings still exists, it 

 

17 A load-serving entity includes: investor-owned utilities in regulated electricity markets; default/standard offer 

utilities in restructured electricity markets (or deregulated generation markets); and competitive retail electricity 

suppliers in restructured electricity markets.
17

usually is less for a federal agency than for a typical commercial customer. Even so, the pursuit 

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

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—such as the sale of renewable energy attributes and other cash incentives—are critical 

to making a project economically attractive. This is explored further in the analysis of a federal 

system found in Section 6, as are the relative contribution of various cash and tax incentives and 

rate savings.

Figure 4. Retail price of electricity for commercial customers averaged for August 2008 (in ¢/kWh)

3.2 Net Metering Revenues

In addition to offsetting electricity purchases from the utility, the majority of U.S. states allow 

customers to net meter, although not all states or utilities explicitly allow federal agencies to net 

meter.18

 

18 According to the Database for State Renewable and Efficiency Incentives (

Net metering is the policy in which a customer with on-site generation is allowed to 

www.dsireusa.org), these include 

Arizona Public Service (Arizona), Arkansas, Connecticut, Delaware, Florida, Orlando Utilities Commission 
18

receive credit on a utility bill for any excess renewable power that is not used on-site and instead 

is sent into the utility’s system.19

The benefits of net metering only can be recognized at those points in time when the PV system 

output is greater than the customer’s demand. Most federal sites are large and have significant 

electricity demand, therefore there are very few federal examples of net metering playing a role 

in a PV project. For most federal facilities that have pursued PV, net metering never comes into 

play because the PV system’s power is fully absorbed behind the meter and no excess is sent into 

the utility system. Net metering, however, has the potential to support PV projects at smaller 

federal facilities and always should be considered in the planning phase of a PV project. 

During times of excess generation, the utility meter is allowed 

to spin backwards. The amount the utility credit differs by state and utility, and depends on how 

much excess generation exists. Depending on the state, the utility can credit either the retail rate 

(the highest rate, as it includes transmission and distribution), the utility’s avoided generation 

cost, or the utility’s wholesale generation rate. Net metering also can enable excess generation in 

any given month to be carried over to the next billing month for up to a year. At that time, the 

utility either can pay for any outstanding credits or can reset the amount to zero with no payment 

to the customer, depending on the state rules. 

Some states do not have net metering rules or regulations. Rather than having the meter spin 

backwards, the customer usually is required to install a second meter (which the customer must 

pay for). The utility might or might not pay for excess generation—at either 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). A breakdown of states that offer net metering to the federal government is 

included in Appendix B. 

3.3 Solar REC Revenue 

Solar renewable energy credits increasingly are critical for structuring the financing of new PV 

projects. This section explains why RECs were developed, how they can be used in the 

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

3.3.1 RECs Overview and Background

Renewable energy credits20

 (Florida), Hawaii, Rocky Mountain Power (Idaho), Illinois, Maryland, Massachusetts, Michigan, Missouri, North 

Carolina, Oregon, Pennsylvania, Utah, and Vermont.

have become the dominant mechanism for compliance with 

mandatory RPS policies and voluntary green power purchases. These credits are tradable 

commodities—separate from the electricity produced—that bundle the non-electric “attributes” 

of renewable generation. Because they are unbundled from the electricity, RECs are not subject 

to transmission constraints (one of their main benefits). One REC typically represents the 

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

“attributes” can vary across contracts, but likely will include any future carbon trading credits, 

emission reduction credits, emission allowances, and other non-electricity attributes. To receive 

credit toward meeting federally mandated renewable energy goals, the REC must include all 

environmental attributes.

19 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. 20 Also called RECs, tradable renewable certificates, or green tags.
19

Once the REC is separated from the underlying electricity and sold to another party, claims to 

the attributes only can be made by the REC owner, and not by the electricity owner or the project 

owner. For example, the host of a solar PV system is not able to claim to be using “green power” 

if the RECs generated by the project are sold to another entity. This concept is explored in the 

third-party ownership model discussion, Section 5.2. 

RECs are currently used by LSEs to demonstrate compliance with RPS requirements (“the 

compliance market”), and by green power marketers and utilities to supply renewable energy 

products to end-use customers who voluntarily purchase RECs (“the voluntary market”). The 

RPS is a state-level mechanism, which requires the LSEs in a given state to meet a certain 

percentage of customer electricity demand using renewable energy sources. When an LSE is 

required to meet a certain level of electricity demand with renewable energy as part of a RPS, 

RECs typically, but not always, are used to demonstrate compliance with the associated mandate.

Exceptions include Arizona, California, Hawaii, and Iowa, where environmental attributes must 

be sold bundled with the underlying power. California currently is considering allowing the use 

of tradable RECs for RPS.21

Additionally, RECs are becoming the dominant mechanism for marketing renewable power into 

the voluntary market.[39] When companies like Intel [40] or Pepsico [41] 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 one year of 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).

 The manner in which RECs are defined and treated in RPS policies 

varies by state and region. 

22

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, the level of penalties in compliance markets, and whether the REC was derived from a 

solar resource. Table 5 shows the different values of RECs, depending on these factors. 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. 

 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.

 

21 For more information, please see the California Public Utility Commission Web site: http://www.cpuc.ca.gov/

PUC/energy/Renewables, and the specific docket Web site: http://www.cpuc.ca.gov/PUC/energy/Renewables/

hot/070824recworkshop.htm. 22 Note that, in reality, the two purchases by Intel and Pepsico come 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.
20

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

3.3.2 SREC Revenue

Solar renewable energy credits are a separate commodity in most REC markets because their 

value is greater than that of other RECs. This is true for a variety of reasons. SRECs have the 

most value in markets having a separate solar tier in their RPS (also called a “carve-out” or a 

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

to make project economics work. Several states encourage solar or distributed generation (DG) 

through a specific solar/DG tier in the 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. The penalty price for non-compliance of a solar set aside 

often is greater than for standard RPS compliance. Increased penalties encourage LSEs to 

support new development, by accounting for the greater cost of solar and the lack of economies 

of scale with smaller projects. The SRECs also tend to be 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 5. 

Examples of the significant SREC project revenues created from solar RPS set-asides can be 

found in Colorado and New Jersey. Prior to summer 2008, SREC prices ranged from $160/MWh 

to $265/MWh in these two states.23

There are 18 RPS programs that include solar or DG RPS set-asides. The set-asides are included 

in programs in Arizona, Colorado, Delaware, Maryland, Massachusetts, Michigan, Missouri, 

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

Pennsylvania, Texas, Washington, and Washington DC. 

 During summer 2008, SREC prices increased to between $50 

and $310/MWh for the 2008 compliance year, as shown in Table 5. At the end of 2008, SREC 

values in New Jersey increased because the state increased its SREC cap from $300/MWh to 

$711/MWh for the 2009 compliance year (which started in July, 2008). [42] This is the highest 

solar price cap in the nation and will ramp down over time. A high SREC price cap, in 

conjunction with phasing out up-front rebates, led to significantly greater SREC prices in the 

first couple months of trading. As shown in the table, NJ SREC prices have exceeded 

$600/MWh. 

 

23 NREL estimate based on Xcel Energy’s “2008 Renewable Energy Standard Compliance Plan,” Section 5—

Acquisition Plans, available at http://www.xcelenergy.com/docs/Section5-Acquisition_Plans_Final.pdf; and New 

Jersey’s Clean Energy Program “SREC Pricing: SREC Trading Statistics,” available at 

http://www.njcleanenergy.com/renewable-energy/programs/solar-renewable-energy-certificates-srec/pricing/pricing. 

RECs Solar RECs

Voluntary $1-3/MWh $5-10/MWh

RPS $1-35/MWh $205-375/MWh

RPS (shortage) $46-56/MWh $660-675/MWh

Sources: Clear Energy, Evolution Markets, NJ Clean Energy

Program, NREL, Spectrometer, Xcel

Updated January 2009
21

As shown in Figure 5, of these: 

• Fifteen 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; 

• Six states and Washington, DC, offer extra credit for either solar or distributed 

generation; and

• A few states have more than one of these provisions.

Collectively these provisions could result in the installation of thousands of megawatts of solar 

electric capacity by 2025. If it is met, for example, then Maryland’s solar set-aside is expected to 

result in 1,500 MW of new solar capacity. [43] An April 2008 report by the Lawrence Berkeley 

National Laboratory estimated that if compliance is achieved with the various state-level solar 

RPS set-asides (in place as of early 2008), it could result in roughly 6,700 MW of additional 

solar capacity by 2025. [44] If the Ohio and Missouri solar set-asides are included, then this total 

jumps to more than 7,600 MW. [45] 

Figure 5. Solar/distributed generation provisions in state RPS policies

SRECs can be a very important revenue stream for developing new projects. Federal agencies 

could decide to sell the SRECs to nearby LSEs that must comply with solar set-asides in RPS 
22

programs to secure a significant payment; the SREC cash-flow stream very well could determine 

whether 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. [46] Personal 

interviews with developers structuring deals have noted that SRECs can account for 40% to 80% 

of the total revenue stream of a project, in particular states.[47] As explained above, however, 

not every state has SREC prices that are high enough to provide solar projects with this type of 

support. 

If the SRECs of a federal project are sold (to parties in either voluntary or mandatory markets), 

however, then the site host also sells the right to claim that it uses green power, unless 

replacement RECs are purchased. The differing state SREC prices in the mandatory and 

voluntary markets present a unique opportunity for federal agencies pursing PV projects. State 

RPS requirements usually tie the solar or distributed generation requirement to renewable energy 

developed within the respective state. Conversely, the Guidance (noted in Section 1.3) for federal 

renewable energy procurement lets agencies use RECs from anywhere. Therefore, federal 

agencies can take advantage of price differentials caused by geography and varying state 

regulations. However, as mentioned earlier, RECs will not be allowed towards federal 

compliance starting in FY 2013. 

In states without solar rebates 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 

located in states such as California, Colorado, and New Jersey. California has a statewide 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 has a high SREC penalty, which 

encourages new PV installations in conjunction with the sale of SRECs to the local utility. Note 

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

3.3.3 SRECs Example: General Services Administration Project, Colorado

A 1.18-MW PV system was completed at the Denver Federal Center (DFC) in Lakewood, 

Colorado, in January 2008. The U.S. General Services Administration (GSA)24

GSA awarded the $6.9 million contract to SunEdison for design and construction of the 

project. [50] In addition to GSA headquarter funding, the financing of this project was made 

possible through three main mechanisms: a congressional appropriation; a utility rebate resultant 

from the state’s RPS policy (which the state calls a renewable energy standard); and the sale of 

SRECs. The Colorado RPS includes a solar set-aside that requires a certain amount of solar 

 Rocky Mountain 

Region utilized 6 acres to install 6,192 PV panels on the grounds of the DFC. The system is 

expected to produce 1.525 million kWh annually and it is connected to the DFC’s substation, so 

no additional transmission is required. [48] Approximately 10% of the DFC’s peak electricity 

(and 3% of annual electricity) will be offset by the PV system, which roughly is equivalent to 

powering 145 homes. [49]

 

24 The GSA owns and manages federal buildings and land, therefore it has participated in several of the solar project 

examples explored in this report. 
23

power be generated at customer sites. To meet this solar set-aside requirement, Xcel Energy

developed the Solar*Rewards program and periodically issues requests for proposals (RFP) for 

projects ranging in size from 100 kW to 2 MW.25

As described in this section, on-site PV generation can lead to cost savings and decreased utility 

bills by reducing electricity use (i.e., fewer kWh demand) and lowering demand charges (in 

some cases). Where eligible, federal agencies can net meter excess output from on-site solar 

projects, particularly if projects are sized to meet the load at a particular federal site. This creates 

additional savings from the utility electricity bill. Potential revenues from SRECs in states with 

solar RPS set-asides can contribute 40% to 80% towards a project’s cost. If replacement RECs 

are purchased, then the federal agency still can count the system output towards federal 

renewable energy mandates.

Project developers bid a solar REC price based 

on the project’s economics. GSA was successful in its bid for the DFC, and as a result received a 

$200,000 up-front rebate.[51] The also array generates an estimated $340,000 per year through 

revenue produced by the sale of SRECs to Xcel Energy. [52] The SRECs are used by the utility 

to demonstrate compliance with Colorado’s renewable energy standard. The PV system at the 

DFC contributes to the federal renewable energy mandate for GSA, because replacement 

voluntary RECs are being purchased to offset the solar RECs sold to Xcel. In addition to the 

utility rebate and monthly payment for SRECs, the GSA also received a federal appropriation to 

cover the remaining costs of this project.

 

25 The Solar*Rewards program also includes separate programs for projects that are 0.5 kW to 10 kW (receive an 

up-front $4.50/kW incentive) and for projects that are 10.1 kW to 100 kW ($2/W up-front rebate, plus monthly 

payment of $115/MWh, based on actual production to buy the SRECs).
24

4 Federal and State Tax Credits

The recently enacted Recovery Act and the Emergency Economic Stabilization Act of 2008 

(EESA 2008) provide unprecedented federal support for renewable energy development in the 

United States through a wide array of new or expanded tax credits, loan guarantees, grants, and 

appropriations.[53] These various mechanisms are intended to stimulate government and private 

enterprise investment in renewable energy facilities and should greatly improve the economics of 

PV development by federal agencies.

In recent years, the third-party ownership/PPA model (described in Section 5) has emerged as a 

mechanism whereby renewable projects on government property can benefit from tax incentives

offered by the federal and state governments. These tax incentives provide tremendous value to 

the system owner, and can be passed on to the public host. The federal investment tax credit 

(ITC) and the Modified Accelerated Cost-Recovery System (MACRS) (or accelerated depreciation), can provide slightly more than 50% of the installed cost of a PV system. [54] This can 

dramatically alter the economic viability of installing solar. State tax incentives also provide 

benefits to tax-paying entities with operations (and therefore a tax base) in those states. The 

value of these incentives can be passed on to public entities. Developers try to set the predetermined electricity price established in the PPA at or below the utility’s retail rate in the first 

year. The tax credits are a primary reason why this is possible in limited areas of the country. 

This section explains the two primary federal tax incentives for solar—the ITC and MACRS—

and also describes several state tax incentives that can improve PV system economics.

4.1 Investment Tax Credit

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

(ITC) to partially offset the up-front installed cost of a PV system.26 A PV system with an 

installed cost of $1 million, for example, will qualify for a $300,000 tax credit for the year in 

which it goes into commercial operation. This tax credit was extended through December 2016 

with the passing of EESA 2008. In addition to the extension, several details were adjusted within 

the ITC that could help new investors participate in solar projects.27

Prior to enactment of the EESA 2008, utilities were not able to directly take advantage of the 

ITC; if an investor-owned utility (IOU) wanted to support solar, it had to either sign a PPA or 

use a third-party ownership/PPA arrangement. Now IOUs can choose to own their own PV 

projects and take the ITC directly, if desired. Many utilities, however, still will want to partner 

with third-party developers to take advantage of the developers’ extensive solar development and 

operations expertise. Overall, the ITC extension is a crucial “demand-signal” for the industry to 

 The Recovery Act expanded 

the usefulness of the ITC by allowing taxable entities to take the ITC in the form of a cash grant. 

Importantly, taking the ITC in the form of a grant expands the eligibility for the program because 

otherwise it is beneficial only to companies with tax liabilities. The U.S. Department of Treasury 

notes that the application process for accepting the ITC via a cash grant opens in July 2009. [55] 

The effectiveness of the program will depend on the speed of this application process and the 

clarity of some of the implementation details.

 

26 See Section 48 (a) (3) (Investment Credit: Energy Credit) in the IRS tax code. 27 Although not relevant to federal agencies, residential applicants for the ITC previously only could receive up to 

$2,000 for the 30% credit; as of January 2009 they can receive an uncapped 30% credit.
25

continue to build and invest in PV development. The expansion of ITC eligibility means there 

also could be a wider variety of potential partners for federal projects—including utilities and 

other corporations. 

The rules associated with the ITC are complex and an interested party should have a tax lawyer 

review the application of the ITC to federal projects. Certain incentives can reduce the ITC’s 

value and also can impact the depreciable basis of the underlying asset. Although the passing of 

the EES Act of 2008 has and will continue to alter some of the details of the ITC, the recently 

updated version of the Solar Energy Industry Association’s (SEIA) 2008 Guide to Federal Tax 

Incentives for Solar Energy: Version 2.0 provides good background information and 

guidance. [56]28

4.2 Modified Accelerated Cost-Recovery System and Bonus Depreciation

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.” [57] Depreciation schedules can range from 3 to 

50 years, depending on the asset. [58] It is a non-cash charge recorded as a depreciation expense 

for tax purposes, and most property today is depreciated using Modified Accelerated CostRecovery System (MACRS). [59] The IRS permits 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 shorter the 

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

So, in the case of PV, five-year MACRS is more advantageous than longer depreciation 

schedules because shorter schedules enable businesses to accelerate the tax benefits of 

depreciating a particular asset.

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

placed in service in the 2008 calendar year (and only that year) [60]. Renewable energy 

installations, including PV systems, can qualify for this bonus depreciation if certain criteria are 

met. Instead of the standard five-year MACRS schedule described above, under the ESA08 50% 

of the installed cost of the PV system can be depreciated in the first year, with the remaining 

50% to be depreciated using the original schedule. By accelerating the amount of depreciation in 

the first year, tax benefits accrue more rapidly to investors, thus improving the return 

characteristics of the project. The ESA08 did not change the requirement that the depreciable 

basis of the underlying asset be reduced by 50% of the federal investment tax credit. 

4.3 Appropriations to Federal Agencies

The Recovery Act appropriated $5.55 billion to be deposited into the Federal Buildings Fund as 

administered by the General Services Administration (GSA) for expenditures to construct, repair, 

and make alterations on federal buildings to increase energy efficiency, including installing solar 

energy equipment. [61] Of the $5.55 billion appropriated, $4.5 billion is to be available for 

measures necessary to convert GSA facilities to high‐performance green buildings—which could 

include PV—to reduce building energy consumption. GSA estimates that 75% of the anticipated 

projects will include a solar component. [62] The Recovery Act intends for these funds to be 

 

28 To purchase this publication, visit: http://seia.org/cs/tax_manual_non_members.
26

issued quickly by specifying that not less than $5.0 billion is to be obligated by September 30, 

2010. The Recovery Act also appropriates $1 billion for non‐recurring maintenance on Veterans 

Affairs facilities—including energy projects.

4.4 State Tax Incentives

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

renewable energy within their jurisdictions. State tax-incentive programs are used to encourage 

and facilitate the use of renewable energy within the state. These mechanisms create additional 

value for corporate entities that purchase and own PV systems. According to DSIRE, 46 states 

offer some form of local tax relief to encourage renewable energy development. [63] Various tax 

credits, exemptions, or deductions could be offered at any point in the value chain—from 

manufacturing to purchasing and installing. Although the federal government might not always 

be directly eligible for these incentives, there might be ways for government agencies to benefit, 

particularly through the third-party ownership/PPA model of project financing. Below is a brief 

summary of the primary state tax incentives offered across the United States.

4.4.1 Corporate Tax Incentives

As of January 2009, 24 states offer corporate tax incentives for renewable energy generation. 

Corporate incentives can include state tax credits ranging from 10% to 35% [64] as well as 

simple deductions or exemptions. [65] The incentives are offered to corporations to cover 

equipment costs or other related material expenses (i.e., not labor) for the renewable energy 

investment. Often these credits are applicable only when a specified minimum dollar amount is 

invested. [66] Although most state corporate tax incentives exclude the federal government as a 

direct recipient, some do allow a third party (e.g., financiers, installers, manufacturers) to be 

eligible, which could indirectly benefit the federal government. 

4.4.2 Sales Tax Incentive

Twenty-four states also offer some form of exemption from the state sales tax for the purchase of 

a renewable energy system or related equipment. [67] 

4.4.3 Production Tax Incentives

Production tax incentives usually come in the form of annual payments made over a period of 

years for the actual electricity (kWh) produced by a renewable energy system. [68] Production 

incentive payments, currently offered by seven states and more than a dozen utilities, can 

motivate proper operations and maintenance of a PV system because it is based on actual 

generation of the system over time. 

4.4.4 Federal Agency Use of State Tax Credit: Oregon Business Energy 

Tax Credit

Although federal agencies do not pay state taxes, there are some innovative ways that state tax 

credits can benefit federal PV projects. The Oregon Business Energy Tax Credit (BETC) is 

noteworthy given its relevance to federal agencies. The BETC is a state income-tax credit that 

provides tax credits totaling up to 50% of the installed costs of a renewable energy system. For 

PV, the maximum eligible credit currently is capped at $20 million for manufacturers of 

renewable energy equipment; and $10 million for all other projects.[69] Once the PV system is 

operational and has been completely paid for, the tax-paying entity applies the tax credit pro rata 

(or equally) over 5 years to lower its state income-tax bill. Those with eligible project costs of 
27

$20,000 or less can take the tax credit in one year. [70] In recognition of the non-tax-paying 

status of government agencies and nonprofits the Oregon Department of Energy created a “PassThrough Option.” It permits a federal agency to sell the present value of its tax credit to a taxpaying entity and use the proceeds to defray the cost of its PV project. [71] Although this 

mechanism has not yet been used to support solar on a federal government building or on federal 

land, federal projects are eligible and it has been used for state and local government 

buildings. [72] In 2002, for example, the North Santiam School District in Oregon’s Central 

Cascade Mountains sold its tax credits to the Nike Corporation and received $129,000 to assist 

with the capital costs of its energy efficiency upgrades. [73]

As described in this section, federal and state tax incentives can significantly improve the 

economics of a PV project. Combined, the ITC and MACRS can cover approximately half of the 

installed cost of a PV system. State tax incentives also can play an important role in reducing the 

total cash needed to install PV—particularly in Oregon, where the state tax credit can be 

transferred from a federal agency to a corporation. The next section describes the third-party 

ownership/PPA model in detail, to explain the structure of how federal agencies can benefit from 

tax incentives for PV systems deployed on government property. 
28

5 Federal PV Financing Models

Unless a PV system is paid for in cash, structuring the financing of PV systems on federal land 

and buildings can be complex. As described above, there are significant federal tax incentives 

that can substantially improve PV project economics. Market participants have determined how 

to incorporate these incentives into projects deployed on federal property in the last few years. 

This section explores the different ways that PV can be financed; the importance of incorporating 

energy efficiency into a project; how federal agencies are using the third-party ownership/PPA 

model to secure PV on their land; and how the energy savings performance contract/utility 

energy service(s) contract (ESPC/UESC) model is being used, sometimes in combination with 

the third-party ownership/PPA model as an Energy Services Agreement.

5.1 Energy Efficiency and PV

Energy efficiency can be a critical component for the deployment of PV on federal property. In 

addition to the cost savings from energy-efficiency retrofits—which can have very attractive 

payback periods—there are direct benefits related to the installation of a PV system. If the 

energy consumption of a facility is lessened as a result of energy-efficiency investments, then the 

PV system can offset a greater portion of the total load of the facility, or reduce the size of the 

PV facility (and the cost). Additionally, energy savings resulting from energy-efficiency 

investments can help defray the cost of owning and maintaining a PV system. In states that do 

not offer PV incentives to federal agencies, the bundling of energy efficiency investments with 

PV can be critical to making the economic case for moving ahead with the project. 

5.1.1 EE and PV Example: U.S. Postal Service Processing Center

In November, 2001, the U.S Postal Service (USPS) installed a 127-kW PV system at the Marina 

Mail Processing Center in Marina del Rey, California. PowerLight Corporation (now SunPower) 

supplied 845 solar tiles to cover 15,000 square feet of the Marina Center’s rooftop. In addition to 

providing electricity, the panels reduce the building’s energy consumption by providing thermal 

insulation with an R-20 value.29

The Marina Center PV project was financed through several sources. The Los Angeles 

Department of Water and Power offered a $6/watt utility rebate which amounted to $683,000 of 

the total cost of $1,033,000 for the system. An additional $125,000 came from the DOE’s 

Federal Energy Management Program (FEMP) through a grant for distributed energy resource 

equipment. The remaining $225,000, was covered by USPS energy conservation funds and 

ultimately will be recovered over a period of nine years (simple payback) through annual energy 

cost savings of $25,000. [77] 

[74]The installation is part of a broader energy project that links 

to a Viron Energy Services energy-management system which enables Marina Center to achieve 

maximum peak-demand savings. [75] The impact of the solar installation and integration of the 

energy-management system was an estimated 10% reduction in peak-demand electricity 

consumption. [76] 

 

29 The ability for insulation to decrease heat transfer between a building and the outside is measured as R-value. The 

greater the R-value, the more efficient the insulation. Average R-values for common insulation materials ranges 

from 2.8 to 7.0 [79] (DOE 2001). Average U-values for windows fall between 1.20 and 0.20, which converts to the 

average R-values of 0.80 to 5.0 [80]. 
29

5.2 Third-Party Ownership/Power Purchase Agreement Model

In the public-sector PV marketplace, some federal agencies are taking advantage of the thirdparty ownership/PPA model. According to Greentech Media, in 2007, 50% of the growth in the 

commercial and institutional market for solar PV in the United States was carried out using the 

third-party owner model, as compared to just 10% in 2006. [78] Although this is common in the 

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

phenomenon in the public sector. 

Federal agencies are starting to see the third-party ownership/PPA 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 PV. Federal agencies unable to sign 

PPAs that are longer than 10 years30

Instead of owning the PV system, a third-party ownership/PPA model allows a public entity to 

host a system that is paid for and owned by a taxable entity. The public entity enters into a longterm contract (the PPA) with a third-party to purchase the electricity generated on its property. 

The electricity price typically is set at or below the host’s current retail rate for the first year, and 

then typically increases 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 6. More details about the roles and ways that a federal agency can execute a third-party 

ownership PPA, including the steps that must be taken, are included in Appendix C. 

might be able to use a contractual intermediary, such as the 

Western Area Power Administration, to help reduce PV deployment costs. Examples of the 

third-party ownership/PPA structure in place in the federal sector are detailed below. Note that 

this section only addresses third-party ownership/PPA models that are separate from—and 

unrelated to—ESPCs; the combination is discussed in Section 5. 

The details of the roles and responsibilities of different parties for one variation of the third-party 

ownership/PPA model are shown in Figure 6. Benefits of the third-party ownership/PPA 

structure include:

Ability to monetize federal tax incentives (ITC and MACRS) through a third-party project 

investor, which lowers the overall cost to the federal agency;

Low/no up-front cost, burden transfers to the project developer and its investors; 

Predetermined electricity price for term of contract, for the portion of load served by the PV 

system; typically around the customer’s current retail rate in the first year. thereafter that the 

rates might be fixed, escalate annually, or even could go down; 

Operations and maintenance responsibilities are shifted to a qualified third-party project 

developer; and 

Path to PV system ownership; if negotiated as an option in the PPA, the federal agency can 

usually purchase the PV system at the fair market value, on or after year six.31

 

30 It is important to note that as of July 2009, draft federal legislation in the U.S. House of Representatives and the 

U.S. Senate include a provision that would allow all federal agencies to use either 20-year or 30-year contracts 

(respectively) for renewable electricity procurement, according to Kevin DeGroat of Anteres Group (personal e-mail 

communication on July 17, 2009). Readers should check to see if this legislation was passed.

31 Federal tax credits typically are fully monetized in year 6 for MACRS and year 1 for ITC.
30

Figure 6. Contracts and cash flow in third-party ownership/PPA model 

Source: Department of Energy Solar Program

Although the third-party owner model is attractive, there are some important caveats, some of 

which are listed below.

Renewable energy claims cannot be made if the SRECs are sold unless replacement RECs are 

purchased. The federal agency can state that it hosts the solar system; and if it buy cheaper 

replacement RECs (e.g. hydro or wind), then it can claim consumption of green (but not solar) 

power. 

Reduced electricity expenditures might take time to manifest because the host agency still pays 

for the solar electricity during the PPA (although payments will be predictable and PPA prices 

could end up being less than utility electricity rates). 

Access to the facility must be provided to the developer under a land-use agreement (lease or 

easement), license, or other agreement to enable the developer to maintain the system—which 

can pose challenges for secure or sensitive sites.

Risks and responsibilities of each party should be outlined in the RFP phase, to the extent 

possible. The more precisely this is done in the RFP, the less the challenge posed to all parties 

during contract negotiations. 

Transaction costs of lawyers and other parties must be covered, 

Legality concerns are starting to be raised in several states (e.g., Nevada), where there is a 

question about whether the third-party is illegally competing with the utilities. This topic will be 

explored further in a forthcoming NREL report. [81] 

Current authority for federal agency/private party PPA agreements could be limited to 10 years

for most federal agencies. This challenge, however, can be overcome with intermediary contract 

partners. This concept is discussed in Section 5.3. 
31

Figure 7. Third-party ownership/PPA model details (one variation)

5.2.1 Third-Party/PPA Example: Nellis Air Force Base

The 14-MW PV system installed at Nellis Air Force Base (Nevada) in December 2007 is the 

largest PV power plant in operation in North America, as of mid-2008.32 The $100-milliondollar project utilizes approximately 70,000 panels across 140 acres, some of which is capped 

landfill space. [82] The array incorporates a tracking system which allows it to capture 30% 

more energy than standard fixed-tilt systems. [83] The system will meet 25%, or 30 million 

kWh, of the base’s annual electricity needs. [84] 

The Air Force purchases the electricity produced through a PPA. [85] MMA Renewable 

Ventures LLC owns and operates the PV system and is selling the generated electricity at a fixed 

price to Nellis for 20 years. Under the rates of the PPA, this should save Nellis base roughly 

$1 million per year in energy costs. [86] Additional benefits are created through the sale of the 

RECs to the local utility, Nevada Power. [87] It is important to note that, because this is a PPA 

on federal property, the PUC deemed the federal agency to be exempt from the PPA legality 

issues mentioned above. 

5.2.2 Third-Party Ownership/PPA Example: GSA Federal Building, California

The GSA installed a 506-kW PV system on the rooftop of the federal building at 2800 Cottage 

Way in Sacramento, California. In November 2006, GSA awarded a 10-year contract to Deliddo 

and Associates (dba DEERS) from Ripon, California, which partnered with Constellation Energy 

 

32 SunEdison was the winning bidder of a Duke Energy RFP in May 2008. Duke will sign a contract to purchase the 

output from a 16-MW PV plant that is expected to be on-line before the end of 2010. If built, this would be the 

largest solar PV installation in North America. For more details, see http://www.renewableenergyworld.com/

rea/news/story?id=52550. 
32

Projects and Services Group Inc. Installation began in the fall of 2007 and the project started to 

produce power on March 1, 2008. The solar system is expected to produce approximately 

740 MWh annually and is mounted using Velcro-type attachments to avoid roof 

penetrations. [88] 

General Services Administration used modified Federal Acquisition Regulations Part 41 clauses, 

as well as Part 12 (Acquisition of Commercial Items), in executing the contract. [89] Any federal 

procurement of material or services requires that any contract must comply with procedures, 

terms, and conditions per applicable FAR. In this case FAR 41 applies to utility services and Part 

12 applies to acquisition of generally available “off-the-shelf services or systems.”[90]

Several aspects of the third-party ownership/PPA model are important in the financing of this 

project. Most importantly, the GSA will retain cost savings from reduced demand charges, as 

well as the added insulating value of the system during the 10 years of the PPA. The contract 

price of power is indexed to equal the energy costs under the local utility’s rates (Sacramento 

Municipal Utility District). Second, DEERS owns the system, arranged the financing, and 

provides all operations and maintenance services during the term of the PPA. DEERS was 

granted a license for use of the federal building’s roof to host the PV system. Third, 

approximately half of the system’s cost will be covered by a utility rebate and federal tax 

incentives (ITC and MACRS—thanks to the participation of a third-party owner). Additionally, 

any net metering credits will be passed on to the contractor. DEERS retains the rights to the 

SRECs. [91] It should be noted that GSA is planning to purchase replacement RECs, to be able 

to claim credit for the renewable energy attributes lost to the contractor. Finally, DEERS also 

gets the incentives offered by the California Public Utilities Commission through the SelfGeneration Incentive Program, as well as other tax benefits. [92]

5.3 PPA Contracting Intermediary: Western Area Power Administration

Using a third-party ownership/PPA model the Western Area Power Administration, in 

partnership with NREL, has developed a mechanism that can help federal agencies in WAPA’s 

service territory finance on-site renewable energy projects. Renewable energy projects with 

PPAs of 20 years are more financially attractive to both the hosting federal agency and the 

project developer. The longer the period over which the costs are amortized, the lower the 

levelized cost becomes. Most federal agencies have are limited to energy purchase contracts of 

10 years or less. A major exception is the DOD, which has 30-year authority under 10 U.S.C. 

2922a, but is subject to the approval of the Secretary of Defense [93],. WAPA can utilize its 

power-marketing authority to enter into contracts for longer periods, and has entered into 

contracts for terms of up to 20 years.33

 

33 Authority is through three mechanisms (1) Economy Act, 31 U.S. C. 1535(b); (2) Western’s Power Marketing 

Management Council’s (PMMC) Renewable Resource Products and Services policy memo, February 2006; and 

(3) Renewable Resources for Federal Agencies (RRFA) Program (charter dated August 8, 2003) (Randy 

Manion/WAPA legal review).

 Both Fort Carson Army Base and NREL have used 

WAPA’s longer contracting authority for renewable energy projects installed at their sites. It is 

important to note that as of July 2009, draft federal legislation in the U.S. House of 

Representatives and the U.S. Senate include a provision that would allow all federal agencies to 

use either 20-year or 30-year contracts (respectively) for renewable electricity procurement, 

according to Kevin DeGroat of Anteres Group (personal e-mail communication on July 17, 
33

2009). Readers should check to see if this legislation was passed. If this were to become law, 

contractual intermediaries like WAPA would not be necessary. 

The current process, discussed in detail in Appendix D, requires the hosting federal agency to 

select the renewable energy developer. WAPA participates by negotiating and executing a longterm contract with the project developer/owner (possibly with options to renew). WAPA also 

negotiates and executes an inter- or intra-agency agreement with the hosting federal 

agency/project host. WAPA’s experience in this area allows it to play an advisory role in the 

development process; however, the hosting federal agency must lead the overall project 

development. 

Figure 8 shows the parties involved in developing a renewable energy project, along with their 

associated responsibilities. As indicated, the hosting federal agency receives the benefits of the 

third-party ownership/PPA model; the only up-front costs are paid to WAPA for the actual 

expense to develop and administer the contracts. This usually is a one-time cost. The federal 

agency usually receives the power produced by the project at a predetermined price over the life 

of the contract—which provides a hedge against utility rate volatility. The project developer gets 

the long-term contract it needs to attract investors. Note that some contract costs could be funded 

by DOE’s FEMP. By acting as a contracting agent, WAPA provides an important service to 

federal agencies that are unable to sign 20-year contracts.

Figure 8. WAPA contracting agent model details
34

One important question is whether the WAPA model can be replicated by other agencies outside 

of WAPA’s service territory. Other power marketing administrations (PMAs) might be able to 

play this contracting agent role. One advantage that WAPA has is its well-established federal 

renewable power program (see http://www.wapa.gov/powerm/pmtags.htm), which has been in 

place for more than 5 years. This program has allowed WAPA to gain practical experience in 

dealing with federal renewable energy issues, and in understanding the market nuances and 

contracting requirements associated with renewable energy projects on federal installations. The 

Defense Energy Support Center (DESC) recently has set up a renewable team to help federal 

agencies with developing and issuing PPA requests for proposals. Unlike WAPA, however, 

DESC does not have long-term contracting authority that extends 20 or more years. 

5.3.1 WAPA Example: Fort Carson

Three-Phases Energy Services (now 3 Degrees) developed a 2-MW PV project at Fort Carson in 

Colorado, which was completed in December 2007. [94] The ground-mounted, thin-film PV 

system covers nearly 12 acres on an old Fort Carson landfill and produces 3,200 MWh annually. 

To support project development, SunTechnics, Inc. designed and constructed the project. The PV 

panels carry a 25-year warranty. [95] 

WAPA acted as contracting agent on Fort Carson’s behalf to acquire the electricity produced 

from the solar array at a fixed cost of $0.055/kWh over the 20-year PPA. As a firm electric 

service (FES) customer of WAPA, Fort Carson was able to use the “support energy” provision of 

the FES contract to purchase the electricity produced by the solar array. The SRECs are sold to 

Xcel Energy, under the Solar*Rewards program, to support their customer-sited solar 

requirement under Colorado’s RPS.[96] As described above (see Table 5), NREL estimated the 

price for Colorado SRECs to be in the range of from $160/MWh to $265/MWh. The challenge is 

that SREC prices in the state are determined through auctions via private contracts with the 

utility, so exact prices are unknown. 

5.3.2 WAPA Example: National Renewable Energy Laboratory

NREL has developed the Mesa Top PV Project, which has a capacity of 720 kW and will 

generate some 1,200 MWh annually, or 7% of NREL’s current annual electricity use. The 

system began commercial operation on December 19, 2008. [97] 

This project is being accomplished via four agreements, including: (1) a PPA between 

WAPA/DOE and SunEdison; (2) an inter-agency agreement between WAPA and DOE; (3) an 

easement/access agreement between DOE and SunEdison; and (4) a SREC/rebate agreement 

between SunEdison and Xcel Energy. For a visual of these relationships see Figure 9 below. 

WAPA is the contracting agent on behalf of DOE (Golden Field Office) and NREL, to provide 

SunEdison with a 20-year contract that parallels the 20-year SREC contract that Sun Edison 

signed with Xcel Energy. SunEdison will finance, build, own, operate, and maintain the 

system. [98] As part of making the project financially viable, SunEdison will receive the federal

tax credits, the revenue from the sale of electricity to DOE/NREL (via WAPA), and revenue 

from Xcel Energy’s rebate and purchase of RECs. [99] WAPA will use its power purchasing 

authority to buy electricity on behalf of DOE for a 20-year term. 
35

Figure 9. Dynamics of Mesa Top PV Project (Westby, B. “NREL Program Manager, Federal Energy 

Management Program & Sustainable NREL: Congressional Staff Study Tour,” August 18–20, 2008) 

The Mesa Top PV Project is considered the Phase I project for NREL in its efforts to meet and 

exceed the renewable energy goals and requirements of EO 13423 and EPAct 2005. Three 

additional Phase II PV projects were awarded May 2008, which replicate the Mesa Top PV 

Project agreement structure described above. [100] These include: 

• A 1.16-MW (1,830-MWh) ground-mounted PV installation at the National Wind 

Technology Center;

• A 725-kW (1,000-MWh) ground-mounted PV system near the Research Support Facility 

at the South Table Mountain Campus; and 

• A 118-kW (161-MWh) rooftop PV system at the Science & Technology Facility. 

As described in this section, the third-party ownership/PPA model is being used in the federal 

sector as a way to effectively monetize federal tax benefits, avoid paying the up-front cost of 
36

solar, more efficiently allocate public funds, and accelerate the deployment of PV. Federal 

agencies located in the west can partner with WAPA as a contractual intermediary to help them 

take advantage of this PV financing model. The next section describes federal agency use of 

performance contracts, which can also be used in conjunction with the third-party 

ownership/PPA financing model. 

5.4 Energy Savings Performance Contracts and Utility Energy Service Contracts 

Financing Models

Enlisting the support of the private sector to finance energy efficiency and conservation upgrades 

at federal facilities has been taking place under performance contracting for decades. Use of 

these partnerships is accelerating as the federal government pursues aggressive energy intensity 

and renewable energy goals and mandates (described above). The Energy Independence and 

Security Act of 2007 in Section 514 permanently authorizes the use of ESPCs34

From 1992 through 2007, more than 460 ESPCs have been implemented by 19 different federal

agencies in 47 states. Approximately $2.3 billion in private-sector funds has been invested in 

U.S. federal facilities through ESPCs, saving 18.5 trillion Btu annually—equivalent to the energy 

used by a city of about 518,000. It is estimated that these projects will save the government

$7.1 billion in energy costs, with $5.7 billion of that going to pay off project investment.[103]

DOE actively has pursued use of ESPCs. On December 18, 2008, for example, 16 additional 

contracts were awarded by the DOE for up to $80 billion in energy efficiency, renewable energy, 

and water conservation projects at federal facilities. [104]

 by federal 

agencies. [101] In addition, EISA 2007 encourages agencies to utilize the full 25-year 

contracting authority for the energy savings performance contracts, or ESPCs. [102]

Energy savings performance contracts create a vehicle for a federal agency to make necessary 

investments in energy efficiency upgrades, including on-site generation and water conservation—sometimes without having to commit to an up-front outlay of capital. In these instances, a 

private-sector entity provides the up-front funding for the cost of purchasing and installing new 

energy-efficiency equipment and recoups this investment over time (up to 25 years). The agency 

repays the performance contractor using cost savings from avoided energy consumption (details 

described below). These private-sector performance contractors can be either an energy services 

company (ESCO) or a utility under a utility energy service contract.

Including renewable energy in an ESPC or UESC still is a relatively novel phenomenon for a 

number of reasons. Renewable energy projects traditionally have a longer payback period than 

the majority of energy conservation measures (ECM). The greater cost and longer payback 

period could be amplified if the ESCO charges a 25% to 30% mark-up on PV as an ECM (even 

though the mark up is negotiable). Additionally, the traditional utility or the ESCO might not 

have the renewable energy technical expertise; although in the instances where PV has been 

incorporated into an ESPC, the performance contractor awarded a subcontract for the PV 

installation to a solar installer. Lastly, financial incentives are critical to the success of renewable 

energy and PV in particular, which limits where such projects are feasible to a handful of states. 

 

34 Note that the original authorization was in April 1986 and was called Shared Savings. EPAct 1992 changed the 

name to ESPC and added clarifying statutory text. Personal Communication with Doug Dahle, National Renewable 

Energy Laboratory, February 4, 2009. 
37

Combining PV with a series of energy conservation measures that have shorter investment 

payback horizons, however, enables the entire portfolio of projects to have a shorter payback 

period than the PV system would have on its own. Additionally, investing in ECMs to reduce 

energy consumption will enhance the benefits of a PV system. All else being equal, either the 

PV system will offset a greater percentage of the facility’s energy demands or a smaller and lessexpansive PV system can be installed and reduce energy demand the by the same percentage.

The structure receiving considerable attention is the combining of an ESPC with a third-party 

ownership/PPA contract. In this case, a federal agency takes ownership of the ECMs but not the 

PV system. Instead, the agency hosts a PV project on-site and signs a long-term contract with a 

third-party for the electricity at a predetermined, stable price (as described previously). Examples 

of this structure are described below. Regardless of the details of the deal, it is clear that energy 

service contracting is playing an increasing role in deploying federal PV systems.35

5.4.1 Energy Services Companies

Energy service companies evolved from the needs of building owners to make major investments 

in energy performance in instances where there was a shortage of project capital, energy system 

expertise, or both. Energy service companies were typically engineering services consultants or 

building control manufacturers who chose to assume the risk of project financing in order to 

increase revenue. [105] Some ESCOs are able to finance energy conservation projects on their 

own balance sheets (e.g., Johnson Controls). Typically ESCOs bring in investors as financial 

partners, such as GE Capital, Hannon & Armstrong, and United Financial. 

The most common ESCO contracts are “guaranteed savings” projects. In this situation the 

building owner finances the up-front project costs and the ESCO guarantees the electricity and 

natural-gas savings related to that project, compared to a projected baseline (i.e., what would 

have happened without the project). If the project does not perform as anticipated, then the 

ESCO covers the cost of the additional energy consumption. If the project performs better than 

anticipated, then the additional savings are shared between the federal agency and the ESCO.

Most ESPCs are considered performance-based projects, and the ESCO is paid out of the energy 

savings and pursues projects that minimize the payback period. Many ESCOs, however, now 

offer “comprehensive” contracts which seek to achieve energy savings from the widest possible 

array of cost-effective measures at a given facility. Comprehensive contracts typically are more 

complex because they often go beyond the most obvious projects and include projects with 

longer payback periods, including PV systems. 

A good example of a federal agency using an ESCO to pursue a PV project is Twentynine Palms, 

a U.S. Marine Corps compound in the Mojave Desert in California. In 2002, as part of an ESCO, 

Johnson Controls installed a 1.29-MW tracking solar photovoltaic system. In the first summer of 

operation the system produced about 5% of the base’s electricity needs. [106] At the time, the 

PV system was one of the largest non-utility PV systems in the world. The $51-million contract 

was one of the largest ESPCs ever awarded by the Naval Facilities Engineering Command

Contracts office. The solar installation, in conjunction with energy efficiency measures 

 

35 This trend is discussed in more depth in Integrating PV into Performance Contracts: Barriers and Trends, by 

Wilson Rickerson, Center for Energy & Environmental Policy, University of Delaware, 2004. 
38

undertaken as part of the ESPC should save the base about $6.9 million each year over the course 

of the contract’s 20-year term, for a total savings of $138 million. [107] 

5.4.2 Utility Energy Service Contracts

Recently, many UESCs have been established, usually as a compliment to a utility’s existing 

demand-side management program. [108] Other than the fact that facilities are owned and 

operated by franchised or serving utilities, these financing structures work in a similar fashion as 

a with a typical ESCO. Most UESCs offer shared savings and performance-guarantee contracts, 

enabling federal agencies to pursue energy systems improvement without capital outlay. The 

Energy Policy Act of 1992 (42 U.S.C. § 8256) provides permanent authority for UESCs and 

therefore authorizes and encourages federal agencies to work with UESCs whenever it is 

advantageous to do so. [109] Conveniently, UESCs are offered on a sole-source basis, without 

the need for a full-fledged competitive process.

Federal agencies can establish contracts with a UESC through an existing GSA area-wide 

contract, basic ordering agreement, or a separate installation contract. Alternatively, agencies 

also can establish entirely new “stand-alone” contracts. [110] 36

5.4.2.1 Utility Energy Service Contract PV Example: Camp Pendleton

Regardless, agencies considering 

any new contracts should refer to the model utility service agreement developed by the Edison 

Electric Institute, Department of Defense (DOE’s FEMP), and other federal agencies. This 

model agreement [111] includes all the essential language that federal agencies should include in 

a UESC contract.

At Camp Pendleton, between Fiscal Years 2002 and 2004 the U.S. Marine Corps utilized several

UESCs (and an ESPC) to achieve a 44% reduction in energy consumption despite, a 2 millionsquare-foot increase in facility space. In addition to substantial energy conservation measures 

(e.g., lighting, daylighting, efficient HVAC), Camp Pendleton’s UESCs included the installation 

of more than 200 solar-powered street lights and caution lights. The success of these installations 

led to the use of a variety of solar-powered applications, including lighting at bus stops, carport 

electric vehicle charging stations, wastewater overflow detection stations, and the powering of 

notification and communication systems. [112] The base is expected to save about $1.3 million 

annually and reduce energy consumption by more than 3.7 million kWh and 129,000 

therms. [113] 

5.4.2.2 Utility Energy Service Contract PV Example: Chicago Social Security Center

The Harold Washington Social Security Center in Chicago hosts the largest federal solar 

installation, a 100-kW array on the 8,000-square-foot roof. [114] The installation came on line in 

the summer of 2005 and generates enough electricity each day to power 100 homes. In fact, the 

solar array has performed beyond expectations and is making more energy than initially was 

anticipated. [115] The Social Security Administration (SSA) estimates that the solar system will 

reduce carbon dioxide emissions by 1,900 tons over the next 30 years—the equivalent of 

 

36 Area-wide contracts (AWC) are blanket contracts—essentially indefinite-quantity, indefinite-delivery contracts—

for public utility services. The AWC spells out general terms and conditions and authorizes any agency in the 

utility’s service territory to place delivery orders for services offered under the contract. Basic ordering agreements 

are not contracts, but establish the general terms and conditions for future contracts, making those contracts easier to 

put in place quickly.
39

planting 545 acres of trees or avoiding driving 4.8 million miles on the roadways of 

Chicago. [116] 

The project was financed using a UESC and operational budget allocations; no city, state or 

utility incentives were used to support this project. The USEC was with the local utility 

company, Commonwealth Edison Company (ComEd) and Powerlight (now SunPower) supplied 

the panels. The project cost about $1 million. This was paid for with a $350,000 down payment 

before the installation, and 6 monthly payments included in the ComEd utility bill over 6 

consecutive months for the remaining $650,000.[117] The SSA covered the up-front payment 

using that year’s entire “energy projects” budget; payment was allocated as certain milestones 

were met (e.g., design accepted, equipment ordered). Monthly costs were covered using 

operational budget allocations which were possible because other projects for that year were 

scaled back. ComEd handled the management duties for the installation. [118] 

5.4.3 Super ESPC Contracts

To streamline the process of obtaining ESPCs, the DOE has evaluated and prequalified a select 

number of ESCOs to provide site-specific ESPC contracts. Federal agencies interested in using 

Super ESPCs (also known as IDIQs, indefinite delivery indefinite quantity) are able to work with 

the ESCOs without executing a full competitive bidding process themselves. By establishing the 

general parameters of any contract agreement and prequalifying capable ESCOs, DOE has made 

the ESPC process easier. In Super ESPCs, the vendor guarantees specific levels of water conservation, energy efficiency, and renewable energy in the contract. Additionally, Super ESPCs 

have helped to make financing cheaper. In the last few years, the premium for financing was 

reduced from 150 to 200 basis points over the London Interbank Offered Rate (LIBOR),37

The concept of working with ESCOs first was instituted in 1986. In 1992, Congress passed 

legislation enhancing the partnership structure and which also changed the name to ESPC. 

Implementation did not occur until 1995, however, with the promulgation of DOE program 

regulations. [120] Since then, 19 different federal agencies that have taken advantage of the 

streamlined Super ESPC contract process including: DOE, DOD, National Parks Service, 

National Aeronautics and Space Administration, Department of Transportation, and Bureau of 

Indian Affairs. [121] A directory of ESCOs approved by the Department of Energy can be found 

at http://www1.eere.energy.gov/femp/financing/superespcs_espcescos.html. 

 down 

to 75 to 125 basis points (the higher end of the scale usually includes renewable projects). [119] 

There are two basic kinds of Super ESPCs. The first is a “general-purpose” ESPC and it allows 

agencies to engage ESCOs for typical energy-efficiency and conservation measures. The second 

type of Super ESPC is termed “technology specific,” and is designed to procure help for agencies 

in implementing advanced technologies such as solar, biomass, and geothermal heat pumps. A 

technology-specific ESPC must focus on advanced energy technologies, but bundling a project 

like this with more conventional savings measures is both effective and encouraged. 

 

37 LIBOR is the London wholesale market rate at which banks lend money to each other. Basis points represent 

1/100th of a percentage point, therefore 150 basis points is 1.5% more than LIBOR.
40

5.4.3.1 Super ESPC PV Example: Coronado Naval Base

In September 2002, Coronado Naval Base in San Diego, California, was one of the first federal 

entities to utilize a technology-specific Super ESPC to enable installing of a 750-kWAC PV 

system in its parking lot. At the time it was completed this was the largest PV system in use by 

the federal government—consisting of 3,078 photovoltaic panels. [122] The panels cover 

81,470 square feet on top of several carports and the roof also serves to shade the roughly 400 

vehicles that park beneath the structure daily. The electricity generated by the system meets 3% 

of the naval base’s summer electricity load (peak demand), and is equivalent to powering about 

935 homes. 

The total cost for the solar installation was approximately $7.7 million. This total was reduced 

with a $3.6 million buy-down from the San Diego Regional Energy Office (SDREO) as well as 

$1.8 million in supplemental money from the DOD. [123] The net $2.3 million was partially 

funded through a combination of Navy Public Works Center (federal) buy-down and ESPC 

financing.[124] The prime contractor for this project was Noresco/ERI Services. The subcontractor and manufacturer of the system was Powerlight Corporation (now SunPower). The 

annual operating costs savings started in year one, at $228,000. [125] Having been bundled with 

other energy conservation measures, the $15.5 million project had a payback of 5.8 years. [126] 

The Navy currently is looking to expand the use of solar power at this site based on the success 

of this project. 

5.4.3.2 Super ESPC PV Example: Sherman Indian High School

In a smaller-scale project, Sherman Indian High School utilized a Super ESPC to work with 

SEMPRA Energy Solutions. The project resulted in a 40% reduction in energy consumption at 

the school. The DOE already had purchased a 7-kW solar power system for the school. 

SEMPRA included installation of the system and training on its operation and maintenance as 

part of the ESPC. [127] 

5.4.4 ESPC in Conjunction with Energy Services Agreement

As described in Section 5.2, some federal agencies are taking advantage of the third-party 

ownership/PPA model to help finance PV projects. Interestingly, this model is being 

incorporated as a component of ESPCs through an energy services agreement (ESA). The goal of 

the ESA not only is to deploy on-site generation (like solar PV), but also to reduce total on-site 

energy usage.38

The ESA, like a PPA, is signed between an ESCO and an agency. The relationship between the 

ESCO and the PV developer basically is a subcontract, although if the PV developer wants to be 

the owner and bring equity and financing to the project, then the ESCO is expected to sign an 

“operating lease” with the PV developer/owner. 

The energy services companies asked to include solar energy in their ESPCs 

typically turn to a specialized solar-energy company to provide third-party financing and 

ownership of the system. The advantage of this approach is that it typically allows the ESCO to 

incorporate solar without assuming the risk of financing that element of the project. 

The ESA can include the following terms: 

 

38 The model probably will not be part of UESC models because utilities currently are not allowed to take advantage 

of the ITC as credit against their own tax payments—a critical component to financing solar PV economically.
41

• PV energy rate (typically ¢/kWh) 

• Rate escalation (if applicable)

• Duration and quantity of annual PV energy delivery 

• Responsibility for PV system operations and maintenance (should be ESCO or PV 

developer) 

• Alternatives for title and disposition of PV system at end of ESPC contract term. 

Several companies finance, install, and operate solar energy projects at a site where long-term 

(typically 20 year) power purchase agreements are signed. Companies such as SunEdison, MMA 

Renewable Ventures, SunPower, Chevron Energy Services, and others currently are providing 

these services, primarily to private-sector clients. These contracts are custom tailored to the sites 

and clients and they can include both options to extend the term of the ESA as well as options to 

purchase the system.

The only ESCO currently handling the solar element of the ESPCs internally is Honeywell. By 

keeping the solar projects on its own balance sheet, Honeywell is able to obtain solar tax credits 

against its federal tax liability. The resulting tax savings are incorporated into the electricity price 

in the ESA.

5.5 Additional Information on ESPCs and Super ESPCs

Many resources are available to help federal agencies understand the options for deploying PV as 

part of an ESPC or a Super ESPC. The first resource any federal agency should use is DOE’s 

FEMP Web site at http://www1.eere.energy.gov/femp/financing/mechanisms.html. The Web site 

contains a wealth of information for federal agencies and energy managers.

Another helpful step is to enroll in a FEMP training course on ESPCs and Super ESPCs. These

provide all the information a federal manager needs to implement these types of contracts. More 

information on this type of training (including a schedule) can be found at: 

http://www1.eere.energy.gov/femp/financing/superespcs_training.html. 

Screening the potential sites to identify which have the best combination of renewable resource 

and incentives to implement PV also is important. Appendix E provides an explanation of the 

critical steps needed to screen a federal agency’s sites, and gives some specific examples of how 

such screenings were used by the DOD and the Department of Labor. 

Federal agencies that are ready to move forward with procurement can secure additional 

technical help at no cost from DOE FEMP through the Initial Proposal stage—without the need 

for an Interagency Agreement. This technical assistance can help federal agencies design and 

develop an appropriate procurement plan. After the Initial Proposal, FEMP services can be 

provided on a cost-reimbursable basis through an Interagency Agreement which spells out tasks 

and costs of FEMP project facilitation. For more information on FEMP support on ESPCs, 

review the program overview at http://www1.eere.energy.gov/femp/pdfs/espc_toolkit.pdf. 

5.6 Multi-Year Construction for Federal System Ownership

For federal agencies interested in directly owning PV projects, but which are unable to secure 

enough funds for a very large project in a single year, there is a unique option for building over 

several years. The cash buyout structure also is relevant for projects in states that do not have the 
42

economic incentives needed for the third-party ownership/PPA model (e.g., Oregon, Hawaii, 

North Carolina). In working with the PV installer, it is possible to stretch the installation—and 

thus the payment period—over 5 years. During this period, an agency includes annual payment 

in its budget, or can commit most/all of its energy conservation/management funds to a large PV 

project. This enables the agency to spread the payments of a large system over time. This does 

require assuring the developer that funds will be received over the entire 5-year period.

The challenge is that projects at minimum must be 20 MW to make this economically feasible.

The critical component is to keep the labor on-site and working over the 5-year period—for a 

number of reasons. First, the cost of mobilizing an installation crew is significant and it does not 

make economic sense to remobilize a crew several times on the same project. Also, by using the 

same delivery/installation team, the consistency and the quality of installation is improved; this is 

important, as it is unlikely that an installer can commit to keeping the same crew working over a 

5-year period on a small project.[128] Although this mechanism is not likely feasible for many 

federal agencies, it could be feasible in the right circumstances.

5.7 Summary of Federal PV Financing Models

As explored in this section, there is a wide variety of financing options available to federal 

agencies interested in deploying and financing PV on their property. Many of the financial 

structures can be complex but, importantly, the federal agencies can partner with the private 

sector to help. 

Complimentary energy-efficiency activities are important for deploying federal-sector PV, 

because the portfolio of projects will have a significantly reduced payback period than a PV 

project alone. Federal agencies can use performance contracting (ESPC, UESC) in combination 

with an ESA (commonly called a third-party owned PPA) to achieve this combined portfolio 

without the up-front costs or operations and maintenance responsibilities, and with guaranteed 

savings over time. The ESPC contracts allow for 25-year terms; this provides a mechanism to 

deploy PV for federal agencies that have limited energy-procurement authority (10 years), if the 

PV developer requires 20-year contracts.

The DOE has made ESPCs and UESCs more accessible to federal energy managers in two ways. 

First, by pre-approving select ESCOs, the DOE has streamlined the procurement process; the 

federal agency does not have to execute a full competitive bidding process itself. Second, the 

general parameters of any contract agreement are predetermined, which can help facilitate the 

actual development of the performance contract by starting from a common set of basic 

parameters.

Although performance contracting is the most widely available financing mechanism for federal 

agencies, the third-party owned PPA structure also is gaining popularity. Without the advantage 

of ECMs as part of the project portfolio, these projects often require a large size (to secure the 

economies of scale to bring down project costs) and also significant payments either through 

state-level incentives or SRECs. Therefore, using the third-party owned PPA model outside of an 

ESPC or UESC currently generally is more feasible in the states with the best PV incentives or 

with a specific solar set-aside in their RPS.
43

An additional challenge with using the third-party owned/PPA structure alone is that many 

federal agencies are unable to sign procurement contracts for terms longer than 10 years. 

Fortunately, federal agencies located in WAPA’s service territory can work with WAPA as a 

contractual intermediary, because its contracting authority extends the necessary 20 years. Even 

federal agencies that are not currently WAPA preferred customers can work with WAPA to 

develop PV using the third-party owned/PPA model. Even though WAPA will be an advisor in 

the development process and will facilitate contracting, it is up to the hosting federal agency to 

lead overall project development (including selecting the renewable energy developer). 

In summary, federal agencies have several options for financing PV projects on their property. 

Incorporating energy efficiency can be crucial for including PV in the project portfolio and is 

accomplished most easily using an ESA in combination with an ESPC, UESC, or even a Super 

ESPC. Directly using the third-party ownership/PPA model without executing a performance 

contract is possible; federal agencies can either take advantage of WAPA’s procurement 

authority, or can use their own if it extends 20 years. 
44

6 Federal Agency PV Revenue and Incentive Analysis

To evaluate the potential options available to federal agencies for financing and deploying PV 

systems, NREL conducted an analysis using the Solar Advisor Model (SAM) [129], which was 

developed at NREL. This section explains the SAM model, assumptions, analysis methodology 

and results of that analysis. The results compare resultant levelized cost of electricity 

generation39

6.1 Solar Advisor Model Background

 (LCOEG) under different incentives and financing structures available to federal 

agencies, and highlight the differences between regions.

The Solar Advisor Model Background (SAM) was developed by staff at NREL and Sandia 

National Laboratory to provide a comprehensive analysis modeling tool of solar technology 

systems to support the federal research and development (R&D) community and the solar 

industry. This tool enables investigation of the impact of variations in physical, cost, and 

financial parameters to better understand their impact on key metrics related to system price and 

performance. These metrics include system output, system efficiencies, levelized cost of 

electricity generation, return on investment, system capital cost requirements, and operations and 

maintenance costs.

The SAM system can analyze various impacts on LCOEG of PV project financing. It can 

examine the impacts of financial variables like loan-debt fraction and term of loan. Additionally, 

the “commercial loan” module can model self-financed projects, even for federal agencies, and 

the third-party ownership/PPA module calculates results from third-party-owned financing 

structures. The calculated financial metrics include annual cash flow throughout the project life, 

the LCOEG for the system, tax payments, the net present value of the system, and the internal 

rate of return. For utility-scale systems using the perspective of the independent power producers 

(IPPs), the model calculates the necessary PPA value and future escalation rate that is needed to 

make the project viable.

Additionally, SAM has the ability to add financial incentives to the system; all standard federal, 

utility, and state-level incentives can be included. The tax implications and final impact on the 

SAM outputs then is included both in the annual cash flow and the resultant levelized cost of 

electricity generation. Likewise, the user can input values for a production tax credit, an up-front 

rebate (total dollars), a capacity-based incentive (a buy-down in $/W), or a production-based 

incentive (either a state or utility cash incentive or an SREC, in ¢/kWh). The tax implications of 

each of these incentives vary with location and will be subject to any future tax changes 

implemented. It is possible to adjust the default values for the tax impact of these incentives by 

changing the taxable status of the incentive, if the incentive reduces the ITC basis or if the 

incentive reduces the depreciation basis. Federal, state, and utility incentives often are critical 

financial components to PV systems, therefore incentives are an important component of SAM 

and open its use to various solar policy analyses.

 

39 The levelized cost of electricity generation includes the all-in cost of the equipment (which includes installation 

and interconnection), as well as the cost of financing (both debt interest rate and equity returns), and other ancillary 

costs (if applicable) such as insurance, land payments, and taxes. Levelized cost of electricity generation also factors 

in all available incentives.
45

6.2 PV Financing Analysis—Methodology and Assumptions

California, Colorado, and New Jersey were selected to site theoretical PV systems in the 

analysis, because they have strong and varied incentives and high solar energy market prices. 

The final result is a side-by-side comparison of LCOEG under third-party ownership/PPA and 

cash/commercial loan models. Assumptions about performance, cost, finance, and incentives are 

described below. Note that, under the third-party ownership/PPA structure, the entity that owns 

the system must pay taxes on it, but when a federal agency owns the system it is exempt from 

paying any taxes, including sales tax. This is taken into account in the modeling. 

6.2.1 System Size and Performance

Two system sizes and types were selected as potential applications for federal projects. Both a 

roof-mounted 100-kW system and a 500-kW ground-mounted system were analyzed. For the 

rooftop PV system, the tilt angle was set to 20 degrees (based on maximum mounting angles 

available from common mounting-rack manufacturers). The 500-kW system was assumed to be 

a fixed-tilt system with the tilt angle set at the latitude of the city in which it is assumed to be 

sited. This configuration typically maximizes solar panel output. 

Inverters were sized based on the nameplate rating of the PV system (100 kW or 500 kW). 

Inverters come with a 10-year manufacturer’s warranty, which was assumed to be the inverter 

lifespan. To account for inverter replacement, the replacement cost was amortized and added to 

operations and maintenance costs. The PV panels themselves are assumed to last the full span of 

the analysis period because they come with a 20- to 25-year warranty. Finally, system 

degradation was assumed to be 0.5% per year which is an average degradation coefficient for 

both single-crystal silicon and multi-crystal silicon PV panels. [130] 

6.2.2 System Capital Costs

Capital costs were based on cost information from Solar Buzz and product catalogues, as 

compiled by NREL. NREL also estimated installed costs of PV systems in California and New 

Jersey. The samples collected were installed between January 1, 2007 and November 14, 2007. 

The cost information of roughly 850 medium- to large-sized systems was averaged for the 

California estimate of installed cost.40

 

40 Program information from the California Energy Commission’s Emerging Renewables Program and the 

California Solar Initiative.

 NJ Clean Energy’s compilation of cost information of 

162 medium and large systems provided the New Jersey estimate. Installed cost numbers were 

not readily available for the state of Colorado, therefore costs were estimated by averaging the 

cost statistics from California and New Jersey. Annual operations and maintenance costs per 

kilowatt were configured based on a Sandia National Laboratory estimate [131]. Table 6 shows 

the total installed cost of PV that was assumed, by location and size of project.
46

Table 6. Total Installed Costs per Capacity ($/Wdc) 

State 100 kW ($/Wdc) 500 kW ($/Wdc)

California (third-party owned, 

including sales tax) $7.93 $6.87 

California (federally owned, no 

sales tax) $7.60 $6.67 

Colorado $8.04 $7.01 

New Jersey $8.65 $6.94 

Source: Dean, J. “2007 Total Installed Costs Module.” National Renewable Energy Laboratory Internal 

Spreadsheet. 2008

6.2.3 Financing Assumptions

Tax assumptions must be made carefully when using SAM. Federally owned projects do not pay 

taxes, so no tax payments are assumed when a federal agency owns the system. The total 

installed costs gathered for Table 6, however, are assumed to include sales tax for California. 

Therefore, for federally owned systems in California, sales tax payments were estimated and 

then subtracted to get the true installed cost for federal systems. Colorado and New Jersey 

exempt renewable electric equipment from sales tax, so no adjustment was necessary.

For the third-party ownership/PPA model, the private investor that owns the system must pay 

relevant taxes and must be included in the modeling. All third-party owned projects are assumed 

to pay the federal and state taxes for the particular location, which combined equal the total tax 

rate shown in Table 7. Sales tax rates are included in Table 7 to indicate the value of the state tax 

exemptions in Colorado and New Jersey. For the sake of simplicity, property tax rates were not 

included in this analysis, although they are discussed briefly. Property taxes vary between 

jurisdiction, and federal agencies are exempt from paying property taxes. Third-party developers, 

however, would be required to pay property taxes on the renewable equipment. California 

exempts PV system owners from paying property taxes, but neither Colorado nor New Jersey 

does; these rates were excluded from this analysis.
47

Table 7. Federal and State Tax Assumptions41

Tax

Third-Party Owned PV Systems Federally Owned 

California Colorado New Jersey Projects

Federal 34% 34% 34% 0%

State 8.84% 4.63% 9.00% 0%

Total tax rate 42.84% 38.63% 43% 0%

Sales tax 7.25%** 2.9%* 7%* 0%**

* State exempts renewable energy equipment from taxation.

** Requires subtracting out sales tax from installed costs.

 Sources: A/N Group, Inc. and the Federation of Tax Administrators

For federal agencies, the inflation rate and discount rate are provided in the 10 CFR § 436A, 

FEMP—Methodology and Procedures for Life Cycle Cost Analyses. The nominal discount rate 

for 2008 is estimated at 4.9% and the calculated long-term inflation rate is 2.6%. These rates are 

recommended for use for analysis of contracts up to 25 years in length. By default, SAM 

assumes that the PV system will be sized to be significantly less than the total demand of the 

host, and therefore no net excess electricity generation is sold back to the utility through net 

metering. The electric utility rate is used to calculate the net present value of the project.

The insurance rate for third-party owned systems was assumed to be 0.4%, the default value in 

SAM and what was assumed for the DOE Solar America Initiative. No insurance was included 

when federal agencies self-financed the system, as the federal government self-insures all of its 

assets under one umbrella. 

Under the third-party ownership/PPA model, the assumed internal rate of return for a project was 

an additional input (i.e., was set to zero for federally owned PV). Based on limited market 

intelligence gathered by NREL, the internal rate of return (IRR) was set at 8% for the third-party 

ownership model, which seems to be close to the minimum return deemed acceptable by the 

investors. NREL assumed that no debt was used to finance PV in the third-party ownership/PPA 

arrangement. [132]42 Additionally, the PPA was assumed to be at a fixed rate and the escalation 

rate was set to 0%. 

Under the commercial self-financed structure, the effect of using debt in project financing was 

investigated. Two cases were evaluated, one without debt (i.e., full, up-front cash payment) and 

one with a 60% loan fraction. 

 

41 Federal Tax rate from A/N Group, “Corporate Income Tax Rates – 2009, 2008, 2007, 2006, 2005, 2004, 2003” 

http://www.smbiz.com/sbrl001.html#ci. Accessed June 8, 2009. Federal Corporate Income Tax Rates range from 

34% to 38% depending on quantity of taxable income, State tax rates from the Federation of Tax Administrators 

table: “RANGE OF STATE CORPORATE INCOME TAX RATES (For tax year 2008 -- as of January 1, 2008)” 

http://www.taxadmin.org/fta/rate/corp_inc.html. Accessed June 8, 2009. Special note for New Jersey only: 

Corporation business franchise tax rate. Corporations with net income of less than $100,000 are taxed at 7.5%. 

Corporations with net income of less than $50,000 are taxed at 6.5%. A 4% surtax applies through July 1, 2009. The 

minimum tax is $500. An Alternative Minimum Assessment based on gross receipts applies if greater than corporate 

franchise tax. Banking and financial corporations are subject to the franchise tax. 42 According to Jimmy Chuang of MMA Renewable Ventures, MMA is the only corporation to structure debt for its 

third-party ownership PV financing deals.
48

6.2.4 Federal Tax Incentives

In this analysis, the federal investment tax credit and 5-year MACRS depreciation schedule are 

assumed to be available for commercial third-party developers building projects at federal 

agencies.

Third-party developers also are able to take advantage of a 5-year MACRS depreciation schedule 

under which investment costs are recovered through accelerated income tax deductions for 

depreciation.43

6.2.5 State-Specific Cash Incentives

The U.S. tax code specifies that, when a commercial entity takes the ITC, the 

“depreciation basis” of the project must be reduced by half the value of the ITC. Thus a thirdparty developer taking the ITC will be able to depreciate 85% of the project’s costs for tax 

purposes using MACRS. 

Incentives vary by state and also can vary by utility service territory. In California, three utility 

districts are eligible for the California Solar Initiative (CSI) rebate schedule: PG&E, SCE, and 

SDG&E. The theoretical systems modeled in this analysis were sited in San Diego. Note that San 

Diego Gas & Electric has higher incentive levels because fewer people have taken advantage of 

the rebates as of yet. Specific incentive levels for different sized systems and locations can be 

found on the CSI Statewide Trigger Point Tracker (http://www.csi-trigger.com/). As of July 

2008, commercial developers receive an Expected Performance-Based Buy-Down (EPBB) of 

$1.9/watt for systems 50 kW or smaller and government agencies receive an EPBB of 

$2.65/watt. The EPBB is available in 2007 to projects less than 100 kW, to projects less than 

50 kW beginning in 2008, and to projects less than 30 kW beginning in 2010. [133] Large 

systems receive performance-based incentives instead of up-front rebates. At the current tier, 

commercial developers receive $0.26/kWh for 5 years, which was assumed for third-party owned 

systems (both 100 kW and 500 kW). Federal government developers receive $0.37/kWh for 

5 years, which is assumed when federal agencies self-finance PV systems.

In Colorado, up-front rebates are available to commercial developers and federal agencies from 

the investor-owned utilities, Xcel and Aquila. Under the Xcel Solar*Rewards programs, systems 

between 10.001 kW and 100.0 kW are eligible for $2/W-DC rebate. For installing systems 

greater than 100.001 kW, developers receive a $200,000 up-front cash incentive. REC contracts 

for the energy generated also are provided (see Section 6.2.6). 

Through the end of 2007, sizable rebates were available for customers under the New Jersey 

Customer On-Site Renewable Energy (CORE) Program. This historic rebate program will be 

considered and compared to the market-based programs available after that. As noted, New 

Jersey has moved away from up-front rebates (given in conjunction with SREC payments) 

toward an SREC-only structure. The CORE rebate level depended on sector and size of the 

project. Effective September 1, 2007, private-sector and PPA customers were offered $2.25/W 

for 100-kW systems, and $2.00/W for 500-kW systems. Public and non-profit sector developers 

were offered $2.50/W for 100-kW systems, and $2.30/W for 500-kW systems.

 

43 If MACRS were not available, then taxable entities otherwise might use a 20-year straight-line depreciation 

schedule for equipment costs. Thus, the 20-year straight-line depreciation schedule is used as a baseline for 

comparison in this analysis. This is because the value to the project of MACRS only can be understood within the 

context of the partnership between the federal agency and developer.
49

6.2.6 State-Specific Solar Renewable Energy Credit Prices

Solar RECs (SRECs) can be used as a market-instrument to assist in financing solar projects. The 

SREC contracts can be provided in conjunction with other state or utility-level incentives or they 

can be the sole mechanism of financing a system (as is the case in a New Jersey pilot program). 

No SREC contracts are offered for financing customer-sited PV in California because there is no 

solar set-aside within the RPS legislation and because REC trading values are low in the state.

In Colorado, investor-owned utilities must meet the 4% solar set-aside in the RPS with SRECs, 

half of which must come from customer-sited projects. To meet this quota, Xcel Energy provides 

20-year contracts for SRECs to customers under the Solar*Rewards program (in conjunction 

with the incentives described above). PV projects of between 10 kW and 100 kW are eligible for 

a contract for SRECs at a fixed price of $115/MWh. Developers of large systems—between 

100 kW and 2.0 MW—bid in a competitive RFP process for a REC contract with Xcel. In 2007, 

the range of SREC prices received was $206/MWh to $265/MWh.44

New Jersey also has a market for SRECs. Trading price data is available on the New Jersey 

SREC Web site.[134] The SREC payments in three different programs are considered: (1) the 

now closed

This analysis assumes the 

median payment, $235/MWh. 

45

The utility PSE&G allows customers in its service territory to apply for a PV-system loan with 

PSE&G and to repay it with SRECs. The interest rate is set at 11.11%. The system owner 

receives the market price for SRECs, which the owner turns over to PSE&G. PSE&G has set a 

floor of $475/MWh for SRECs. This program is approximated in this analysis by assuming the 

floor price for the loan term of 15 years. If SREC prices are greater, however, then the loan will 

be repaid faster.

CORE rebate program with historic SREC prices, (2) a Public Service Electric & 

Gas (PSE&G) Solar Loan program, and (3) an SREC-cap program, in which SREC prices are 

assumed to be at the price cap (an upper boundary). The 2007 CORE rebate program allowed 

customers to sell SRECs into the market. In 2007, the average of the weighted monthly averages 

for SREC prices was $220/MWh. 

Finally, in an effort to test closing the CORE program, in 2008 NJ Clean Energy tested an 

SREC-only pilot program for financing solar. SREC prices are based on supply and demand, 

therefore all risk is borne by the program participant. To approximate the upper bound of this 

program, the solar alternative compliance payment (SACP) cap price was used for a period of 

8 years (the total lifetime currently defined). If there is an undersupply of SRECs, then it would 

be likely that the prices will near the cap. In July 2008, a new schedule for the SACP was established, beginning in 2008 at a price of $711/MWh. As the price trends down, an average of the 

yearly SACP prices is $654/MWh, which was used as the SREC value in the SAM model over 

8 years. It is important to note that, at the end of 2008, NJ SREC prices sometimes have 

exceeded $600/MWh. [135] Therefore the SREC-cap case will be closest to this year’s SREC 

prices.

 

44 NREL calculation based on Xcel’s 2008 Renewable Energy Standard Compliance Plan at 

http://www.xcelenergy.com/Company/Newsroom/News%20Releases/Pages/Xcel_Energy_files_2008_Renewable_

Energy_Compliance_Plan.aspx. 45 The program remains open for residential customers, but is closed for commercial and industrial customers.
50

6.2.7 Summary of Available Incentives and Assumed SREC Market Prices

Table 8 below summarizes the different incentive programs highlighted in this analysis. If 

incentives vary between the public and private sectors, the difference in payments received also 

is emphasized.

Table 8. State-Specific PV Cash Incentive and SREC Price Assumptions

State Available to a 100-kW PV System Available to a 500-kW PV System

CA

Performance-based incentives:

• Third-Party/PPA: $0.26/kWh for 5 years,

• Self-financed by federal agency: 

$0.37/kWh for 5 years

Performance-based incentives:

• Third-Party/PPA: $0.26/kWh for 5 

years,

• Self-financed by federal agency: 

$0.37/kWh for 5 years

CO Xcel $2.00/W up front, and an SREC contract 

for $115/MWh for 20 years

Xcel $200,000 up front, and an SREC 

contract for an average of $235/MWh for 

20 years

NJ

CORE Rebates:

• Third-Party/PPA: $2.25/W and SRECs 

averaging $220/MWh for 10 years, or

• Self-financed by federal agency: $2.50/W 

and SRECs averaging $220/MWh for 

10 years

CORE Rebates:

• Third-Party/PPA: $2.00/W and SRECs 

averaging $220/MWh for 10 years, or

• Self-financed by federal agency: 

$2.30/W and SRECs averaging 

$220/MWh for 10 years

PSE&G Solar Loan: $475/MWh for 15 years PSE&G Solar Loan: $475/MWh for 15 years

SREC-Cap: $654/MWh for 8 years SREC-cap: $654/MWh for 8 years

6.3 Federal PV Analysis Results

The PV systems modeled in this analysis are meant to provide a general comparison of the 

different incentive structures in different state environments. Costs and investment incentives 

vary drastically, therefore it is important for organizations considering specific PV projects to 

perform their own analysis to capture their project’s actual costs, currently available incentives, 

financing options, and actual resource quality. This analysis also does not consider the savings 

reflected in a customer’s electricity bill as a result of having on-site generation—because this 

benefit is shared across all financing structures, it was considered out of scope. Entities interested 

in determining the LCOEG of a particular project, however, should include this important 

benefit. 

As described below, the total benefit from including all available incentives and revenues is 

striking. For both the 100-kW and the 500-kW systems in all three locations, entering a power 

purchase agreement with a third party results in a reduced final LCOE, after incentives and REC 

payments are incorporated. The margin of benefit of the third-party ownership/PPA model 

depends on several site-specific variables.

6.3.1 LCOEG of a 500-kW System

The first set of results analyzes a 500-kW PV ground-mounted system, tilted at the latitude of the 

3 system locations under study (San Diego, Denver, Atlantic City). The geographic differences 

of installed cost, capacity factor, available incentives, and REC revenues lead to different 

LCOEG in the 3 locations. The PSE&G Solar Loan program, which is based solely on REC 

market prices, results in the lowest LCOEG overall. Although the incentive is not as much as the 
51

NJ SREC-cap price, its availability for 15 years as opposed to 8 years has the greatest impact on 

lowering the LCOEG. Xcel’s Solar*Rewards program, which includes a cash incentive and REC 

payments, results in much lower LCOEG than does the cash payment method used in California. 

Again, Xcel’s 20-year payments are for a longer period—as compared to 5 years in California—

which reduces the LCOEG. A comparison of LCOEG under the different incentive programs and 

financing structures is shown in Table 9. 

Table 9. An LCOEG Comparison of Financing Structures and Average Retail Rate 

500 kW 

PV 

System

Incentives and SRECs 

available

SREC/ 

PBI 

contract 

(years)

Nominal LCOEG

Commercial 

average retail 

rate (¢/kWh)

Thirdparty 

owned/ 

PPA 

(¢/kWh)

Selffinanced 

with cash 

(no debt) 

(¢/kWh)

Net benefit 

of thirdparty PPA 

over cash 

(¢/kWh and 

%) Aug-08

Yearto-date 

through 

Oct-08

CA

CSI PBI contract for 

$260/MWh (commercial 

ownership)

5 33.8 

0.5 (1.5%) 15.2 13.1 CSI PBI contract for 

$370/MWh (federal 

agencies)

5 34.3

CO

Xcel $200,000 up front, 

assumed $235/MWh for 

SRECs

20 16.2 23.1 6.9 (40%) 9.6 8.7

NJ

CORE (now closed) ($2/W 

private sector, $2.30/W 

public sector), SREC 

contract for $220/MWh

10 21.7 27.5 5.8 (27%)

16.5 14.9 PSE&G loan floor: 

$475/MWh for entire 

contract

15 9.6 16.5 6.9 (72%)

SREC trading assumed at 

$654/MWh (avg SREC 

cap)

8 14.7 22.1 7.4 (50%)

Source for Commercial Average Retail Electricity Rates: EIA 2008 Electric Power Monthly with data for October 2008.

6.3.1.1 Benefit of Third-Party Ownership/PPA Financing

The third-party ownership model results in a lower price of energy than the self-financed model 

because of the federal tax benefits available to commercially owned PV systems. For a federal 

agency the savings from contracting with a third-party developer (compared to self-financing) 

can be significant (as is the case in all three locations examined).

First, consider the direct benefit of third-party financing. Under all the scenarios considered for 

Colorado and New Jersey, contracting with a third-party developer leads to an LCOEG that is 

approximately $0.06 to $0.07/kWh cheaper than that of self-financing the PV system (no debt). 

Note that cash incentive levels for the public and private sectors are roughly the same under 

these programs. In California, however, the performance-based incentive offered to governments 

is nearly 1.5 times that offered to private-sector developers. The greater cash incentive awarded 

to the federal government cancels out some of the net benefit of contracting with a third-party 
52

developer. The impact of financial structure and available incentives for a 500-kW system is 

summarized in Table 9. 

The LCOEG for California is relatively greater than for Colorado or New Jersey. This is likely a 

result of the California PBI being available for only 5 years, compared to longer periods for 

SREC payments in the other two states. In general, the longer the period during which a project’s 

revenues, incentives, and costs are levelized, the lower the levelized price will be.

Table 9 also shows the average retail electricity rate for the year 2008 that customers in different 

states must pay. This represents the approximate price that a customer will consider (i.e. their 

current electricity rates) and compare to the levelized price of PV. The LCOEG in California is 

approximately 2.6 times that of the state’s average retail rate for commercial customers. In 

Colorado, the LCOEG is 1.9 times the average retail electricity rate under the third-party 

owned/PPA and 2.6 times the average retail electricity rate under the cash model. In New Jersey, 

both the PSE&G loan and the SREC price cap cases have LCOEGs that are below the average 

retail rate if financed by a third-party developer. When self-financed the LCOEG is between 

1.1 and 1.8 times greater than the average retail rate. Therefore, it appears that developing 

projects in New Jersey generally is the most advantageous. 

6.3.1.2 The Importance of Federal Tax Incentives

As mentioned, the price paid by a federal agency seems to be less when using a third-party 

developer, compared to owning the project itself. In part, this is because of the ability to take 

advantage of federal tax credits. Taxable entities can take advantage of two federal tax 

incentives, the 30% ITC for solar and a 5-year modified accelerated depreciation schedule 

(MACRS). Although federal agencies do not have to pay taxes in the first place, if the benefit of 

these tax credits exceeds the actual taxes paid, then it would be advantageous to partner with 

commercial entities.

For federal PV projects developed under the third-party ownership model, federal tax incentives 

bring down the price of electric generation significantly, as shown in Table 10. Combined, the 

federal tax incentives reduce project LCOEG by 38% as compared to a project that receives no 

tax credits and uses a 20-year straight-line depreciation schedule. Receiving the 30% ITC brings 

down price on a dollar-for-dollar basis, reducing project LCOEG by 30%. A 5-year MACRS 

depreciation schedule also is quite advantageous relative to a typical 20-year straight-line 

schedule (that might otherwise be used by a commercial developer if solar was not eligible for 5-

year MACRS). Price recovery through accelerated income tax deduction reduces the LCOEG of 

the sample projects by 8%. 

6.3.1.3 The Importance of Cash Incentives

Incentives for solar vary across states, therefore the impact of state and utility cash incentives 

varies significantly. The analysis shown in Table 10 and described below assumes that available 

federal tax incentives already are applied to the third-party ownership models. Therefore the 

third-party comparison is between the LCOEG with federal tax incentives and that also including 

the cash incentives. For self-financed PV systems, however, the comparison is between the base 

level LCOEG and that with cash incentives.
53

Only Colorado’s Xcel Energy currently offers up-front rebates for large systems (500-kW and 

greater). The $200,000 up-front rebate (equivalent to $0.40/W for a 500-kW system) reduces the 

LCOEG by about $0.03/kWh—for both third-party owned systems and federal agency selffinanced systems. The 2007 CORE rebates in New Jersey were more valuable, as they brought 

down LCOEG by $0.18/kWh in the case of a third-party owned system (receiving $2.00/W for a 

500-kW system) and $0.19/kWh in the case of federally self-financed systems (receiving 

$2.30/W). The performance-based incentive in California is a payment of $0.26/kWh for privatesector developers and $0.37/kWh for public-sector developers awarded for five years. These 

payments reduce LCOEG by $0.11/kWh under the PPA model (after federal tax credits are 

applied), and by $0.16/kWh for a self-financed system.

When state, utility, and federal incentives were included for a federal agency contracting with a 

third-party developer, the LCOEG was reduced by 54% in California, 42% in Colorado, and 

58% in New Jersey (under the 2007 CORE rebates). When the same projects are self financed, 

state and utility incentives (because they are not eligible for federal tax credits) reduce LCOEG 

by 31% in California, 5% in Colorado, and 30% in New Jersey. 

6.3.1.4 The Importance of SREC Revenue

SREC revenue is important for projects in Colorado and New Jersey, where utilities are 

obligated to meet solar set-asides. In Table 10, the SREC results are incremental to both the 

federal tax credits (for third-party owned systems) and for cash incentives. In Colorado, Xcel 

locks into 20-year contracts for SRECs with customer-sited projects through an RFP process. 

With an assumed contract price of $235/MWh for 20 years, LCOEG is reduced by $0.27/kWh

under both financing structures. Long-term contracts for SRECs provide a constant stream of 

revenue for the project, bringing down the LCOEG significantly. 

The three cases analyzed in New Jersey all assume different REC market conditions and contract 

lengths. Under the CORE program, projects could sell SRECs to NJ Clean Energy for a period of 

10 years at the market price. Assuming 10 years of SREC revenue at an average price of 

$220/MWh, a project’s LCOEG was reduced by $0.16/kWh under both financing structures. 

The PSE&G Loan program sets a floor price for SRECs at $475/MWh for projects in the 

program. Under the contract term of 15 years, this reduces LCOEG by $0.47/kWh. The SRECcap program is more uncertain as to how it will impact revenue streams. The SREC prices 

modeled here are not projections of the future—rather they are presented as indicators of the 

relative contribution of SRECs at these high prices, to establish an upper-bound case for 

reducing the LCOEG. The SREC-cap program was approximated by using the alternative 

compliance payment cap for 8 years. Such a contract reduces LCOEG by $0.42/kWh. If 

achievable, SREC prices on the order of those modeled in this analysis would make the two 

SREC-only programs much more advantageous than the up-front grants.

6.3.1.5 Comparison of LCOEG With and Without Incentives and SREC Revenue

When combined, the cash incentives, tax credits, and SRECs create significant savings. Under 

the third-party ownership model, available incentives and revenues reduce LCOEG by 54% in 

California, by 78% in Colorado, by 76% for the New Jersey CORE program, by 89% for the 

PSE&G Solar Loan, and by 84% for New Jersey’s SREC-cap program. When PV systems are 

self-financed, cash incentives and SREC revenues reduce LCOEG by 31% in California, by 57% 
54

in Colorado, by 56% for the New Jersey CORE program, by 74% for the PSE&G Solar Loan, 

and by 65% for New Jersey’s SREC-cap program. 

Values of nominal LCOEG and the percentage decreases from baseline LCOEG are laid out in 

Table 10. Note that these cases do not include the value of reduced electricity purchases from a 

customer’s utility, which can contribute to a customer’s decision to move forward with a 

project.46

Table 10. Comparison of LCOEG With and Without Incentives, for a 500 kW System

500 kW PV system

Nominal LCOEG (¢/kWh) (% decrease from baseline 

LCOEG)

State Incentives available

Without 

incentives

With federal 

tax 

incentives

With state 

incentives

With state 

incentives 

and SREC 

revenues

Third-party owned with a PPA

CA CSI PBI contract for $260/MWh for 5 years 72.9 45.0 (38%) 30.4 (54%) 

CO Xcel $200,000 up front, assumed $235/MWh 

for SRECs for 20 years 74.3 46.3 (38%) 39.9 (42%) 12.8 (78%)

NJ

CORE (now closed) $2/W, SREC contract for 

$220/MWh for 10 years 90.5 56.3 (38%) 34.1 (58%) 17.6 (76%)

PSE&G loan floor: $475/MWh for 15 years 90.5 56.3 (38%) 5.5 (89%)

SREC trading assumed at $654/MWh for 8 

years (avg SREC cap) 90.5 56.3 (38%) 10.6 (84%)

Self-financed with cash (no debt)

CA CSI PBI contract for $370/MWh for 5 years 50.1 34.3 (31%) 

CO Xcel $200,000 up front, assumed $235/MWh 

for SRECs for 20 years 53.1 50.2 (5%) 23.1 (57%)

NJ

CORE (now closed) $2.30/W, SREC contract 

for $220/MWh for 10 years 63 43.8 (30%) 27.5 (56%)

PSE&G loan floor: $475/MWh for 15 years 63 63 (0%) 16.5 (74%)

SREC trading assumed at $654/MWh for 8 

years (avg SREC cap) 63 63 (0%) 22.1 (65%)

6.3.1.6 Impact of Debt

Under the self-financed model, two sets of projects were evaluated to examine the impact of debt 

on the project, one without debt and one with 60% debt. It was found that debt fraction did not 

alter LCOEG significantly. The difference between 0% and 60% debt in the scenarios was 

between $0.01 and $0.03/kWh. Because of this minimal difference only the 0% debt scenarios 

are presented in the tables above.

 

46 This was not included because the point of this analysis is to compare the relative impact of incentives on 

reducing the LCOEG, and to compare different financing structures for a variety of geographic locations. In analyzing the actual LCOEG for a project, the electric utility-bill savings should be calculated and included in the analysis.
55

6.3.1.7 Final 500-kW PV Analysis Results 

Figure 10 simultaneously shows (1) the differences in LCOEG between financing structures; 

(2) the relative value of each component’s ability to reduce the LCOEG; and (3) geographic 

differences’ effect on financing PV. The height of the entire bar represents the LCOEG of the 

project, not including any incentives; the bottom black bar for each case represents the final 

LCOEG, including all of the revenues and incentives. The relative reduction of the LCOEG by 

each component is represented by the bar height of each incentive, and each incentive is applied 

only to applicable cases. 

First, consider the differences between the financing structures. The total relative level of the 

LCOEG without incentives (the total bar) is significantly higher for the third-party 

ownership/PPA model. As explained previously, the total installed cost ($/W) generally is the 

same47 for both third-party ownership and the self-financed model (as shown in Table 6). Even 

though total installed cost does not contribute to the difference in LCOEG, there are several 

items that federal agencies do not have to pay (but which third-party investors must pay), 

including federal and state taxes, insurance, and state sales tax. 

Second, Figure 10 and Table 10 show that tax credits and cash incentives are critical to reducing 

the high up-front cost of solar PV. The final LCOEGs, after all incentives have been applied 

(solid black bars at the bottom), are less for the third-party ownership/PPA model than for selffinanced projects. The reason is that the relative value of state or utility cash incentives and 

federal tax incentives (ITC and MACRS) is greater than the cash benefits available for federally 

owned projects. In other words, although the third-party investors must pay more, the sum of the 

benefits seems to be greater than the benefits provided directly to federal agencies (at least for 

these generic projects). 

The third aspect clearly shown in Figure 10 is the geographic differences between the values of 

incentives, SREC prices, and also the final LCOEG. Embedded in this comparison are differences in installed costs and solar resource. In general, it appears that it could be most 

advantageous to develop solar PV in New Jersey; in reality that will depend on future SREC 

market prices. The 8- to 15-year time horizon in New Jersey and the 20-year time horizon in 

Colorado result in much lower LCOEG that the short, 5-year timeframe in California. Finally, 

because the debt fraction did not alter the LCOEG significantly, New Jersey shows only the nodebt cases for self-financed PV. Colorado has the lowest LCOEG, thanks to the substantial 

SREC prices for a period of 20 years. Again, the short 5-year timeframe in California appears to 

not have as great an impact as that of the longer-term SREC prices in New Jersey and Colorado. 

 

47 The one exception is for states that do not have sales tax exemptions for renewable equipment, such as California. 

The total installed cost for a California project therefore differs, depending on whether the owner is a federal agency 

or a private, third-party investor. 
56

Figure 10. The LCOEG of 500 kW projects for federal agencies using different financial structures 

and incentives

This chart shows the LCOEG of 500-kW projects for federal agencies using different financial 

structures and incentives. Installed costs were the same for each location except California, for 

which the sales tax was removed for self-financed systems owned by federal agencies. The name 

of each case designates: Who provides the incentives, the level of any applicable up-front 

incentives (in $/W or $), any SREC payments or PBI payments (in $/MWh), and the number of 

years of REC contracts or PBI payments. The NJ SREC Cap incentive uses the average SACP 

price—$654/MW—over the course of 8 years. 

6.3.1.8 The Utility Third-Party Investor

The Emergency Economic Stabilization Act of 2008 extends the solar ITC to utilities. Therefore, 

under the third-party ownership/PPA model, some utilities might choose to be the tax-equity 

investor. Duke Energy, for example, is interested in owning up to 20 MW of customer-sited PV 

systems to help it meet its solar RPS and to gain experience with distributed generation. [136] 

Now that utilities can capture the federal ITC incentives and their regulated rate of return, 

investing in solar might be more attractive to more utilities.

In Figure 11, the LCOEG of a federal PV system in Colorado is modeled under three financing 

structures: third-party developer owned, utility owned, and self-financed. It is important to note 

that, to isolate the differences in financing terms, this analysis ignores the value of cash 

incentives and SREC payments. The utility investor is comparable to the third-party developer, 

33.8 31.0 34.3

16.2 19.8 23.1 21.7

9.6 14.7

27.5

16.5

22.1

0

10

20

30

40

50

60

70

80

90

100

CSI PBI

$260/MWh:

5 yrs

CSI PBI

$370/MWh:

5 yrs

CSI PBI

$370/MWh:

5 yrs

Xcel

$200,000,

SREC

$235/MWh:

20 yrs

Xcel

$200,000,

SREC

$235/MWh:

20 yrs

Xcel

$200,000,

SREC

$235/MWh:

20 yrs

CORE

$2/W,

SREC

$220/MWh:

10 yrs

PSE&G

Loan

$475/MWh:

15 yrs

SREC Cap

$654/MWh:

8 yrs

CORE

$2.30/W,

SREC

$220/MWh:

10 yrs

PSE&G

Loan

$475/MWh:

15 yrs

SREC Cap

$654/MWh:

8 yrs

Nominal LCOEG (¢/kWh)

Final LCOEG SRECs PBI State Rebates MACRS 30% ITC

60% 

Debt

60% 

Debt

0% 

Debt

0% 

Debt

Cash Cash

Cash (No Debt) PPA PPA

PPA

San Diego, CA

With sales tax: $6.87/W

Without sales tax: $6.67/W

Denver, CO

All systems: $7.01/W

Atlantic City, NJ

All systems: $6.94/W
57

except that the utility’s rate of return is regulated by the state’s public utility commission. Taxequity investors can take advantage of the 30% ITC and 5-year MACRS. The baseline LCOEG 

for these two cases assumes that the developers depreciate equipment using a 20-year straightline depreciation schedule. The difference between the LCOEG for the third-party developer and 

the utility investor is based solely on the rate of return that the investors receive. 

Assuming an 8% IRR for a third-party developer, LCOEG after absorbing the federal tax 

incentives is $0.43/kWh. At the utility’s regulated rate of return of 11% (an approximate 

assumption for a U.S. utility), LCOEG after federal tax incentives is more than $0.10 more at 

$0.54/kWh. The two tax-investor cases also are compared to a self-financed system in Figure 11. 

Interestingly, the tax benefits of solar result in a reduced LCOEG with an 8% rate of return. At 

the utility’s 11% IRR, the LCOEG is about the same as the self-financed model, even after the 

federal tax benefits are absorbed. 

Figure 11. LCOEG after federal tax incentives for a 500 kW system in Colorado

6.3.2 LCOEG of a 100-kW System

Next is a consideration of a 100-kW roof-mounted PV system installed in San Diego, Denver, or 

Atlantic City. Smaller systems cost more per watt to install because the larger installations can 

achieve economies of scale. To make up for this, states and utilities usually provide smaller 

systems with greater incentives than those for large PV projects. The LCOEG of a 100-kW 

system, however, is considerably more than for a 500-kW, even with the incentives and SREC 

payments. Regardless, the incentives analyzed in this study are quite valuable for small PV 

projects overall. The levelized cost of electricity generation of all the incentive programs 

modeled for a 100-kW PV system is shown in Table 11. 

42.9 53.7 53.1

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

Tax Investor

(8% IRR)

Utility

Investor

(11% IRR)

Federal

Agency (No

Debt)

Nominal LPOE (¢/kWh)

30% ITC

MACRS

Remaining LCOE

(no cash

incentives or

SRECs)
58

Table 11. LCOEG Comparison of Financing Structures and Average Retail Rate 

100 kW 

PV 

system

Incentives and SRECs 

available

SREC/ 

PBI 

contract 

(years)

Nominal LCOEG

Commercial 

average retail 

rate (¢/kWh)

Thirdparty 

owned/ 

PPA 

(¢/kWh)

Selffinanced 

with cash 

(no debt) 

(¢/kWh)

Net benefit 

of third-party 

PPA over 

cash (¢/kWh 

and %)

Aug08

Year-todate 

thru 

Oct-08

CA

CSI PBI contract for 

$260/MWh (commercial 

ownership)

5 40.2 

1.3 (3%) 15.2 13.1 CSI PBI contract for 

$370/MWh (federal 

agencies)

5 41.5

CO

Xcel $2/watt and an 

SREC contract for 

$115/MWh for 20 years

20 25.3 35.6 10.3 (41%) 9.6 8.7

NJ

CORE (now closed) 

($2.25/W private sector, 

$2.50/W public sector), 

SREC contract for 

$220/MWh

10 33.2 41.4 8.2 (25%)

PSE&G loan floor: 16.5 14.9

$475/MWh for entire 

contract

15 23.8 32.6 8.8 (37%)

SREC trading assumed 

at $654/MWh (avg SREC 

cap)

8 28.9 38.1 9.2 (32%)

Source for commercial average retail electricity rates: EIA 2008 Electric Power Monthly with data for October 2008. 

6.3.2.1 Benefit of Third-Party Ownership/PPA Financing

As noted, for a 100-kW system the third-party ownership model results in a reduced price of 

energy (Table 11).48

For a 100-kW system, LCOEG can be as much as four times the average commercial retail 

electricity rate. Table 11 shows these comparisons between retail utility rates and project 

LCOEG. It appears that developing projects in New Jersey under the third-party ownership 

model is the most advantageous. 

 In Colorado and New Jersey—where each state’s incentives and SREC

revenues are close to identical for the public and private sectors—the third-party ownership 

model has a net benefit of approximately $ 0.08 to $ 0.10/kWh over the self-financed model. In 

California, where private-sector developers receive $260/MWh and public-sector developers 

receive $370/MWh, the net benefit of the third-party ownership model is only $ 0.01/kWh. 

Again, the shorter period in California is part of the reason for a lower overall benefit.

 

48 There is some question as to whether an installer would be interested in using the third-party ownership model for 

a system that is only 100 kW in size. This example therefore might be relevant only for agencies willing to install 

several 100-kW systems—perhaps on several buildings on a campus or located relatively near to each other. This 

analysis did not attempt to quantify the minimum size of a PV project that would be required for developers to 

consider using the third-party financing model.
59

6.3.2.2 The Importance of Federal Tax Incentives

As with 500-kW systems, the tax benefit of PV captured by third-party developers is quite 

valuable for smaller systems. The federal ITC and MACRS tax incentives combine to reduce 

LCOEG by 38% compared to 100-kW projects developed with 20-year straight-line depreciation 

alone. Results are shown in Table 12. 

6.3.2.3 The Importance of Cash Incentives

After federal tax credits were incorporated, cash incentives were explored. As shown in Table 

12, these were layered upon the federal tax incentive benefits for the third-party ownership 

model. Up-front incentives or rebates can reduce the price for a small project significantly. 

Colorado’s $2.00/W incentive (or $200,000) reduces a 100-kW system’s LCOEG by $0.16/kWh, 

compared to the price with only federal tax credits for the third-party owned system. For selffinanced systems the LCOEG is reduced by $0.15/kWh. For systems larger than 100-kW, the upfront incentive is capped at $200,000—so the larger the project, the lower the resulting dollarper-watt incentive. Comparing the two projects, the 100-kW rebate reduced LCOEG by 

$0.15/kW to $0.16/kWh, but the same monetary award to a 500-kW system only reduced 

LCOEG by $0.03/kWh (for both third-party owned and self-financed).

New Jersey’s CORE rebate ($2.25/W for the private sector and $2.50/W for the public sector) 

brings down LCOEG by $0.21/kWh. Again, this is for both the self-financed systems as well as 

third-party owned systems (which already incorporated federal tax credits). 

California awards 100-kW systems the same performance-based incentives that 500-kW systems 

receive. Thus, the reduction of LCOEG in terms of cents per kilowatt-hour is the same—

$0.11/kWh for third-party owned systems with federal tax incentives and $0.16/kWh for selffinanced systems. The performance-based incentive, however, is less valuable on a percentage 

basis for 100-kW systems.

6.3.2.4 The Importance of SREC Revenues

Lastly, the SREC value was layered upon the federal tax credits and any available cash 

incentives. The SREC revenues were assumed to be equally valuable for 100-kW systems as for 

500-kW systems. The only difference is in Colorado, where Xcel has established a 

predetermined SREC price for systems of up to 100 kW ($115/MWh). Larger projects bid into a 

utility procurement process, which means that the SREC price could be greater or less than for 

systems up to 100 kW. In this analysis, the $115/MWh for 100-kW systems is less than the 

assumed $235/MWh contract for the 500-kW system.

6.3.2.5 Comparison of LCOEG With and Without Incentives and SREC Revenue

The inclusion of all available federal tax credits, cash incentives and SREC revenues 

dramatically reduces the overall cost of 100-kW PV systems. Compared to the up-front cost 

without them, all available incentives and revenues reduce project LCOEG for 100-kW systems 

by between 52% and 79% under the third-party ownership model, and by between 27% and 59% 

for the self-financed model. On a percentage basis, this is less than the benefit of incentives and 

revenues for larger systems, due to the economies of scale reached by larger systems.

Under the third-party ownership model, available incentives and revenues reduce LCOEG by 

52% in California, by 71% in Colorado, by 71% for the New Jersey CORE program, by 79% for 
60

the PSE&G Solar Loan, and by 75% for New Jersey’s SREC-cap program. When PV systems 

are self-financed, the cash incentives combined with SREC revenues reduce LCOEG by 27% in 

California, by 44% in Colorado, by 48% for the New Jersey CORE program, by 59% for the 

PSE&G Solar Loan, and by 52% for New Jersey’s SREC-cap program. Values of nominal 

LCOEG and the percentage decreases from baseline LCOEG are laid out in Table 12. 

Table 12. Comparison of LCOEG With and Without Incentives for a 100 kW System

100 kW PV system Nominal LCOEG (¢/kWh) (% decrease from Baseline LCOEG)

State Incentives available

Without 

incentives

With federal 

tax incentives

With state 

incentives

With state 

incentives and 

SREC revenues

Third-party owned with a PPA

CA CSI PBI contract for $260/MWh for 5 

years

84.1 51.5 (38%) 40.2 (52%) 

CO Xcel $2/watt and an SREC contract 

for $115/MWh for 20 years 87.6 54.4 (38%) 38.6 (56%) 25.3 (71%)

NJ

CORE (now closed) $2.25/W, SREC 

contract for $220/MWh for 10 years 114 70.4 (38%) 49.7 (56%) 33.2 (71%)

PSE&G loan floor: $475/MWh for 15 

years

114 70.4 (38%) 23.8 (79%)

SREC trading assumed at $654/MWh 

for 8 years (avg SREC cap) 114 70.4 (38%) 28.9 (75%)

Self-financed with cash (no debt)

CA CSI PBI contract for $370/MWh for 5 

years

57.3 41.5 (27%) 

CO Xcel $2/watt and an SREC contract 

for $115/MWh for 20 years 63.5 48.8 (23%) 35.6 (44%)

NJ

CORE (now closed) $2.50/W, SREC 

contract for $220/MWh for 10 years 79.1 57.8 (27%) 41.4 (48%)

PSE&G loan floor: $475/MWh for 15 

years

79.1 79.1 (0%) 32.6 (59%)

SREC trading assumed at $654/MWh 

for 8 years (avg SREC cap) 79.1 79.1 (0%) 38.1 (52%)

6.3.2.6 Final 100-kW PV Analysis Results

Figure 10 simultaneously shows the differences in LCOEG between financing structures; the 

relative value of each component’s ability to reduce the LCOEG; and the geographic differences 

of financing PV. In general, the overall pattern of results identified for the 500-kW PV system 

appears to hold for the smaller 100-kW system.

The third-party investor’s ability to capture federal tax incentives results in a lower LCOEG than 

that of the cash-financed models (Table 12, Figure 10). Federal tax credits, cash incentives, and 

SREC revenues are critical to reducing the high up-front cost of solar PV. The PSE&G Solar 

Loan program in New Jersey resulted in the lowest LCOEG, because it sets a floor SREC price

over 15 years—a long period. In contrast, the 5-year California PBI provides an important 

benefit, but appears to be less effective than the SREC prices in Colorado or New Jersey.

When the self-financed structures are compared to each other the benefits of cash incentives and 

SREC revenues become clear for federal agencies. Colorado has the lowest LCOEG due to the 

substantial SREC prices offered for a period of 20 years. Again, the short 5-year timeframe in 
61

California’s structure appears to have less impact than the longer-term SREC prices used in New 

Jersey and Colorado. 

Figure 12. The LCOEG of 100 kW projects for federal agencies using different financial structures 

and incentives

Figure 12 shows the LCOEG of 100-kW projects under different financial structures and 

incentives. Installed costs under the PPA and loan models are not different—except in 

California, because the estimates for installed cost include sales tax, and federal agencies do not 

have to pay sales tax. The name of each case designates who provides the incentives, the level of 

any up-front incentives (in $/W), any SREC payments or PBI payments (in $/MWh), and the 

number of years of REC contracts or PBI payments. The NJ SREC Cap incentive uses the 

average SACP price ($654/MWh) over the course of 8 years. 

6.4 Federal PV System Analysis Conclusions

This analysis explores the role that financial incentives and investment models play in determining the levelized cost of a PV system for a federal agency. Overall, the financial incentives 

offered in New Jersey result in the lowest LCOEG, followed by Colorado and then California. 

There are three main reasons why this generic analysis resulted in higher LCOEG for California. 

First, the PBI incentives are only available for a period of 5 years. The longer 8- to 20-year time 

horizons in New Jersey and Colorado enable the project price to be levelized over a longer 

period, and thus reduced. Second, California has established aggressive incentive reductions. At 

40.2 37.7 41.5

25.3

32.4 35.6 33.2

23.8 28.9

41.4

32.6 38.1

0

20

40

60

80

100

120

CSI PBI

$260/MWh:

5 yrs

CSI PBI

$370/MWh:

5 yrs

CSI PBI

$370/MWh:

5 yrs

Xcel $2/W,

SREC

$115/MWh:

20 yrs

Xcel $2/W,

SREC

$115/MWh:

20 yrs

Xcel $2/W,

SREC

$115/MWh:

20 yrs

CORE

$2.25/W,

SREC

$220/MWh:

10 yrs

PSE&G

Loan

$475/MWh:

15 yrs

SREC Cap

$654/MWh:

8 yrs

CORE

$2.50/W,

SREC

$220/MWh:

10 yrs

PSE&G

Loan

$475/MWh:

15 yrs

SREC Cap

$654/MWh:

8 yrs

Nominal LCOEG (¢/kWh)

Final LCOEG SREC Revenue PBI Upfront Grant MACRS 30% ITC

60% 

Debt

60% 

Debt

0% 

Debt

0% 

Debt

Cash Cash

Cash (No Debt) PPA PPA

PPA

San Diego, CA

With sales tax: $7.93/W

Without sales tax: $7.60/W

Denver, CO

All systems: $8.04/W

Atlantic City, NJ

All systems: $8.65/W
62

points when a predetermined amount of installed capacity has signed up for the PBI, the incentive payment level is lessened. Currently, California is ahead of schedule in stepping down its 

PBI payments. Finally, California does not allow for RECs to be traded separately from 

renewable power generation; they must remain bundled. The value of the SREC revenue stream 

in Colorado and New Jersey appear to be quite valuable, however, mainly because both states 

have a solar set-aside in their RPS policies. It is apparent that contract length and whether the 

price is negotiated, fixed, or based on the market price are expected to have a significant impact 

on LCOEG.

Overall, it appears that the third-party ownership/PPA model is cheaper than either the cash or 

loan models because of all the tax incentives that can be captured by a third-party developer. The 

benefit of the PPA model over the cash model is more definite in Colorado and New Jersey than 

it is in California. Most noticeably, the two current New Jersey incentives (PSE&G Solar Loan 

and SREC-cap program) resulted in the largest net benefits for a 500-kW system. Although the 

analysis presented here can give a rough estimate of relative values of incentives and financing 

structures, it is important for project developers and federal agencies to do their own LCOEG 

calculations to ensure the capturing all of the site-specific characteristics of a project, as well as 

currently available incentives.
63

7 Conclusions

The options for financing PV projects on federal buildings and land have expanded in recent 

years. Several market forces have converged to make the economics of PV projects attractive to 

federal agencies—including substantial decreases in the cost of PV, increased federal tax credits, 

and increased state incentives. Together these factors have driven an increased amount of capital 

towards development of new PV projects, especially in the federal sector. Federal agencies also 

have an increased interest in deploying on-site renewable generation to meet various federal 

goals and mandates. The combination of increased demand and increased supply has resulted in 

substantial innovation in the options for financing PV projects on federal property. As explored 

in this report, each method has its own advantages and challenges. 

The federal government has established a number of goals and mandates that both encourage and 

require reductions in energy intensity and a greater use of renewable electricity. Most federal 

agencies therefore are evaluating strategies for deploying PV on public property. Payback 

periods are longer than most public entities consider reasonable, so state incentive programs and 

RPS policies have proven critical in supporting additional PV deployment. Appropriate policies 

and adequate financial incentives can motivate federal agencies to consider implementing PV on 

their sites. One goal of this report is to gauge the progress of federal sector PV deployment 

throughout the country, determine what policies and programs are working, and identify barriers 

to deployment. Several examples are presented that highlight the success of federal PV 

deployment, and which explain how these projects utilize a number of incentives, revenue 

streams, and financial incentives. It is hoped that other federal agencies can learn from the 

examples and successfully deploy their own projects. 

A significant source of funding for PV on public and private buildings comes from state 

incentives and policies. In most states, a federal PV installation sized to meet the average load 

on-site can receive credit on its utility bill for excess generation sent to the grid, through net 

metering. Other cash incentives—many of which are funded by SBC programs—are enacted on 

a state-by-state or utility-specific basis, and federal agencies often are eligible for up-front 

rebates or production-based incentives to reduce the cost of PV systems. Much of the success of 

the PV financing structures depends directly on the availability of state and federal cash and tax 

incentives (described in Section 5). Unless a PV system is paid for in cash (through a line-item 

appropriation or that year’s energy conservation project budget), these incentives can be critical 

components to making the economics of a PV project work. It therefore could be challenging to 

deploy PV in states without these incentives and still achieve the necessary payback. As shown 

for California, these incentives can be critical to making the payback period acceptable for 

federal projects.

The use of RECs has 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 

having specific RPS set-asides for solar (which does not include California). In Colorado, Xcel 

Energy purchases SRECs from the owners of qualified PV systems, in addition to providing an 

up-front cash rebate. Now that New Jersey has phased out up-front rebates for all but residential 

customers, developers must depend solely on SREC sales to utilities to finance any projects. The 
64

elimination of the up-front solar rebate could create additional financing hurdles for new PV 

projects, particularly for small projects.

Energy-efficiency measures can be a critical component when considering PV deployment. In 

addition to supporting mandated reductions in energy intensity under EISA 2007, energy 

efficiency can reduce the overall payback period of PV when both elements are bundled 

together. Additionally, if less electricity is used on-site, then deployment of PV can provide a 

much greater percentage of the site’s electricity.

In states that provide significant support for PV, federal entities recently have been able to use 

the third-party ownership/PPA structure to monetize federal (and sometimes state) tax credits. 

Given their non-taxpayer status, government agencies traditionally are unable to benefit from the 

generous federal tax incentives for PV such as the ITC and accelerated depreciation. Under a 

third-party ownership/PPA structure, however, 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/PPA model offers great promise to 

those federal agencies looking to install a significant number of PV systems in the most costefficient manner, especially because it can be used in conjunction with performance contracting. 

Third-party ownership is not necessarily the solution for all public entities, especially because it 

requires the ability to sign long-term contracts (up to 20 years in duration). However, proposed 

laws could extend all federal procurement up to at least 20 years, if not 30. This financial model 

is also not the right solution for federal agencies that want to reduce annual electricity bills by 

taking immediate ownership of the PV system, or for those agencies which are reluctant to give 

third parties access to their facilities.

One unique innovation with the third-party ownership/PPA financing structure was developed by 

WAPA in partnership with NREL. For federal agencies operating within WAPA’s footprint 

(slightly larger than its service territory) and which are limited to signing procurement contracts 

of 10 years, WAPA is willing to act as a contractual intermediary with the PV project developer 

and sign a PPA for 20 years. This critical role enables federal agencies to deploy PV on-site, 

when they otherwise might not have been able to do so. Potentially, other power marketing 

administrations or the Defense Energy Support Center also could play this intermediary role for 

federal agencies.

The ESPCs and UESCs used by federal agencies have helped save significant energy through 

improved efficiency and conservation. Super ESPCs are particularly attractive; by establishing 

the general parameters of any contract agreement and prequalifying a select number of capable 

ESCOs, the DOE has made it considerably easier for any federal agency to access ESPCs 

quickly. Recently, these programs also have included deployment of on-site renewables, 

typically through a subcontractor to the ESCO. As the third-party ownership/PPA model 

becomes more common in the marketplace it is being used in conjunction with ESPCs, under an 

ESA, to take advantage of the best elements of each structure (e.g., no capital outlay for the 

federal agency, a predetermined electricity price, better PV financing terms and payback).
65

Overall, there are a number of opportunities for federal agencies to deploy and finance PV 

systems. With the right combination of incentives, revenues, and financing structures, the federal 

government is positioned to play a leading role in deploying renewable energy. Bringing together 

all the necessary elements and contracting authorities is a complex process, however, and 

requires both creativity and persistence. Despite the challenges, several federal agencies have 

shown that PV successfully can be deployed on federal property. 
66

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10, 2009. 

72. Colello, J. Pass-Through Program Manager, Oregon Department of Energy, Conservation 

Division. Personal communication. June 20, 2008. 

73. Oregon Department of Energy, Conservation Division. “Case Study: North Santiam School 

District: Homework pays off for North Santiam Schools.” http://egov.oregon.gov/ENERGY/ 

CONS/SB1149/Schools/docs/NorthSantiam.PDF. Accessed June 10, 2009. 

74. PowerLight Corporation. “Case Study: Marina Mail Processing Center, Marina del Rey, 

California.” No longer available on the web. 

75. Ibid. 

76. FEMP: Distributed Energy Resources Case Study. “Photovoltaic DER System Could Save 

USPS $25,000 per Year in Marina del Rey, California.” November 2002. 

http://www.nrel.gov/docs/fy03osti/31847.pdf. Accessed June 10, 2009. 

77. Ibid. 
72

78. Guice, J.; King, J. 2007. Solar Power Services: How PPAs are Changing the PV Value 

Chain. Greentech Media Inc.

79. Department of Energy. 2001. Greening Federal Facilities: An Energy, Environmental, and 

Economic Resource Guide for Federal Facility Managers and Designer. Second Edition. NREL 

Subcontract No. AAR-0-29469-01. DOE Prime Contract No. DE-AC36-99GO10337. Available 

online at: http://www.eere.energy.gov/femp/pdfs/29267-0.pdf. Accessed July 1, 2009.

80. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. 2009. 

“Fenestration.” Building Technologies. http://www1.eere.energy.gov/buildings/

commercial/fenestration.html#U-Factor. Accessed June 10, 2009. 

81. Kollins, K.; Cory, K.; Speer, B. Forthcoming 2009. Solar Photovoltaic Financing: 

Addressing Regulation of Third-Party PPA System Owners. National Renewable Energy 

Laboratory. Technical Report.

82. Western Area Power Administration. “Nellis AFB Credits Teamwork for Largest PV System 

in U.S.” Reliable Energy Solutions Bulletin; February 2008. http://www.wapa.gov/ES/pubs/esb/ 

2008/feb/feb081.htm. Accessed June 10, 2009.

83. Nellis Air Force Base. Press Release. Largest Photovoltaic System Begins Construction at 

Nellis Air Force Base. April 23, 2007. http://www.mmarenewableventures.com/news/docs/ 

MMARV%20Nellis%20Apr%2007%20final.pdf. Accessed June 10, 2009. 

84. Nellis Air Force Base. Nellis Activates Nations Largest PV Array, December 18, 2007. 

http://www.nellis.af.mil/news/story.asp?id=123079933. Accessed June 10, 2009. 

85. Western Area Power Administration. “Nellis AFB Credits Teamwork for Largest PV System 

in U.S.” Reliable Energy Solutions Bulletin. February 2008. http://www.wapa.gov/ES/pubs/

esb/2008/feb/feb081.htm. Accessed June 10, 2009. 

86. Lamonica, M. “Air Force Base in Nevada Goes Solar with 14-Megawatt Array,” CNET 

News. http://news.cnet.com/8301-11128_3-9829328-54.html. Accessed June 10, 2009. 

87. Ibid. 

88. Shah, C. National Renewable Energy Laboratory. Personal communication. July 2008.

89. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. On-Site 

Renewable Energy Projects with Innovative Project Financing. News release, August 28, 2007. 

http://www1.eere.energy.gov/femp/news/news_detail.html?news_id=11218. Accessed June 

10, 2009. 

90. Dahle, D. National Renewable Energy Laboratory. Personal communication. February 4, 

2009. 
73

91. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. On-Site 

Renewable Energy Projects with Innovative Project Financing. News release, August 28, 2007. 

http://www1.eere.energy.gov/femp/news/news_detail.html?news_id=11218. Accessed June 

10, 2009. 

92. Levi, M. Energy Program Manager, General Services Administration. Personal 

communication. August 21, 2008. 

93. U.S. Code, Title 10, Subtitle A, Part IV, Chapter 173, Subchapter II, Section 2922a, 

“Contracts for energy or fuel for military installations” subsection (b).

http://www4.law.cornell.edu/uscode/html/uscode10/usc_sec_10_00002922---a000-.html 

94. Lenardic, D. “Photovoltaic Systems—Technologies and Applications” (last updated Jan 16, 

2008). http://www.pvresources.com/en/top500pv.php . Accessed June 22, 2009. 

95. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. On-Site 

Renewable Energy Projects with Innovative Project Financing. News release, August 28, 2007. 

http://www1.eere.energy.gov/femp/news/news_detail.html?news_id=11218. Accessed June 

10, 2009. 

96. Reed, M. “Renewable Energy Generation on Federal Sites.” Western Area Power 

Administration presentation. RRFA webcast, January 17, 2008. 

97. Westby, R., Technology Manager, NREL Federal Energy Management Program. Personal 

communication. December 15, 2008. 

98. “Mesa Top Photovoltaic Array Fact Sheet.” http://www1.eere.energy.gov/femp/pdfs/ 

pfs_mesatoparray.pdf. Accessed June 10, 2009. 

99. NREL news release, October 30, 2007. “Department of Energy’s National Renewable 

Energy Lab to Dramatically Increase Use of Clean, Renewable Energy: New ‘Green Building,’ 

Biomass and Solar Facilities to Transform How NREL Uses Power.” 

http://www.nrel.gov/news/press/2007/534.html. Accessed June 10, 2009. 

100. Westby, R, National Renewable Energy Laboratory. Personal communication. December 

15, 2008. 

101. “Energy Independence and Security Act of 2007: A Summary of Major Provisions.” CRS 

Report for Congress, December 21, 2007. Order Code RL34294. 

http://energy.senate.gov/public/_files/RL342941.pdf. Accessed June 10, 2009. 

102. Ibid. 

103. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. 

“$2.0 Billion Investment and $5.8 Billion Energy Cost Savings.” Fact Sheet: Federal Energy 

Management Program: Super ESPC—Just the Facts. http://www1.eere.energy.gov/femp/ 

pdfs/espc_fact_sheet.pdf. Accessed June 10, 2009.
74

104. U.S. Department of Energy. Press Release. DOE Awards Sixteen Contracts for up to 

$80 Billion in Energy Efficiency, Renewable Energy, and Water Conservation Projects at 

Federal Facilities. December 18, 2008. http://www.energy.gov/news/6804.htm. Accessed June 

10, 2009. 

105. Anderson, R.; Sullivan, J. “Briefing Paper on Energy Services Companies,” World Energy 

Efficiency Association. No longer available on World Efficiency Association Web site. 

106. BP Solar. BP Solar: USMC 29 Palms California. http://www.bp.com/liveassets/

bp_internet/solar/bp_solar_usa/STAGING/local_assets/downloads_pdfs/29PalmsTag.pdf. 

Accessed June 10, 2009. 

107. California Solar Center. “Military Base Upgrades with 1.1 MW Solar Array [Twentynine 

Palms].” Solar E-Clips. http://www.californiasolarcenter.org/solareclips/2003.02/20030211-

5.html. Accessed June 10, 2009. 

108. Anderson, R.; Sullivan, J. “Briefing Paper on Energy Services Companies,” World Energy 

Efficiency Association. No longer available on WEAA Web site. 

109. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. “Federal 

Energy Management Program: Utility Energy Services Contracts.” 

http://www1.eere.energy.gov/ femp/financing/uescs.html. Accessed June 10, 2009.

110. Snook, J. “UESC: Utility Energy Service Contracts: Energy Conservation Services from 

Your Utility Company.” Presented at GovEnergy Training Workshop, August 6, New Orleans. 

http://www.govenergy.com/2007/pdfs/finance/Snook_Finance_track_S1.pdf. Accessed June 10, 

2009. 

111. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. 

“Agreement for Energy Conservation and Demand Side Management Services Agreement for 

Energy Conservation Between the United States of America and _________________ Utility 

Company.” http://www1.eere.energy.gov/femp/docs/civagree.doc. Accessed June 10, 2009. 

112. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. “Marine 

Corps Base Camp Pendleton Shares the Keys to Their Successful Energy Program.” August 31, 

2005. http://www1.eere.energy.gov/femp/news/news_detail.html?news_id=9358. Accessed June 

10, 2009. 

113. San Diego Gas and Electric Energy Efficiency Case Study 2008. “Local Military Facility 

Helps Protect the Planet.” 

http://sdge.com/business/esc/documents/energyshowcase/Pendlton.pdf. Accessed June 22, 2009. 

114. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. Federal 

Energy Management Program: You Have the Power. “Energy Projects—Harold Washington 

Social Security Center.” http://www1.eere.energy.gov/femp/services/yhtp/

energy_projects_detail.cfm/id=20. Accessed June 10, 2009. 
75

115. Shirley, L. Project Manager. Social Security Administration, Chicago Regional Office. 

Personal communication. November 2007. 

116. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. Federal 

Energy Management Program: You Have the Power. “Energy Projects—Harold Washington 

Social Security Center.” http://www1.eere.energy.gov/femp/services/yhtp/

energy_projects_detail.cfm/id=20. Accessed June 10, 2009. 

117. Shirley, L. Project Manager. Social Security Administration, Chicago Regional Office. 

Personal communication. November 2007. 

118. Ibid. 

119. Dahle, D. National Renewable Energy Laboratory, Federal Energy Management Program. 

Personal communication. October 2007. 

120. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. Program 

Overview: Federal Energy Management Program: Energy Savings Performance Contract.

“Congress and President Encourage Agencies to Use ESPCs.” http://www1.eere.energy.gov/

femp/pdfs/espc_toolkit.pdf. Accessed June 10, 2009. 

121. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. Fact 

Sheet: Federal Energy Management Program: Super ESPC—Just the Facts. “Federal ESPC 

Projects in 46 States.” http://www1.eere.energy.gov/femp/pdfs/espc_fact_sheet.pdf. 

Accessed June 10, 2009. “Super ESPC Awarded Delivery Orders Summary.” 

http://www1.eere.energy.gov/femp/pdfs/do_awardedcontracts.pdf. Accessed June 10, 2009.

122. U.S. Department of Energy. “Federal Energy Management Program: FEMP Focus—

March/April 2003”; “Navy Uses Super ESPC to Make Photovoltaic Energy Pay.” 

http://www1.eere.energy.gov/femp/pdfs/fempfocus_mar_apr_2003.pdf. Accessed June 22, 2009. 

123. Ibid. 

124. Ibid. 

125. Ibid. 

126. Ibid. 

127. U.S. Department of Energy. “Federal Energy Management Program: Department of 

Energy’s Energy Savings Performance Contracts Stretch Budgets at the Bureau of Indian 

Affairs”; “Overview”; “Project Summary.” 

http://www1.eere.energy.gov/femp/financing/superespcs_indianaff.html. Accessed July 1, 2008. 

128. Schoch, J. SunEdison, Public Sector Sales Manager. Personal communication. February 

2008; Schoch, J. & Dickey, M. SunEdison. Personal communication. July 2008. 
76

129. Blair, N.; Mehos, M.; Christensen, C. 2008. “Sensitivity of Concentrating Solar Power 

trough performance, cost, and financing with the Solar Advisor Model.” 

http://www.nrel.gov/csp/ pdfs/42852.pdf. Accessed June 10, 2009.

130. Osterwald,C.; Adelstein J.; del Cueto, J.; Kroposki, B.; Trudell, D.; Moriarty, T. 2006. 

Comparison of Degradation Rates of Individual Modules Held at Maximum Power. National 

Renewable Energy Laboratory. http://www.solarintegrated.com/fileadmin/dateiablage/

media/ScientificPapers/NREL_-_Comparison_of_Degradation_Rates_-_May_2006.pdf. 

Accessed June 10, 2009. 

131. Moore, L.; Post, H.; Hayden, H.; Canada, S.; Narang, D. 2007. “Photovoltaic Power Plant 

Experience at Arizona Public Service, a 5-Year Assessment.” Sandia National Laboratory, 2007. 

132. Chuang, J. 2008. “Role of Debt Financing,” Panel Discussion. Solar Power Project 

Development and Finance Tutorial. Infocast, San Francisco, California. July 10–11, 2008. 

133. California Public Utilities Commission. 2008. California Solar Initiative Handbook.

http://www.gosolarcalifornia.ca.gov/documents/CSI_HANDBOOK.PDF. Accessed June 10, 

2009. 

134. Available at http://www.njcleanenergy.com/renewable-energy/programs/solar-renewableenergy-certificates-srec/pricing/pricing. Accessed June 10, 2009. 

135. Ibid. 

136. Duke Energy. Press release. June 9, 2008. “Duke Energy Launches Plan to Own and 

Operate Solar Power Generation at up to 850 North Carolina Sites.” http://www.dukeenergy.com/news/releases/2008060901.asp. Accessed June 10, 2009. 

137. Guice, J., King, J. Solar Power Services: How PPAs are Changing the PV Value Chain. 

Greentech Media Inc. February 14, 2008. 

138. National Renewable Energy Laboratory. “PVWATTS: A Performance Calculator for GridConnected PV Systems.” http://www.nrel.gov/rredc/pvwatts. Accessed June 11, 2009. 

139. National Renewable Energy Laboratory. “Solar Advisor Model (SAM).” 

https://www.nrel.gov/analysis/sam/. Accessed June 11, 2009. 

140. Kandt, A. “Identifying Cost-Effective Renewable Energy Projects.” National Renewable 

Energy Laboratory Presentation to the National Defense Center for Energy and Environment. 

June 2008. 

141. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Federal 

Energy Management Program. “Federal Renewable Energy Screening Assistant.” 

http://analysis.nrel.gov/fresa/. Accessed June 11, 2009. 

142. DSIRE home page. http://www.dsireusa.org/. Accessed June 11, 2009. 
77

143. Natural Resources Canada. RETScreen home page. http://www.retscreen.net/ang/home.php. 

Accessed June 11, 2009. 

144. Bureau of Land Management. “BLM Initiates Environmental Analysis of Solar Energy 

Development.” Press release. May 8, 2008. http://www.blm.gov/wo/st/en/info/newsroom/

2008/may_08/NR_053008.html. Accessed June 11, 2009. 

145. National Renewable Energy Laboratory. “HOMER.” https://analysis.nrel.gov/homer/. 

Accessed June 11, 2009. 

146. National Renewable Energy Laboratory. “Energy Analysis: Market Analysis Models and 

Tools.” http://www.nrel.gov/analysis/analysis_tools_market.html. Accessed June 11, 2009. 

147. Sustainable Building Energy Council. “Energy-10, A Powerful Energy Simulation Tool for 

Buildings and Homes.” http://www.sbicouncil.org/ 

displaycommon.cfm?an=1&subarticlenbr=112. Accessed June 11, 2009. 

148. Walker, A. National Renewable Energy Laboratory, Personal communication. July 2008; 

Walker, A. “Renewable Energy Planning: Multiparametric Cost Optimization,” Presented at 

Solar 2008, American Solar Energy Society (ASES), San Diego, CA, May 3–8, 2008. 

http://www.nrel.gov/docs/fy08osti/42921.pdf. Accessed June 11, 2009. 

149. Ibid. 

150. Ibid. 

151. Walker, A. National Renewable Energy Laboratory. Personal communication. July 2008. 

152. “Executive Order 13123—Greening the Government Through Efficient Energy 

Management.” Federal Register. June 8, 1999. Available at http://www.ofee.gov/eo/ 

eo13123.pdf. Accessed June 11, 2009. 

153. Ibid. § 204. 

154. “2007 Buildings Energy Data Book,” Chapter 1.4: Federal Agency Progress Toward the 

Renewable Energy Goal. 

http://buildingsdatabook.eere.energy.gov/docs%5CDataBooks%5C2007_BEDB.pdf. Accessed 

May 16, 2008. 

155. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Federal 

Energy Management Program. “About the Program: Energy Policy Act of 2005.”No longer 

available on DOE Web site. 

156. “Energy Policy Act of 2005.” Public Law No. 109–58. Aug. 8, 2005. Section 203(b)(2). 

http://www.energy.wsu.edu/ftp-ep/pubs/library/EnergyPolicyAct-PublicLaw109-58.pdf. 

Accessed June 11, 2009. 
78

157. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Federal 

Energy Management Program. “2007 FEMP Renewable Energy Requirement Guidance for 

EPAct 2005 and EO 13423,” pg. 9. http://www1.eere.energy.gov/femp/pdfs/

epact05_fedrenewenergyguid.pdf. Accessed June 11, 2009. 

158. “Energy Policy Act of 2005,” Public Law 109–58. Aug. 8, 2005. Section 204. 

http://www.energy.wsu.edu/ftp-ep/pubs/library/EnergyPolicyAct-PublicLaw109-58.pdf. 

Accessed June 11, 2009. 

159. Ibid. 

160. “Executive Order 13423: Strengthening Federal Environmental, Energy, and Transportation 

Management.” Federal Register, January 26, 2007. http://www.ofee.gov/eo/EO_13423.pdf. 

Accessed June 11, 2009. 

161. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Federal 

Energy Management Program. “Laws and Regulations: Executive Order 13423.” 

http://www1.eere.energy.gov/femp/regulations/eo13423.html. Accessed June 20, 2008. 

162. Ibid. 

163. U.S. Environmental Protection Agency. “Greening EPA: Federal Requirements.” 

http://www.epa.gov/oaintrnt/energy/fedreq.htm. Accessed June 11, 2009. 

164. “Energy Independence and Security Act of 2007,” Section 431. Enacted December 2007. 

http://frwebgate.access.gpo.gov/cgibin/getdoc.cgi?dbname=110_cong_bills&docid=f:h6enr.txt.pdf. Accessed June 24, 2009. 

165. Ibid. 

166. “Energy Independence and Security Act (EISA) 2007: New and Enhanced FEMP 

Responsibilities.” Public Law No. 110-140 (H.R.6). March 2008. 

http://www1.eere.energy.gov/femp/pdfs/eisa_femp.pdf. Accessed June 11, 2009. 

167. Ibid. § 515. 

168. Energy Independence and Security Act 2007, Subtitle C—High Performance Federal 

Buildings, § 432, paragraph (10), subparagraph (B) Funding Options. 

http://frwebgate.access.gpo.gov/cgi-bin/ 

getdoc.cgi?dbname=110_cong_bills&docid=f:h6enr.txt.pdf. Accessed June 11, 2009. 

169. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Federal 

Energy Management Program. “Annual Report to Congress on Federal Government Energy 

Management and Conservation Programs, Fiscal Year 2005.” pg. 29. 

http://www1.eere.energy.gov/femp/pdfs/annrep05.pdf. Accessed June 11, 2009. 
79

170. U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Federal 

Energy Management Program. “2007 FEMP Renewable Energy Requirement Guidance for 

EPAct 2005 and EO 13423,” pg. 9. http://www1.eere.energy.gov/femp/pdfs/

epact05_fedrenewenergyguid.pdf. Accessed June 11, 2009. 

171. Remarks of President Barack Obama promoting the recovery plan with U.S. Department of 

Energy Secretary Steven Chu. February 2009. 

http://www.whitehouse.gov/blog_post/serious_about_energy_independence/. Accessed June 11, 

2009. 
80

Appendices 

Appendix A. Federal Sector PV Deployment

Table A-1. Select Examples of Federal Sector PV Deployment, by State and Project

State

Cash 

Incentives REC

Energy 

Efficiency PPA WCI

ESPC / 

SES

Super 

ESPC UESC

Tax 

Credits

California

USPS, Sacramento Processing & 

Dist. Center (§ 2.2.4) X X X

USPS, Marina Del Ray Processing & 

Dist. Center (§ 5.1.1) X X

GSA, Sacramento Federal Building 

(§ 5.2.2) X X X X

Marine Corps, Twenty-Nine Palms 

Compound (§ 6.5.1.1) X X 

Marine Corp, Camp Pendleton 

(§ 5.4.2.1) X X X

Navy, Coronado Base (§ 5.4.3.1) X X

Education, Sherman Indian High 

School (§ 5.4.3.2) X X

Colorado

GSA, Denver Federal Center 

(§ 3.3.3) X X X X

Army, Fort Carson Base (§ 5.3.1) X X X X

NREL, Mesa Top PV Project 

(§ 5.3.2) X X X X X X X

Illinois

Social Security Center, Harold 

Washington (§ 5.4.2.2) X X 

Massachusetts

GSA, Trapelo Road facility (§ 2.2.1) X X X

Nevada

Air Force, Nellis Base (§ 5.2.1) X X X 

New Jersey

GSA, Trenton Courthouse Annex 

(§ 2.2.2) X

New York

Army, New Windsor Base (§ 2.2.3) X 

National Park Service, Jamaica Bay 

Wildlife Refuge (§ 2.2.3) X

Oregon

EPA, Corvallis building (§ 2.2.4) X

Education, North Santiam School 

District (§ 4.4.4) X X

Note: This table provides an overview of the federal-sector PV project examples detailed in this document; it is not 

comprehensive of all federal solar PV projects.
81

Appendix B. Federal-Sector Eligibility for Net Metering

Table B-1. Federal-Sector Eligibility for Net Metering, by State

State kW Size/Limit

Net Excess Generation 

Compensation Credit Method

Interconnection 

Standards

Statewide 

Capacity Limits

Liability 

Insurance

AZ APS: 100 kW 

Credited to customer’s next bill at 

utility’s retail rate; granted to utility 

at end of calendar year

No 15 MW N/A

AR Residential: 25 kW; 

Commercial: 300 kW

Credited to customer’s next bill at 

the retail rate; granted to utility at 

end of 12-month billing cycle

Yes None Not specified

CT 2 MW Yes None stated Yes

DE

Residential: 25 kW; 

Non-residential 

(DP&L): 2 MW; Nonresidential (DEC) 

and municipal 

utilities: 500 kW

Credited to customer’s next bill at 

retail rate; at end of 12-month 

period any remaining NEG is 

granted at the utility’s avoided-cost 

rate to Delaware’s Green Energy 

Fund

Yes

1% (utilities could 

allow a higher limit 

or no limit)

Yes (DEC): at 

least $1 million in 

liability ins. and 

$1 million in 

property-loss ins.

FL 2 MW

Credited to customer’s next bill at 

retail rate; purchased by utility at 

avoided-cost rate at end of 12-

month billing cycle

Yes None stated Yes: 10 kW–

2 MW 

HI

HECO, MECO and 

HELCO: 100 kW; 

KIUC: 50 kW

Credited to customer’s next bill; 

granted to utility at end of 12-month 

billing cycle

Yes

1.0% of each 

utility’s peak 

demand

Yes (subject to 

change)

ID

Avista : 25 kW

Idaho Power: 25 kW 

– 100 kW (large 

cust.) 

Rocky Mountain 

Power:100 kW

Credited to customer’s next bill at 

utility’s retail rate for residential and 

small commercial customers; 

credited at 85% of utility’s avoidedcost rate for all other customers

No

0.1% of utility’s 

2002 peak demand 

(in Idaho)

Not specified

IL 40 kW

Credited to customer’s next bill at 

utility’s retail rate; granted to utility 

at end of 12-month billing cycle

Yes

1% of the total 

peak demand 

supplied by a utility 

the previous year 

for net-metered 

and dual-metered 

systems ≤ 2 MW

≤1 MW: No; 

>1 MW: Yes

KY 30 kW Credited to customer’s next bill (no 

expiration) Yes

1% of a utility’s 

hour peak load 

during the previous 

year

General liability 

coverage 

required

MD 2 MW

Credited to customer’s next bill at 

the retail rate; granted to utility at 

end of 12-month period with no 

compensation for the customer

Yes 1,500 MW Not specified

MA At capacity 2 MW Varies by system type and 

customer class Yes 1% of each utility’s peak load No

MI < 30 kW

Credited to customer’s next bill 

(rates vary by utility); granted to 

utility at end of 12-month billing 

cycle

Yes

0.1% of a utility’s 

peak load or 100 

kW (whichever is 

greater)

Varies by utility; 

could be in 

interconnection 

agreement

MO 100 kW

Credited to customer’s next bill at 

utility’s avoided-cost rate; granted 

to utility at end of 12-months

Yes

5% of a utility’s 

single-hour peak 

load (previous 

year)

≤ 10 kW: 

$100,000; 

>10 kW: $1 

million
82

State kW Size/Limit

Net Excess Generation 

Compensation Credit Method

Interconnection 

Standards

Statewide 

Capacity Limits

Liability 

Insurance

NE 25 kW

Credited to customer and carried 

over monthly at varying rates 

depending on season and 

technology, accumulated ENG 

credits paid to customer at end of 

calendar year

No

1% of peak annual 

demand of retail 

customers 

No

NC

Residential: 20 kW; 

Nonresidential:100 kW 

Credited to customer’s next bill at 

applicable time-of-use rate or less; 

granted to utility (annually) at 

beginning of each summer

Yes

0.2% of each 

utility’s North 

Carolina retail 

peak load for the 

previous year

No

OH

No specified limit 

(but must match 

some/all of customer 

load)

Credited at utility's unbundled 

generation rate to customer's next 

bill; customer may request refund 

of NEG credits accumulated over a 

12-month period

Three levels 

of interconnection 

standards

None specified

Utilities may not 

require additional 

liability insurance 

beyond proof of 

insurance.

OR

Residential: 25 kW, 

Non-residential (PGE 

and Pacific Corp): 

2 MW. Nonresidential 

munis/coops/utility 

districts: 25 kW

Varies by utility Yes

PGE and 

PacificCorp: no 

limit. Others: 0.5% 

of utilities’ historic 

single-hour peak 

load

No

PA 

Resid.: 50 kW; Nonresid.: 3 MW; 

Customers with 

microgrids or 

emergency systems: 

5 MW

Credited to customer’s next bill at 

retail rate; PUC to address 

treatment of NEG remaining at end 

of 12-month period

Yes No limit specified No

SC 

Duke Energy—

Residential: 20 kW; 

Non-residential: 

100 kW 

Credited to customer’s next bill at 

applicable time-of-use rate or less; 

granted to utility (annually) at 

beginning of each summer

Yes

0.2% of Duke’s SC 

peak demand for 

the previous year

No

SC 

Progress Energy—

Residential: 20 kW; 

Non-residential: 

100 kW

Credited to customer’s next bill at 

applicable time-of-use rate or less; 

granted to utility (annually) at 

beginning of each summer

Yes

0.2% of Progress 

Energy’s peak load 

for the previous 

year

No

UT

Residential: 25 kW; 

Non-residential: 

2 MW

Credited to customer’s next bill at 

utility’s retail rate; granted to utility 

after 12 months

Yes

0.1% of each 

utility’s peak 

demand in 2007

No

VT 

250 kW (farm 

systems and “group 

net metering” 

systems might be 

larger, but might not 

net meter)

Credited to customer’s next bill at 

utility’s retail rate; granted to utility 

at end of 12-month billing cycle

Yes

The greater of 2% 

of each utility’s 

1996 peak demand 

or peak demand of 

recent calendar 

year 

No

Source: Database of State Incentives for Renewable Energy
83

Appendix C. Critical Steps in Executing the Third-party 

Ownership/PPA Model

Figure 7 (Section 5.2) shows one variation of how a third-party ownership model can be used to 

help public entities own renewable projects—many others exist. To execute this model using a 

PPA or ESA for the power (or SREC), the steps listed below are recommended. These were 

adapted from a report by GreenTech Media [137] and from conversations with Bob Westby at 

NREL, who has been actively involved in the PPA negotiations for several NREL PV projects. 

Although the steps are presented in linear fashion, many are concurrent activities.

Step 1: Identify Potential Location(s)

Identify the buildings or land on which to install a PV system. In preparation for the next step, it 

is a good idea to characterize the site(s) being considered for development by gathering and 

providing detailed information. Characterizing the potential solar resource using PVWatts [138] 

or the Solar Advisor Model (SAM) [139] also is recommended; site hosts are required to enter 

longitude and latitude, the PV technology of interest, and the tilt and azimuth angles. It also can 

be useful to characterize other site-specific characteristics, including potential for shading (e.g., 

buildings, trees, other structures), distance to nearest substation, overall site load, and average 

electricity prices paid. 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, particularly as 

it relates to ground-mounted systems. Finally, address both safety and security issues with the 

appropriate internal parties to make sure these two areas do not present barriers later in the 

process.

Step 2: Select Developer Through Competitive Process

Federal agencies must comply with the Federal Regulation Acquisition (FAR) 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) after the number of potential vendors has been narrowed. If the site only can 

support a smaller system, then developers might not respond to a formal RFP and perhaps should 

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 could 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 federal agency and its own research, the 

developer conducts a high-level site assessment that includes electricity needs, solar generation 

potential, financial incentives, and engineering issues. This is an initial proposal to determine the 

feasibility of the project. Based on this assessment, the developer drafts a term sheet that 

includes the estimated output of a solar project, the price of electricity, and contract’s term. If a 

tentative agreement on the term sheet is made, then the project can move forward.
84

Step 4: Contract Development

The contracts are negotiated and signed. There are multiple contracts involved in the PPA 

process. A PPA agreement is made between the public entity and the PPA provider. There also 

could be a separate agreement between these same two parties, and related to the easement or 

lease which provides access to the property. The PPA provider and the utility also can sign a 

separate agreement for the solar RECs.

Step 5: Rebate Processing

If the state or utility offers incentives, then the application requesting them should be filed no 

later than at this point in the process. Note that in some states, there might be a limited window 

of time during which incentives are awarded to qualifying projects—for example, New York 

holds auctions. Depending on the state, in some cases the rebate could go to the host who must 

endorse it over to the PPA provider. The utility pays 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 issue building permits. It is 

useful to determine whether there is a backlog of permits and the date that the project must be in 

the queue for this step to be completed (aiming for approximately the same date the contract is 

signed). 

Step 8: Procurement, Construction, and Commissioning

The developer arranges 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 the utility will interconnect the system and allow 

system activation.

Step 9: Monitoring and Maintenance

The host must allow the developer and the owner to access the site for maintenance activities 

during the entire life of the project. The system is monitored through a combination of automatic, 

remote readings of power performance and other indicators, and also can include manual, on-site 

readings of performance indicators. If there an anomaly is detected, then the system is accessed 

on the host’s site for any needed repairs and equipment replacement. 

Important Federal PPA Provisions for Agreements Involving WAPA

In addition to the steps described for how to execute a third-party ownership/PPA, there are some 

specific contract provisions important for WAPA involvement as a contractual intermediary. 

Federal agencies should consider these provisions before issuing an RFP. Including such 

provisions on how to distribute the project’s risks in the RFP will help the agency secure the 

most promising and economical responses.

The information below mostly comes from a January 17, 2008, “webinar” presentation by 

Melanie Reed, RMR Contracts and Energy Services Manager at WAPA, titled “Renewable 
85

Energy Generation on Federal Sites.” It is supplemented with information from the discussion 

during the webinar. 

Term: 

• Generally, needs to be long-term to attract project financing

• The longer term also could provide a financial benefit to the government 

• Initial term of 20 years is standard, with renewal options 

Payment to vendor: 

• Federal agency pays the vendor directly for the power purchase 

• Eliminates WAPA as the middleman, thus reducing administrative costs

• Failure to perform

o Holds the vendor accountable for its obligations 

 Example: If the generator fails during the term of the contract

 Generally does NOT include paying a penalty for failure to build a system 

by a specific date; it is more acceptable to the developer to include 

milestones and track them regularly

 Can negotiate accountability if milestones are not met

o Hold the federal agency accountable for its obligations 

 Example: Payment (contingent on appropriations), site lease, etc. 

 Financiers do not like the appropriations contingency, but it is part of 

working with the federal government 

o Off-ramp provisions 

 The more off-ramps a federal agency has, the more likely the contract 

price will be higher (particularly if there are monetary penalties)

o Off-ramp examples

 Vendor is unable to obtain a site easement with the federal government 

 Vendor is unable to obtain an interconnection agreement with the local 

utility

 Vendor cannot secure REC buyer 

 Vendor cannot obtain financing 

o Important to describe situations in which the project would be unable move 

forward

Federal agency’s cost for the power: 

• Fixed kilowatt-hour rate over the term of the contract, or an escalating rate 

o Monthly bill from vendor 

• Early termination penalties

• Provisions that could transfer project ownership to the federal agency 

• Provisions that would increase cost during the life of the contract if market conditions 

change 

• Recommendation: Flesh-out the potential costs and risks and perform a cost/risk 

analysis 

Metering and communications: 

• Required by local utility, REC purchaser, and WAPA 

• Provisions vary depending on requirements 

• Minimum delivery requirements (specify them in the RFP, to be clear) 
86

Appendix D. Critical Steps Using WAPA as a Contractual 

Intermediary

Information in this section mostly is drawn from a January 17, 2008 “webinar” presentation by 

Melanie Reed, the RMR Contracts and Energy Services Manager at WAPA, titled “Renewable 

Energy Generation on Federal Sites.” It is supplemented with information from the discussion 

during the webinar. 

Generally, the requesting agency must manage the process. The WAPA is willing to review and 

provide input on requests for information (RFI) or requests for proposals, but it will not write the 

RFI/RFP and it will not select the winning vendor. WAPA does not have the resources to 

manage the vendor; it will be involved, but it will not manage the process. Also, WAPA prefers 

to allocate its resources to commit a little bit of time to each project over 6 months, for example, 

rather than being 100% committed to a single project for 2 months. 

Contracts Needed

Putting together contract templates can be difficult for a number of reasons, including capturing 

the unique requirements of each vendor and financier. Because there can be surprises along the 

way, it is important to be able to understand and articulate the federal agency’s requirements upfront, and to be as clear as possible in the RFI/RFP. For a typical federal project that uses WAPA 

as the contracting intermediary, the following contracts are needed: 

WAPA and federal agency

• Statement of interest (SI) to initiate the process

• Interagency agreement (IA) to purchase power (and RECs, if applicable) through WAPA 

on a pass-through cost basis; or 

• Support energy or supplemental energy provision of the federal agency’s firm electric 

service contract with WAPA

WAPA and vendor 

• Contract for WAPA to purchase the power for the federal agency (might or might not 

include RECs) 

Federal agency and vendor 

• Site lease or easement agreement

o Environmental assessment is required and the results should be in the 

lease/easement

o Could require involvement of other federal agencies if there is a separate manager 

(such as the Army Corps of Engineers, GSA, etc.—the more entities are involved, 

the longer process likely will take)

Federal agency and local utility

• Coordinate and receive approval for interconnection of the project from the local utility 

serving the federal agency 

o Usually can be done under existing contracts for firm electric service

o Is helped by net metering laws, where applicable

Vendor and REC purchaser, if applicable 

Vendor and financier
87

Note that neither WAPA nor the federal agency is involved in the last two scenarios, but the 

terms of these agreements will impact the PPA price, so these agreements are of interest.

Important Issues and Lessons Learned for Contracts Involving WAPA

Non-disclosure agreement (NDA) from vendor 

• WAPA and the federal agency could be asked to sign an NDA. To date, WAPA has not 

done so. 

Metering and communications 

• Coordinating, installing, and implementing metering and communication agreements 

have proven to be more complicated and difficult than expected. 

• In most cases, WAPA requires real-time data. Capturing this data takes coordination 

among the vendor, WAPA, and the local utility. 

Contract terms

• Include as many requirements as possible in the RFP before selecting a vendor.

• If requirements are not included in the RFP, be sure to discuss them as soon as possible 

upon selecting a vendor. 

WAPA Contact

Randy Manion, Renewable Resource Program Manager, Western Area Power Administration

(720) 962-7423, Manion@wapa.gov. 
88

Appendix E. Critical Steps for Assessing Federal 

Project Potential

The Federal Energy Management Program team at NREL has developed a methodology for 

assessing the project potential at federal sites, based on several years of technical assistance 

experience. This methodology is briefly outlined below to provide federal agencies with basic 

recommendations on how to screen for the most cost-effective renewable energy projects; a few 

agency examples are also explored. Additional information can be obtained by securing technical 

assistance from the NREL FEMP team, which works to support federal agencies in meeting 

renewable energy and energy efficiency goals and mandates.

Step 1: The Project Screening Process

Before deciding to deploy solar or other renewable technologies on-site, federal agencies should 

first assess which of sites presents the best opportunity and which renewable technologies are 

most appropriate. As on-site renewable energy technologies are evaluated, the sites(s) also 

should be evaluated for appropriate energy-efficiency measures that can reduce the project’s 

overall cost. 

NREL has developed a four-step process when evaluating whether to move forward with a 

renewable energy project at a federal site. At potential sites of interest, an agency should:

• Screen for highest potential renewable energy technologies and select the most promising 

locations; 

• Develop in-depth economic and engineering feasibility analyses for sites selected through 

screening (Step 1);

• Proceed with procurement of those projects that pass the feasibility test (Step 2); and

• Construct and implement the project.

Following this four-step process of evaluation, NREL also encourages that the sites be monitored 

to ensure that performance expectations are being met. Lastly, NREL recommends that these 

projects be publicized. Communicating the experiences gained through individual projects is a 

valuable tool in both promoting and educating other departments on renewable energy and 

energy-efficiency opportunities. 

The NREL FEMP team has helped numerous agencies and private entities consider and execute 

all of the steps listed above. Much of the assistance has come in the form of technical aid and 

recommendations for the screening phase of potential projects. Determining whether a federal 

facility is a potential candidate for renewable energy generation can be overwhelming for on-site 

personnel that lack expertise in this area. As a result, NREL has created a screening process to 

evaluate federal facilities for on-site renewable energy generation potential. The screening 

process is a structured approach that examines key factors to make an initial assessment. If this 

initial assessment is positive, then a more in-depth analysis is conducted before a decision is 

made to move forward with an on-site renewable project.

The cost-effectiveness for renewable energy at various sites is evaluated using the following 

three criteria: 
89

• Current energy rates

• Availability of financial incentives

• Renewable resource. 

Ideally, a proposed project would be supported by high regional energy rates, strong financial 

incentives, and a good renewable resource. Energy rates are evaluated differently depending on 

whether the proposed project would be on an existing site, a new site, or an off-grid site The 

agency also must consider its current cost of power versus future project costs, the cost to add 

new power (including the need to extend the grid), the cost of transporting fuel, and any 

environmental consequences or risks associated with potential fuel use or fuel spills. [140] Also 

important are the financial incentives available for many renewable energy technologies and 

which are accessible to federal agencies (described above). State, local, federal, and utility 

incentives are vital components to understanding the feasibility and opportunities of an 

individual project. Finally, the quality of renewable energy resources at each location under 

consideration must be analyzed during the screening assessment. Even if a project is in a location 

that does not have high electricity rates or great renewable resources, if the financial incentives 

are great enough, the renewable project still might be financially viable.

Step 2: Tools Available for Screening

Reviewing these three criteria is challenging, particularly when considering multiple renewable 

energy technologies for numerous sites. Federal agencies, however, have access to a variety of 

Web resources that can help with quick assessments during the screening phase. The following 

links are to Web sites that provide additional software tools that can aid agencies in developing a 

general overview of proposed projects at designated renewable energy sites. Note that this list is 

not comprehensive and does not include all screening tools available. 

Federal Renewable Energy Screening Assistant

The National Renewable Energy Laboratory developed the Federal Renewable Energy Screening 

Assistant (FRESA) as a basic renewable energy screening tool. At the building scale, FRESA 

can assess photovoltaics, solar hot water heating, and wind energy; at the facility scale, it can 

evaluate photovoltaics and wind energy. [141] This tool is currently in development, and a beta 

version can be accessed at http://apps2.eere.energy.gov/femp/fresa/. 

Renewable Energy Optimization Tool

To identify the combination of renewable energy measures that minimizes life-cycle cost at a 

site, NREL has been providing a service called Renewable Energy Optimization. An effort to 

produce a software tool is underway and, once complete, it will be available on the NREL 

Web site.

Database of State Incentives for Renewables and Efficiency (DSIRE)

DSIRE is a Web-based, searchable database of renewable energy and energy efficiency policies 

and financial incentives that are available at the state, local, utility, and federal level. [142] It can 

be searched to target those incentives for which federal agencies are specifically available, and 

can be found at http://www.dsireusa.org/. 
90

PVWatts

PVWatts was created through NREL’s Renewable Resource Data Center (RReDC). PVWatts 

was developed to aid non-experts in estimating the performance of grid-connected PV systems 

within the United States and its territories. [142] It is best used for standard PV technologies and 

not thin-film PV and can be found at http://www.nrel.gov/rredc/pvwatts. 

Renewable Resource Maps

NREL has a wide variety of renewable energy resource maps that can aid agencies in analyzing 

and determining where the greatest renewable energy resources exist. In addition to national 

maps that show an overview by technology, NREL constantly is refining detailed, technologyspecific maps by U.S. state that include significant county-level detail. Available maps are on the 

NREL Web site at http://www.nrel.gov/gis/maps.html. 

For high-cost technologies like solar, it is important to remember that areas with excellent 

resources might not have adequate incentives to support on-site development of renewable 

generation. Conversely, areas with poor resources might have incentives great enough to make 

the economics of renewable energy projects work. Each location must be evaluated separately to 

concurrently examine base electricity rates, incentives, and resources.

Renewable Energy Technology Screen (RETScreen)

RETScreen is an international, free software tool that can be used to “evaluate the energy 

production and savings, costs, emission reductions, financial viability and risk for various types 

of Renewable-energy and Energy-efficient Technologies (RETs).”[143] 

http://www.retscreen.net/. 

Step 3: Assessing the Information Gathered

In ideal situations, detailed information for each of the assessment criteria is obtained. The 

screening team, however, often must make do with much less information and therefore makes 

assumptions as necessary which will need to be validated if a project moves forward. The greater 

the detail provided, the more valuable the screening assessment.

Various projects should weight the significance of the three criteria differently. For instance, the 

cost-effectiveness of a PV project likely would be more dependent on financial incentives than 

on resource availability. The reason for this not only is that solar generally is more expensive 

than other renewable energy options, but also because it is an abundant resource throughout most 

of the country and is therefore less constrained geographically. 

Step 4: Additional Information Might Be Required

Lastly, additional information could be needed to comply with specific laws before a project can 

be sited. Examples include compliance with the National Environmental Policy Act (NEPA), 

discussed in more detail below. Other laws, like the National Historic Preservation Act (NHPA)

also might need to be addressed.

Under the NEPA, when federal agencies propose any “major federal action” a detailed 

environmental review of the action and its alternatives are required to determine the overall 

environmental, economic, and social impacts. Major federal actions can include the building of 

new buildings, major modifications to an existing building, or any significant construction 
91

occurring on federal land, such as a PV array. For a PV system, the level of detail of the review 

depends on the scale of the activity. An environmental assessment (EA) is prepared to determine 

whether a significant impact will occur and, if the answer is “no,” then a finding of no significant 

impact (FONSI) is prepared. If the answer is “yes,” or if a project is already suspected to have an 

impact, then the federal agency prepares more comprehensive environmental impact statement 

(EIS). During the process of developing an EIS, the public, other federal agencies, and interested 

stakeholders can provide comments. EPA carries out the operational duties associated with the 

administrative aspects of the EIS filing process. The Council on Environmental Quality (CEQ) 

requires all federal agencies to assess environmental impacts of major federal actions including 

all actions which are the subject of an EIS.

If a federal agency is preparing to perform the same federal action several times on one or more 

than one site, then the agency can prepare a programmatic EIS (PEIS). The PEIS examines the 

details of the environmental impact of the activity as it relates to all potential sites of the activity. 

This provides an umbrella mechanism for an activity that will be repeated on several sites. When 

a specific project moves forward, an EA can be prepared to examine the site-specific aspects of 

the project, and the bulk of the information needed be captured in the PEIS. Any site-specific 

concerns could require evaluation with a site-specific EIS for those specific aspects not covered 

in the PEIS.

Example: BLM Solar Programmatic EIS

The Bureau of Land Management and the Department of Energy have teamed together to initiate 

a joint PEIS for development of solar in six western states: Arizona, California, Colorado, 

Nevada, New Mexico, and Utah.[144] The joint PEIS will evaluate solar energy development on 

BLM lands in these six states and will examine alternative management strategies. The goal of 

the overall study is to identify how to mitigate potential impacts of developing solar energy 

projects. As specific projects are developed, a site-specific environmental analysis can be 

conducted to identify potential site-specific impacts and ways to mitigate them.

As work on the PEIS is performed, BLM concurrently will examine project-specific details of 

the solar projects that have already applied for rights-of-way for project development. To date, 

BLM has received more than 130 such applications for land covering almost 1 million acres and 

with the potential to generate 70 million kilowatts of electricity (enough to power 20 million 

average U.S. homes). The BLM expects to be able to complete the PEIS before being able to 

review the 130 land applications, at which point remaining projects can shift over to use the 

PEIS process for their development. Federal agencies can keep up to date on PEIS development 

at http://solareis.anl.gov. 

Once the PEIS is in place it establishes the process for future solar development. Any additional 

applications received as the PEIS is being developed are evaluated after the PEIS is in place. To 

promote additional solar development, the BLM can establish a competitive process to attract 

qualified companies to develop solar quickly and effectively. 

Step 5: Detailed Feasibility Studies

After applying the screening process described above, the result is a list of the most viable 

renewable energy projects available at a federal agency’s sites. The second step of this process 

involves a more detailed look at the economic and engineering feasibility of potential projects. 
92

As with the initial screening, there are many software tools that can aid with these analyses, a 

few of which are described below.

HOMER

The National Renewable Energy Laboratory developed HOMER, which is an optimization tool 

that accounts for economic and technical feasibility of both off-grid (remote and standalone) and 

grid-connected, distributed power systems.[145] The software is designed to help the user 

consider a great number of technology options, range of technology costs, and variability of 

energy resources, all of which typically can make distributed technology choices difficult. 

HOMER’s optimization and sensitivity analysis algorithms make it easier to evaluate the many 

possible system configurations. [146] The HOMER software is available for use at 

https://analysis.nrel.gov/homer/. 

Energy-10

Another in-depth software tool is the Sustainable Building Energy Council’s (SBIC) Energy-10. 

This simulation tool analyzes up to a dozen sustainable design strategies, including renewable 

energy technologies, for homes and buildings. [147] The tool is available at 

http://www.sbicouncil.org/displaycommon.cfm?an=1&subarticlenbr=112. 

In addition to these elaborate tools, an understanding of financing options (as discussed in this 

report) becomes vital to decisions that can make or break prospective projects.

Two Examples: Federal Project Assessments

NREL has conducted large-scale screenings of renewable energy project potential for several 

federal agencies. Two screening examples are provided below to further explain how to assess 

project potential. The examples include project assessments for the Smithsonian Institution 

National Zoological Park, and for 88 Job Corps Centers for the Department of Labor. 

Smithsonian Institution National Zoological Park—Two Locations

The National Renewable Energy Laboratory worked with the Smithsonian Institution National 

Zoological Park on an economic analysis to identify the best solution for becoming a net-zero 

facility, whereby 100% of the Zoo’s annual energy consumption is met with renewable sources. 

The project took into consideration the energy needs of both the National Zoo in Washington, 

DC, and the 4,600-acre Conservation Research Center in Front Royal, Virginia. NREL used an 

early version of the Renewable Energy Optimization tool to assess which combination of 

renewable energy technologies would produce the minimal life-cycle cost. [148] Although 

previous screening efforts have evaluated each renewable energy technology independently, this 

example highlights the ability to analyze the interactions among multiple technologies at a site.

As described, the process of optimizing available EE and RE technologies utilizes three main 

criteria: local resources, utility rates, and incentives. Such initial information usually is readily 

available, which reduces time and cost associated with detailed analyses. The results from the 

initial analysis provide an efficient starting point for more detailed assessments. Table E-1 presents 

the initial results of an analysis of renewable energy opportunities for the National Zoological 

Park’s primary facilities. As explained by Andy Walker, the NREL staff member that conducted 

the assessment, “results indicate that renewable energy measures could be integrated directly into 
93

buildings at both sites (PV, solar water heating, solar ventilation air preheating) but that central 

plant use of renewables (wind and biomass) would be needed to meet the zero energy goal.” [149]

Table E-1. Optimal Sizes of Each Technology in Zoo Example

National. 

Zoological Park, 

Washington, DC

Conservation. 

Research 

Center, VA Total

Photovoltaics Size (kW) 638 224 862

Wind Capacity (kW) 0 14,500 14,500

Solar Vent Preheat Area (ft2) 10,655 8,075 18,730

Solar Water Heating Area (ft2) 7,535 2,180 9,715

Biomass Gasifier Size (M Btu/h) 10,996 0.000 10,996

Biomass Cogeneration Size (kW) 1,168 0 1,168

Anaerobic Digester Size (ft3) 3,723 459 4,182

Anaerobic Digester Cogeneration Size (kW) 12 0 12

Daylight Aperture (Skylight) Area (ft2) 21,221 6,476 27,697

Source: Walker, A. “Renewable Energy Planning: Multiparametric Cost Optimization.” Presented at 

Solar 2008, American Solar Energy Society (ASES), San Diego, CA, May 3–8, 2008. 

http://www.nrel.gov/docs/fy08osti/42921.pdf. Accessed June 11, 2009.

This optimized portfolio of RE technologies resulted in a net cost of about $22 million more than 

the business-as-usual cost of purchasing electricity and natural gas from the utility. The life-cycle 

cost of deploying the portfolio of RE technologies is calculated by adding the total up-front 

capital cost to any annual costs (e.g., maintenance, fuel, payments to utility, production 

incentives, cash flows), and discounting them back to their present value. [150] Details of the 

cost analysis are shown below in Table E-2. Although the life-cycle costs of the RE portfolio—

even when fully optimized—were significantly more than the business-as-usual costs, several 

key factors were not evaluated quantitatively. These factors include potential benefits from 

emissions reductions, educational value, as well as the significance in achieving the net-zero 

goal. 
94

Table E-2. Life-Cycle Cost of Business-as-Usual Case as Compared to the Zero-Energy Zoo Case

Name

Business as 

Usual Life Cycle 

Cost ($)

RE Case Life 

Cycle Cost 

($)

Initial Cost $0 $45,858,421

Operations and Maintenance 

Cost $0 $13,135,266

Biomass Fuel Cost $0 $5,762,545

Gas Cost $17,323,188 $5,713,053

Electric Cost $34,914,085 $7,196,488

Production Incentives $0 -$2,887,806

Total $52,237,272 $74,777,968

Source: Walker, A. “Renewable Energy Planning: Multiparametric Cost 

Optimization.” Presented at Solar 2008, American Solar Energy Society 

(ASES), San Diego, CA, May 3–8, 2008. 

http://www.nrel.gov/docs/fy08osti/42921.pdf. Accessed June 10, 2009.

Job Corps Centers of the Department of Labor—88 Locations

At the request of the Department of Labor, NREL carried out a renewable energy screening for 

88 Job Corps Centers across the United States and Puerto Rico. [151] To conduct the screening, 

the different Centers provided site-specific information, including: 

• Longitude and latitude; 

• Number of users;

• Square footage of buildings; 

• Electricity and fuel usage; and 

• Electricity and fuel costs.

Using NREL GIS solar resource maps, NREL screened sites for the potential application of PV, 

solar hot water heating, and solar ventilation air preheating. For each site, NREL calculated the 

maximum resource potential per technology, a lifecycle savings-to-investment ratio (SIR) and a 

simple payback ratio. The most promising sites were then ranked according to their SIR ratios. 

The table below shows the four sites with an SIR of greater than 1 for potential PV projects. 

Table E-3. Cost-Effective Opportunities for Photovoltaics at Job Corps Centers

Center 

Name State

PV Annual Energy 

Delivery per kW of 

PV (kWh/year/kW)

PV Installed Cost per 

kW of PV with 

Incentives

PV Annual Energy 

Cost Savings per 

kW of PV ($/year)

Grid 

Connected 

PV SIR

Edison NJ 1,229 1,280 100 1.81

South Bronx NY 1,235 2,945 256 1.46

Los Angeles CA 1,517 2,600 178 1.13

San Diego CA 1,533 4,300 273 1.06

Photovoltaics were evaluated at 88 locations. The SIR ranged from 0.22 to 3. Table E-3 lists the 

best four sites. After NREL conducted these screenings it became the responsibility of the 

Department of Labor to determine how and whether it will act on the information provided. 
95

NREL can remain involved in the process to provide additional technical expertise or the agency 

could seek assistance elsewhere. If NREL is hired to remain involved, an interagency agreement 

will be executed.
96

Appendix F. History of Relevant Legislation and Executive Orders

Executive Order 13123 (superseded)

In 1999, President Clinton signed EO 13123, which asked agencies to reduce overall federal 

building CO2 emissions to 30% of 1990 levels by 2010. Section 202 set energy-efficiency goals 

for standard buildings to reduce their energy consumption per gross square foot 30% by 2005 

and 35% by 2010, relative to 1985. Similarly, Section 203 set efficiency goals for energyintensive facilities to reduce energy consumption per gross square foot by 20% by 2005 and 25% 

by 2010 relative to 1990 consumption. [152] Section 204 of this EO also created a federal goal 

whereby each agency would “strive to expand the use of renewable energy within its facilities 

and in its activities by implementing renewable energy projects and by purchasing electricity 

from renewable energy sources.” [153] In 2001, the U.S. Secretary of Energy issued guidance on 

the EO renewable energy goal that requested federal agencies obtain a minimum of 2.5% 

renewable electricity by 2005.[154]49

Energy Policy Act 2005

The bulk of federal agencies was able to achieve this goal, 

and in 2005 renewables accounted for nearly 7% of total federal electricity consumed. [155] As 

described in Section 1.3, this EO was superseded by EO 13423. 

Although EO 13123 resulted in renewable energy goals for the federal sector, the first piece of 

legislation that actually required renewable electricity was the Energy Policy Act 2005 (EPAct

2005). The mandate requires that the following percentages of renewable energy (compared to 

total electric energy consumed by the federal agency) must be met during each specific fiscal 

year: 3% in FY 2007–2009; 5% in FY 2010–2012; and 7.5% in FY 2013 and thereafter. [156] 

Note that these renewable requirements are incremental to any state or local renewable energy 

mandates, such as RPS mandates. The term “renewable energy” in EPAct 2005 includes “electric 

energy generated from solar, wind, biomass, landfill gas, ocean (including tidal, wave, current, 

and thermal), geothermal, municipal solid waste, or new hydroelectric generation capacity 

achieved from increased efficiency or additions of new capacity at an existing hydroelectric 

project.” [157] 

In addition to renewable energy use requirements, EPAct 2005 created incentives for renewable 

energy to be produced and used on federal grounds. A bonus within section 203(c) allows 

renewable electricity to count doubly towards compliance if it is: Produced and used on-site at a 

federal facility; produced on federal lands and used at a federal facility; produced on Native 

American land and used in a federal facility; or the on-site electricity produced by a federal 

agency is sold to a third party, but the power purchase contract states that the federal agency 

retains ownership of all related RECs and non-energy attributes. [158] The bonus is in place to 

encourage federal agencies to pursue energy projects sited on federal or Native American land, 

such as PV. It should be noted that the federal agency must either retain or replace the RECs to 

be eligible for the bonus. 

The EPAct 2005 also established mandatory energy reductions in federal buildings. It requires 

reductions in federal facility energy intensity by 2% per year beginning in FY 2006, up to a 

reduction of at least 20% by the end of FY 2015. Additionally, Section 204 granted the General 

 

49 This guidance fulfills the requirement for the U.S. Secretary of Energy to establish a federal renewable energy 

goal under section 503(b) of Executive Order 13123, and consistent with section 204.
97

Services Administration the authority to establish a “photovoltaic energy commercialization 

program for the procurement and installation of photovoltaic solar electric systems in new and 

existing public buildings.” [159] EPAct 2005 directs that the energy commercialization program 

be allocated $50 million annually for PV systems in fiscal years 2006–2010, and that the PV 

evaluation program be allocated $10 million annually during the same period. Both of these 

“sums shall remain available until expended.” [160] Even though these sums were authorized, 

Congress has not actually appropriated funds for this program, so the program remains 

unfulfilled. The GSA supports federal agencies in a number of ways, including centrally owning 

and maintaining federal buildings and equipment, so GSA could play a key role in federal PV 

deployment if funds were appropriated. 

Executive Order 13423

In January 2007, EO 13423 was signed by President George W. Bush, and completely revoked 

EO 13123 (among others). EO 13423, Section 2(b) established that (i) a federal agency should 

strive to have at least half of the statutorily required (by EPAct 2005) renewable energy 

consumed in a fiscal year come from new renewable sources, and (ii) to the extent feasible, the 

agency should try to implement renewable energy generation projects on agency property for 

agency use. [161] 

Executive Order 13423 superseded and updated aspects of EO 13123 and also has several 

differences from EPAct 2005. It includes a goal that at least 50% of renewables come from new 

generation resources, with new defined as projects in commercial operation on or after January 1, 

1999. This replaced the definition in the guidance document for EO 13123, of on-line on or after 

1990. Further, like the previous executive order, EO 13423 allows non-electric renewable 

energy, such as thermal, to count as a new renewable resource. Non-electric renewable energy, 

however, still cannot be used to meet the EPAct 2005 mandate. Additionally, EO 13423 set a 

goal for agencies to reduce GHG emissions through a reduction in energy intensity of 3% per 

year, or 30% by 2015, which is faster than the 2% per year and 20% overall reduction required 

by EPAct 2005. [162] This percentage is based on reductions in energy consumption per gross 

square feet, and uses fiscal year 2003 as the baseline, as opposed to a 2006 baseline in EPAct 

2005. [163] 

Energy Independence and Security Act of 2007

The Energy Independence and Security Act of 2007 (EISA 2007) was signed into law in 

December of 2007 and updated or increased several efficiency and renewable energy requirements for federal agencies. The Act effectively codified into law the EO 13423 goal of reducing 

energy intensity by 3% per year to ultimately achieve at least a 30% reduction by 2015. [164] 

Therefore, EISA 2007 replaces the EPAct 2005 mandate of 2% per year. As with the EO goal, 

EISA 2007 uses 2003 as the baseline year. The Act also requires federal energy managers to 

conduct a comprehensive energy evaluation for each facility at least once every 4 years. [165] 

EISA 2007 has additional provisions that could influence PV development. In Section 433 of the 

Act (“Federal Building Energy Efficiency Performance Standards”), the DOE is directed to 

revise federal building standards so that the fossil energy use of new buildings (compared to 

2003) be reduced as follows: [166] 

• 55% by 2010 

• 65% by 2015 
98

• 80% by 2020 

• 90% by 2025 

• 100% by 2030. 

EISA 2007 also redefines energy savings for ESPCs. Energy savings now also can include the 

sale or transfer of excess (above on-site use) electrical or thermal energy generated from 

renewable sources or cogeneration to utilities or non-federal users. [167] Further, EISA 2007 

clarified the ability of agencies to combine federally appropriated funds with private financing, 

including ESPCs and UESCs, to make projects work. [168] See Section 5.4 for a full description 

of ESPCs.
99

Appendix G. Energy Intensity Reductions and Renewable 

Energy’s Role

In addition to increasing the total amount of renewable energy use, the federal government also 

is targeting energy intensity reductions. This section clarifies the eligibility of renewable energy 

purchases and on-site renewable generation that can be counted towards these energy intensity 

reduction requirements—both now and in the future. 

Unbundled RECs, renewable energy purchases (energy and attributes together), and on-site

renewable energy generation all have contributed in helping the federal government achieve 

reductions in energy intensity. The ability to use renewable energy and REC purchases, however, 

as well as large on-site generation toward energy intensity goals (and perhaps mandates) will be 

eliminated gradually going forward. 

As mentioned in Section 1.3, EISA 2007 codified into law the EO 13423 requirement that 

federal agencies continue reducing the energy intensity of their buildings by 3% per year through 

FY 2015, to culminate in a 30% reduction based on levels from FY 2003. Energy intensity is the 

ratio of energy consumption (electric and non-electric uses) to total building square footage. 

Thanks to a number of efforts, the federal sector successfully has decreased its energy intensity 

since the late 1980s. From 1985 to 2005, the federal government invested $7.3 billion in energyefficiency measures. Of that, $4.2 billion came in the form of direct appropriations, and 

$3.1 billion through ESPCs and UESCs. [169] These substantial programs resulted in significant 

energy-efficiency savings across the federal government, including the DOD and DOE. Table 

G-1 shows recent energy intensity improvements. 

Table G-1. Federal Building Energy Intensity (Btu Energy Use per Gross Square Foot)

Agency

Gross Square 

Footage Energy Intensity (Btu / GSF)

2006 2003 2006 % Change

DOD 1,887,637 113,510 107,208 -5.6%

DOE 89,266 261,340 235,908 -9.7%

All Other 1,023,084 122,652 114,269 -6.8%

Total 2,999,987 121,264 113,446 -6.4%

Eligibility of most renewable projects to count toward energy intensity goals gradually is being 

phased out and will be eliminated by 2013. Currently, purchases of renewable energy and 

unbundled RECs,50

 

50 Renewable energy purchases include the purchase of RECs (or environmental attributes), or the purchase of RECs 

bundled together with electricity. It does not include electricity from a renewable generator, unless the associated 

attributes are attached.

as well as on-site renewable energy generation, can be credited toward 

energy intensity reduction targets set by Executive Order 13423. As shown in Table G-2, as the 

energy intensity reductions ramp-up, the ability to use REC purchases and large-scale metered 

renewable energy systems towards energy intensity calculations is reduced. Per the 2007 

Guidance for EPAct 2005 and EO 13423, the single exception is for “small on-site renewable 

generation projects that do not incur fuel costs, are un-metered, and are located on the customer 

side of a facility’s energy meter.” [170] Therefore, some federal agencies could choose behind-
100

the-meter PV as one way to help meet energy intensity mandates (in addition to energyefficiency activities).

Table G-2. Renewable Energy Purchase Contributions Toward Meeting

Energy Intensity Requirements

Fiscal 

Year

Energy 

Reduction 

Goal

Max Contribution of RE 

and REC Purchases 

Toward Energy Goal

Max Contribution of 

Long-Term Renewable 

Energy and REC 

Purchases toward Energy 

Goal

Energy 

Reduction 

Goal of New 

Buildings

2003 Base Year

RECs and purchases not 

applied in Base Year

RECs and purchases not 

applied in Base Year Base Year

2007 4% No Limit Not Applicable

2008 9% 5.4% 7.2%

2009 12% 4.8% 7.2%

2010 15% 3.0% 6.0% 55%

2011 18% 1.8% 3.6%

2012 21% 0.0% 0.0%

2013 24%

2014 27%

2015 30% 65%

2020 80%

2025 90%

2030 100%

* The combined total of both regular and long-term renewable purchases may not contribute more than 

the percentages shown in column 4 above. 

Source: U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Federal Energy 

Management Program. “Annual Report to Congress on Federal Government Energy Management and 

Conservation Programs, Fiscal Year 2005,” pg. 15. http://www1.eere.energy.gov/femp/pdfs/annrep05.pdf. 

Accessed June 11, 2009.

The success of the federal government in reducing the energy intensity of its buildings and 

facilities could create both opportunities and challenges for PV development. On the one hand, 

bundling together the costs of energy-efficiency measures with PV deployment has the potential 

of reducing the payback period for a PV system and therefore encouraging investment in PV. 

Conversely, if energy conservation measures (ECMs) have already been executed, the agency 

might have to look toward more expensive ECMs and there could be fewer “bundling” 

opportunities for PV projects. President Obama is further emphasizing energy efficiency with the 

announcement of plans to modernize 75% of federal buildings with energy-efficiency 

improvements with the goal of reducing the government’s total energy bill by a third. [171] 
101

Appendix H. Useful Reference Documents and 

Internet Resources 

BLM Solar Programmatic Environmental Impact Statement, http://solareis.anl.gov/index.cfm. 

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/. 

Executive Order 13423. “Instructions for Implementing Executive Order 13423.” 

http://ofee.gov/eo/eo13423_instructions.pdf. 

Federal Energy Management Program (FEMP) Financing Mechanisms, 

http://www1.eere.energy.gov/femp/financing/mechanisms.html. 

FEMP ESPC and Super ESPC Training, 

http://www1.eere.energy.gov/femp/financing/superespcs_training.html. 

FEMP free technical services (without the need for an interagency agreement), 

http://www1.eere.energy.gov/femp/pdfs/espc_toolkit.pdf. 

Federal Renewable Energy Guidance, 

http://www1.eere.energy.gov/femp/pdfs/epact05_fedrenewenergyguid.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/galleries/pdf/SEIA_manual_version_1.2.pdf. 

Accessed June 22, 2009. . 

U.S. Environmental Protection Agency. 2004. “Guide to Purchasing Green Power,” 

http://www.epa.gov/greenpower/documents/purchasing_guide_for_web.pdf. 

Wiser, R. and Bolinger, M. 2006. “Federal Tax Incentives for PV: Potential Implications for 

Program Design.” Lawrence Berkeley National Laboratory. 

http://repositories.cdlib.org/lbnl/LBNL-60193/. 
102

Appendix I. Useful Contacts

U.S. Department of Energy—Federal Energy Management Program

Renewable Energy

Anne Crawley

anne.crawley@ee.doe.gov 

(202) 586-1505 

Matt Gray

matthew.gray@ee.doe.gov 

(202) 586-0067 

Energy Savings Performance Contracts

Bill Raup

william.raup@ee.doe.gov 

(202) 586-2214 

Utility Energy Service Contracts

David McAndrew 

david.mcandrew@ee.doe.gov 

(202) 586-7722 

BLM Solar Programmatic Environmental Impact Statement

Lisa Jorgensen

Department of Energy 

Golden Field Office 

lisa.jorgensen@go.doe.gov

Phone: (303) 275-4906 

PEIS Information Center: http://solareis.anl.gov

National Renewable Energy Laboratory—Federal Energy Management Program

Federal Energy Management Program Team Lead

Karen Thomas 

karen.thomas@nrel.gov 

(202) 488-2223 

Project Financing

John Barnett 

john.barnett@nrel.gov 

(303) 384-7469 

Power Purchase Agreements

Chandra Shah 

Chandra.shah@nrel.gov 

(303) 384-7557 
103

Initial Federal Agency Site Screening

Andy Walker

andy.walker@nrel.gov 

(303) 384-7531 

Alicen Kandt

alicen.kandt@nrel.gov 

(303) 384-7518 

Energy-Savings Performance Contracts

NREL can provide unbiased technical support for your project with a U.S. Department of 

Energy–approved energy services company (ESCO). Under an Energy-Savings Performance 

Contract (ESPC), U.S. federal agencies can contract with ESCOs to acquire private-sector 

investment for the capital costs of installing energy- and water-conservation equipment and 

renewable energy systems.

An ESCO guarantees a fixed amount of energy cost savings throughout the life of the contract 

(up to 25 years) and is paid by the agency from energy cost savings after the savings begin. 

Federal agencies retain the remainder of the energy cost savings.

Doug Dahle 

douglas.dahle@nrel.gov 

(303) 384-7513 

John Barnett 

john.barnett@nrel.gov 

(303) 384-7469 

Utility Energy-Savings Contracts

The Energy Policy Act of 1992 authorizes and encourages U.S. federal agencies to participate in 

utility incentive programs. Services provided by a utility for a project can range from auditing to 

installation and commissioning, including financing the entire project under a UESC. Utilities 

could cover the capital costs of the project in consideration of the energy savings the retrofits 

will produce. The net cost to the federal agency remains minimal, and the agency saves time and 

resources by using the “one-stop shopping” provided by the utility. 

Karen Thomas 

karen.thomas@nrel.gov 

(202) 488-2223 

Western Area Power Marketing Administration

Randy Manion 

Renewable Resource Program Manager

Manion@wapa.gov 

(720) 962-7423 
104

Defense Energy Support Center

For military agencies interested in doing separate third-party ownership/PPAs, or ESAs under 

ESPCs, the Defense Energy Support Center is preparing to execute these types of contracts. For 

more information, please contact the people listed below. 

John Nelson 

john.nelson@dla.mil 

(703) 767-8523 

Andrea Kincaid

Andrea.Kincaid@dla.mil 

(703) 767-8669 

Nonprofit Organizations

CESA—Clean Energy States Alliance, http://www.cleanenergystates.org/

Mark Sinclair

msinclair@cleanegroup.org

Community Office for Resource Efficiency

http://www.aspencore.org/ 

Gary Goodson 

gary@aspencore.org 

The Vote Solar Initiative

http://www.votesolar.org/ 

Adam Browning 

abrowning@votesolar.org 
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Solar Photovoltaic Financing: Deployment by Federal Government 

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The goal of this report is to examine how federal agencies can finance on-site PV projects. It explains state-level 

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