Direct Federal Financial

Interventions and Subsidies

in Energy in Fiscal Year 2010

JULY 2011

www.eia.gov

U.S. Department of Energy

Washington, DC 20585
This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and analytical agency 

within the U.S. Department of Energy. By law, EIA’s data, analyses, and forecasts are independent of approval by 

any other officer or employee of the United States Government. The views in this report therefore should not be 

construed as representing those of the U.S. Department of Energy or other Federal agencies.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 i 

Contacts 

This report, Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010, was prepared under 

the general guidance of John Conti, Assistance Administrator for Energy Analysis, J. Alan Beamon at 202/586-2025 

(email, joseph.beamon@eia.gov), Director, Office of Electricity, Coal, Nuclear, and Renewables Analysis, and Jim 

Diefenderfer at 202/586-2432 (email, jim.diefenderfer@eia.gov).

Technical information concerning the content of the report may be obtained from Kevin Lillis at 202/586-3704 

(email, kevin.lillis@eia.gov), Executive Summary, Chapters 1, 2 and 4; William Watson at 202/586-1707 (email, 

william.watson@eia.gov), Chapter 2; coal tax expenditures; Scott McKee at 202/287-6049 (email, 

scott.mckee@eia.gov), Chapter 2; Robert Eynon at 202/586-239 (email, robert.eynon@eia.gov), Chapter 3; and 

James Hewlett at 202/586-9536 (email, james.hewlett@eia.gov), Chapters 4 and 5.

Other contributors to the report include: Margie Daymude, Marie LaRiviere, Louise Guey-Lee, Robert Schmitt, and 

Peggy Wells.
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ii U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Preface 

This report responds to a November 2010 request to the U.S. Energy Information Administration (EIA) from U.S. 

Representatives Roscoe G. Bartlett, Marsha Blackburn, and Jason Chaffetz for an update to a 2008 report prepared 

by EIA that provided a snapshot of direct federal financial interventions and subsidies in energy markets in fiscal 

year (FY) 2007, focusing on subsidies to electricity production. As requested, this report updates the previous 

report using FY 2010 data and is limited to subsidies that are provided by the federal government, provide a 

financial benefit with an identifiable federal budget impact, and are specifically targeted at energy markets. 

Subsidies to federal electric utilities, in the way of financial support, are also included as requested. 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 iii

Contents 

Contacts.......................................................................................................................................................................... i

Preface...........................................................................................................................................................................ii

Contents .......................................................................................................................................................................iii

Tables............................................................................................................................................................................. v

Figures ......................................................................................................................................................................... vii

Executive Summary .................................................................................................................................................... viii

Background ........................................................................................................................................................... viii

Not All Subsidies Impacting the Energy Sector Are Included in this Report...........................................................ix

Key Findings............................................................................................................................................................ xi

Energy Provisions Included in Legislation Responding to the Recent Financial Crisis........................................... xv

Findings Regarding Electricity-Related Subsidies and Support............................................................................ xvii

Findings Regarding Subsidies and Support For Fuels Used Outside of the Electricity Sector............................... xix

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

Background .............................................................................................................................................................. 1

Organization of Report ............................................................................................................................................ 4

2. Tax Expenditure and Direct Expenditures................................................................................................................. 5

Overview.................................................................................................................................................................. 5

Tax Expenditures...................................................................................................................................................... 5

Tax Expenditure Caveats.......................................................................................................................................... 8

Energy-Specifc Tax Expenditure Programs.................................................................................................................... 9

Coal-Related Tax Expenditures................................................................................................................................ 9

Renewable-Related Tax Expenditures ...................................................................................................................12

Natural Gas and Petroleum-Related Tax Expenditures .........................................................................................18

Nuclear-Related Tax Expenditures.........................................................................................................................20

Energy Efficiency and Conservation-Related Tax Expenditures.............................................................................21

Electricity Transmission-Related Tax Expenditures ...............................................................................................24

Direct Expenditures................................................................................................................................................25

Energy-Specific Direct Expenditure Program Descriptions....................................................................................26

Department of Energy ...........................................................................................................................................26

Department of Labor .............................................................................................................................................28

Department of Transportation ..............................................................................................................................28
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iv U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Environmental Protection Agency .........................................................................................................................28

General Services Administration............................................................................................................................29

Department of Housing and Urban Development................................................................................................. 29

Department of Health and Human Services..........................................................................................................29

Department of Agriculture.....................................................................................................................................29

Department of the Treasury ..................................................................................................................................30

3. Federal Energy Research and Development...........................................................................................................33

4. Federal Electricity Programs...................................................................................................................................39

Introduction ...........................................................................................................................................................39

Measuring the Support..........................................................................................................................................39

Selection of a Market Interest Rate.......................................................................................................................41

Tennessee Valley Authority ...................................................................................................................................44

Power Marketing Authorities................................................................................................................................. 46

BPA’s Borrowing Costs...........................................................................................................................................46

New Financial Arrangement ...........................................................................................................................49

BPA’s Federal Interest Support..............................................................................................................................50

The Smaller Power Marketing Administrations.....................................................................................................50

PMA Borrowing Costs............................................................................................................................................52

Rural Utilities Service Electric Loans, Guarantees, and Grants..............................................................................53

Estimates of the subsidy provided by RUS electric loans and loan guarantees.....................................................54

Summary ................................................................................................................................................................58

5. Loan Guarantee Programs.......................................................................................................................................59

Introduction ...........................................................................................................................................................59

The Federal Credit Reform Act of 1990 and the Computation of the Credit Subsidy Cost....................................61

Energy-Related Loan Guarantee Programs............................................................................................................63

Advanced Technology Vehicle Manufacturing Loan Guarantee Program.............................................................65

Other Energy related Loan Guarantee programs ..................................................................................................66

Subsidies Resulting from DOE's Loan Guarantee Program....................................................................................67

Results....................................................................................................................................................................75

Conclusions............................................................................................................................................................77

Appendix A. Request Letter.........................................................................................................................................80
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 v 

Tables 

Table ES1. Value of energy subsidies by major use, FY 2007 and FY 2010 (million 2010 dollars)................................ xi

Table ES2. Quantified energy-specific subsidies and support by type, FY 2010 and FY 2007 (million 2010 dollars) . xiii

Table ES3. Energy subsidies and support, selected indicators, 2007 and 2010 ......................................................... xvi

Table ES4. Fiscal year 2010 electricity production subsidies and support (million 2010 dollars) ........................... xviii

Table ES5. Measures of electricity production and production growth...................................................................... xx

Table ES6. Subsidies and support to fuels used outside of the electricity sector ...................................................... xxi

Table 1. Estimates of energy-specific tax expenditures (million 2010 dollars)............................................................. 6

Table 2. Coal-related tax expenditures (million 2010 dollars)..................................................................................... 9

Table 3. Renewable-related tax expenditures (million 2010 dollars).........................................................................13

Table 4. U.S. renewable net generation (billion kilowatthours).................................................................................13

Table 5. NCREBs allocations by project type and issuer, 2009 (million 2010 dollars) .................................................17

Table 6. Natural gas and petroleum related tax expenditures (million 2010 dollars)................................................18

Table 7. Nuclear transformation-related tax expenditures (million 2010 dollars)......................................................21

Table 8. Conservation, efficiency, and end-use tax expenditures (million 2010 dollars) ...........................................22

Table 9. Electricity transmission-related tax expenditures (million 2010 dollars)......................................................24

Table 10. Direct expenditures in energy (million 2010 dollars)..................................................................................26

Table 11. Section 1603 facility property eligibility amounts .......................................................................................32

Table 12. Applied Federal energy R&D expenditures by type and function, 2007 and 2010 (million 2010 dollars)..34

Table 13. Renewable R&D expenditures, 2007 and 2010 (million 2010 dollars) .......................................................36

Table 14. Nuclear R&D expenditures, 2007 and 2010 (million 2010 dollars).............................................................36

Table 15. Coal R&D expenditures, 2007 and 2010 (million 2010 dollars) ................................................................... 37

Table 16. Natural gas and petroleum R&D expenditures, 2007 and 2010 (million 2010 dollars)...............................37

Table 17. End-Use and Electricity Delivery and Energy Reliability R&D Expenditures, 2007 and 2010 (million 2010 

dollars).........................................................................................................................................................................38

Table 18. Basic federal energy R&D expenditures by type and function, 2007 and 2010 (million 2010 dollars).......38

Table 19. Interest Rates used to Estimate Federal Utilities and RUS Interest Subsidies, 2007 and 2010 (percent) ..41

Table 20. Estimate of federal electricity interest rate support to TVA, 2007 and 2010 (million 2010 dollars) ..........42

Table 21. Estimate of federal electricity interest rate support to BPA, 2007 and 2010 (million 2010 dollars)..........49

Table 22. Estimate of federal electricity interest rate support to the three smaller PMAs, 2007 and 2010 (million 

2010 dollars)................................................................................................................................................................51

Table 23. Interest subsidy to RUS borrowers 2007 and 2010 (million 2010 dollars)..................................................56

Table 24. Interest subsidy to federal utilities and RUS borrowers 2007 and 2010 (million 2010 dollars) .................57
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Table 25. Additional lending authority for loan guarantee programs in selected government agencies, 2004 and 

2010 (thousand 2010 dollars)......................................................................................................................................59

Table 26. An example of the computation of the credit subsidy costs .......................................................................62

Table 27. Section 1705 loans by technology as of early 2011 (billions of dollars) ......................................................66

Table 28. ATVM loans made as of January 2011 (billions of dollars) ..........................................................................67

Table 29. Estimated subsidy costs on DOE loan guarantees (millions of dollars).......................................................70

Table 30. An example of the total savings from the DOE loan guarantee program....................................................72

Table 31. Assumptions made to compute the total savings from the DOE loan guarantee program.........................73

Table 32. Total cost savings from DOE loan guarantee program. (million dollars) .....................................................76

Table 33. Reduction in Total Financing Costs Assuming No Change in Capital Structure (million dollars) .................77

Table 34. Summary of estimates of the subsidies resulting from DOE’s loan guarantees made in FY2010 (million 

dollars).........................................................................................................................................................................78
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 vii

Figures 

Figure ES 1. Electricity generating capacity additions by year.................................................................................... xix

Figure 1. Percentage share of the section 1603 investment grant by energy category, 2010....................................31

Figure 2. U.S. DOE cumulative R&D expenditures, 1978-2010 (billion dollars)...........................................................34

Figure 3. Research and development expenditures by energy category, 2007 and 2010 (billion dollars)..................35
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viii U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Executive Summary

Background

This report responds to a November 2010 request to the U.S. Energy Information Administration (EIA) from U.S. 

Representatives Roscoe G. Bartlett, Marsha Blackburn, and Jason Chaffetz for an update to a 2008 report prepared 

by EIA that provided a snapshot of direct federal financial interventions and subsidies in energy markets in fiscal 

year (FY) 2007, focusing on subsidies to electricity production (Appendix A). As requested, this report updates the 

previous report using FY 2010 data and is limited to subsidies that are provided by the federal government, 

provide a financial benefit with an identifiable federal budget impact, and are specifically targeted at energy 

markets. Subsidies to federal electric utilities, in the way of financial support, are also included, as requested. 

These criteria do exclude some subsidies beneficial to energy sector activities (see box entitled “Not All Subsidies 

Impacting the Energy Sector Are Included in this Report”) and this should be kept in mind when comparing this 

report to other studies that may use narrower or more expansive inclusion criteria. 

Energy subsidies and interventions discussed in this report are divided into five separate program categories:

Direct Expenditures to Producers or Consumers. These are federal programs that involve direct cash outlays 

which provide a financial benefit to producers or consumers of energy.

Tax Expenditures. These are provisions in the federal tax code that reduce the tax liability of firms or individuals 

who take specified actions that affect energy production, consumption, or conservation.

Research and Development (R&D). These are federal expenditures aimed at a variety of goals, such as increasing 

U.S. energy supplies or improving the efficiency of various energy consumption, production, transformation, and 

end-use technologies. R&D expenditures generally do not directly affect current energy consumption, production, 

and prices, but, if successful, they could affect future consumption, production, and prices.

Loans and Loan Guarantees. These involve federal financial support for certain energy technologies. The U.S. 

Department of Energy (DOE) is authorized to provide financial support for “innovative clean energy technologies 

that are typically unable to obtain conventional private financing due to their ‘high technology risks.’ In addition, 

eligible technologies must avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse 

gases."1

Electricity programs serving targeted categories of electricity consumers in several geographic regions of the 

country. Through the Tennessee Valley Authority (TVA) and the Power Marketing Administrations (PMAs), which 

include the Bonneville Power Administration (BPA) and three smaller PMAs, the federal government brings to 

market large amounts of electricity, stipulating that “preference in the sale of such power and energy shall be 

given to public bodies and cooperatives.”2

 

1 Section 1703 of Title XVII of the Energy Policy Act of 2005 authorizes the U.S. Department of Energy to support innovative clean energy 

technologies that are typically unable to obtain conventional private financing due to high technology risks. In addition, the technologies must 

avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse gases. See: United States Department of Energy, Loan 

Programs Office at 

The federal government also indirectly supports portions of the 

electricity industry through loans and loan guarantees made by the U.S. Department of Agriculture’s Rural Utilities 

Service (RUS) at interest rates generally below those available to investor-owned utilities.

https://lpo.energy.gov/?page_id=39. 2 Flood Control Act of 1944 (58 Stat. 890; 16 U.S.C. 825s). 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 ix

With the exception of the federal electricity programs and loan guarantee programs, this report measures 

subsidies and support on the basis of the cost of the programs to the federal budget as provided in budget 

documents.

3

Not All Subsidies Impacting the Energy Sector Are Included in this Report

 This report measures support provided by federal electricity programs by comparing the actual cost 

of funds made available to these entities to the cost of funds that they might otherwise have incurred. Similarly, 

the value of the support provided by DOE’s loan guarantee program is estimated by analyzing what the costs of 

financing eligible projects might be without the guarantees and the cost of the credit subsidy required for the 

guarantee. Uncertainties in the estimation of subsidy and support costs for federally-guaranteed loans, federal 

utilities, and participants in Rural Utilities Service loan programs are reflected by providing a range of subsidy 

estimates for selected programs in the body of the report. To facilitate exposition, the Executive Summary 

presents only midpoint value estimates for these programs. 

This report only includes subsidies meeting the following criteria: they are provided by the federal government, 

they provide a financial benefit with an identifiable FY 2010 federal budget impact, and, they are specifically 

targeted at energy. These criteria, particularly the energy-specific requirement, exclude some subsidies that 

benefit the energy sector. Some of the subsidies excluded from this analysis are discussed below.

For example, Section 199 of the American Jobs Creation Act of 2004, referred to as the domestic manufacturing 

deduction, provides reductions in taxable income for American manufacturers, including domestic oil and gas 

producers and refiners. The value of the Section 199 deduction in FY 2010 is estimated at $13 billion and 

approximately 25 percent is energy-related. While domestic oil and natural gas companies utilized this provision 

to reduce their 2010 tax liability, other industries, including traditional manufacturing sectors and other activities 

such as engineering and architectural services, sound recordings, and qualified film production, also took 

advantage of it.

Accelerated depreciation schedules arise from many provisions of the tax code and are widely available to energy 

and non-energy industries. Because the Internal Revenue Service (IRS) allows firms and individuals to deduct 

depreciation as an expense when computing their tax liability, accelerated depreciation front-loads deductible 

expenses, thereby reducing the present value of that liability. Accelerated depreciation provides a subsidy only to 

the extent that the amount of depreciation specified by the IRS exceeds the true economic “wear and tear” costs. 

Most empirical studies of economic depreciation have found evidence of some type of accelerated economic 

depreciation affecting various industries, though the exact pattern varied from study to study. This report includes 

the impacts of accelerated depreciation schedules identified as specific to the energy sector, but excludes 

schedules with applicability beyond the energy sector. 

Subsidized credit for energy infrastructure projects is frequently provided by export credit agencies and 

multilateral development banks. However, entities such as the Export-Import Bank of the United States also 

provide support to non-energy industries including aerospace, medical equipment, non-energy mining, and 

agribusiness.

Tax-exempt municipal bonds allow publicly-owned utilities to obtain lower interest rates than those available from 

either private borrowers or the U.S. Treasury. However, while they are used by energy industries such as electric 

 

3 Office of Management and Budget, Analytical Perspectives of the Budget of the United States, Editions 2009 and 2012. Data for 2007 appeared 

in Table 19-1; data for 2010-1016 appeared in Table 17-1. Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 

2010-2014, JCS-3-10, Table 1.
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utilities, the group of eligible borrowers also includes water utilities, telecommunication facilities, waste treatment 

plants, and other publicly-owned entities.

The tax code allows a foreign tax credit for income taxes paid to foreign countries. If a multinational company is 

subject to a foreign country's levy, and it also receives a specific economic benefit from that foreign country, it is 

classified as a “dual-capacity taxpayer.” Dual-capacity taxpayers cannot claim a credit for any part of the foreign 

levy unless it is established that the amount paid under a distinct element of the foreign levy is a tax, rather than a 

compulsory payment for some direct or indirect economic benefit. Major oil companies are significant 

beneficiaries of this provision. However, this tax provision is also available to non-energy industries.

The tax code also provides special treatment for some publicly-traded partnerships (PTP). Section 7704 of the 

Code generally treats a publicly-traded partnership as a corporation for federal income tax purposes. For this 

purpose, a PTP is any partnership that is traded on an established securities market or secondary market. 

However, a notable exception to Section 7704 occurs if 90 percent of the gross income of a PTP is passive-type 

income, such as interest, dividends, real property rents, gains from the disposition of real property, and similar 

income or gains. This would include gains from natural resource sales. In these cases, the PTP is exempt from 

corporate level taxation, thus allowing it to claim pass-through status for tax purposes.4

Another potential subsidy source not addressed in this report is associated with energy-related trust funds 

financed by taxes and fees. Examples include the Black Lung Disability Trust Fund, the Leaking Underground 

Storage Tank Trust Fund, the Oil Spill Liability Trust Fund, the Pipeline Safety Fund, the Aquatic Resources Trust 

Fund, the Abandoned Mine Reclamation Fund, the Nuclear Waste Fund, and the Uranium Enrichment 

Decontamination and Decommissioning Fund. By tying trust fund collections to products and activities responsible 

for the damages they address, the cost of programs for remediation and prevention of those damages can be 

reflected in the market price of energy use and production. If the fees or taxes collected by trust funds have been 

set appropriately, the funds will have sufficient resources to meet their obligations with the result that no subsidy 

is involved. However, if the fees or taxes are set too low, energy companies are receiving an implicit subsidy. 

These potential subsidies are not addressed in this report because of the difficulty in determining the sufficiency of 

the funds to meet potential liabilities and the fact that there is no direct federal budgetary impact in FY 2010.

 As with many other tax 

provisions, the tax treatment of PTPs is not exclusive to the energy sector.

This report also does not attempt to quantify the potential subsidy resulting from limits to liability in case of a 

nuclear accident provided by Section 170 of the Atomic Energy Act of 1954, the Price-Anderson Act. The PriceAnderson Act requires each operator of a nuclear power plant to obtain the maximum amount of primary 

coverage of liability insurance. Currently, the amount is about $400 million. Damages exceeding that amount 

would be funded with a retroactive assessment on all other firms owning commercial reactors based upon the 

number of reactors they own. However, Price-Anderson places a limit on the total liability to all owners of 

commercial reactors at about $12 billion.

 

4 The Pew Charitable Trusts, Subsidy Scope, http://subsidyscope.org/tax_expenditures/db/group/31/?estimate=1&year=2001. 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 xi 

Key Findings

The value of direct federal financial interventions and subsidies in energy markets doubled between 2007 and 

2010, growing from $17.9 billion to $37.2 billion. In broad categories, the largest increase was for conservation 

and end-use subsidies, followed to a lesser degree by increases in electricity-related subsidies and subsidies for 

fuels used outside the electricity sector (Table ES1). 

Table ES1. Value of energy subsidies by major use, FY 2007 and FY 2010

(million 2010 dollars)

Subsidy and Support Category FY 2007 FY 2010

Electricity-Related 7,663 11,873

 Fuels and Technologies Used for Electricity Production 6,582 10,902

 Transmission and Distribution 1,081 971

Fuels Used Outside the Electricity Sector 6,246 10,448

Conservation, End Use and LIHEAP 3,987 14,838 

 Conservation 369 6,597 

 End-Use/Other 1,342 3,241 

 LIHEAP 2,276 5,000

Total 17,895 37,160

Notes: Totals may not equal sum of components due to independent rounding.

Note that the 2007 values reported here are inflated to 2010 dollars and reflect final 2007 data estimates. The values provided in this table also 

represent the average of the low and high values of more detailed estimates provided in the body of the report.

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.

A key factor in the increased support for conservation programs, end-use technologies and renewables was the 

passage of several pieces of legislation responding to the recent financial crisis and subsequent economic 

downturn, particularly the American Recovery and Reinvestment Act of 2009 (ARRA) and the Energy 

Improvement and Extension Act (EIEA). Some of the ARRA-related programs that account for a large portion of 

the growth in subsidies and support between FY 2007 and FY 2010 (Table ES2) are temporary and the subsidies 

associated with them are scheduled to phase out over the next few years (see box “Energy Provisions Included in 

Legislation Responding to the Recent Financial Crisis”). Other recent legislation impacting energy subsidies 

included the Food, Conservation, and Energy Act of 2008, which provided significant new subsidies to biofuels 

(primarily ethanol and biodiesel) producers, and the Tax Relief, Unemployment Insurance Reauthorization, and Job 

Creation Act of 2010, which extended the sunset dates for several tax expenditure programs, as well as the grant 

program for qualifying renewables.
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Conservation and end-use subsidies experienced rapid growth in both absolute and percentage terms, more 

than tripling in real terms between FY 2007 and FY 2010. The increase in subsidies and support was led by growth 

in direct expenditures and tax expenditures (Table ES2). The home energy efficiency improvement tax expenditure 

accounts for most of the increase in conservation-related subsidies between FY 2007 and FY 2010. Conservation 

subsidies were almost equally divided between direct expenditures and tax expenditures, with estimated tax 

credits for energy efficiency improvements to existing homes totaling $3.2 billion. These tax credits funded 

investments in energy-efficient windows, furnaces, boilers, boiler fans, and building envelope components. Enduse subsidies, nearly all of which were provided through direct expenditures of appropriated funds, were boosted 

by a doubling of expenditures in the Low Income Home Energy Assistance Program (LIHEAP) spending between FY 

2007 and FY 2010.5

The composition of subsidies to specific fuels and technologies in FY 2010 is significantly different than in FY 

2007, reflecting the elimination of subsidies to refined coal and increases in subsidies to renewable energy due 

to a change in the incentive structure. The growth in subsidies for renewable fuels is primarily driven by the $4.2 

billion in expenditures for grants under Section 1603 of ARRA, which went mainly to wind facilities, and by growth 

in federal support for biofuels. The ARRA grant program allowed investors in new qualifying facilities to choose an 

upfront grant in lieu of the longstanding 10-year production tax credit that was also available, but which became 

less attractive to developers as the market for financial instruments based on tax credit streams withered following 

the financial crisis. Though the two options have roughly similar value to investors and cost to the government 

over the life of the projects, the grant program front loads the government’s support for covered projects in the 

year that the grant is awarded. If the wind and solar plants that took advantage of the grant program during the 

financial crisis had instead utilized the production tax credit program, the subsidy value reported in FY 2010 would 

have been much smaller, reflecting only the credit for up to one year of generation.

 

6

The DOE loan program, designed to support nuclear power, energy efficiency and renewable energy projects, 

advanced fossil fuels, electric power transmission systems, advanced technology vehicles, and leading-edge 

biofuels, was only in its early stages in FY 2010. The midpoint estimate of the loan subsidies was $1.6 billion in 

2010. As more projects are approved, the loan subsidies associated with this program are expected to rise over 

time.

 Tax expenditures associated 

with ethanol tax credits also increased significantly between FY 2007 and FY 2010 with the growth in ethanol 

blending activity under the Renewable Fuel Standard. 

 

5 LIHEAP provides funds to states, the District of Columbia, U.S. territories and commonwealths, and Indian tribal organizations (collectively 

referred to as grantees) primarily to help low-income households pay home energy expenses. 6 The amount of the subsidy for the Production Tax Credit (PTC) reflects the dollar amount for production from all qualifying generators in that 

year. Qualifying generators receive the credit for 10 years from the initial in-service date. For 2010, the total dollar amount reflects the annual 

PTC for all qualifying generators and the grant amount for those new generators qualifying under the Section 1603 program under ARRA. 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 xiii

Table ES2. Quantified energy-specific subsidies and support by type, FY 2010 and FY 2007

(million 2010 dollars)

Beneficiary

Direct ExpendituresTax Expenditures

Research & 

Development

DOE Loan 

Guarantee 

Program

Federal & 

RUS 

Electricity1 Total

ARRA 

Related

2010

Coal 42 561 663 0 91 1,358 97

Refined Coal 0 0 0 0 0 0 0 

Natural Gas and 

Petroleum Liquids 4 2,690 70 0 56 2,820 0 

Nuclear 0 908 1,169 265 157 2,499 147

Renewables 4,696 8,168 1,409 269 133 14,674 6,193 

 Biomass 57 523 537 0 0 1,117 10

 Geothermal 160 1 100 12 0 273 228

 Hydro 17 17 52 0 130 216 16

 Solar 496 120 348 173 0 1,134 788

 Wind 3,556 1,178 166 85 1 4,986 4,852

 Other 95 0 205 0 1 302 130 

 Biofuels 314 6,330 0 0 0 6,644 169

Electricity

-Smart Grid & 

Transmission 461 58 222 20 211 971 495

Conservation 3,387 3,206 0 4 0 6,597 6,305

End-Use 5,705 693 832 1,011 0 8,241 1,549

 LIHEAP 5,000 0 0 0 0 5,000 0 

 Other 705 693 832 1,011 0 3,241 1,549

 Total 14,295 16,284 4,365 1,570 648 37,160 14,786 
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Table ES2. Quantified energy-specific subsidies and support by type, FY 2010 and FY 2007 (cont.)

(million 2010 dollars)

Beneficiary

Direct ExpendituresTax Expenditures

Research & 

Development

DOE Loan 

Guarantee 

Program

Federal & 

RUS 

Electricity1 Total

ARRA 

Related

2007

Coal 0 291 582 NA 70 943 NA

Refined Coal 0 3,038 0 NA 0 3,038 NA

Natural Gas and 

Petroleum Liquids

0 1,914 43 NA 53 2,010 NA

Nuclear 0 600 1,017 NA 96 1,714 NA

Renewables 110 4,130 717 NA 167 5,124 NA

 Biomass 16 5 40 NA 0 61 NA

 Geothermal 0 5 9 NA 0 14 NA

 Hydro 0 6 0 NA 165 170 NA

 Solar 0 8 171 NA 0 179 NA

 Wind 0 418 58 NA 1 476 NA

 Other 5 6 211 NA 1 224 NA

 Biofuels 89 3,682 228 NA 0 3,999 NA

Electricity

-Smart Grid & 

Transmission 0 696 142 NA 243 1,081 NA

Conservation 369 0 0 NA 0 369 NA

End-Use 2,276 832 509 NA 0 3,618 NA

 LIHEAP 2,276 0 0 0 0 2,276 NA

 Other 0 832 509 NA 0 1,342 NA

 Total 2,755 11,501 3,010 NA 629 17,895 NA 1

Total will not match Table 24 midpoint of “Estimated Interest Subsidy at Benchmark Interest Rate” because some data can not be allocated by 

fuel or activity. 

Notes: Totals may not equal sum of components due to independent rounding.

Renewable other includes landfill gas, municipal solid waste and hydrogen.

The values provided in this table represent the average of the low and high values of more detailed estimates provided in the body of this report.

Due to data availability issues, not all federal utility data was allocated by fuel or activity.

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 xv 

Energy Provisions Included in Legislation Responding to the Recent Financial 

Crisis

Two laws enacted in response to the financial crisis of late 2008 and early 2009, the American Recovery and 

Reinvestment Act of 2009 (ARRA) and the Energy Improvement and Extension Act (EIEA), include significant 

energy-related provisions.

Both bills emphasize particular segments of the energy market such as use of renewable fuels in electricity 

production, alternative transportation fuels, clean energy facilities, upgrading the Nation’s high voltage 

transmission system, energy efficiency, and conservation. 

Both laws extended sunset provisions for some existing tax expenditures in addition to introducing new ones. 

These laws also featured provisions expanding the use of tax exempt bonds to publicly-owned energy providers. 

The energy-related provisions of EIEA were focused on tax expenditures. The energy-related provisions of ARRA 

included additional funding of existing direct expenditure, tax expenditure, and R&D programs, as well as funding 

for new direct expenditure, tax expenditure, and R&D programs; a new grant program available in lieu of 

production tax credits; and, expansion of DOE’s loan guarantee program, first established in 2005. Finally, ARRA 

provided the Western Area Power Administration and the Bonneville Power Administration each with $3.25 billion 

in new borrowing authority to expand their transmission systems to better accommodate renewable sources of 

electricity supply. 

ARRA created, expanded, or extended programs to increase the use of clean energy and improve energy efficiency. 

ARRA coupled an emphasis on promoting economic recovery and job creation with investments in energy 

programs. While only energy-related funds expended in FY 2010 are included in this report, ARRA included 

appropriations of more than $35.2 billion to the Department of Energy and provided more than $21 billion in 

energy tax incentives. This funding focused on energy efficiency, renewable energy, and smart grid investments. 

ARRA also provided $6 billion, of which $3.5 billion was subsequently rescinded, to fund a loan guarantee program 

administered by the U.S. DOE for eligible energy projects.

ARRA’s Section 1603 energy grant program, which was designed as a supplement to existing energy production 

and investment tax credit programs directed at renewables, paid out $4.2 billion in FY 2010, targeted at wind (84 

percent) and solar (11 percent) projects. ARRA also included additional spending on several existing direct 

expenditure programs. ARRA-related direct expenditures in FY 2010 totaled $8.5 billion.7

At $3.2 billion, the Credit for Energy Efficiency Improvements to Existing Homes was the largest energy-specific tax 

expenditure in FY 2010 after the ethanol tax credit. Although established under the Energy Policy Act of 2005 

(EPAct 2005), it was expanded under Section 302 of EIEA and amended under Section 1121 of ARRA. This credit is 

available to offset funds used for the installation of energy-efficient windows, furnaces, boilers, boiler fans, and

building envelope components, such as exterior doors and any metal roof that has appropriate pigmented 

coatings.

 This included $1.5 billion 

to the Weatherization Assistance program, $682 million to the State Energy program, $409 million to smart grid 

investments, and $317 million to fund a program supporting advanced battery manufacturing. ARRA also provided 

$473 million in initial funding to the Conservation Block program (authorized by the Energy Independence and 

Security Act of 2007 (EISA)), to deploy economical, clean, and reliable conservation technologies.

 

7

The $8.5 billion includes non-DOE-related energy expenditures.
July 2011

xvi U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

ARRA included $0.6 billion in new R&D funding. The largest target of this funding included basic science, at $159 

million, followed by non-defense uranium enrichment decontamination and decommissioning, at $139 million.

ARRA also expanded DOE’s loan guarantee authority that was first established under Section 1703 of EPAct 2005 

by authorizing loan guarantees to electric power transmission systems and biofuels projects. 

EIEA and ARRA both contained provisions providing significant tax benefits to issuers and holders of certain 

energy-related tax-exempt bonds.8

The growth in energy-specific subsidies and support between FY 2007 and FY 2010 does not closely correspond 

to changes in energy consumption and production over the same time period. In fact, overall energy 

consumption actually fell from 101 quadrillion Btu to 98 quadrillion Btu between 2007 and 2010, reflecting 

economic conditions, while domestic energy production rose from 71 quadrillion Btu to 75 quadrillion Btu due to 

increasing domestic production of shale gas, crude oil, and renewable energy (Table ES3). While the overall 

amount of federal subsidies and support provided per unit of overall energy consumption or production has clearly 

grown, simply dividing the current value of subsidies by current consumption or production does not reflect either 

the long-run impact of imbedded subsidies and or the future impacts of current subsidies and support that may 

only be starting to impact energy markets. For example, increases in R&D expenditures are not reflected in the 

Nation’s energy mix unless and until the research leads to successful innovations that penetrate the market, a 

process that can take many years.

EIEA provided $800 million in additional financing for Clean Renewable Energy 

Bonds (CREBs) and provided a one-year extension to existing CREBs. EIEA also created two new categories of 

CREB-like financing: New Clean Renewable Energy Bonds (New CREBs) and Qualified Energy Conservation Bonds 

(QECBs). Section 1111 of ARRA increased the amount of funds available to issue New CREBS from $800 million to 

$2.4 billion. Section 1112 of ARRA increased the amount of funds available to finance QECBs from $800 million to

$2.4 billion.

Table ES3. Energy subsidies and support, selected indicators, 2007 and 2010

Item 2007 2010

Total Energy Subsidies and Support (million 2010 dollars) 17,895 37,160

U.S. Energy Consumption (quadrillion Btu) 101.4 98.0

U.S Energy Production (quadrillion Btu) 71.4 75.0

Notes: Totals may not equal sum of components due to independent rounding.

The subsidy and support values provided in this table represent the average of the low and high values of more detailed estimates provided in the 

body of the report.

The energy consumption and production values shown in this table represent 2007 and 2010 calendar year data rather than the fiscal year data 

reported for the estimated subsidies.

Sources: U.S. Energy Information Administration, Monthly Energy Review May 2011, DOE/EIA-0035(2011/05) (Washington, DC, May, 2011), 

Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. Joint 

Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), Table 

1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing and 

Urban Development, the Environmental Protection Agency and the General Services Administration.

 

8 These bonds are classified by the U.S. Treasury as tax expenditures although they are targeted at public power providers, which do not have any 

federal profit tax liabilities. They are, in some sense, the equivalent of the Production Tax Credit or Investment Tax Credit provided to investorowned utilities. In essence, they amount to interest free loans, with the Treasury providing the interest payments rather than the public power 

provider.
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 xvii

Findings Regarding Electricity-Related Subsidies and Support

Electricity-related subsidies and support are estimated at $11.9 billion in FY 2010, up from $7.7 billion in FY 2007 

(Table ES1). While fuel- and technology-related electricity subsidies grew 66 percent between FY 2007 and FY 

2010, transmission and distribution system-related subsidies actually declined.

Direct expenditures accounted for 39 percent of total electricity-related subsidies in FY 2010 (Table ES4). These 

expenditures were mostly the result of the ARRA Section 1603 grant program, 84-percent of which went to wind 

generation. As noted, the relatively high value for this program stems from the fact that the grant program places 

all of the costs in the year that a project is initiated, while the existing production tax credit that the grant 

substituted for spread the costs of the tax credit over the first 10 years of a project's operation. If developers 

return to using the production tax credit in the future, the first-year costs for each project will be much lower.

Tax expenditures comprise over 28 percent of the total subsidies and support related to electricity production. 

Renewables accounted for 40 percent of all electricity-related tax expenditures in FY 2010, mostly due to the 

Sections 45 and 48 production and investment tax credits which predominantly went to wind facilities. A nuclear 

decommissioning–related tax credit accounted for $908 million in tax expenditures. 

Research and development accounted for 22 percent of the total subsidies and support to the electric power 

sector. Nuclear accounted for the highest level of R&D expenditures at $1,169 million, followed by renewables at

$632 million, and coal at $575 million. 

Federal electricity support to federal utilities and participants in the Rural Utilities Service loan programs in the 

form of explicit and implicit loan guarantees are estimated at approximately $648 million in FY 2010. The level 

of this support is largely a function of the value of outstanding debt and prevailing interest rates. 

Relative to their share of total electricity generation, renewables received a large share of direct federal 

subsidies and support in FY 2010. For example, renewable fuels accounted for 10.3 percent of total generation, 

while they received 55.3 percent of federal subsidies and support (Tables ES4 and ES5). However, caution should 

be used when making such calculations because many factors can drive the results. For example, many of the 

programs that showed the largest increases in subsidies between FY 2007 and FY 2010 are supporting facilities that 

are still under construction, including energy equipment manufacturing facilities that may not affect energy 

consumption or production for several years. Furthermore, the ARRA 1603 grant program, that allows investors to 

choose an upfront grant instead of a 10-year production tax credit, tended to lead to much higher overall 

electricity subsidy estimates for renewables in FY 2010 than would have occurred had they continued to rely on 

the existing production tax credit program, which does not front-load subsidy costs. Focusing on a single year's 

data also does not capture the imbedded effects of subsidies that may have occurred over many years across all 

energy fuels and technologies.
July 2011

xviii U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table ES4. Fiscal year 2010 electricity production subsidies and support 

(million 2010 dollars)

Direct 

Expenditures

Tax 

Expenditures

Research 

& 

Development

Federal & 

RUS 

Electricity 

Support 

Loan 

Guarantee Total

Share of 

Total 

Subsidies 

and 

Support

Coal 37 486 575 91 0 1,189 10.0%

Natural Gas and 

Petroleum Liquids 1 583 15 56 0 654 5.5%

Nuclear 0 908 1,169 157 265 2,499 21.0% 

Renewables 4,178 1,347 632 133 269 6,560 55.3% 

 Biomass 6 54 55 0 0 114 1.0% 

 Geothermal 115 1 72 0 12 200 1.7%

 Hydropower 17 17 51 130 0 215 1.8% 

 Solar 409 99 287 0 173 968 8.2% 

 Wind 3,556 1,178 166 1 85 4,986 42.0% 

 Unallocated

 Renewables 75 0 0 0 0 75 0.6%

Transmission and 

Distribution 461 58 222 211 20 971 8.2%

Total 4,677 3,382 2,613 648 555 11,873 100%

Notes: Estimates of federal electricity program support are based on the most recent audited annual reports for federally-owned utilities which 

conform to federal fiscal year convention.

Totals may not equal sum of components due to independent rounding.

The values provided in this table represent the average of the low and high values of more detailed estimates provided in the body of the report.

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.

Among the specific fuels and technologies, wind plants received the largest share of direct federal subsidies and 

support in FY 2010, accounting for 42 percent of total electricity-related subsidies. While the share of electricityrelated subsidies and support received by wind and solar technologies is disproportionate to their generation 

share, their generation has increased dramatically in the last decade. Wind generation in 2010 is nearly 16 times 

the level achieved in 2000 (Table ES5). While natural gas-fired capacity additions have dominated for most of the 

last 15 years, wind generating capacity additions have also ramped up substantially in recent years (Figure ES1). 
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 xix

Findings Regarding Subsidies and Support For Fuels Used Outside of the 

Electricity Sector

Biofuels receive most of the subsidies and support for fuels used outside the electricity sector. Based on the 

subsidy categories used in this report, subsidies and support for fuels used outside the electricity sector, at $10.4 

billion, accounted for 28 percent of total energy subsidies. In this category, biomass and biofuels received the 

largest subsidy in FY 2010, at $7.6 billion (Table ES6). Under the Volumetric Ethanol Excise Tax Credit (VEETC), 

blenders receive a $0.45-per gallon credit for each gallon of ethanol that is blended with gasoline for use as a 

motor fuel.9

Natural gas and petroleum liquids also received significant subsidies and support for fuels used outside the 

electricity sector. They accounted for 20.7 percent of the fuel specific subsidies and support and, together with 

biofuels, accounted for nearly 94 percent of the subsidies and support going to fuels not supporting electricity 

production.

 Internal Revenue Service regulations require that blenders apply for VEETC refunds to offset gasoline 

excise tax payments, but they may submit a claim for payment or take a credit against other taxes if their VEETC 

credits exceed their gasoline excise tax liability. Based on its implementation rules, the Treasury reports VEETC as 

a $5.7-billion reduction in excise tax revenues for FY 2010. For purposes of this report, VEETC is classified as tax 

expenditure. 

Source: U.S. Energy Information Administration, Form EIA-860 Annual Electric Generator Report , and Form EIA-860M (see Table ES3 in the 

March 2011 Electric Power Monthly).

 

9 The credits for mixtures other than ethanol are $0.60–per-gallon for alcohol fuel mixtures (other than ethanol), $0.50-per-gallon of biodiesel, 

and $1.00-per-gallon for agri-biodiesel.

0

10

20

30

40

50

60

70

1995 1997 1999 2001 2003 2005 2007 2009

natural gas coal petroleum nuclear wind other

gigawatts

Figure ES 1. Electricity generating capacity additions by year
July 2011

xx U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table ES5. Measures of electricity production and production growth

Notes: Total net generation includes batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, miscellaneous technologies not included in 

individual rows.

NA=Not applicable.

Totals may not equal sum of components due to independent rounding.

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.

2000 Net 

Generation 

(billion 

kilowatthours)

2010 Net 

Generation 

(billion 

kilowatthours)

Share of 2000 

Generation 

(percent)

Share of 2010 

Generation 

(percent)

Annual 

Growth from 

2000 to 2010

(percent)

Coal 1,966 1,851 51.7% 44.9% -0.6%

Natural Gas and 

Petroleum Liquids 726 1,030 19.1% 25.0% 3.6% 

Nuclear 754 807 19.8% 19.6% 0.7%

Renewables 356 425 9.4% 10.3% 1.8% 

 Biomass Power 61 57 1.6% 1.4% -0.7% 

 Geothermal 14 16 0.4% 0.4% 1.3%

 Hydroelectric 276 257 7.3% 6.2% -0.7%

 Solar 0 1 0.0% 0.0% NA

 Wind 6 95 0.2% 2.3% 31.8%

Total 3,802 4,120 100.0% 100.0% 0.8%
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 xxi 

Table ES6. Subsidies and support to fuels used outside of the electricity sector

2000 Fuel 

Production 

Excluding That 

Used for 

Electricity 

Generation

(quadrillion 

btu)

2010 Fuel 

Production 

Excluding That 

Used for 

Electricity 

Generation

(quadrillion 

btu)

FY 2010 

Subsidy and 

Support

(million 2010 

dollars)

Share of 2010 

Non-ElectricityRelated Fuel 

Production 

(percent)

Share of 2010 

Fuel-Specific 

Non-ElectricityRelated 

Subsidies 

(percent)

Coal 2.52 2.94 169 8.3% 1.6%

Natural Gas 

Petroleum Liquids 28.20 28.55 2,165 80.3% 20.7% 

Biomass and Biofuels 2.55 3.87 7,646 10.9% 73.2% 

Geothermal 0.02 0.06 73 0.2% 0.7%

Solar 0.06 0.10 169 0.3% 1.6%

Other Renewables 0.04 0.02 226 0.0% 2.2%

 Total 33.39 35.54 10,448 100.0% 100.0%

Notes: Totals may not equal sum of components due to independent rounding.

The fuel production values in this table represent domestic fuel production for each fuel minus the amount consumed in the electricity sector.

The values provided in this table represent the average of the low and high values of more detailed estimates provided in the body of the report.

Other Renewables includes hydroelectricity, wind, and hydrogen.

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.

July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 1 

1. Introduction 

Background

This report responds to a November 2010 request to the Energy Information Administration (EIA) from U.S. 

Representatives Roscoe G. Bartlett, Marsha Blackburn, and Jason Chaffetz for an update to a 2008 report prepared 

by EIA that provided a snapshot of direct federal financial interventions and subsidies in energy markets in fiscal 

year (FY) 2007, focusing on subsidies to electricity production (Appendix A). As requested, this report updates the 

previous report using FY 2010 data and is limited to subsidies that are provided by the federal government, 

provide a financial benefit with an identifiable federal budget impact, and are specifically targeted at energy 

markets. Subsidies to federal electric utilities, in the way of financial support, are also included as requested. These 

criteria do exclude some subsidies beneficial to energy sector activities (see box Not All Subsidies Impacting the 

Energy Sector Are Included in this Report) and this should be kept in mind when comparing this report to other 

studies that may use narrower or more expansive inclusion criteria. 

Energy subsidies and interventions discussed in this report are divided into five separate program categories:

Direct Expenditures to Producers or Consumers. These are federal programs that involve direct cash outlays 

which provide a financial benefit to producers or consumers of energy.

Tax Expenditures. These are provisions in the federal tax code that reduce the tax liability of firms or individuals 

who take specified actions that affect energy production, consumption, or conservation.

Research and Development (R&D). These are federal expenditures aimed at a variety of goals, such as increasing 

U.S. energy supplies or improving the efficiency of various energy consumption, production, transformation, and 

end-use technologies. R&D expenditures generally do not directly affect current energy consumption, production, 

and prices, but, if successful, they could affect future consumption, production, and prices.

Loans and Loan Guarantees. These involve federal financial support for certain energy technologies. The U.S. 

Department of Energy (DOE) is authorized to provide financial support for “innovative clean energy technologies 

that are typically unable to obtain conventional private financing due to their ‘high technology risks.’ In addition, 

eligible technologies must avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse 

gases."10

Electricity programs serving targeted categories of electricity consumers in several geographic regions of the 

country. Through the Tennessee Valley Authority (TVA) and the Power Marketing Administrations (PMAs), which 

include the Bonneville Power Administration (BPA) and three smaller PMAs, the federal government brings to 

market large amounts of electricity, stipulating that “preference in the sale of such power and energy shall be 

given to public bodies and cooperatives.”11

 

10 Section 1703 of Title XVII of the Energy Policy Act of 2005 authorizes the U.S. Department of Energy to support innovative clean energy 

technologies that are typically unable to obtain conventional private financing due to high technology risks. In addition, the technologies must 

avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse gases. See United States Department of Energy, Loan 

Programs Office at:

The federal government also indirectly supports portions of the 

electricity industry through loans and loan guarantees made by the U.S. Department of Agriculture’s Rural Utilities 

Service (RUS).

https://lpo.energy.gov/?page_id=39. 11 Flood Control Act of December 2, 1944 (58 Stat. 890; 16 U.S.C. 825s). 
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2 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

With the exception of the federal electricity programs and loan guarantee programs, this report measures 

subsidies and support on the basis of the cost of the programs to the federal budget as provided in budget 

documents from the Office of Management and Budget, and the Joint Committee on Taxation.

12

Not All Subsidies Impacting the Energy Sector Are Included in this Report

 This report 

measures support provided by federal electricity programs by comparing the actual cost of funds made available to 

these entities to the cost of funds that they might otherwise have incurred in the absence of federal support. 

Similarly, the value of the support provided by DOE’s loan guarantee program is estimated by analyzing what the 

costs of financing eligible projects might be without the guarantees and the cost of the credit subsidy required for 

the guarantee. In contrast to the Executive Summary where midpoint estimates are used to provide measures of 

finance-related subsidies, subsequent chapters present a range of subsidy estimates, to reflect uncertainty in the 

estimation of the costs of federally-guaranteed loans and the borrowing costs of the federal utilities and 

participants in Rural Utilities Service loan programs. This report estimates these costs based upon the savings 

realized from borrowing at preferential rates compared to market rates. Rather than choosing a single benchmark 

interest rate to estimate the cost of these programs, a range of borrowing costs starting with the 30-year Treasury 

rate through the Baa investor- owned- utility interest rate were used.

This report only includes subsidies meeting the following criteria: they are provided by the federal government, 

they provide a financial benefit with an identifiable FY 2010 federal budget impact, and, they are specifically 

targeted at energy. These criteria, particularly the energy-specific requirement, exclude some subsidies that 

benefit the energy sector. Some of the subsidies excluded from this analysis are discussed below.

For example, Section 199 of the American Jobs Creation Act of 2004, referred to as the domestic manufacturing 

deduction, provides reductions in taxable income for American manufacturers, including domestic oil and gas 

producers and refiners. The value of the Section 199 deduction in FY 2010 is estimated at $13 billion and 

approximately 25 percent is energy-related. While domestic oil and natural gas companies utilized this provision 

to reduce their 2010 tax liability, other industries, including traditional manufacturing sectors and other activities 

such as engineering and architectural services, sound recordings, and qualified film production, also took 

advantage of it.

Accelerated depreciation schedules arise from many provisions of the tax code and are widely available to energy 

and non-energy industries. Because the Internal Revenue Service (IRS) allows firms and individuals to deduct 

depreciation as an expense when computing their tax liability, accelerated depreciation front-loads deductible 

expenses, thereby reducing the present value of that liability. Accelerated depreciation provides a subsidy only to 

the extent that the amount of depreciation specified by the IRS exceeds the true economic “wear and tear” costs. 

Most empirical studies of economic depreciation have found evidence of some type of accelerated economic 

depreciation affecting various industries, though the exact pattern varied from study to study. This report includes 

the impacts of accelerated depreciation schedules identified as specific to the energy sector, but excludes 

schedules with applicability beyond the energy sector. 

Subsidized credit for energy infrastructure projects is frequently provided by export credit agencies and 

multilateral development banks. However, entities such as the Export-Import Bank of the United States also 

 

12 Office of Management and Budget, Analytical Perspectives of the Budget of the United States, Editions 2009 and 2012. Data for 2007 appeared 

in Table 19-1; data for 2010-1016 appeared in Table 17-1. Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 

2010-2014, JCS-3-10, Table 1.
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 3 

provide support to non-energy industries including aerospace, medical equipment, non-energy mining, and 

agribusiness.

Tax-exempt municipal bonds allow publicly-owned utilities to obtain lower interest rates than those available from 

either private borrowers or the U.S. Treasury. However, while they are used by energy industries such as electric 

utilities, the group of eligible borrowers also includes water utilities, telecommunication facilities, waste treatment 

plants, and other publicly-owned entities.

The tax code allows a foreign tax credit for income taxes paid to foreign countries. If a multinational company is 

subject to a foreign country's levy, and it also receives a specific economic benefit from that foreign country, it is 

classified as a “dual-capacity taxpayer.” Dual-capacity taxpayers cannot claim a credit for any part of the foreign 

levy unless it is established that the amount paid under a distinct element of the foreign levy is a tax, rather than a 

compulsory payment for some direct or indirect economic benefit. Major oil companies are significant 

beneficiaries of this provision. However, this tax provision is also available to non-energy industries.

The tax code also provides special treatment for some publicly-traded partnerships. Section 7704 of the Code 

generally treats a publicly-traded partnership (PTP) as a corporation for federal income tax purposes. For this 

purpose, a PTP is any partnership that is traded on an established securities market or secondary market. 

However, a notable exception to Section 7704 occurs if 90 percent of the gross income of a PTP is passive-type 

income, such as interest, dividends, real property rents, gains from the disposition of real property, and similar 

income or gains. This would include gains from natural resource sales. In these cases, the PTP is exempt from 

corporate level taxation, thus allowing it to claim pass-through status for tax purposes.13

Another potential subsidy source not addressed in this report is associated with energy-related trust funds 

financed by taxes and fees. Examples include the Black Lung Trust Fund, the Leaking Underground Storage Tank 

Trust Fund, the Oil Spill Liability Trust Fund, the Pipeline Safety Fund, the Aquatic Resources Trust Fund, the 

Abandoned Mine Reclamation Fund, the Nuclear Waste Fund, and the Uranium Enrichment Decontamination and 

Decommissioning Fund. By tying trust fund collections to products and activities responsible for the damages they 

address, the cost of programs for remediation and prevention of those damages can be reflected in the market 

price of energy use and production. If the fees or taxes collected by trust funds have been set appropriately, the 

funds will have sufficient resources to meet their obligations with the result that no subsidy is involved. However, 

if the fees or taxes are set too low, energy companies are receiving an implicit subsidy. These potential subsidies 

are not addressed in this report because of the difficulty in determining the sufficiency of the funds to meet 

potential liabilities and the fact that there is no direct federal budgetary impact in FY 2010.

 As with many other tax 

provisions, the tax treatment of PTPs is not exclusive to the energy sector.

This report also does not attempt to quantify the potential subsidy resulting from limits to liability in case of a 

nuclear accident provided by Section 170 of the Atomic Energy Act of 1954, the Price-Anderson Act. The PriceAnderson Act requires each operator of a nuclear power plant to obtain the maximum amount of primary 

coverage of liability insurance. Currently, the amount is about $400 million. Damages exceeding that amount 

would be funded with a retroactive assessment on all other firms owning commercial reactors based upon the 

number of reactors they own. However, Price-Anderson places a limit on the total liability to all owners of 

commercial reactors of about $12 billion.

 

13 The Pew Charitable Trusts, Subsidy Scope, http://subsidyscope.org/tax_expenditures/db/group/31/?estimate=1&year=2001.
July 2011

4 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Organization of Report

In addition to this introductory chapter, this report contains five chapters. Chapter 2 reports on energy-related tax 

expenditures and direct expenditures. Chapter 3 discusses subsidies which are listed in the federal budget as R&D 

expenditures. Chapter 4 evaluates support associated with federal electricity programs. Chapter 5 analyzes loan 

guarantee subsidies associated with recent legislation. Since this report is essentially an update of the report 

prepared in 2008, it focuses on providing revised tabular information and generally limits discussion to areas 

where changes were made or new methodologies were used. Readers are referred to the earlier report and other 

supporting documents for more information.14

 

14 Energy Information Administration, Federal Financial Interventions and Subsidies in Energy Markets 2007, Washington, DC, 20585, April 

2008, available at http://www.eia.gov/oiaf/servicerpt/subsidy2/index.html. 
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 5 

2. Tax Expenditure and Direct Expenditures

Overview

This chapter focuses on energy-specific federal tax expenditures and direct expenditures that subsidize activities of 

energy producers and consumers. 

In FY 2010, energy-related tax expenditures are estimated at $16.3 billion (2010 dollars) (Table 1). This represents 

an increase of $4.8 billion (42 percent) from the estimated $11.5 billion in energy-related tax expenditures in EIA's 

2007 report. Most of this increase is accounted for by changes in a small number of tax expenditure programs, 

notably the tax credit for alcohol fuels, up $2.2 billion between FY 2007 and FY 2010, and credits for energy 

efficiency improvements to existing homes, which increased by $2.8 billion over the same period. As discussed 

below, increases and decreases in other energy-specific tax expenditures between FY 2007 and FY 2010 came close 

to no net change, with the sharp drop in tax credits for coal-based synfuels nearly balancing increases in other tax 

expenditures.. 

For several decades, policies in the federal budget affecting energy production have largely been exercised 

through the Internal Revenue Code (Tax Code or IRC). Recently, in order to inject funds more quickly into a weak 

economy, ARRA made more prominent use of direct spending. This was done with the intention of providing 

capital to investors with little or no taxable income to offset during the financial crisis. The most significant of 

these new grants arose from Section 1603 of ARRA. As with the pre-existing PTC and ITC for eligible renewable 

electricity technologies, this grant has been used primarily to fund wind power investments. Eligible investors 

have elected to take the cash grant over the ITC or PTC by a wide margin. Direct expenditure programs to support 

biofuels saw funding rise to $300 million by FY 2010 with the addition of several new programs after FY 2007. 

Turning from production to consumption, a sizable gain in LIHEAP funding, which increased by $2.7billion between 

FY 2007 and FY 2010 also lifted direct expenditures, which in total were up $11.5 billion from FY 2007. 

Tax Expenditures

Energy tax expenditures are broadly defined as provisions in the IRC that provide beneficial tax treatment to 

taxpayers who produce, consume, or economize on energy in ways that are deemed to be in the public interest. 

Tax expenditures are not treated in budgetary terms as federal spending even though they have a similar impact 

on the budget. Energy-specific tax expenditures for FY 2007 together with FY 2010 estimates are reported in Table 

1. 

The federal budget lists tax expenditures, pursuant to the Congressional Budget Act of 1974 (Public Law 93-344), 

which defines them as “revenue losses attributable to provisions of Federal tax laws, which allow a special 

exclusion, exemption, or deduction from gross income or provide a special credit, preferential rate of tax, or 

deferral liability.” 

Tax expenditures arise from provisions in federal tax laws including credits, deductions, deferrals, preferential 

rates, and exemptions (exclusions), as briefly described below. 

Tax Credit. A tax credit is an amount deducted directly from income tax otherwise payable. For Instance, the 

HOPE credit can lower an eligible party’s tax bill by a fixed amount per child for the first two years of their college 

education.
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6 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Tax Deduction. A tax deduction is an amount deducted from taxable income to arrive at adjusted taxable income. 

An example is the mortgage interest deduction available to homeowners.

Tax Deferral. A tax deferral allows for payment of a tax in a later year, providing in essence an interest free loan. 

The Office of Management and Budget (OMB) reports the annual value of tax expenditures for tax deferrals on a 

cash basis. The OMB notes that “although such estimates are useful as a measure of cash flow into the 

government, they do not accurately reflect the true economic cost of the provisions. For example, for a provision 

where activity levels have changed, so that incoming tax receipts from past deferrals are greater than deferred 

receipts from new activity, the cash-basis tax expenditure estimate can be negative, despite the fact that in 

present value terms current deferrals have a real cost to Government.”

Preferential Tax Rate. A preferential tax rate treats certain forms of taxable income more favorably than other

income. One example is the lower tax rate applied to capital gains. 

Tax Exclusion. A tax exclusion exempts a portion of income from taxation. For example, employee provided 

health insurance can often be excluded from income.

Table 1. Estimates of energy-specific tax expenditures 

(million 2010 dollars)

Tax Expenditures FY 2007 FY 2010

Expensing of Exploration and Development Costs 551 400

Exception from Passive Loss Limitation for Working Interests in Oil and Gas Properties 31 30

Excess of Percentage over Cost Depletion 822 980

Capital Gains Treatment of Royalties on Coal 187 50

Alcohol Fuel Credits 42 70

Qualified Energy Conservation Bonds - - 

Alternative Fuel Production Credit 3,038 170

Energy Investment Credit - 130

Energy Production Credit 426 1,540

Tax Credit and Deduction for Clean-Burning Vehicles 270 250

Biodiesel land Small Agri-Biodiesel Producer Tax Credits 187 20

Alcohol Fuel Exemptiona 3,454 5,680

Biodiesel Producer Tax Credita 490

Exclusion from Income of Conservation Subsidies Provided by Public Utilities 125 220

Credit for Holding Clean Renewable Energy Bondsb 21 70
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 7 

Table 1. Estimates of energy-specific tax expenditures (cont)

(million 2010 dollars)

Tax Expenditures FY 2007 FY 2010

Deferral of Gain from Disposition of Transmission Property to Implement FERC Restructuring 

Policy 635 (50)

Credit for Investment in Clean Coal Facilities 31 240

Credit for Production from Advanced Nuclear Power Facilities - - 

Temporary 50-Percent Expensing for Equipment used in the Refining of Liquid Fuels 31 760

Natural Gas Distribution Pipelines being Treated as 15-Year Property 62 120

Amortize all Geological and Geophysical Expenditures over 2 Years 52 150

Allowance for the Deduction of Certain Energy Efficient Commercial Building Property 198 60

Credit for Construction of New Energy Efficient Homes 21 20

Credit for Energy Efficiency Improvements to Existing Homes 395 3,190

Credit for Energy Efficient Appliances 83 150

Credit for Residential Energy Efficient Property 10 220

Credit for Business Installation of Qualified Fuel Cells and Stationary Microturbine Power 

Plants 83 - 

Partial Expensing for Advanced Mine Safety Equipment 10 3 

Expensing of Capital Goods with Respect to Complying with EPA Sulfur Regulations 10 - 

Exclusion of Special Benefits for Disabled Coal Miners 31 40

Transmission Property Treated as Fifteen-Year Property 19 100

5-Year Net Operating Loss Carryover for Electric Transmission Equipment 43 - 

Amortization of Certain Pollution Control Facilities 31 100

Nuclear Decommissioning 600 900

Advanced Energy Manufacturing Facility Investment Tax Credit - 180

Total 11,501 16,284

Note; Total may not equal sum due to independent rounding.

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.

a

The alcohol fuel exemption (VEETC) is essentially the excise tax exemption equivalent to the Alcohol Fuel Credits. The Biodiesel Producer 

Tax Credit is the excise tax exemption to the Biodiesel and Small Agri-biodiesel Producer Tax Credits. These are both listed as footnotes to an 

OMB table which includes energy tax expenditures. b

In addition, the provision has an outlay effectof $10 million in 2010.
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8 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

The determination of what exactly is a preferential provision is subject to interpretation. Items in the budget 

identified as tax expenditures by the U.S. Treasury Department on occasion differ from those determined to be tax 

expenditures by the Joint Committee on Taxation (JCT)—the two bodies which produce these estimates. Historical 

tax expenditure data used in this report are taken from a number of government sources. For FY 2010, the 

Treasury Department is the primary provider of estimates for tax expenditures, supplemented by data provided by 

the JCT.

Tax Expenditure Caveats

Each year the U.S. Treasury Department estimates tax expenditures for the upcoming fiscal year budget. This data 

appears in the Office of Management and Budget document, Analytical Perspectives of the United States Budget. It 

is important to recognize that tax expenditure data are estimates and forecasts. Furthermore, prior year tax 

expenditure estimates may be substantially revised. However, a particular year’s revision will not necessarily 

affect all past estimates. Additionally, the methodology used to estimate tax expenditures is subject to periodic 

modification and these changes are not always applied to revisions of all historical tax expenditure data.

This report uses tax expenditure estimates for FYs 2007 and 2010. Sizable changes in the dollar value of particular 

expenditures over time often reflect changes in their utilization due to changes in the IRC, key interpretations of 

the IRC, or in other key market and policy drivers. The historical data also reveal when particular energy programs 

were implemented and terminated. Although there are gaps in the data for some years, generalized trends in tax 

expenditures are still apparent. Readers of this report are cautioned that some of the tax expenditure data 

presented in this report will be revised in the future and that some of the historical data presented here have not 

been fully revised. This report sums annual tax expenditures across various programs. These summations should 

be treated with care as the Treasury Department cautions that the estimates would be different if tax 

expenditures were changed simultaneously because of potential interactions among provisions. 

In many cases, the level of energy production or investment determines the potential value of the tax expenditure 

for qualified taxpayers. However, the value of the tax expenditure received by eligible taxpayers may not equal the 

potential value of the expenditure based upon production or investment. One factor mitigating against the eligible 

party receiving the full value of the tax expenditure is the alternative minimum tax (AMT), a separately calculated 

tax that eliminates many deductions and credits for which many tax expenditures are not exempt. Another 

mitigating factor is that a tax expenditure, in many cases, may not be received in the year in which the investment 

or production took place, but may, by law, be carried back or forward a number of years. 

The Treasury Department does not provide estimates of de minimis tax expenditures, i.e., $5 million or less. 

Therefore, the impact of these tax expenditures is not reported in either OMB budget documents or this report. 

Also, this report does not address in a quantitative manner energy legislation that has recently been passed and 

for which the budgetary impact has not yet been assessed by the OMB for FY 2010 or for future years. A case in 

point is Section 1306 of EPAct2005 which provides a production tax credit for eligible nuclear power sales. This 

credit does not have a value until such time as an eligible plant is producing electricity, which is not anticipated to 

occur until after FY 2015.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 9 

Energy-Specifc Tax Expenditure Programs

Coal-Related Tax Expenditures

Over 90 percent of coal is consumed by the electricity sector. Coal-fired generation accounted for 45 percent of 

total electricity generation in 2010. However, coal was estimated to be a relatively small recipient of tax 

expenditures in FY 2010, with an estimated value of $561 million in FY 2010, down from $3.3 billion in FY 2007 

(Table 2). The alternative fuel production tax credit for refined coal was the largest tax expenditure related to coal 

use during FY 2007, but the relevant provisions of the IRC were not available for production beyond 2007. The 

credit for clean coal facilities, in contrast, showed a marked gain over FY 2007 spending. While coal is also eligible 

for percentage depletion and expensing of exploration and development costs, there are no data to break these 

out by fuel type and they are not included in the estimate of coal-related tax expenditures for FY 2010.

Table 2. Coal-related tax expenditures 

(million 2010 dollars)

Tax Expenditure Type FY 2007 FY 2010

Exclusion of Special Benefits for Disabled Coal Miners Exemption 31 40

Partial Expensing for Advanced Mine Safety Equipment Expense Deduction 10 3 

Credit for Investment in Clean Coal Facilities Credit 31 240

Capital Gain Treatment of Royalties in Coal Preferential Tax Rate 187 50

Amortization of Pollution Control Equipment Expense Deduction 31 100 

Advanced Energy Property Credit Credit 0 1 

Energy Production Credit (Refined coal and Indian coal 

credits) Credit 0 27

Subtotal Coal Tax Expenditures 290 461

Alternative Fuel Production Credit (Synthetic coal, 

Coke and coke gas credit, and Steel industry fuel) Credit 3,038 100 

Total Coal and Refined Coal Tax Expenditures 3,329 561

Notes: Totals may not equal sum of components due to independent rounding. The advanced energy property credit was allocated by fuel using 

data appearing in: http://www.whitehouse.gov/the-press-office/president-obama-awards-23-billion-new-clean-tech-manufacturing-jobs. EIA 

estimated that $12 million of the new technology credit is directed at refined coal. This credit appeared under the alternative fuel production 

credit in 2007. 

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.

Exclusion of Special Benefits for Disabled Coal Miners. Disability payments to former coal miners out of the Black 

Lung Trust Fund are generally excluded from taxable income. This provision is categorized by the Treasury 

Department as an income security tax expenditure. The value of this expenditure is estimated at $40 million in FY 

2010 versus $31 million in FY 2007.

Partial Expensing of Mine Safety Equipment. Section 404 of the Tax Relief and Welfare Act of 2006 (Public Law 

109-432) allowed qualified mine safety equipment to be expensed rather than capitalized. Its value for FY 2007 is 

estimated at $10 million. This tax expenditure expired on December 31, 2008. However, in 2010, the Tax Relief, 
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10 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Public Law 111-312) extended this credit 

through the end of 2011. The value of this tax expenditure was $3 million in 2010.

Credit for Investment in Clean Coal Facilities. This credit has an estimated value of $31 million in FY 2007 and 

$240 million in FY 2010. Section 1307 of the EPAct 2005 provided for a 20-percent credit to coal gasification 

projects using integrated gasification combined-cycle (IGCC) technology and a 15-percent credit to other advanced 

coal technologies. It allocated $800 million tax credits towards electricity-related IGCC projects and $500 million 

towards other advanced coal technologies. An additional $350 million was applied to coal gasification technologies 

for industrial use. Eligible plants are expected to achieve a 90-percent reduction in SO2 and a 90-percent reduction 

in mercury. The Energy Improvement and Extension Act of 2008 authorized an additional $1.5 billion in tax credits 

for clean coal, $1.5 billion for advanced coal-based generation technologies that sequester at least 65 percent of 

CO2, and $250 million for projects that sequester 75 percent of CO2. Section 112 of the Energy Improvement and 

Extension Act included an income tax credit for coal gasification investments. In July 2010, the U.S. government 

awarded a $417-million investment tax credit to builders of the 602-megawatt Taylorville "clean coal" power plant 

with carbon capture and storage in south central Illinois. The Taylorville plant is designed to capture at least 65 

percent of its CO2 emissions. Construction of the Taylorville plant has encountered delays as the Illinois state 

senate has yet to approve construction.

Capital Gains Treatment of Royalties on Coal. The estimated value of this credit in FY 2010 was $50 million down 

from $187 million in 2007. Owners of coal mining rights who lease their property usually receive royalties on 

mined coal. If the owners are individuals, these royalties can be taxed at a lower individual capital gains tax rate 

rather than at the higher individual top tax rate.

Amortization of Pollution Control Equipment. This provision was added by EPAct2005, under Section 1309. In 

general, a taxpayer may elect to recover the cost of any certified pollution control facility over a period of 60 

months. A certified pollution control facility is defined as a new, identifiable treatment facility which (1) is used in 

connection with a plant in operation before January 1, 1976, to abate or control water or atmospheric pollution or 

contamination. A certified air pollution control facility (but not a water pollution control facility) used in 

connection with an electric generation plant which is primarily coal fired is eligible for 84-month amortization if the 

associated plant or other property was not in operation prior to January 1, 1976. The 60-month amortization 

period remains in effect for any certified air pollution control facility used in connection with an electric generation 

plant which is primarily coal fired and which was in operation prior to January 1, 1976. The JCT estimated the 

value of this expenditure to be $31 million for FY 2007 and $100 million for FY 2010.

Advanced Energy Property Credit. This credit, whose impact is largest on renewable fuels, is discussed later in this 

chapter. However, an estimated $1 million of this credit was directed at two Carbon Capture and Storage (CCS) 

projects in 2010.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 11

Energy Production Credit (Refined coal and Indian coal). In total, these credits are estimated to be $27 million in 

2010.

Refined Coal. This tax credit was created in the American Jobs Creation Act of 2004. Section 45 

of the Internal Revenue Code, dealing with the refined coal production credit, provides guidance 

for this tax credit. In 2009, the section 45 tax credit was about $6.20 per ton of refined coal. To 

qualify for the credit, facilities had to meet two tests: (1) the facility must be placed in service 

after October 22, 2004 and before January 1, 2012; and, (2) facilities placed in service after Dec. 

31, 2008 must produce refined coal that reduces emissions of nitrogen oxide by at least 20 

percent and at least 40 percent of either sulfur dioxide or mercury compared to the emissions 

released when burning the original feedstock coal or comparable coal. The 40-percent reduction 

for sulfur dioxide or mercury is relaxed to a 20-percent reduction for facilities placed in service 

before Dec. 31, 2008. The lower tax credit per ton and the emission reduction requirements 

provided a much reduced set of opportunities compared to the prior coal synthetic fuel credit 

program. In 2009, only one refined coal facility operated in the U.S. and it produced only about 

100,000 tons of refined coal. Two additional refined coal plants are scheduled to begin operating 

in 2010. The value of the refined coal tax credit is expected to be about $12 million in FY2010. 

Indian Coal. The credit in 2010 for coal produced from reserves owned by an Indian tribe or held 

in trust by the U.S. for an Indian tribe was $2.20 per ton. The qualifying Kayenta mine in Arizona, 

produced about 7.7 million short tons in 2010 and earned a credit of about $15 million.

Alternative Fuel Production Credit (Synthetic coal, Coke and coke gas credit, and Steel industry fuel). In total, 

these credits are estimated to be $100 million in FY 2010, all attributable to the coke and coke gas tax credit.

Synthetic coal. In FY 2007, the value of this credit for synthetic fuel produced from coal, and 

biomass, at $3.0 billion, made it the second largest tax expenditure. However under the Code, 

the credit was available only for synthetic fuel produced from coal and biomass sold up through 

2007. Absent the tax credit, none of the 59 coal synthetic plants producing about 140 million 

tons of coal synfuel in 2007 remained profitable and all ceased production at the end of 2007. 

Coke and coke gas. Currently the alternative fuel section 45 K credit (formerly section 29) is still 

available for coke and coke gas. The tax credit is about $30/ton of coke produced. Credit-eligible 

coke at any one facility many not exceed an average barrel-of-oil equivalent of 4,000 barrels per 

day, which is approximately 1,000 tons of coke per day, 360,000 tons of coke per year, and about 

$11 million in tax credit per plant. The original owner of the coke plant must still be its owner. 

There are 20 coke plants in the U.S. Some have been resold. The cumulative value of the tax 

credit is estimated to be $100 million in 2010. Some of this credit may be carried forward, 

depending upon profit prospects at specific coke plants.

Steel Industry Fuel. Steel industry fuel, which is included as a type of refined coal under the 

American Jobs Creation Act of 2004, is produced through a process of liquefying coal waste 

sludge, distributing the liquefied product on coal, and using the resulting mixture as a feedstock 

for the manufacture of coke. The credit in 2010 is $2.87 per ton of barrel-of-oil equivalent 

produced and sold. Coke plants can claim either the coke and coke gas credit or the steel 
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12 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

industry fuel credit, but not both within a given year. Because the coke and coke gas credit is 

much larger per ton and usually covers more tons than the steel industry fuel credit, coke plants 

are choosing to take the coke and coke gas credit for now. The time period for the steel industry 

fuel credit is 1 year from the placed-in-service date, which can be as late as Dec. 31, 2011. Unless 

there is an extension to the credit period, there probably will be very little or no tax credit 

claimed for producing steel industry fuel. 

Renewable-Related Tax Expenditures

At $8.2 billion, renewable-related tax expenditures in FY 2010 were more than double their FY 2007 $4.1 billion 

(Table 3) largely due to the expanding U.S. ethanol industry and expanded renewable production of electricity 

(Table 4). The Volumetric Ethanol Excise Tax Credit (VEETC) continued to be the largest renewable-related tax 

credit in FY 2010 as was the case in FY 2007.15

The Alcohol Fuel Credit is the sum of some smaller credits for which tax revenue losses have not been estimated. 

They include the Alcohol Mixture credit, the Alcohol Credit, and the Cellulosic Biofuel Credit. The Alcohol Fuel 

Credit also contains a Small Ethanol Producer Credit, which provides qualified producers with tax credit worth 10 

cent per gallon of ethanol. To be eligible, the ethanol producer must have productive capacity less than 60 million 

gallons per year with the credit being applied to the first 15 million gallons. 

 This credit accounted for nearly 70 percent of tax expenditures 

directed at renewable sources of energy. Renewables accounted for 10 percent of total electricity production in 

2010, primarily due to conventional hydroelectricity, which does not receive significant support from renewablerelated tax expenditures. However, wind power has shown considerable growth in recent years, and in 2010 

provided 2.3 percent of total U.S. electricity generation. Wind power has received significant support from The 

New Technology credit and the investment tax credit, as well as from the ARRA Section 1603 grant program that is 

discussed in the Direct Expenditures section of this chapter. 

In recent years this credit has seen dramatic swings in value. This occurred because tax specialists working for the 

pulp and paper industry realized that this credit could be applied to the mixture of black liquor with conventional 

fuels and the paper industry began claiming this credit in 2008. An estimated $4 billion went to the pulp and paper 

industry in 2009 due to this credit.16

The Volumetric Ethanol Excise Tax Credit (VEETC) is related to the Alcohol Fuel Credit. VEETC is not directed at 

ethanol producers but rather to facilities that blend ethanol with gasoline. At $5.7 billion, it is estimated to be the 

largest energy-related tax provision in FY 2010. In FY 2007, VEETC’s had a value estimated at $3.5 billion and was 

also the largest energy-related revenue reduction in that year. Historically, alcohol fuels have received the greatest 

amount of federal financial support in the way of energy tax expenditures. In 2004 Section 301 of the American 

Subsequently, the eligibility of black liquor was removed and the value of the 

credits fell to $70 million in 2010. 

 

16 As a footnote to the alcohol fuels credit in the table which lists energy tax expenditures. 17 Congressional Budget Office, http://www.cbo.gov/ftpdocs/108xx/doc10871/Chapter4.shtml.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 13

Table 3. Renewable-related tax expenditures 

(million 2010 dollars)

 

Note: Totals may not equal sum of individual components due to independent rounding. The credit for business installation of qualified fuel cells 

and microturbine power plants is part of the investment tax credit (Section 48 of the code). The new technology credit included both the 

investment tax credit and the production tax credit in 2007. These were broken out in 2010 Similar to the alcohol fuel credit, the credit can be 

taken as an income tax credit or an excise tax credit. The small producer credit is only available as income tax credit. a The Alternative Fuel 

Production credit in 2007 went primarily to coal. 

b In addition, the provision has outlay effects of (in millions of dollars): 2010; $10; 2011 $20; 2012 $30; 2013 $30; 2014 $30; 2015 $30; 2016 

$30.

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.

Table 4. U.S. renewable net generation 

(billion kilowatthours) 

Fuel 1970 1980 1990 2000 2010

Conventional Hydroelectric 251.96 279.18 292.87 275.51 257.05 

Wood 0.14 0.28 32.52 37.9 37.97 

Waste 0.22 0.16 13.26 23.13 18.56 

Geothermal 0.53 5.07 15.43 14.09 15.67 

Solar/PV NA NA 0.37 0.49 1.30 

Wind NA NA 2.79 5.59 94.65 

 Total 251.84 284.69 357.24 356.48 425.20 

Source: U.S. Energy Information Administration, Annual Energy Review, 2009, DOE/EIA-0384 (2009) (Washington, DC, August 2010), Table 

8.2a, and Monthly Energy Review, DOE/EIA-0035(2011/04) (Washington, DC, April 2011), Table 7.2a.

Tax Expenditures Type FY 2007 FY 2010

Alcohol Fuel Credit Credit 42 70 

Excise Taxes/VEETC (ethanol fuel) Credit 3,454 5,680 

Alternative Fuel Production Credita Credit 0 70

New Technology Credit (Energy Production Credit) Credit 426 1,513 

Energy Investment Credit Credit 0 130 

BioDiesel Producer Credit Credit 0 490

BioDiesel and Small Agri-Biodiesel Producer Tax Credit Credit 187 20 

Credit for Holding Clean Renewable Energy Bondsb Credit 21 70 

Advanced Energy Property Credit Credit 0 125 

 Total 4,130 8,168 
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14 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Jobs Creation Act (AJCA) (Public Law 108-357) instituted the VEETC as a replacement for the excise tax exemption 

for alcohol fuels. Initially, VEETC provided ethanol blenders/retailers with 51 cents per gallon of ethanol or $.0051 

per percentage point of ethanol blended in motor gasoline. VEETC was extended by the Food, Conservation, and 

Energy Act of 2008 in Section 15331 of Public Law 110-234, although the rate was lowered to 45 cents per gallon. 

Public Law 110-246 also extended ethanol import duties and established new loan and grant programs. The Tax 

Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Public Law 111-312) extended this 

credit (under IRC § 6426 and 6427) through the December 31, 2011. Ethanol production reached a record level of 

over 860,000 barrels per day in 2010. 

Production Tax Credit In 2007, this credit, along with the energy Investment Tax Credit discussed below, were 

combined to form the New Technology Credit. This credit is frequently referred to as the as the Section 45 credit 

for its applicable provision in the Code. Section 242 of EPAct2005 expanded the tax credit to include incremental 

hydroelectric generation for a 10- year period at 1.8 cents per kilowatthour. EPAct2005 also extended the inservice date to qualify for the credit by 2 years for closed-loop biomass, geothermal, landfill gas, irrigationproduced power, landfill gas, municipal solid waste, open-loop biomass, and wind facilities. For qualifying openloop biomass, geothermal, solar, and small irrigation power facilities, the credit period was expanded from 5 to 10 

years. The production tax credit is estimated at $1.5 billion in FY 2010 versus $426 million in FY 2007. The Treasury 

Department forecasts that the production tax new technology credit will exceed $1.5 billion per year between 

2011 and 2016. Wind power is estimated to be the primary beneficiary of the credit in FY 2010. Section 1603 of 

ARRA offered a cash grant in lieu of the production tax credit. This cash grant is discussed in the direct expenditure 

section later in this chapter.

Section 101 of the Energy Improvement and Extension Act of 2008 (Public Law 110-343) extended the placed-inservice date for the Production Tax Credit through December 31, 2009 (1 year) for wind and refined coal, and 

through December 31, 2010 (2 years) for other eligible sources (geothermal, some biomass, landfill gas, 

hydroelectric facilities) by amending Section 45 of the Code. EIEA added several new sources of energy to become 

eligible for the tax credit through December 31, 2016. Section 102 extended the credit to include marine and 

hydrokinetic energy; Section 103 extended the credit for solar energy, fuel cells, and microturbine properties 

through December 31, 2016; and, Section 108 included steel industry fuel as a renewable resource. Section 1101 

of ARRA extended the eligibility dates for the credit for wind till January 1, 2013 and for other eligible facilities to 

January 1, 2014. 

The Energy Investment Tax Credit is the alternative to the Production Tax Credit discussed above. Section 1102 of 

ARRA allowed for the election of an Investment Tax Credit in lieu of the production credit for businesses property 

placed in service facilities that produce electricity from solar and geothermal energy property, qualified fuel cell 

power plants, stationary microturbine power plants, geothermal heat pumps, small wind property and combined 

heat and power property after December 31, 2008. Investors can either chose the energy Investment Tax Credit, 

which generally provides for a 30-percent tax credit, or a 1.2-cent-per-kilowatt hour electricity Production Tax 

Credit. 

The energy Investment Tax Credit offers a 30-percent energy tax credit for the purchase of qualified fuel cells with 

a maximum of $1,500 per 0.5 kilowatt of capacity, with a cap of $500 for each 0.5 kilowatt of capacity placed in 

service before October 24, 2008. A 10-percent credit is applied to qualifying stationary mircroturbine power plants. 

For qualified microturbine property, the nameplate capacity must be less than 2,000 kilowatts and the electricity-
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 15

only efficiency must exceed 26 percent of International Standard Organization conditions. For qualified fuel cells, 

in order to qualify for the credit, the plant must have an electricity-only efficiency of 30 percent or more and 

capacity of at least 0.5 kilowatts of power generation. This provision is included in Section 48 of the Code.

Section 201 of the Tax Relief and Health Care Act (109-432) extended the credit through December 31, 2008. 

Section 103 of EIEA (Public Law 110-343) increased the credit limit for fuel cells from $500 to $1,500 per half 

kilowatt of capacity. EIEA extended the 30-percent investment tax credit (ITC) for solar power, previously set to 

expire on December 31, 2008, to December 31, 2016, and also eliminated the $2,000 cap on the tax credit. Solar 

power capacity has grown from 1,350 MWs in 2008 to 2,950 MWs in 2010.17

The BioDiesel and Small Agri-Biodiesel Producer Tax Credit This credit has an expected value of $20 million in FY 

2010. Section 313 of the AJCA created a $1-per-gallon credit for the sale of agri-biodiesel fuel. The credit applied to 

"virgin" agricultural feedstock such as soybeans or cotton-seed. A 50-cent credit is provided to biodiesel produced 

from recycled grease. Initially, the credit was due to expire at the end of 2006. Section 1344 of EPAct2005 

extended the credit though the end of 2008. Section 202 of EIEA further extended the tax credit for biodiesel and 

renewable diesel to December 31, 2009. EIEA also increased the amount of the tax credit for biodiesel and 

renewable diesel produced from recycled feedstock from 50 cents to one dollar. ARRA also increased the amount 

of the tax credit for biodiesel and renewable diesel produced from recycled feedstock. Section 202 of ARRA 

amended Section 40A of the Code to extend the $1 per gallon production credit for biodiesel and the 10 cent per 

gallon credit for small biodiesel producers through December 31, 2009. Section 202 also extended the credit to 

biomass diesel. Section 701 of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 

2010 (Public Law 111-312) retroactively extended the credit for biodiesel and renewable diesel for two years, 

through December 31, 2011. The Small Agri-Biodiesel Producer Tax Credit is purely an income tax credit and is 

worth 10-cents-per-gallon credit for up to 15 million gallons of agri-biodiesel produced by small producers.

EIA expects penetration of 10,420 

MWs of solar capacity, including residential capacity, to be in place by 2016. Due to the desirability of the “grant” 

in lieu of the production tax credit and investment tax credit, $444 million, or 11 percent of the Section 1603 grant 

will be used to fund solar power projects in 2010. Section 104 of EIEA allowed for the energy investment credit to 

be applied to small wind property with a nameplate capacity of under 100 KW, with a termination date of 

December 31, 2016. Section 1103 of ARRA removed the cap on the ITC for small wind property that was 

established in EIEA and provided a tax credit for investments in generating, storing, conserving and distributing 

renewable energy, advanced battery technology, carbon capture and sequestration, and next-generation” 

technologies. Section 1122 of American Recovery and Reinvestment Act (Public Law 111-5) reinstated the $500-

cap on fuel cell property expenditures per kilowatt of capacity.

Similar to the Alcohol Fuel Credit, the Biodiesel Credit can be taken as an income tax (under Code 40A) or as an 

excise tax credit (under Code 6426). The Biodiesel Tax Credit is limited to biodiesel not mixed with conventional 

diesel fuel. In lieu of the Biodiesel Tax Credit, there is an excise tax exemption. The value of this exemption was 

estimated at $490 million in 2010. The Biodiesel Fuel provisions include: (1) A Biodiesel Mixture Credit, which is 

$1.00 for each gallon of biodiesel and agri-diesel used by the taxpayer in the production of a qualified biodiesel 

mixture. This can be taken as a fuel which is a blend of biodiesel and diesel, as either an income tax credit or an 

excise tax credit.

 

17 Energy Information Administration, Annual Energy Outlook, 2011 DOE/EIA-0383(2011) (Washington, DC, April, 2011). 

http://www.eia.gov/forecasts/aeo/source_renewable.cfm,Table 6.
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16 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

The Credit for Holding Clean Renewable Energy Bonds This credit was established under Section 1303 of 

EPAct2005, which provided for the issuance of Clean Renewable Energy Bonds (CREBs) through December 31, 

2007. Purchases of CREBs bonds are to be provided with a tax credit in an amount intended to provide an after-tax 

return equal to that of a comparable taxable investment. In 2006, amendments added $400 million to CREBS and 

extended the deadline to December 31, 2007. New CREBs (NCREBs) were added in 2008 with an $800 million cap 

by Section 107 of EIEA. ARRA authorized an additional $1.6 billion from qualifying facilities. Whereas CREBS receive 

an exemption on interest, NCREBs are tax credit bonds.

Eligible participants in CREBs and NCREBS include: State and local governments, U.S. territories and possessions, 

the District of Columbia, Indian tribal governments, the National Rural Utilities Cooperative Finance Corporation, 

and mutual or cooperative electric entities. Prior to passage of EPAct2005, only investor-owned utilities (IOUs) 

qualified to receive tax incentives for producing electricity from renewable energy resources. In essence, CREBS 

allowed non-IOU electricity providers to issue interest free bonds to finance qualified energy projects. CREBS 

applied to the following sources of energy: wind, closed-loop biomass, open-loop biomass, geothermal, solar, small 

irrigation hydro, land fill gas, municipal solid waste, refined coal, and qualifying hydro. The value of the CREB tax 

credit is estimated at $21 million in FY 2007 and $70 million in 2010 in NCREB revenue losses in 2010. Section 202 

of the Tax Relief and Health Care Act of 2006 (Public Law 109-432) increased the allocation of CREBs to $1.2 billion 

and extended the deadline to December 31, 2008. NCREBs effectively replaced CREBs in 2008, NCREBS do not have 

a defined expiration date. However, NCREBS allocations are valid for 3 years after which any unused authority 

reverts to the Treasury for reallocation. 

Under NCREBS, the bond purchaser can claim a 70-percent tax credit versus the 100 percent tax credit claimable 

under CREBS. The initial allocation of NCREBs was capped at $800 million. Section 1111 of Public Law 111-5 

increased the amount of funds available for NCREBs to $2.4 billion. Section 301 of the Hiring Incentives to Restore 

Employment Act 2010 (Public Law 111-147) offered issuers the option of converting NCREBs from tax credits to 

direct subsidy bonds similar to the Build America Bonds (BABs) whereby the NCREB issuer pays investors a taxable 

coupon and receives a direct payment from the U.S. Treasury. The U.S. Treasury estimated that the value of 

NCREBs was $70 million in 2010. There is, however, an associated outlay, which appears as a direct expenditure. 

NCREBS have an outlay equivalent effect of $10 million in 2010.

Advanced Energy Property Investment Tax Credit (Renewables) Section 1302 of ARRA established a credit 

providing a 30-percent credit for investment in eligible property used in a qualified advanced energy 

manufacturing project. This credit had a $125-million estimated value in FY 2010 directed at renewables. 

Renewables accounted for 69 percent of the recipients of this credit in 2010. Manufacturers of solar PV units, and 

wind towers, turbines, and blades were the largest recipients of this credit. A qualified advanced energy 

manufacturing project re-equips, expands, or establishes a manufacturing facility for the production of: (1) 

property designed to be used to produce energy from the sun, wind, geothermal deposits, or other renewable 

resources; (2) fuel cells, microturbines, or an energy storage system for use with electric or hybrid-electric motor 

vehicles; (3) electric grids to support the transmission of intermittent sources of renewable energy, including the 

storage of such energy; (4) property designed to capture and sequester carbon dioxide; (5) property designed to 

refine or blend renewable fuels (excluding fossil fuels) or to produce energy conservation technologies; (6) new 

qualified plug-in electric drive motor vehicles or components that are designed specifically for use with such 

vehicles; or, (7) other advanced energy property designed to reduce greenhouse gas emissions as may be 

determined by the Department of the Treasury. Eligible property must be depreciable (or amortizable) property 
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 17

used in a qualified advanced energy project and does not include property designed to manufacture equipment for 

use in the refining or blending of any transportation fuel other than renewable fuels. The credit is available only for 

projects certified by the Department of the Treasury (in consultation with the Department of Energy).

Table 5. NCREBs allocations by project type and issuer, 2009

(million 2010 dollars)

Approved 

Projects

Municipal Utilities Co-ops Governments Total

# of 

projects $ 

# of 

projects $ 

# of 

projects $ 

# of 

projects $ 

Solar 13 55 4 70 694 714 711 839

Wind 9 395 8 161 30 63 47 619

Landfill Gas 0 0 0 0 0 0 0 0 

Biomass 1 6 11 204 3 8 15 218

Hydropower 12 345 8 175 6 11 26 531

Geothermal 0 0 0 0 3 4 3 4 

Total 35 800 31 609 736 800 802 2,209

Note: The above data are estimates of the value of NCREB supported projects, not the value of the subsidy. Totals may not equal sum of 

components due to independent rounding.

Source: National Renewable Energy Laboratory. These estimates are incomplete as they lack some private placements.

The Credit for Holding Qualified Energy Conservation Bonds EIEA provided for $800 million in funding for a new 

category of tax credit bonds to finance state, local, and tribal governments initiatives designed to reduce 

greenhouse gases. Qualified Energy Conservation Bonds (QECBs) do not have a termination date and are directed 

at qualified conservation purposes, such as projects which reduce energy consumption in publicly-owned 

buildings, green community programs, and rural development involving renewable energy production. Wind, 

biomass, geothermal, landfill gas, municipal solid waste, qualified hydroelectric power facilities were also made 

eligible for this credit as were certain energy research activities. A minimum of 70 percent of a state’s allocation 

must be used for governmental purposes, which the remainder may be used to finance private activity projects. 

Section 1112 of ARRA increased the amount of funds available to finance QECBs by $2.4 billion to $3.2 billion. 

Section 301 of the Hiring Incentives to Restore Employment (HIRE) Act 2010, (Public Law 111-147) gave issuers the 

option of converging QECBs from tax credit bonds to direct subsidy bonds similar to BABs whereby the QECB issuer 

pays investors a taxable coupon and receives a direct payment from the U.S. Treasury. The U.S. Treasury estimates 

the income tax effect of QECBs will be $10 million in FY 2011, having had no value in prior years. There is, 

however, an associated outlay, which appears as a direct expenditure.
July 2011

18 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Natural Gas and Petroleum-Related Tax Expenditures

Natural gas and petroleum-related tax expenditures grew from $1.9 billion in FY 2007 to $2.7 billion in FY 2010 

(Table 6). Natural gas-fired generation accounted for an estimated 24 percent of total electricity production in 

2010, while oil provided less than one percent of electricity generation.

The Expensing of Exploration and Development Costs Deferral Federal tax law allows energy producers, principally 

oil and natural gas producers, to expense exploration and development (E&D) expenditures rather than capitalize 

and depreciate them over time. In FY 2010, this tax expenditure estimate, at $400 million, was down from the 

$551 million estimated for FY 2007.

Table 6. Natural gas and petroleum related tax expenditures 

(million 2010 dollars)

Note: Totals may not equal sum of components due to independent rounding. A portion of the tax expenditures, but indeterminate amount, of the 

Excess of Percentage over Cost Depletion and the Expensing of exploration and Development Costs goes to coal. 

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration. 

Tax Expenditures Type FY 2007 FY 2010

Expensing of Exploration and Development Costs Deferral 551 400 

Credit for Business Installation of Qualified Fuel Cells and Stationary 

Microturbine Power Plants Credit

 

83

 

0 

Excess of Percentage over Cost Depletion Deferral 822 980

Amortize All Geological and Geophysical Expenditures over 2 Years Deferral 52 150

Tax Credit and Deduction for Clean-Burning Vehicles Credit 270 250

Natural Gas Distribution Pipelines Treated as 15-year Property Deferral 62 120

Exception from Passive Loss Limitation for Working Interests in Oil 

and Gas Properties Deferral

 

31 

 

30

Temporary 50 Percentage Expensing for Equipment Used in the 

Refining of Liquid Fuels Deferral

 

31 

 

760 

Expensing of Capital Costs with Respect to Complying with EPA 

Sulfur Regulations Deferral

 

10 

 

0 

Total 1,914 2,690 
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 19

The Excess of Percentage over Cost Depletion Deferral Percentage depletion for oil and gas properties became 

law with the passage of the 1926 Revenue Act Under cost depletion, the annual deduction is equal to the nonrecovered cost of acquisition and development of the resource times the proportion of the resource removed 

during that year. Under percentage depletion, taxpayers deduct a percentage of gross income from resource 

production. In FY 2010 this deferral had a value of $980 versus $822 million in FY 2007. The Tax Relief and Health 

Care Act of 2006 (Public Law 109-342) extended for two years the present-law taxable income limitation on the 

provision for marginal production (through taxable years beginning on or before December 31, 2007). Section 706, 

of Public Law 111-312 extended the use of the limitation on percentage depletion for oil and gas from marginal 

wells through December 31, 2011. 

The Amortization of all Geological and Geophysical Expenditures Over 2 Years This provision provides that 

geological and geophysical (G&G) expenditures for domestic exploration of oil and natural gas be amortized over 2 

years. This tax expenditure was enacted in EPAct2005, Section 1329. This tax expenditure is estimated to be worth 

$150 million in 2010 versus $52 million in FY 2007. Section 503 of the Tax Increase Prevention and Reconciliation 

Act of 2005 (Public Law 109-222) scaled back this benefit by lengthening the amortization period for integrated 

petroleum companies to 5 years. A major integrated oil company is defined as a producer of crude oil which has an 

average daily worldwide production of crude oil of at least 500,000 barrels for the taxable year, which has gross 

receipts in excess of $1 billion for its last taxable year ending during calendar year 2005, and has an ownership 

interest of 15 percent or more in a refiner. The geological and geophysical deduction for major integrated oil 

companies was further amended by the Tax Increase Prevention and Reconciliation Act (Public Law 109-222) 

signed on May 17, 2006. Major integrated oil companies are required to substitute 5 years for the 24-month 

amortization period.

The Tax Credit and Deduction for Clean-Fuel, Alternative Fuel, and Electric Vehicles was initiated under Section 

1913 of the Energy Policy Act of 1992 (EPACT1992, Public Law 108-486) The value of the tax credit is estimated at 

$250 million in FY 2010 and $270 million in FY 2007. Subsequent legislation has further expanded this credit. Title II 

Section 205 of EIEA provided a tax credit for the purchase of new, qualified plug-in electric drive motor vehicles. 

Section 1141 of ARRA modified the law for PHEVs purchased after December 31, 2009. Section 1143 of ARRA 

provided a tax credit for PHEV conversion kits equal to 10 percent of converting the vehicle if placed in service 

after February 17, 2009 and before December 31, 2011. Section 1144, of ARRA, allowed for the treatment of 

alternative motor vehicle as a personal credit against the alternative minimum tax. Section 1123 of ARRA increased 

the credit for refueling properties. Section 711 of the Tax Relief, Unemployment Insurance Reauthorization, and 

Job Creation Act of 2010, (Public Law 111-312) extended this credit for two years. 

The Natural Gas Distribution Pipelines Treated as 15-Year Property Deferral This deferral was established by 

EPAct2005 (Section 1308) and is estimated to have a value of $120 million in FY 2010 and a value of $62 million in 

FY 2007. Section 1308 accelerated the recovery period for natural gas distribution lines from 20 years to 15 years. 

This provision, which began in 2005, ended in 2010.

The Exception from Passive Loss Limitation for Working Interest in Oil and Natural Gas Properties Deferral The 

value of this tax credit in FY 2010 is $30 million versus an estimated at $31 million in FY 2007. The exception allows 

owners of working interests to offset their losses from passive activities against active income. Under normal rules, 

passive losses that remain after being netted against passive income can only be carried forward to apply against 
July 2011

20 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

passive income in future years. The exception from passive loss limitation provision on oil and natural gas 

properties applies principally to partnerships and individuals rather than corporations.

The Temporary 50-Percent Expensing of Equipment Used in the Refining of Liquid Fuels Deferral This provision 

was established under Section 1323 of EPAct2005 and expires on December 31, 2011. This provision is available for 

property, which is placed in service before January 1, 2014, which a binding construction contract has been 

entered into before January 1, 2010. It allows for an accelerated recovery of the cost of certain refinery 

investment under Section 179 C of the Code by allowing a partial expensing of the cost. It is estimated to have 

grown considerably from $31 million in FY 2007 to an estimated $760 million in 2010. EIEA extended this provision 

through December 31, 2013.

The Expensing of Capital Costs with Respect to Complying with Environmental Protection Agency Sulfur 

Regulations Deferral This provision was provided for in Section 1324 of EPAct2005. It allows small refiners (defined 

to employ less than 1,500 employees and have less than 205,000 barrels per day of total refining capacity) to 

deduct 75 percent of qualified capital costs related to complying with EPA sulfur regulations. “Qualified costs 

include expenditures for the construction of new process units or the dismantling and reconstruction of existing 

process units to be used in the production of low sulfur diesel fuel, associated adjacent or offsite equipment 

(including tankage, catalyst, and power supply), engineering, construction period interest, and site work.” The 

percentage of costs allowed is reduced for amounts in excess of 155,000 barrels a day of total refinery capacity. 

The estimated value of this tax expenditure is $10 million in FY 2007 and no value in FY 2010 as this credit expired 

December 31, 2009. 

The Enhanced Oil Recovery Credit This credit enables taxpayers to claim a general business credit for enhanced oil 

recovery (EOR) investment. The EOR credit applies to 15 percent of the cost of one or more tertiary recovery 

methods. EOR involves the extraction of oil from a petroleum reservoir greater than that which can be 

economically recovered by conventional primary and secondary methods. The credit also applies to the 

construction of a natural gas treatment plant in Alaska to process Alaskan natural gas for pipeline transportation. 

The credit phases out when the inflation-adjusted price of oil exceeds $28 per barrel (in 1991 dollars) in the 

preceding year. Due to the average price of oil in 2010 being above the cap, the value of this credit was zero in FY 

2010.

Nuclear-Related Tax Expenditures

EPAct 2005 extended the Production Tax Credit to approved new nuclear facilities. The credit for the production 

from advanced nuclear power facilities had no value in 2010 as this credit does not go into effect until qualifying 

new nuclear power plants produce electricity (Table 7). The Code was also modified to eliminate impediments to 

the transfer of ownership of nuclear plants arising from the tax treatment of qualified and nonqualified nuclear 

decommissioning trust funds. Because these particular revisions to the Code were not itemized by OMB, EIA relied 

on the estimates of the value of these tax expenditures prepared by the JCT. A small portion of the advanced 

energy property tax credit was also directed to nuclear facilities.

The Credit for the Production of Advanced Nuclear This credit was established under EPAct2005 (Section 1306). 

Over the Treasury Department’s 2010 through 2015 tax expenditure forecast horizon, the value of this credit 

remains at zero as no eligible nuclear power plants are expected to come on line during that time frame. The credit 

is worth 1.8 cents per kilowatthour of electricity produced during the first 8 years of operation from plants having 
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 21

a Nuclear Regulatory Commission (NRC) approved design. The legislation limits the capacity for this production tax 

credit (PTC) to 6,000 megawatts. The Secretary of Energy is responsible for the allocation of this credit by capacity. 

The provision has an additional limitation of $125 million per thousand megawatts of capacity per taxable year. 

The Modification to Special Rules for Nuclear Decommissioning Costs Section 1310 of EPAct2005 changed the IRS 

rules for qualified nuclear decommissioning trust funds by repealing the cost of service requirement for 

contributions to a qualified decommissioning trust fund created under IRC Section 468A. This change permitted full 

present value funding of a qualified nuclear decommissioning fund and the transfer of pre-1984 decommissioning 

funds held in nonqualified trusts. The provision also required that nuclear plant owners obtain a new schedule of 

ruling amounts from the IRS upon renewal of a plant’s operating license by the NRC. In FY 2010, the estimated 

value of this tax expenditure is $900 million versus $600 in FY 2007. Modification of section 468A of the Code was 

done to eliminate an impediment to nuclear plant sales arising from the structural change in the electric utility

industry.

Advanced Energy Property Credit (Nuclear) By early 2010, there were two nuclear recipients of this credit. Alstom 

will establish a new turbine manufacturing facility designed to manufacture the world’s largest steam turbines, 

with unit output up to 1700 MW. The new facility will focus on turbines used in advanced nuclear power plants, 

nd retrofitting existing turbines in nuclear power plants with higher efficiency technologies. The other recipient, 

Shaw Modular Solutions LLC, will fabricate modules used in advanced, passively-safe, nuclear stations. This credit 

had an estimated $8 million value in 2010 (Table 9).

Table 7. Nuclear transformation-related tax expenditures

(million 2010 dollars)

Tax Expenditures Type FY 2007 FY 2010

Credit for Production from Advanced Nuclear 

Power Facilities Credit 0 0 

Nuclear Decommissioning 600 900 

Advanced Energy Property Credit Credit 0 8 

Total 600 908

Notes: Totals may not equal sum of components due to independent rounding. The Advanced Energy Property Credit was allocated by fuel using 

data appearing at: http://www.whitehouse.gov/the-press-office/president-obama-awards-23-billion-new-clean-tech-manufacturing-jobs.

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.

Energy Efficiency and Conservation-Related Tax Expenditures

Recently, efficiency and conservation-related tax expenditures have become more prominent tools in shaping 

energy policy. These tax provisions are primarily directed at individuals (residential) and commercial taxpayers in 

the form of tax expense deductions, tax credits, or exclusion of certain receipts from gross income. Conservationrelated tax expenditures are estimated to have increased by nearly 400 percent since FY 2007, having grown from 

$832 million to $3.9 billion in FY 2010 (Table 8). The credit for energy efficiency improvements of existing homes is 

the most prominent conservation tax provision, having grown from $395 million in 2007 to $3.2 billion in 2010. In 

2010, it accounted for 82 percent of total conservation-related tax expenditures.
July 2011

22 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 8. Conservation, efficiency, and end-use tax expenditures 

(million 2010 dollars)

Tax Expenditures Type FY 2007 FY 2010

Credit for Energy Efficiency Improvements of Existing 

Homes Credit 395 3,190

Allowance of Deduction for Certain Energy Efficient 

Commercial Building Property Deduction 198 60

Exclusion for Utility-Sponsored Conservation 

Measures Exemption 125 220

Credit for Energy Efficient Appliances Credit 83 150

Qualified Energy Conservation Bonds Credit 0 0 

Credit for Construction of New Energy-Efficient 

Homes Credit 21 20

30-Percent Credit for Residential 

Purchases/Installations of Solar and Fuel Cells Credit 10 220

Advanced Energy Property Credit Credit 0 39 

Total 832 3,899 

Notes: Totals may not equal sum of components due to independent rounding. The advanced energy property credit was allocated by fuel using 

data appearing in: http://www.whitehouse.gov/the-press-office/president-obama-awards-23-billion-new-clean-tech-manufacturing-jobs 

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.

The Credit for Energy-Efficiency Improvements of Existing Homes Established in EPAct2005, Section 1333, this 

credit had an estimated value of $3.2 billion in FY 2010 up sharply from an estimated $395 million in FY 2007, with 

most of this growth traceable to the higher credit amounts made available due to ARRA. This credit applies to 

windows, furnaces, boilers, furnace fans, and building envelope components, such as exterior doors and any metal 

roof that has appropriated pigmented coatings. Initially, the credit was available to houses constructed before 

December 31, 2007 (the credit expires on December 31, 2011). 

Sections 103 through 106 reinstated the credits for efficient water heaters, boilers, furnaces, heat pumps, air 

conditioners, and building shell equipment, such as windows, doors, weather stripping, and insulation. Section 

1121 of ARRA (Public Law 111-5) increased the tax credit to 30 percent (from 10 percent) of the cost of all 

qualifying improvements and raised the maximum credit limit to $1,500 for improvements placed in service in 

2009 and 2010. ARRA also extended the tax credits for improvements to existing homes through December 31, 

2010. Section 710 of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 

(Public Law 111-312) extended the credit one year, although reestablishing pre-ARRA limitations and Standards. 

Currently, the credit is equal to 10 percent of the costs of qualified property up to $500 per taxpayer for all taxable 

years. No more than $200 may be attributable to expenditures on windows. 

The Allowance of Deduction for Certain Energy-Efficient Commercial Building Property This deduction was 

established under EPAct2005 (Section 1331). Taxpayers are permitted to take a deduction of $1.80 per square foot 
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 23

on new construction built after December 31, 2005, and before December 31, 2007, if annual energy and power 

costs of interior lighting systems, heating, cooling, ventilation, and hot water systems are 50 percent or more 

below the standards set by the American Society of Heating, Refrigerating (ASHRAE). The value of this credit is 

estimated at $60 million for FY 2010, a marked decline from the estimated $198 million for FY 2007. Section 201 of 

The Tax Relief and Health Care Act of 2006 (Public Law 109-432) extended the credit to December 31, 2008. 

Section 303 of EIEA extended this tax deduction through December 31, 2013.

The Exclusion for Utility-Sponsored Conservation Measures This exclusion was established by Section 136 of 

EPAct1992. Section 136 amended the Code to provide tax benefits to individual consumers for participating in 

utility-sponsored energy conservation programs. Payments to individual consumers from utilities for investing in 

energy conversation measures may be excluded from gross income for purposes of calculating taxable income. For 

example, utilities engaged in demand-side management activities often pay rebates to consumers who purchase 

more efficient heating or cooling equipment in order to reduce the consumption of natural gas and electricity. The 

value of this credit is estimated at $125 million for FY 2007 and $220 million for FY 2010.

The Credit for Efficient Appliances Established by Section 1334 of EPAct2005, this credit has an estimated value of 

$150 million in FY 2010 versus an estimated $83 million for FY 2007. Appliance manufacturers receive a tax credit 

for manufacturing energy-efficient dishwashers, clothes washers, and refrigerators. The tax credit is limited to 2 

percent of the gross revenue for the 3 taxable years prior to the taxable year in which the credit occurs. Initially, 

the credits applied to appliances manufactured between December 31, 2005, and January 1, 2008. Section 305 of 

EIEA extended the credit for energy efficient appliances that are a certain percent more efficient than the 

prevailing federal standard. The duration and value of the credit vary by appliance and the level of efficiency 

achieved. Section 709 of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 

(Public Law 111-312) extended this credit (under IRC § 45M) through the end of 2011. Public Law 111-312 raised 

the credit level to 4 percent of the average annual gross receipts.

The Credit for Construction of New Energy-Efficient Homes This credit was established under Section 1332 of 

EPAct2005. It provides home builders a tax credit of $2,000 for the construction of a new energy-efficient home. 

To qualify, the home must achieve energy savings of 50 percent over a comparable unit constructed in 

conformance with the International Energy Conservation Code. The value of this credit is estimated at $21 million 

for FY 2007 and $20 million in FY 2010. Initially, the credit was available to houses constructed before December 

31, 2007. However, Section 304 of EIEA extended the $2,000 credit for new homes through 2009 that are 50 

percent more efficient than specified in the International Conservation Code. Section 703 of the Tax Relief, 

Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Public Law 111-312) extended this credit 

(under IRC § 45L) through the end of 2011. 

The 30-Percent Credit for Residential Purchases/Installations of Solar and Fuel Cells has an estimated value of $220 

million in 2010 and $10 million in FY 2007. Section 1335 of EPAct2005 established a 30-percent personal tax credit, 

not to exceed $2,000, for the purchase of solar electric and solar water heating property. A 30-percent tax credit 

up to $500 per 0.5 kilowatt (kW) of capacity is also available for fuel cells. The fuel cell provision of EPAct2005 was 

due to expire at the end of 2007. It was extended through the end of calendar year 2008 by Section 206 of the Tax 

Relief and Health Care Act of 2006 (Public Law 109-432). Section 106 of EIEA removed the cap on the tax credit for 

purchase of residential solar photovoltaic installations and extended the credit out to December 31, 2016. Section 

104 of EIEA extended the credit to include small wind properties (under 100 kilowatts) through December 31, 
July 2011

24 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

2016; and, Section 105 extended the tax credit to include geothermal heat pumps through December 31, 2016. 

Section 1122 of ARRA removed some of the previous maximum amounts and allowed a credit equal to 30 percent 

of the cost of qualified property. 

Advanced Energy Property Credit (Conservation) This credit had an estimated value of $39 million in 2010. The 

largest investment in conservation involved Texas Instruments re-equipping a facility and purchasing equipment to 

produce 300mm wafers for advanced power management semiconductors. Another significant investment 

involved GE, which is using the credit to re-equip a facility to manufacture new Energy Star compliant appliances – 

specifically, Ultra-high Efficient Dishwashers. This new dishwasher line is expected to exceed the future, 

anticipated ENERGY STAR standards for residential dishwashers. 

Electricity Transmission-Related Tax Expenditures

Overall, it is estimated that the electric power industry tax expenditures in FY 2010 have a value of a $58 million, 

down considerably from the estimated value of $696 million in 2007 (Table 9). This decline is largely due to a 

$685-million reversal in the value of the deferred gain from the disposition of transmission property to implement 

FERC restructuring policy. 

Table 9. Electricity transmission-related tax expenditures 

(million 2010 dollars) 

Tax Expenditures Type FY 2007 FY 2010

Deferral of Gain from Disposal of Transmission 

Property to Implement FERC Restructuring Policy Deferral

 

635 

 

(50)

Transmission Property Treated as a 15-Year Property Expense Deduction 19 100 

5-Year Net Operating Loss Carryover for Transmission 

Investment Enhanced Tax Attribute

 

43 0 

Advanced Energy Property Credit Credit 0 8 

Total 696 58 

Note: Totals may not equal sum of individual components due to independent rounding. For 2010, the Credit for Business Installation of 

Qualified Fuel Cells and Microturbine Power Plants is part of the investment tax credit (Section 48 of the code).

Sources: Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year s 2012 and 2009. 

Joint Committee on Taxation, Estimates of Federal Tax Expenditures for Fiscal Years 2010-2014, JCS-3-10 (Washington, DC, December 2010), 

Table 1, and budget documents from the Departments of Energy, Agriculture, Transportation, Treasury, Health and Human Services, Housing 

and Urban Development, the Environmental Protection Agency and the General Services Administration.
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 25

The Deferral of Gain from Disposition of Transmission Property to Implement Federal Energy Regulatory 

Commission (FERC) Restructuring Policy This provision has in previous years been the largest tax credit directly 

affecting the provision of electricity, as opposed to an electricity-related fuel. However, the value of this 

expenditure was a negative $50-million in 2010, as previously deferred taxes came due. The FY 2007 value of this 

tax expenditure was estimated at $635 million. This tax expenditure was provided for in Section 1305 of 

EPAct2005. The Treasury Department projects a negative $2.5 billion cumulative deferral between 2010 and 2015. 

Section 109 of Public Law 110-343 extended the credit to December 31, 2009. Section 705 of the Tax Relief, 

Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Public Law 111-312) extended this credit 

through the end of 2011.

The Transmission Property Treated as 15-year Property This provision was set forth in Section 1308 of EPAct2005 

and modified Section 168 of the Code by shortening the recovery period from 20 to 15 years for eligible assets 

used in the transmission of electricity following sale of the property or related land improvements. Specifically, this 

applies to Section 1245 property, (i.e., personal property and real property subject to depreciation or 

amortization) used in the transmission of electricity that is energized at 69 kilovolts or more. The provision applies 

to transmission facilities placed in service by the taxpayer after April 11, 2005, but excludes any transmission 

facilities for which the taxpayer or related party had entered into a binding construction contract for or initiated 

self-construction on or before April 11, 2005. This provision expired on December 31, 2009.

The 5-Year Net Operating Loss Carryover for Electric Transmission Equipment Section 1311 of EPAct 2005 

implemented this provision that has allowed taxpayers the option to carry back a net operating loss (NOL) for each 

of the 5 years prior to the tax year in which the loss was incurred. The amount of NOL that may be carried back 

may not exceed 20 percent of the value of investment made in qualified transmission and pollution control 

facilities in the preceding year. There was no estimated value of this tax benefit for FY 2010 as it expired at the end 

of 2008. The value of this carryover was estimated at $43 million for FY 2007. 

Direct Expenditures

Until recently energy-related direct expenditures were dominated by funding for LIHEAP and weatherization 

programs. Expenditures for these programs have increased in recent years reflecting increased spending to assist 

low income consumers with rising energy costs. In the wake of the credit crisis and a sharp economic downturn, 

the federal government launched several new energy-specific direct expenditure programs that are largely 

directed at renewables and energy conservation. Section 1603 of ARRA, which provides a grant option in lieu of 

long-standing PTC and ITCs for qualifying sources of renewable energy, is the most prominent of these new 

programs. Energy specific direct expenditures in FY 2007 and FY 2010 by federal agencies are summarized in Table 

10. Descriptions of each direct expenditure program are provided below. 
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26 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 10. Direct expenditures in energy 

(million 2010 dollars)

Department FY2007 FY2010

Department of Energy 273 4,239

 Office of Energy Efficiency and Renewable Energy 273 3,722

 Office of Fossil Energy 0 42

 Office of Electricity and Energy Reliability 0 448

 Other DOE Offices 0 27

Department of Labor 0 46

Department of Transportation 0 121

Environmental Protection Agency 0 144

General Services Administration 0 50

Department of Housing and Urban Development 0 65

Department of Health and Human Services 2,276 5,000

Department of Agriculture 206 385

Department of Treasury 0 4,250

 Total 2,755 14,295

Note: Totals may not equal sum of components due to independent rounding.

Source: Department of Energy, Department of Agriculture, and Department of Health and Human Services Budgetary documents.

Energy-Specific Direct Expenditure Program Descriptions

Department of Energy

The Department of Energy spent $4.2 billion in FY 2010 on energy-related direct expenditures, nearly $4 billion of 

which was from ARRA-appropriated funds. The direct expenditures were spread among various programs under 

the offices of Energy Efficiency and Renewable Energy, Fossil Energy, and Electricity and Energy Reliability. The 

Office of Energy Efficiency and Renewable Energy spent $3.7 billion in FY 2010 on direct expenditures related to 

energy – the largest of program offices’ expenditures. Approximately $3 billion was spent on conservation and 

efficiency programs, with the remainder spent on programs related to various energy technologies.

Weatherization and Intergovernmental Activities (WIA): The Department of Energy’s Office of Energy Efficiency 

and Renewable Energy (EERE) funds and supports programs fall under the umbrella of Weatherization and 

Intergovernmental Activities. Within this group are three budget-funded subprograms: Weatherization Assistance 

Grants, the State Energy program, Tribal Energy Activities, and the Energy Efficiency Conservation Block Grant 

program. Total appropriation for the Weatherization and Intergovernmental Activities programs (WIP) in FY2010 

were $270 million, with $210 million allocated to WIA, $50 million to State Energy programs and $10 million to 

Tribal Energy Activities. In FY 2010, WIP had $258 million in actual expenditures from the budget appropriated 

funds. The original FY2009 appropriation for the entire program was $516 million, but ARRA appropriated an 

additional $11.6 billion to this program, with $5 billion for Weatherization Assistance Grants, $3.1 billion for State 

Energy programs, and $3.2 billion for Energy Conservation Block grants. Of the ARRA-appropriated funds, $2.6 

billion was spent in FY 2010.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 27

Subprogram: Weatherization Assistance Grants are offered by DOE to assist low-income households in 

weatherizing their homes. Both single and multi-family residences are eligible for the program. This program 

involves implementing efficiency measures that range from sealing and caulking to the installation of energy 

efficient appliances. By increasing home energy efficiency, this program helps eligible recipients to reduce their 

energy usage thereby lowering heating and cooling costs. DOE administers this program by funneling funding to 

state-based weatherization programs.

The weatherization program received $450 million in FY 2009 and an additional $5 billion from ARRA for the 

weatherization of 590,000 residences. In 2009, $4.73 billion was awarded in the form of grants at the State, 

territory or Tribe level, but both spending levels and weatherization progress fell far short of DOE goals. A 

significant impediment to the program’s implementation involved a dispute which arose between the federal 

government and States over language in ARRA that related to wage rates of laborers paid by weatherization funds. 

ARRA set forth a requirement that Davis-Bacon wage rates apply to ARRA funded projects. In implementing the 

weatherization program, the Department of Labor began conducting surveys to determine appropriate wage rates 

for weatherization work. DOL later joined with DOE to issues a memorandum recommending that State and local 

agencies move the program forward prior to the completion of the wage survey in order to expedite 

weatherization projects. Upon completion of the survey, worker payments could be adjusted retroactively, if 

necessary. However, many state agencies decided not to undertake weatherization projects until after the rate 

issue was resolved for fear of possible legal complications and burdens that might arise with any retroactive wage 

adjustment. Due to these delays, most recipients of ARRA weatherization funds did not begin to draw upon funds 

until the end of 2009 and into the beginning on 2010. 

Subprogram: The State Energy subprogram offers grants to States for energy efficiency, renewable energy, and new 

technology programs and usage. The States administer these programs and match the DOE grant at a level of 20 

percent. Formula grants are also offered for energy priority and goal-setting at the State level. DOE’s stated goals 

for these programs are to reduce energy costs, to increase energy efficiency, to improve reliability, to increase the 

usage of renewable and alternative energy sources, and to promote economic growth. 

Subprogram: The Tribal Energy program, in existence since 2002, funds a competitive grant program for Indian 

tribes to research, develop and deploy renewable energy resources on tribal lands. Additionally, grants offered by 

the program fund energy efficiency improvements and education as well as training opportunities. Past projects 

include feasibility studies for the development of wind and solar resources. 

Subprogram: The Energy Efficiency and Conservation Block Grant (EECBG) program was a new program under 

ARRA in 2009. The program invests in the cheapest, cleanest, most reliable energy technologies available—

efficiency and conservation—which can be deployed immediately. Through $3.2 billion in formula and competitive 

grants to over 2,300 U.S. cities, counties, states, territories, and Indian tribes, EECBG empowers communities to 

make strategic investments to meet the nation’s long-term goals for energy independence and leadership climate 

change.

Renewable Energy Production Incentive: The Renewable Energy Production Incentive (REPI) was part of an 

integrated strategy to promote the generation of electricity from renewable energy sources and to advance 

renewable energy technologies. It provided financial incentive payments for electricity produced and sold by 

qualifying renewable energy generation facilities. Qualifying facilities included: State and local government entities 
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28 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

(such as municipal utilities and Tribal governments) and not-for-profit electric cooperatives. The REPI provided notfor-profit entities with a financial incentive to invest in renewable generation technologies much like the incentive 

provided to for-profit entities eligible for Section 45 PTC. Qualifying facilities were to use solar, wind, geothermal 

(with certain restrictions as contained in the rulemaking), or closed-loop biomass (except for municipal solid waste 

combustion) generation technologies. In FY 2007, the value of REPI was estimated to be $5 million. However, REPI 

received no funds under the FY 2010 budget.

Department of Labor

Training and Employment Services: Under ARRA, the Department of Labor was appropriated $500 million to the 

Training and Employment Services program for research, labor exchange, and job training projects that prepare 

workers for careers in energy efficiency and renewable energy. The program spent approximately $46 million of 

the total appropriation in FY 2010.

Department of Transportation

Transit Investments for Greenhouse Gas and Energy Reduction (TIGGER) program: In FY 2010, the Department of 

Transportation spent approximately $121 million on the Transit Investments for Greenhouse Gas and Energy 

Reduction (TIGGER) program, with approximately a third of the spending from ARRA funds. The TIGGER program 

works directly with public transit agencies to implement new strategies for reducing greenhouse gas emissions or 

reduce energy usage from their operations. These strategies can be implemented through operational or 

technological enhancements or innovations.

Environmental Protection Agency

Diesel Emissions Reduction Program: In FY 2010, the Environmental Protection Agency (EPA) spent a total of $144 

million on the Diesel Emissions Reduction program, with less than $0.1 million coming from ARRA funds. As part of 

the Energy Policy Act of 2005, the Diesel Emissions Reduction Act (DERA) authorizes funding of up to $200 million 

annually for FY 2007 through FY 2011 to help fleet owners reduce diesel emissions. Under this act, EPA has 

developed four programs.

Subprogram: The National Clean Diesel Funding Assistance program awards competitive grants to fund projects 

that implement EPA or California Air Resources Board (CARB) verified and certified diesel emission reduction 

technologies.

Subprogram: The National Clean Diesel Emerging Technologies program awards competitive grants for projects 

that spur innovation in reducing diesel emissions through the use, development and commercialization of 

emerging technologies. Up to 10 percent of the national funds may be spent on emerging technologies.

Subprogram: SmartWay Clean Diesel Finance program issues competitive grants to establish national low-cost 

revolving loans or other innovative financing programs that help vehicle fleets reduce diesel emissions.

Subprogram: State Clean Diesel Grant program allocates funds to participating states to implement grant and loan 

programs for clean diesel projects. Base funding is distributed to states using a specific formula based on 

participation, and incentive funding is available for any states that match their base funding. Currently all 50 States 

and the District of Columbia are participating in this program.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 29

General Services Administration

Fuel-efficient vehicles: Under ARRA, the General Services Administration (GSA) was appropriated $300 million for 

the procurement of energy-efficiency motor vehicles for use in federal agency fleets. Eligible vehicles include 

hybrids, plug-in hybrids, and pure electric vehicles. The GSA spent approximately $50 million of the total 

appropriation in FY 2010.

Department of Housing and Urban Development

Green Retrofits for Multifamily Housing (also known as the Energy Efficiency Assisted Housing Retrofits).This 

program, created under ARRA, is administered by the Housing and Urban Development agency‘s (HUD) office of 

Affordable Housing Preservation. Funding for FY2009 was $250 million and was to be disbursed in a multi-year 

schedule. Funding is provided up to $15,000 per residential unit and the total amount of appropriations is 

expected to be used to retrofit upwards of 25,000 units. Retrofit and efficiency projects that are eligible under this 

program include the installation of efficient heating and cooling systems and appliances, and the upgrade of units 

to reduce water usage, increase indoor air quality and provide other various environmental benefits. Funds were 

be dispersed via a competitive loan and grant program, and have ranged from small amounts up to almost $4 

million for a single property. Approximate expenditures for FY 2010 totaled $65 million.

Department of Health and Human Services

Low Income Home Energy Assistance Program: For FY 2010, the Department of Health and Human Services (DHHS) 

LIHEAP spent of $5 billion dollars (Table 10). Of this $5 billion, $4.5 billion was directed at formula grants while 

$590 million was set aside in a contingency fund to be used in the case of extreme energy price swings or other 

unprecedented event that affects LIHEAP recipients. This level of funding is the same as the original FY 2009 

appropriations, and LIHEAP received no additional funding under ARRA. 

LIHEAP was established as a block grant program in 1981 for the purpose of subsidizing heating and cooling costs 

for low-income households. Because LIHEAP is a block grant, LIHEAP grants are provided to States, territories and 

Tribes who are then free to administer the program within the requirements of federal law. Federal LIHEAP 

requirements set eligibility at 150 percent of the federal poverty level or 60 percent of the State’s median income, 

but do have some flexibility and allow “maximum policy discretion to grantees.” Other federal rules include 

coordination with DOE’s Weatherization Assistance program, annual audits, and outreach activities. Heating 

and/or cooling assistance funds may be paid directly to eligible households or to retail energy suppliers in the form 

of cash or vouchers but in practice the majority of funds are paid directly to the energy providers. In addition to 

funds used for heating and/or cooling assistance, money must be set aside by recipients for energy crisis 

intervention and has been released for natural disasters, such as Hurricane Katrina in 2005. 

Department of Agriculture

Rural Business Service Programs and Rural Utility Services High Energy Cost Grant Program: These programs fall 

under the USDA’s Rural Business-Cooperative Service (RBS) and Rural Utility Service (RUS), and are intended to 

promote clean energy in rural business environments and subsidize energy consumption in high-cost rural areas. 

FY 2010 expenditures were $105 million for Rural Business Services and $18 million for the High Energy Cost Grant 

program.

Subprogram: The Rural Energy for America joint program between USDA and DOE promotes energy efficiency and 

renewable energy usage by rural agricultural producers and small rural businesses. The program is broken into
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30 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

two parts, the first of which provides grants for renewable energy development and energy audits. Under this part 

of the program, eligible rural entities include units of government (such as local or Tribal governments), rural 

electric cooperatives, public power entities, land grant colleges, universities or other institutions of higher learning 

or any other similar entity to be defined by the USDA Secretary. The recipients use the grant funds to assist rural 

agricultural producers and small businesses with conducting energy audits, improving the efficiency of their 

operations while also incorporating renewable energy technologies and resources. The second half of the program 

provides loan guarantees directly to rural small businesses and agricultural producers to make energy efficiency 

improvements, and purchase and employ renewable energy systems.

Subprogram: The Repowering Assistance program both encourages biorefineries that are currently using fossil 

fuels for heat inputs to switch to renewable biomass sources. The Secretary of USDA is authorized to make direct 

payments to any biorefinery that meets the particular specifications. These payments are to be calculated based 

on two factors: the amount of fossil fuels usage that will be avoided and the efficiency and cost of the newlyinstalled biomass system.

Subprogram: The Bioenergy for Advanced Biofuels program functions via direct payments to producers of 

advanced biofuels, based on the volume of fuels produced and the amount of renewable energy content contained 

therein. Eligible Fuels include: Biofuels derived from cellulose, hemicelluloses, or lignin; biofuel derived from sugar 

and starch (other than Ethanol derived from corn kernel starch); biofuel derived from waste material, including 

crop residue, other vegetative waste material, animal waste, food waste and yard waste; diesel-equivalent fuel 

derived from Renewable Biomass, including vegetable oil and animal fat; biogas (including landfill gas and sewage 

waste treatment gas) produced through the conversion of organic matter from Renewable Biomass; butanol or 

other alcohols produced through the conversion of organic matter from Renewable Biomass; and, other fuel 

derived from cellulosic biomass.

Subprogram: The High Energy Costs Grants under the Rural Utilities Service (RUS) are available for improving and 

providing energy generation, transmission, and distribution facilities serving communities with average home 

energy costs exceeding 275 percent of the national average. Grant funds may be used for on-grid and off-grid 

renewable energy projects, energy efficiency, and energy conservation projects serving eligible communities.

Biomass Crop Assistance Program: This program provides financial assistance to owners and operators of 

agricultural and non-industrial private forest land who wish to establish, produce, and deliver biomass feedstocks. 

The program spent $246 million in FY 2010.

Department of the Treasury

Grant in Lieu of Production or Investment Tax Credit Section 1603 provision in ARRA provided for the tax-free grant 

program. Eligible beneficiaries (including solar, fuel cells, geothermal, wind, hydro, and biomass, in particular), can 

apply for a grant in lieu of the 30 percent Investment Tax Credit. Eligible funding is fuel dependent with coverage 

ranging from 10 percent to 30 percent of a projects cost (Table 11). Section 1603 has become an enormously 

popular program. The Office of Management and Budget shows this value to have grown to $1.1 billion in 2009 

during the first year of eligibility. In 2010, the value of the grant, at $4.2 billion, was the second largest “tax 

expenditure” for that year. Between 2009 and 2015, the value of the grant is forecasted to approach $19 billion. In 

2010, 84 percent of 1603 grants went to wind projects, 11 percent to solar projects, 3 percent to geothermal 

projects, and 1 percent to biomass (Figure 1).
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 31

Figure 1. Percentage share of the section 1603 investment grant by energy category, 2010

Note: Data depicts only dollar amounts allocated by energy source.

Source: U.S. Department of the Treasury, http://www.treasury.gov/initiatives/recovery/Documents/Web%20Posting.xls

Grants can cover between 10 percent and 30 percent of the cost of an eligible project depending upon the nature 

of the project (Table 11). Eligible properties are described in Sections 45 and 48 of the Code. Section 1603 applied 

to eligible properties placed in service between January 1, 2009 and January 1, 2011. Section 707 of the Tax Relief, 

Unemployment Reauthorization, and Job Creation Act of 2011 extended the placed in service date to run through 

December 31, 2011.

Solar 11%

Geothermal 3%

Biomass 1%

Other 1%

Wind 84%
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32 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 11. Section 1603 facility property eligibility amounts

Energy Property Eligible Funding (Percent)

Closed-Loop Biomass Facility 30

Combined Heat & Power 10

Fuel Cells 30

Geothermal Heat Pumps 10

Geothermal under IRC sec. 45 30

Geothermal under IRC sec. 48 10

Landfill Gas Facility 30

Large Wind 30

Marine & Hydrokinetic 30

Microturbines 10

Open-Loop Biomass Facility 30

Qualified Hydropower Facility 30

Small Wind 30

Solar 30

Trash Facility 30

Source: American Recovery and Reinvestment Act of 2009, Section 1603 (Public Law 111-5).
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 33

3. Federal Energy Research and Development

The federal government's role in financing large-scale civilian research and development (R&D) dates back to the 

late 1940s. The principal landmarks were President Eisenhower's decision to commercialize nuclear energy 

articulated in his 1953 "Atoms for Peace" speech, and the public concern raised by the launch of the Soviet Sputnik 

satellite in 1957. In 1975, the Energy Research and Development Administration (ERDA) was created through the 

consolidation of several existing R&D programs. In 1977, ERDA became a part of the United States Department of 

Energy.18 According to the Office of Management and Budget (OMB), the FY 2010 budget authority for energyrelated R&D amounted to about 7 percent of all federally-funded R&D.19

Since the last EIA subsidy report was released in 2008, energy-related R&D expenditures for biofuels, renewables, 

end use, and electricity delivery and energy reliability have risen substantially. Like the growth in tax expenditures, 

the passage of EPAct2005 and ARRA had a significant impact on energy-related R&D expenditures. The American 

Competes Act (Public Law 110-69) established the Advanced Research Projects Agency within the Department of 

Energy (ARPA-E). The mission of ARPA-E was to support transformational energy technology research projects. 

Under ARRA, the Advanced Research Projects Agency-Energy received $387 million in funding. 

Total federal R&D for fiscal year FY 2010 

exceeded $147 billion, 55 percent of which was defense-related, making the DOD the largest recipient of federal

R&D spending, followed by the Department of Health and Human Services, the Department of Energy, and NASA. 

In 2008, federally funded R&D comprised 57 percent of total basic U.S. Research and Development spending.Over 

the period 1978 through 2010 funding for energy-related R&D has totaled $121 billion, of which, $45 billion has 

been devoted to nuclear, $26 billion to coal, $26 billion to end use and electricity delivery and energy reliability, 

$20 billion to renewable energy, and $4 billion to oil and gas (Figure 2).

Since EIA produced its last subsidy report in 2008 (which used primarily 2007 R&D data), applied R&D funding 

authorizations for renewable technologies, end use and electricity delivery and energy reliability (EDER) energy has 

grown considerably. Funding for renewable R&D rose 97 percent between 2007 and 2010, while expenditures on 

end use and EDER rose 62 percent (Table 12 and Figure 3). Renewables have seen their share rise from 24 percent 

of total spending in 2007 to 32 percent of total spending in 2010. In 2010, nuclear, at 27 percent of total spending 

declined from 2007 when nuclear's share equaled 34 percent. Over the same period, coal related R&D declined—

from 19 percent of total spending to 15 percent. End use and EDER expenditures accounted for 24 percent of total 

spending in 2010 versus 22 percent in 2007. 

 

18 See, http://www.whitehouse.gov/omb/budget/fy2008/pdf/hist.pdf. 19 Perspectives of the U.S. Budget 2012, pp. 367 and 368.
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34 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

 

Sources: DOE Historical Budget Authorizations by Organization 1978-2011, M Leonard 08-18-10 v2 and DOE ARRA 753 Recovery Act - 

Historical Monthly Payments and Obligations.

Notes: The expenditures for FY 2009 and FY 2010 also include ARRA expenditures and obligations. Energy R & D Expenditures by other 

federal agencies such as DOD are not included.

Table 12. Applied Federal energy R&D expenditures by type and function, 2007 and 2010 

(million 2010 dollars)

Applied R & D FY 2007 FY2010

Coal 582 663 

Natural Gas and Petroleum Liquids 43 70

Nuclear Power 1,017 1,169

Renewable Technologies 717 1,409 

End Use and Electricity Delivery and 

Energy Reliability 652 1,053

 Total 3,010 4,365

Note: Totals may not equal sum of components due to independent rounding.

Sources: Department of Energy FY 2009 Congressional Budget Request (DOE/CF-031) and Department of Energy FY 2012 Congressional 

Budget Request (DOE/CF-0064).

Figure 2. U.S. DOE cumulative R&D expenditures, 1978-2010

(billion dollars)
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 35

Sources: Department of Energy FY 2009 Congressional Budget Request (DOE/CF-031) and Department of Energy FY 2012 Congressional 

Budget Request (DOE/CF-0064) 

Notes: Other is the Electricity Delivery and Energy Reliability Program. 

Tables 13 through 18 breakout R&D spending for 2007 and 2010 by fuel / program type. For detailed information 

on Department of Energy R&D expenditures see the Department of Energy’s fiscal year 2009 Congressional Budget 

Request (DOE/CF-031) and the Department of Energy fiscal year 2012 Congressional Budget Request (DOE/CF0064) which can be found at http://www.ne.doe.gov/budget/budgetpdfs/Highlight2009.pdf and 

http://www.cfo.doe.gov/budget/12budget/Content/FY2012Highlights.pdf, respectively.20

 

20 While most of the information in this chapter comes from DOE documents, additional information from the Department of the Interior (see 

http://www.doi.gov/budget/2011/data/greenbook/FY2011_USGS_Greenbook.pdf), the U.S. Geological Survey (see 

http://www.usgs.gov/budget/2009/green_book/FY2009_USGS_Greenbook.pdf), the National Institute of Standards and Technology (see 

http://www.nist.gov/public_affairs/budget/2010_budget_inits_portal.cfm), the Defense Advanced Research Projects Agency (see 

www.darpa.mil/WorkArea/DownloadAsset.aspx?id=2400) and U.S. Department of Agriculture (see 

http://www.obpa.usda.gov/budsum/FY10budsum.pdf and http://www.obpa.usda.gov/budsum/FY07budsum.pdf). 

Figure 3. Research and development expenditures by energy category, 2007 and 2010

(billion dollars)
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36 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 13. Renewable R&D expenditures, 2007 and 2010 

(million 2010 dollars)

Source / Program FY2007 FY2010

Wind 58 166

Solar 171 348

Hydrogen Technology 211 205

Biofuels and Biomass 268 537

Geothermal 9 100

Hydroelectric 0 52

Total Renewables 717 1,409

Sources: Department of Energy FY 2009 Congressional Budget Request (DOE/CF-031) and Department of Energy FY 2012 Congressional 

Budget Request (DOE/CF-0064), U.S. Geological Survey (see http://www.usgs.gov/budget/2009/green_book/FY2009_USGS_Greenbook.pdf), 

the National Institute of Standards and Technology (see http://www.nist.gov/public_affairs/budget/2010_budget_inits_portal.cfm), the Defense 

Advanced Research Projects Agency (see www.darpa.mil/WorkArea/DownloadAsset.aspx?id=2400) and U.S. Department of Agriculture (see 

http://www.obpa.usda.gov/budsum/FY07budsum.pdf, http://www.obpa.usda.gov/budsum/FY10budsum.pdf). 

Table 14. Nuclear R&D expenditures, 2007 and 2010 

(million 2010 dollars)

Source / Program FY2007 FY2010

Integrated University Program 17 5 

Research & Development 312 - 

Infrastructure 246 - 

Nuclear Power 2010 - 102 

Generation IV Nuclear Energy Systems - 213 

Fuel Cycle Research & Development - 132 

Radiological Facilities Management - 72 

Idaho Facilities Management - 173 

Program Direction - 73 

Congressionally Directed 65 3 

Transfer from State Department 13 3 

Non-defense environmental cleanup 364 393 

Total 1,017 1,169 

Note: Totals may not equal sum of components due to independent rounding.

Sources: Department of Energy FY 2009 Congressional Budget Request (DOE/CF-031) and Department of Energy FY 2012 Congressional 

Budget Request (DOE/CF-0064),and the National Institute of Standards and Technology (see 

http://www.nist.gov/public_affairs/budget/2010_budget_inits_portal.cfm).
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 37

Table 15. Coal R&D expenditures, 2007 and 2010

(million 2010 dollars)

Source / Program FY2007 FY2010

Coal 555 582

Plant & Capital Equipment 12 27

Fossil Energy Environmental Restoration 10 13

Cooperative R & D 1 7 

Special Recruitment Programs 0 1 

Congressional Directed Projects 0 32

National Coal Resources (USGS) 3 1 

 Total 582 663 

Note: Totals may not equal sum of components due to independent rounding.

Sources: Department of Energy FY 2009 Congressional Budget Request (DOE/CF-031) and Department of Energy FY 2012 Congressional 

Budget Request (DOE/CF-0064), the U.S. Geological Survey (see 

http://www.usgs.gov/budget/2009/green_book/FY2009_USGS_Greenbook.pdf), and the National Institute of Standards and Technology (see 

http://www.nist.gov/public_affairs/budget/2010_budget_inits_portal.cfm), and

http://www.doi.gov/budget/2011/data/greenbook/FY2011_USGS_Greenbook.pdf. 

Table 16. Natural gas and petroleum R&D expenditures, 2007 and 2010

(million 2010 dollars)

Source / Program FY2007 FY2010

Natural Gas Technologies 17 24

Unconventional Fossil Energy Technologies 0 26

Petroleum- Oil Technologies 8 1 

Oil Shale 1 2 

National Oil & Gas Resources 15 15

World Oil & Gas Resources 2 2 

Total 43 70

Note: Totals may not equal sum of components due to independent rounding.

Sources: Department of Energy FY 2009 Congressional Budget Request (DOE/CF-031) and Department of Energy FY 2012 Congressional 

Budget Request (DOE/CF-0064), the U.S. Geological Survey (see 

http://www.usgs.gov/budget/2009/green_book/FY2009_USGS_Greenbook.pdf), and the National Institute of Standards and Technology (see 

http://www.nist.gov/public_affairs/budget/2010_budget_inits_portal.cfm), and 

http://www.doi.gov/budget/2011/data/greenbook/FY2011_USGS_Greenbook.pdf. 
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38 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 17. End-Use and Electricity Delivery and Energy Reliability R&D Expenditures, 2007 and 2010

(million 2010 dollars)

Source / Program FY2007 FY2010

Vehicle Technologies 204 352

Building Technologies 129 315

Industrial Technologies 65 139

Congressionally Directed 0 6 

Facilities & Infrastructure 111 19

 Total End Use 509 832

Electricity Delivery and Energy Reliability 142 222

 Total 652 1,053

Note: Totals may not equal sum of components due to independent rounding.

Sources: Department of Energy FY 2009 Congressional Budget Request (DOE/CF-031) and Department of Energy FY 2012 Congressional 

Budget Request (DOE/CF-0064) and National Institute of Standards and Technology (see 

http://www.nist.gov/public_affairs/budget/2010_budget_inits_portal.cfm), and the Defense Advanced Research Projects Agency (see 

www.darpa.mil/WorkArea/DownloadAsset.aspx?id=2400). 

Table 18. Basic federal energy R&D expenditures by type and function, 2007 and 2010 

(million 2010 dollars)

Source / Program FY2007 FY2010

Basic Energy Sciences 1,270 1,797 

Advanced Scientific Computing 287 383 

Biological & Environmental Research 499 629 

High Energy Physics 762 791 

Nuclear Physics 429 522 

Fusion Energy Systems 324 418 

Other Allocated 419 736 

 Total 3,990 5,277 

Note: Totals may not equal sum of components due to independent rounding. Basic R&D expenditures are not attributable to specific fuels and, 

therefore, are not included elsewhere in this report.

Sources: Department of Energy FY 2009 Congressional Budget Request (DOE/CF-031) and Department of Energy FY 2012 Congressional 

Budget Request (DOE/CF-0064). 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 39

4. Federal Electricity Programs

Introduction

The federal government provides federal utilities and electric utilities participating in the RUS electric program 

access to capital at reduced interest rates. federal utilities also receive support by pricing power with rates of 

return that are lower than possible for a competitive company. The federally-owned utilities include the 

Tennessee Valley Authority (TVA) and the four Power Marketing Administrations (PMAs), the Bonneville Power 

Administration (BPA), the Western Area Power Administration (WAPA), the Southeastern Power Administration 

(SEPA), and the Southwestern Power Administration (SWPA).21 Lending subsidies provided through the RUS loan 

programs are included due to the advantages that these programs provide to eligible borrowers.22

This chapter examines support provided by the federal government to certain electric power customers. This 

support differs significantly from the support provided to other energy sectors described in this report. First, the 

federal support outlined in the following discussion does not include any direct expenditures provided to federal 

utilities by the federal government, as is the case for other federal programs. The market value of the interest 

subsidies provided to TVA, the PMAs, and RUS borrowers is not measured by the Treasury Department, and it is 

not reported in federal budget documents. The measures of support described in this chapter are values estimated 

by the EIA. 

Measuring the Support

In this report, the federal subsidies to TVA, the PMAs, and RUS borrowers are quantified by estimating the benefits 

they receive because of their ability to borrow directly from the Treasury and access low cost federal loans and 

loan guarantees. In additions, TVA and BPA, have access to lower cost private financing due to the financial 

markets’ perception of an implied federal guarantee for their non-federal obligations. This measure of support 

represents a snapshot of the difference between the interest expense paid by TVA, the PMAs, and RUS borrowers 

at their embedded cost of debt relative to what they would have paid at a range of market interest rates. Unlike 

the previous report, a range of interest rates is used here because of the uncertainty about selecting the 

appropriate market. 

 

21 The United States Department of Interior, Bureau of Indian Affairs owns or has interests in projects primarily engaged in irrigation that also 

provide electric service on Indian Reservations. See NEOS Corporation," Draft Final Report: Tribal Authority Case Studies: The Conversion of 

on-Reservation Electric Utilities to Tribal Ownership and Operation," prepared for the Western Area Power Administration, Contract No. DEAC65-91WA07849, January 1996. Any support that may exist with respect to these government-owned projects are excluded from the analysis 

because their primary purpose is agricultural irrigation, not electricity production.

22 For more information on the history of the federal utilities role in electricity markets and the issues involved with assessing whether subsidies 

are provided to them see Energy Information Administration, Federal Financial Interventions and Subsidies in Energy Markets 2007, 

Washington, DC, 20585, April 2008, available at http://www.eia.gov/oiaf/servicerpt/subsidy2/index.html. 
July 2011

40 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

These interest rates include the Treasury’s cost of money on 30-year debt instruments and interest rates that 

reflect the variations in credit quality within the general category of investment grade debt (i.e., Aaa to Baa) for 

IOU bonds rated by nationally-recognized rating agencies.23

It should be pointed out that there are other approaches for measuring federal support to these utilities. These 

include a comparison of the prices charged for electricity under federal programs versus an estimate of relevant 

"market" prices and a comparison of rates of return on assets between the federal utilities and IOUs. The price 

measure looks at the benefit received by preference customers based on the difference between the cost-based 

rates charged for federal power versus the rate charged in competitive wholesale markets. These other methods 

are not addressed in this report, but were discussed in the previous report.

 

This analysis uses both public-sector and private-sector interest rates as benchmarks against which to measure the 

value of interest rate support. The public-sector benchmark is the Treasury’s 30-year constant yield to maturity 

debt obligation. For the private-sector rates, the benchmarks used are the Moody's utility bond ratings ranging 

from Aaa down to Baa. These ratings indicate two different measures of support. When debt carried on the 

balance sheets of federal utilities has lower average borrowing costs than the U.S. Treasury itself, the underlying 

advantage can be viewed as support provided directly to the borrower by the U.S. Treasury or by the public at 

large. The second measure of support assumes that federal utilities are advantaged to the extent that the 

associated average interest costs of their outstanding borrowing costs are at rates less than they would be if they 

were private entities. This measure of support compares the borrowing costs of the federal utilities with the cost 

of funds paid out by risk-adjusted groups of IOUs that raise debt in the market place. The comparable IOU rating 

may or may not be appropriate, depending on the presumed creditworthiness a federal utility would command 

were it to lose the borrowing benefits derived from federal ownership or its implicit financial backing by the U.S. 

Treasury. 

The measure used to estimate the federal interest rate support for federally-owned utilities is highly dependent on 

the risk differential reflected by the spread between the interest rates for the various categories of investment 

grade bonds described above. In 2010, interest rates were close to record lows (Table 19).24

 

23 An alternative measure of Federal support would employ a comparison of a weighted average of the various maturities of all Federal debt at the 

time of issuance against Treasury and IOU debt being issued contemporaneously to the Federal debt with the same maturities. There are several 

shortcomings with this alternative measure. First there is a lack of relevant interest data. The source of constant-maturity U.S. Treasury interest 

rates used in this report is the Federal Reserve Bank’s Form H-15. In 2001, due to expectations of future budgetary surpluses, the United States 

Treasury announced that it would suspend issuance of its 30-year bond, the long-bond. Hence, Form H-125 lacks historical data on constantmaturity 30-year Treasuries for the years 2003 through 2005, making a comparison for those years subject to estimating 30-year Treasury 

surrogates. A second issue also concerns data availability. While the Federal utilities reported historical debt issuances of 50 years or more, 

corresponding data are unavailable for U.S. Treasuries and IOUs. For instance, Form H-15 reports long-bond Treasury rates going back no 

earlier than 1977. In 2010, TVA reported debt with a maturity of 50 years (Source: TVA 2010 Annual Report, p. 52). Another issue concerns 

standardized maturities. While the Treasury issues bonds with standardized maturities of 10, 20, and 30 years, Federal utilities issue debt with 

various maturities. For instance, a Federal utility issuing debt having a maturity of 15 years would have no U.S. Treasury counterpart with the 

same maturity. Furthermore, a portion of BPA’s ENW debt has variable interest rates (See: BPA 2010 Annual Report, p. 36. Any attempt to 

estimate interest rates based upon “hypothetical” comparative Treasuries involves extrapolations for debt with maturity dates greater than 30 

years, which would have to surmount a number of issues, such as how to deal with periodic yield curve inversions. Finally, bond-by-bond 

comparisons would overlook an advantage available to the PMAs in that they are allowed by the Department of Energy to pay off their high cost 

debt prior to maturity. While IOUs may issue callable debt, which also may be retired prior to maturity, this debt would be priced at rates higher 

than those associated with debt, which could not be retired prior to maturity. 

However, in 

measuring interest support for a single year, what matters is the interest rate spread, which reflects the risk 

premium. Table 20 illustrates that the level of estimated support varies directly with the benchmark interest rate 

chosen. The spread between these rates could remain relatively stable or could change over time. In 2010, the 

24 Changes over time in the spread between interest rates of Federal utilities and the benchmark rates they are being measured against in no way 

reflect intended changes in Federal support for these electricity programs. Rather, they reflect supply and demand conditions in credit markets 

prevailing in 2007 and in 2010.
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 41

average yield on 30-year Treasury bonds was 4.24 percent while the average yield on Aaa-rated utility bonds was 

4.96 percent, producing a spread of 72 basis points; in contrast, the spread between the 4.84 percent 30-year 

Treasury and the 5.67 percent investor- owned Aaa rate in 2007 equaled 83 basis points. The estimated interest 

support will be higher when the IOU Aa rate is compared to the Treasury rate, and higher still when the 

comparison is graduated downward to the IOU Baa rate. For the year 2010, the difference in yield between a 30-

year Treasury and a Baa IOU-rated bond was 173 basis points versus 149 basis points in 2007. The difference in 

yield between an Aaa utility rating and Baa utility was 101 basis points in 2010 versus 66 basis points in 2007. The 

level of support rises and falls depending on: (1) changes in the yield spread between different debt instruments 

(e.g., Treasuries and utilities); (2) changes in the level of outstanding debt; (3) and, the federal utilities and RUS 

borrowers embedded cost of debt versus the Treasury’s and utilities’ current cost of money.

Selection of a Market Interest Rate 

This analysis is a snapshot that compares the current interest expense based on the average cost of outstanding 

debt to a hypothetical interest expense that applies a contemporaneous market interest rate to the outstanding 

debt. In effect this implies the debt is being refinanced. A more accurate measure would have been to estimate 

the value based on the sum of the difference between the face amount of each original loan or bond and the 

present value of each loan or bond issue at the market rate of interest at the time the obligation was incurred. 

However, the data required to perform this alternative analysis was not readily available.

Table 19. Interest Rates used to Estimate Federal Utilities and RUS Interest Subsidies, 2007 and 2010 

(percent)

Sources: Source: Moody's Investor Services and Federal Reserve Bank Form H-15. 

Since the financial accounts of the four PMAs, TVA, and RUS borrowers differ considerably and due to reasons 

cited below, a single federal interest rate support estimate was used in this analysis. A more complicated method 

would be to measure the interest paid by federally-supported power entities against the interest paid on similar 

debt (i.e., same maturity) issued by the Treasury or by IOUs at the same time the debt was issued. However, 

several difficulties arise with the latter methodology. In essence the yield curve for the federal utilities is 

fundamentally different from the yield curve for the IOUs. One problem is that the debt maturities cannot always 

be matched. For instance, TVA has issued debt with maturities as long as 50 years, for which there are no similar 

Treasury or IOU debt instruments. Another difficulty is that some debt is callable, which means it may never be 

held to maturity. There is an interest rate differential between callable and non-callable debt. Callable debt, all 

other factors being equal, has a higher interest rate. Another problem is the lack of available data. Although some 

of the debt on the books of the PMAs dates back to the 1940s, there is little in the way of comparable IOU and 

Treasury interest rate data available. For instance, the U.S. Treasury did not start to issue 30-year debt until 1978 

Comparison Debt 2007 2010

30-Year Treasury 4.84 4.24

Investor-Owned Aaa 5.67 4.96

Investor-Owned Aa 5.94 5.23

Investor-Owned A 6.07 5.46

Investor-Owned Baa 6.33 5.97
July 2011

42 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 20. Estimate of federal electricity interest rate support to TVA, 2007 and 2010 

(million 2010 dollars)

 Treasury 

Rate

Aaa IOU 

Rate

Aa IOU 

Rate

A IOU 

Rate

Baa IOU 

Rate

2007

1) Benchmark Interest Rate (%) 4.84 5.67 5.94 6.07 6.33

2) Outstanding Debt ($) 25, 834 25,834 25, 834 25,834 25,834 

3) Average Cost of Outstanding Debt (%) 5.67 5.67 5.67 5.67 5.67 

4) Actual Interest Expense ($) 1,466 1, 466 1,466 1,466 1,466 

5) Interest Expense Computed at Benchmark 

Rate ($) [(1)*(2)]

 

1,250 

 

1,466 

 

1,535 

 

1,569 

 

1,636 

6) Estimated Interest Support at Benchmark 

Rate ($) [(5)-(4)]

 

NA 

 

NA 

 

70 

 

103 

 

170 

2010

1) Benchmark Interest Rate (%) 4.24 4.96 5.23 5.46 5.97

2) Outstanding Debt ($) 24,591 24, 591 24,591 24,591 24,591 

3) Average Cost of Outstanding Debt (%) 4.96 4.96 4.96 4.96 4.96 

4) Actual Interest Expense ($) 1,220 1,220 1,220 1, 220 1,220 

5) Interest Expense Computed at Benchmark 

Rate ($) [(1)*(2)]

 

1,043 

 

1,220 

 

1,286 

 

1,342 

 

1,467 

6) Estimated Interest Support at Benchmark 

Rate ($) [(5)-(4)]

 

NA

 

NA 

 

66 

 

123 

 

247 

Notes: The above table represents the historic value of TVA's debt in 2010 dollars for purposes of illustrating how support values for 2007 and 

2010 were calculated. The nominal value of debt reported on TVA's balance sheet for the year 2007 was: $24,925,000,000.

A negative estimate of interest support indicates the weighted average cost of outstanding debt exceeds the benchmark interest rate.

Source: Tennessee Valley Authority Annual Report, 2007 and 2010. Moody's Investors Service, Federal Reserve 

Bank Form H-15.

and in the years 2003, 2004 and 2005, no 30-year Treasury bonds were in circulation. Finally, the PMAs also have 

two other advantages over IOUs that tend to make an IOU/PMA bond-to-bond comparison problematic. First, the 

PMAs have the right to pay off high-interest debt first and, second, the PMAs can defer payments of debt during 

revenue shortfalls up to the point of the maturity of the loan. These deferrals can be as long as 50 years.25

 

25 General Accounting Office, Power Marketing Administrations, Their Ratesetting Practices Compared with those of NonFederal Utilities, 

GAO/AIMD-00-114, (Washington, DC, March 2000), p.14.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 43

In making comparisons between the interest costs faced by the federal utilities and the IOUs, two other 

complications arise. The first began in FY 2000, when TVA initiated lease/lease back arrangements.26 In lease/lease 

back arrangements, the TVA "leases" TVA generation assets to investors for a one-time cash payment used to 

retire debt. In turn, the TVA leases back the plants and makes periodic lease payments.27

TVA’s debt in 2010 received an Aaa bond rating from Moody’s Rating Service and AAA from Standard and Poor’s 

and Fitch Ratings.

The other complication 

relates to TVA’s prepayment plan. In 2003, the TVA initiated a pre-payment plan, which allowed TVA customers to 

pay for their power in advance in return for discounted, wholesale rates. Again, TVA used the transactions 

proceeds to retire long-term debt. Due to both of these transactions, the TVA significantly reduced its long-term 

debt. Both of these obligations are recorded as liabilities on TVA’s balance sheet although TVA does not define 

these liabilities as debt. However, due to their strong resemblance to debt, this report defines them as such. Both 

lease/lease back arrangements and prepayments are discussed later in the TVA section of this chapter.

28

For the PMAs, the debt values and interest expenses were obtained from their 2008-2010 annual reports. Having 

actual data on both PMAs' long-term debt and the interest on the long-term debt allows for a comparison of what 

that interest would be if the PMA’s rates available to IOUs. In 2007, the three smaller PMAs had an embedded 

cost of debt below the current 30-year Treasury rate. By 2010, the embedded cost of PMA debt slightly exceeded 

the Treasury rate. Furthermore, unlike TVA, the three smaller PMAs have an advantage unavailable to the Treasury 

itself in that DOE requires the retirement of high-interest debt first whenever possible. Borrowing costs for the 3 

smaller PMAs were also measured against borrowing costs at the Treasury rate, as well as, the interest rates for 

investment grade IOU bonds rated Aaa, Aa, A, and Baa.

The imputed interest expense for the TVA lease payments and the prepayment discount were 

not treated as interest expense in TVA’s financial documents. Therefore, TVA’s interest costs were estimated by 

applying an Aaa interest expense to TVA’s long-term debt which includes both the values of its lease payment 

obligations, as well as, the unamortized balance of the prepayments which represents TVA’s power supply 

obligation to those who prepaid. The Aaa interest rate expense was then compared to what TVA would pay in 

interest payments if its debt was priced at a lower bond rating.

 

26 In general, Lease Lease-Back arrangements appeared in the 1980s. These leases often involved the transfer of tax benefits to third parties when 

the utility cannot use them (i.e., publicly-owned utilities do not benefit from accelerated depreciation). Source: Public Utilities Report Guide, 

Chapter 5 Financial Issues for Utilities 1999, p. 5-28, Public Utilities Reports Inc., Vienna, Virginia. 27 One of the benefits of this arrangement is the transfer of the tax benefit of depreciation to the equity investors participating in the lease 

lease/back transaction that is not available to TVA. Under this type of transaction, the parties typically share in the benefit of the tax benefit 

being transferred. In this case, TVA realizes a portion of the benefit in lease payments that are passed on to its customers. The equity investors 

realize the benefits of the deductibility of deprecation as an operating expense and the deferral associated with the timing difference between 

book and tax depreciation. The value of the portion of the transaction transferred to the counterparty may be viewed as a form of Federal 

government support, although insufficient information prevents estimating the value of this subsidy in this report.

28Tennessee Valley Authority, TVA’s News Release, “TVA Issues 50-Year Bonds at Record Low Interest,” September 17, 2010.
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44 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Tennessee Valley Authority

Prior to the TVA Act of 1959, TVA was financed through federal appropriations. The 1959 TVA Act authorized the 

TVA to raise capital on its own—to be "self-financing," allowing TVA considerably more latitude in making its 

investment decisions. Congress initially imposed a $750 million debt cap on TVA. This debt cap was later raised to 

$1.75 billion in 1966, $5 billion in 1970, $15 billion in 1975, and $30 billion in 1979. In 2010, TVA’s long-term debt 

stood at $26 billion.29

A number of explicit and implicit benefits are conferred upon TVA by the federal government. For example, TVA 

receives implicit interest rate support via a favorable debt rating since it is owned by the federal government. The 

rating does not reflect TVA’s underlying business or financial condition. In general, TVA borrows at rates 

comparable to those of federal government agencies. TVA also benefits from having a captive market and certain 

other regulatory advantages, which fall outside the scope of this study. Its customers are required to provide up to 

10-years notice before they are allowed to switch their service to another utility.

 Since 2000, TVA has not relied on federal appropriations to fund its non-power operations, 

such as multipurpose activities and recreational programs, when other sources of revenues, such as user’s fees, 

were insufficient to fund those operations. Funding for these operations has been derived from user fees, other 

revenues, and electricity sales. 

30 This provides for stability in 

TVA’s revenue from electricity generation, a competitive advantage not enjoyed by competing IOUs. It is also 

exempt from antitrust laws, an exemption IOUs and the other federal utilities also do not enjoy. EPAct 1992 

provided an exemption for TVA from amendments to the federal Power Act that enhanced the federal Energy 

Regulatory Commission’s authority to order utilities to provide transmission service. This exemption is referred to 

as the "anti-cherry picking" advantage.31,32

TVA rates are not regulated by the FERC, nor are its rates subject to State regulation. TVA’s Board has complete 

discretion in setting rates. Over the last decade, TVA’s rates have been generally higher than those of surrounding 

utilities. Until recently, TVA was exempt from the reporting requirements required of publicly-held companies. 

However, in February 2003, the TVA Board adopted the TVA Corporate Accountability and Disclosure Plan which 

required TVA to develop corporate practices that reflect the reforms of the Sarbanes-Oxley Act of 2002 (Public Law 

107-204), including certification of financial statements and related disclosures by the TVA Board of Directors and 

the Chief Financial Officer.

The anti-cherry picking provision, although regulatory, and not included 

as a subsidy in this report, reinforces the financial community’s perception that TVA bonds are virtually a risk-free 

investment. However, the TVA Act of 1959 places strict limits on how much power TVA can sell outside of its 

jurisdiction. The TVA Act of 1959 established a "fence" based upon the geographic area of the distributors served 

by the TVA in 1957. 

33

Based on these factors, EIA adjusted TVA’s outstanding debt to reflect two obligations that pursuant to Generally 

Accepted Accounting Practices (GAAP) are not reflected as long-term debt on its balance sheet, but as “other 

liabilities.” These liabilities included TVA’s obligations pursuant to two lease/lease back transactions and future 

 

 

29 General Accounting Office, Tennessee Valley Authority: Bond Ratings Based on Ties to the Federal Government and Other Nonfinancial 

Factors, GAO-01-540 (Washington, DC, April 2001), p. 3. 30 This restriction is not absolute, as customers are allowed to expand outside TVA’s territory or to self-generate. 31 General Accounting Office, Tennessee Valley Authority, Debt Reduction Efforts and Potential Stranded Costs, GAO-01-327, (Washington, 

DC, February 2001), p. 6.

32 General Accounting Office, Tennessee Valley Authority, Assessment of 10-year Business Plan, GAO/T-AIMD-99-295, (Washington, DC, 

September 1999), p. 2.

33 Tennessee Valley Authority: http://www.tva.gov/foia/readroom/policy/prinprac/bun24.htm, accessed October 11, 2007. 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 45

obligations to supply power to its largest customer, Memphis Light, Gas, and Water Division (MLGW). MLGW 

issued tax-exempt debt, the proceeds of which were used to prepay future power supply costs at a discount.34

In 2010, the TVA carried over $1.4 billion (2010 dollars) in lease/lease back liabilities on its balance and energy 

prepayment obligations totaling $822 million (2010 dollars) on its balance sheet. These obligations have an effect 

on TVA’s cash flow and therefore, its ability to meet debt service obligations. The Office of Management and 

Budget (OMB) treats TVA’s lease/lease back arrangements as debt and has advised that this should be included in 

the TVA’s $30 billion debt ceiling.

 

35 More recently, TVA’s office of the Inspector General treated these obligations 

as debt to be applied to TVA’s $30 billion debt ceiling.36 In the FY 2012 budget, the OMB determined "that each of 

these methods (lease/lease back obligations and prepayment financing methods) is a means of financing the 

acquisition of assets owned and used by the federal government, or refinancing debt previously incurred to 

finance such assets. They are equivalent in concept to other forms of borrowing from the public, although at 

different terms and conditions."37 The GAO also concluded that "while the lease/lease back arrangements are not 

considered debt for purposes of financial reporting and debt cap compliances, they have substantially the same 

economic impact on TVA’s financial condition and future competitiveness as traditional debt financing...Thus while 

the lease/lease back arrangements are not treated as debt for financial reporting purposes, they are in essence 

debt because they have substantially the same economic impact on TVA as traditional debt financing."38

For its part, TVA has expressed concerns that applying the $30-billion debt ceiling to lease/lease back 

arrangements may result in a capital shortfall: "If Congress decides to broaden the type of financial instruments 

that are covered by the debt ceiling or to lower the debt ceiling, TVA might not be able to raise enough capital to, 

among other things, service its then-existing financial obligations, properly operate and maintain its power assets, 

and provide for reinvestment in its power program."

GAO also 

noted that GAAP does not require that the lease/lease back arrangements be classified as debt.

39

In 2010, TVA had outstanding long-and short-term debt of $25 billion (Table 20), which compares to the $26 billion 

in debt it reported in 2007 (2010 dollars). One method of calculating the value underlying TVA’s high credit rating 

would be to compare TVA’s total interest costs against what TVA would pay if it had a lower credit rating. To 

determine the different levels of borrowing costs under various credit ratings, an estimate of the spread between 

different interest rates was calculated. The spread between TVA’s borrowing costs and alternative borrowing costs 

TVA records lease/lease back transactions and power 

prepayment obligations—along with more traditional forms of debt—as Total Financial Obligations (TFOs). 

 

34 In 2003 TVA initiated a pre-payment plan, which allowed TVA customers to pay for their power in advance but in return receive discounted 

rates, again resulting in a reduction in long-term debt. In 2004, TVA and MLGW, entered into an energy prepayment agreement under which 

MLGW prepaid TVA $1.5 billion for the future costs of electricity to be delivered by TVA to MLGW over a period of 180 months. TVA 

reported the prepayment as unearned revenue, and booked future energy sales obligations to MLGW as a long-term liability on its balance sheet. 

In 2010, TVA reported $822 billion (2010 dollars) liability in energy prepayment obligations.

35 Office of Management and Budget: http://www.whitehouse.gov/omb/budget/fy2004/pma/tvapower.pdf and 

http://www.whitehouse.gov/omb/budget/fy2004/agencies.html. 

36 TVA, Office of the Inspector General, “Final Report—Inspection 2007-11399—Review of TVA’s Financial Performance,” June, 2009. 37 Office of Management and Budget, Analytical Perspectives of the United States Budget Fiscal Year 2012, (Washington, 2011), p. 67. 38 General Accounting Office, Information on Lease-Leaseback and Other Financing Arrangements, “GAO-03-784, (Washington, DC, June 

2003).

39 Tennessee Valley Authority, SEC 10-K, 2006, p. 42. In TVA’s 2010, in summing the potential risk factors the TVA faced outlined in their 

forward looking statement, TVA stated: “Also, Congress may lower TVA’s debt ceiling or broaden the types of financial instruments that are 

covered by the ceiling.” Source: TVA 2010 10-K, p. 38.
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46 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

presents a measure of the value of TVA’s interest rate support. This report benchmarks TVA’s support to its Aaa 

bond rating. In other words, if TVA borrowed money at the Aa rate rather than the Aaa rate, its borrowing costs in 

2010 would increase 27 basis points, or result in $66 million (2010 dollars) in additional interest expense. This is 

one measure of federal support. An A bond rating would raise TVA’s 2010 borrowing costs by $123 million (2010 

dollars), and the Baa rating by $247 million (2010 dollars). In 2007, an Aa rating would have raised TVA’s borrowing 

costs by $70 million (2010 dollars), an A rating by $103 million (2010 dollars) and a Baa rating by $170 million 

(2010 dollars). The significantly larger Baa subsidy value in 2010 was largely driven by the broadening of the basis 

point spread between the Aaa rate and the Baa rate since 2007. Despite the decline in interest rates between 2007 

and 2010, the increased point spread between the Aaa and A, and the Aaa and Baa resulted in a larger subsidy in 

2010 than in 2007 when TVA’s debt is priced at the single A and Baa rates.

Power Marketing Authorities

The Bonneville Project Act of 1937 (Public Law 75-329) resulted in the creation of the Bonneville Power 

Administration. The Act required BPA to market hydropower produced from the Columbia River and to promote 

regional economic development. BPA is the largest of the federal PMAs and the second largest federal utility in 

terms of assets after TVA. The second largest PMA, the Western Area Power Administration (WAPA), was created 

in 1977 with the Department of Energy Organization Act of 1977 (Public Law 95-91). WAPA was charged with 

marketing hydropower facilities in the western United States including the power from the Hoover Dam, which 

was built in 1935. Both the Southwestern Power Administration and the Southeastern Power Administration owe 

their existence to the Flood Control Act of 1944 (Public Law 78-534) although the Southeastern Power 

Administration was not actually created until 1950. The Flood Control Act required: "Electric power and energy 

generated at reservoir projects under the control of the Department of the Army and in the opinion of the 

Secretary of the Army not required in the operation of such projects shall be delivered to the Secretary of the 

Interior, who shall transmit and dispose of such power and energy in such manner as to encourage the most 

widespread use thereof at the lowest possible rate to consumers consistent with sound business principles...Rate 

schedules shall be drawn having regard to the recovery (upon the basis of the application of such rate schedules to 

the capacity of the electric facilities of the projects) of the cost of producing and transmitting such electric energy, 

including the amortization of the capital investment allocated to power over a reasonable period of years. 

Preference in the sale of such power and energy shall be given to public bodies and cooperatives. The PMAs 

operate within the Department of Energy and the Secretary of Energy selects the PMA administrators.

BPA’s Borrowing Costs

BPA receives no direct payment from the Treasury. Rather, the support it receives from the Treasury involves the 

interest it pays on its debt. As with all other federal utilities, BPA is a not-for-profit enterprise and prices its power 

to recover its operating and capital costs. 

Although in large measure BPA’s lower prices are the result of its access to low-cost generation from federal 

hydropower facilities, below-market borrowing costs also add to its price advantage. BPA has, since its inception, 

benefited from substantial federal intervention in the form of interest rate support. The size of BPA’s estimated 

federal interest rate support is a function of the interest rate chosen to reflect the appropriate "market" interest

rate. Table 21 illustrates a computation of federal utility interest support, making alternative assumptions about 

the appropriate market interest rate. The estimated interest cost of BPA’s total debt lies somewhere between 

where it would be if it were priced between the 30-year Treasury and a Baa utility bond rating. BPA carries three 

forms of debt on its books. 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 47

Appropriated Debt. BPA appropriated debt refers to the unpaid portion of pre-1992 appropriations by Congress to 

fund the construction and replacement of U.S. Army Corps of Engineer’s generation facilities.40 Since passage of 

the EPAct1992, BPA has been required to fund these operations directly. BPA’s appropriated debt was 

restructured in 1996. Under the BPA Appropriations Refinancing Act of 199641 (The Refinancing Act), BPA reduced 

its principal obligation of the debt by $2.5 billion based on the present value of its debt service payment. It was 

then required to pay interest on the restated principal balance based on prevailing Treasury rates as of October 

1996.42

In 2010, BPA’s appropriated debt plus the Capitalization Adjustment equaled $5.9 billion in (2010 dollars) versus 

$6.4 billion in 2007 (2010 dollars). The nominal value of BPA’s appropriated debt was $6.2 billion in 2007. 

The $2.5 billion reflects the difference between BPA’s original principal balance and restated principal. It 

appears on BPA’s financial statements as a Capitalization Adjustment. Because BPA sets its own rates, it is able to 

record the Capitalization Adjustment on its balance sheet as a regulatory liability and amortize it through its 

income statement under Financial Accounting Standards Board Announcement No. 71 (FAS No. 71). In the absence 

of meeting the requirements of FAS No. 71, BPA would be required to write-off the Capitalization Adjustment. In 

other words, the Refinancing Act obligated BPA to pay a higher interest rate on a lower amount of debt. After the 

refinancing, the total cash flow to the Treasury, including a $100 million up-front cash payment, yields the same 

present value as BPA’s pre-refinancing obligation. 

Long-Term Debt. BPA’s long-term debt primarily funds its transmission system. In 1974, the Congress, as a part of 

the Columbia River Transmission Act (Public Law 93-454), allowed BPA an amount limited to a nominal $4.5 billion 

in direct borrowing authority from the Treasury with $3.2 billion earmarked to fund the utility’s transmission and 

other investment capital program and $1.3 billion for conservation and renewable energy investments. The 

appropriations are to be repaid to the Treasury by BPA. This long-term debt is actually a combination of medium 

and long-term maturities. The debt is held by the Treasury at interest rates set by the Treasury, which approximate 

the interest rates paid by government agencies. The rates are adjusted to reflect the cost of specific features of 

BPA’s bonds. In 2010, BPA’s long-term debt equaled approximately $2.2 billion versus $1.9 billion in 2007 (2010 

dollars). ARRA provided BPA with an additional $3.25 billion in Treasury borrowing authority. This additional sum 

was earmarked for transmission planning operation and construction. Thus far, BPA has used this authority to 

begin construction on the $343 million McNary-John Day transmission project, which is intended to support the 

integration of wind development in the Northwest

Non-Federal Projects Debt. Non-Federal projects debt stems from BPA’s assumption of the payment obligation on 

the debt of three Washington State Public Power Supply System (WPPSS) nuclear projects and several smaller 

generation and conservation investments. In 2000, BPA’s one commercially-operating reactor, WNP-2 was 

renamed the Columbia Generating Station. During the 1980’s, WPPSS defaulted on nuclear units 4 and 5.43 WPPSS 

is now known as Energy Northwest.44

 

40 This includes some funding for fish and wildlife recovery.

Energy Northwest is responsible for the financing of Nuclear Projects 1, 2, 

41 16 U.S.C. 838l. 42 The Act also required the BPA to pay the Treasury an additional $100 million, prorated over the course of the appropriations. This value was 

incorporated by BPA into its interest payment on appropriated debt and was captured in the interest support estimated in this chapter. In 2010, 

BPA’s appropriated debt stood at $5.9 billion. This includes a capitalization adjustment of $1.7 billion, which was included under appropriated 

debt prior to 1997. In 1997, the principal on BPA’s appropriated debt was reduced by $2.5 billion while interest on the debt was raised to 7.1 

percent from 3.5 percent. BPA realized a $100-million dollar transaction cost as a result of this principal and interest adjustment. 43 Myers, Elaine and David, Lessons from WPPSS, "In Context," Volume No. 7, p. 28 August 1984. See, 

http://www.context.org/ICLIB/IC07/Myers.htm. 44 Unit 4 is located at Richland, Washington while unit 5 is located at Satsop, Washington.
July 2011

48 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

and 3.45 As a result of its net billing arrangements, BPA passes on the cost of its non-Federal project debt to its 

customers. Net billing agreements are contractual arrangements under which the BPA bills participants in its 

inoperable Trojan nuclear plant46,47 and the Columbia Generating Station. Each participant assigns its share of 

output to the BPA and in return BPA credits the participant’s wholesale bill up to the monetary value of the 

participant’s share of the generation output.48 Thus, non-Federal project debt is not actually issued by BPA, but 

rather it is issued by Energy Northwest with BPA as the obligor pursuant to a net billing power supply 

arrangement.49

In 2010, approximately $3.4 billion of BPA’s $6.0 billion (2010 dollars) in non-Federal project debt was devoted to 

cancelled nuclear power plants. Although the federal government does not explicitly guarantee BPA’s non-Federal 

debt, the financial community treats the debt as though it was guaranteed. BPA is a federally-owned utility, and for 

its latest debt financing in 2010, Standard and Poor’s and Fitch Ratings assigned newly issued Energy Northwest 

revenue and refinancing bonds an AA rating.

 

50 Moody’s rated the bonds as Aaa.51 In Moody’s Investor Services 

High Profile New Issue dated December 2010, Moody’s states: “BPA’s Status as a U.S. Energy Department Line 

Agency and Its Relationship to the federal Government Are Important to the Credit Rating. While BPA’s obligations 

do not benefit from the full faith and credit of the United States Government, BPA benefits from significant 

support from the US government and strong interrelationships as shown below. In a major stress scenario, 

Moody’s expects any US government support to BPA is likely to be provided through the established US Treasury 

credit lines or deferral of payments to the US Treasury.“52

In the estimate of BPA’s federal interest rate support presented below, the interest cost of BPA’s non-Federal 

power debt is compared to the cost of similar debt issued by IOUs. This estimate is not without controversy. On 

the one hand, although much of BPA’s Energy Northwest debt is exempt from federal taxation, BPA is obligated to 

pay the debt service on Energy Northwest bonds and this debt appears on the balance sheet of the federallyowned utility.53 As obligor of this debt, whatever tax-free status this debt enjoys due to it “municipal” status, is 

deemed not relevant to the calculation of interest support provided through implicit federal ownership and 

backing. However, an alternative view might be to compare the cost of this debt to the cost of debt on tax-free 

municipal bonds. 

 

45 The only operating unit among these is Project 2, the Columbia Generating Station. 46 The Trojan project is among Bonneville’s terminated nuclear plants along with Energy Northwest Nuclear Projects 1 and 3. 47 BPA charges preference customers’ entitlement shares of output from the abandoned Trojan project. BPA became responsible for Trojan’s debt 

service and decommissioning costs. 48 Bonneville Power Administration http://www.bpa.gov/Power/PSR/pbl_billing_procedures.pdf, accessed October 11, 2007. 49 Standard and Poor’s notes that "Debt service on the $7.17 billion of outstanding ENW debt as of March 1, 2007 is legally an operating expense 

of Bonneville." Source: Standard and Poor’s Public Finance: 

http://www.bpa.gov/corporate/Finance/Debt_Management/reports_articles/docs/SP_2_17_04.pdf, accessed October 11, 2007. 50 Standard and Poor’s Global Credit Portal, “Summary: Energy Northwest, Washington Bonneville Power Administration,: Wholesale Electric,” 

February 25, 2011, http://www.bpa.gov/corporate/Finance/Debt_Management/reports_articles/docs/2011/S_P_Rating_Report-feb-2011. Fitch 

Ratings, Fitch Rates Energy Northwest, WA’s Columbia Generating Station ‘AA’ & Bonneville Power Implied ‘AA’ Ratings, December 2010,

http://www.bpa.gov/corporate/Finance/Debt_Management/reports_articles/docs/2010/Fitch_Rates_ENW__AA__Stable_Outlook_12-9-10.pdf. 51Moody’s Investors Service, High Profile New Issue, Energy Northwest, Bonneville Power Administration, December, 2010, 

http://www.bpa.gov/corporate/Finance/Debt_Management/reports_articles/docs/2010/BPA-ENW_high_profile_report_dec_2010.pdf 52 http://www.bpa.gov/corporate/Finance/Debt_Management/reports_articles/docs/2010/BPA-ENW_high_profile_report_dec_2010.pdf. 53 Certain Energy Northwest bond issues are also enhanced with bond insurance.
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 49

Table 21. Estimate of federal electricity interest rate support to BPA, 2007 and 2010 

(million 2010 dollars)

 Treasury 

Rate

Aaa IOU 

Rate

Aa IOU 

Rate

A IOU 

Rate

Baa IOU 

Rate

2007

1) Benchmark Interest Rate (%)

 

4.84 

 

5.67 

 

5.94 

 

6.07 

 

6.33 

2) Outstanding Debt ($) 18,378 18,378 18,378 18,378 18,378 

3) Average Cost of Outstanding Debt ($)

 

4.90 

 

4.90 

 

4.90 

 

4.90 

 

4.90 

4) Actual Interest Expense (%) 901 901 901 901 901 

5) Interest Expense Computed at Benchmark 

Rate ($) [(1)*(2)] 899 1,043 1,092 1,116 1,164 

6) Estimated Interest Support at Benchmark 

Rate ($) [(5)-(4)] 142 191 215 263 

2010

1) Benchmark Interest Rate (%) 4.24 4.96 5.23 5.46 5.97

2) Outstanding Debt ($) 18,246 18,246 18,246 18,246 18,246 

3) Average Cost of Outstanding Debt (%)

 

4.28 

 

4.28 

 

4.28 

 

4.28 

 

4.28

4) Actual Interest Expense ($) 782 782 782 782 782 

5) Interest Expense Computed at Benchmark 

Rate ($) [(1)*(2)] 774 905 954 996 1,088

6) Estimated Interest Support at Benchmark 

Rate ($) [(5)-(4)] 123 172 214 307 

Notes: The above table represents the historic value of BPA's debt in 2010 dollars for purposes of illustrating how support values for 2007 and 

2010 were calculated. The nominal value of debt reported on BPA's balance sheet for the year 2007 was: $14,531,190,000.

A negative estimate of interest support indicates the weighted average cost of outstanding debt exceeds the benchmark interest rate.

Source: Bonneville Power Administration, 2007 and 2010. Moody's Investors Service, Federal Reserve Bank Form H-15.

New Financial Arrangement

In April 2008, BPA and the U.S. Treasury formalized a new arrangement that provided what BPA calls “a more 

flexible banking financial relationship that better meets the Agency’s business needs. As part of this arrangement, 

BPA gained the ability to use part of its, then, $4.45 billion line of credit with the U.S. Treasury to borrow for 

expenses. Formerly, BPA had no arrangement with Treasury to borrow for such costs. BPA can now borrow up to 

$750 million for Northwest Power Act-related operating expenses, with funds available the same day as the 

request is made. The repayment period for these borrowings can range from three months to two years. When 

drawn on, this facility would be a use of Treasury borrowing authority.”
July 2011

50 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

BPA’s Federal Interest Support

EIA has estimated BPA’s cost of funds as being based upon its three sources of debt (Appropriated debt, long term 

debt, and non-Federal power debt) multiplied by the appropriate interest rates. In the case of appropriated debt, a 

30-year Treasury rate was applied. In the case of long term debt, the weighted average of BPA’s long term debt 

was used. In the case of non-Federal power debt, the average interest rate for municipal utilities was used. BPA’s 

current total cost of funds compared to what it would have spent had it borrowed at the U.S. Treasury rate and 

various IOU rates varies by the alternative interest rate selected for purposes of estimating the support (Table 21). 

This report estimates BPA’s borrowing costs based upon its three forms of debt. Estimates of the cost of this debt 

were done as follows: BPA’s appropriated debt is benchmarked to the BPA’s embedded borrowing costs, which 

are assumed to reflect long-term Treasury rates in both 2007 and 2010. Long-term debt is benchmarked to a 

weighted average of BPA’s reported long term borrowing costs as a percent of associated long-term debt 

issuances, as reported in BPA financial documents. BPA’s non-federal power interest payments are benchmarked 

to municipal bond rates as found in the Federal Reserve Bank’s Form H-15. In 2010, borrowing at a public utility 

rating of Aaa would have cost BPA an additional $123 million (2010 dollars); an Aa rating would have cost BPA an 

additional $172 million (2010 dollars); an A rate would have cost BPA an additional $214 million (2010 dollars); 

and, a Baa rating an additional $307 million (2010 dollars). In contrast, in 2007, an Aaa rating would have raised 

BPA’s borrowing costs by $142 million (2010 dollars); an Aa rate would have increased BPA’s borrowing costs by 

$191 million (2010 dollars); an A rate by $215 million dollars; and, a Baa rate by $263 million dollars (2010 dollars). 

The Smaller Power Marketing Administrations

The three smaller PMAs are the SEPA, the SWPA, and the WAPA. Each is headed by an administrator appointed by 

the Secretary of Energy. More so than either BPA or TVA, the three smaller PMAs benefit from low-cost 

hydropower dams that were built as long as 60 years ago. The PMAs receive appropriations from the Treasury for 

most of their operations and maintenance expenses, as well as for capital expenditures. The former is expected to 

be paid off in the year it is received; the latter can be paid back with interest over the service life of the 

investment, for a period not to exceed 50 years. In 2007, the PMAs' embedded cost of debt was more than 100 

basis points below the Treasury’s own borrowing costs, while in 2010, PMA’s embedded cost of debt was 24 basis 

points higher the Treasury benchmark rate. 

The largest of the 3 smaller Power Marketing Administrations, the Western Area Power Administration, received 

additional borrowing authority under the ARRA. The Act grants the Western Area Power Administration the 
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 51

Table 22. Estimate of federal electricity interest rate support to the three smaller PMAs, 2007 and 2010 

(million 2010 dollars)

 Treasury

Rate

Aaa IOU 

Rate

Aa IOU 

Rate

A IOU 

Rate

Baa IOU 

Rate

2007

1) Benchmark Interest Rate (%) 4.84 5.67 5.94 6.07 6.33 

2) Outstanding Debt ($) 7,310 7,310 7,310 7,310 7,310 

3) Average Cost of Outstanding Debt ($) 3.80 3.80 3.80 3.80 3.80 

4) Actual Interest Expense (%) 278 278 278 278 278 

5) Interest Expense Computed at Benchmark 

Rate ($) [(1)*(2)] 354 415 434 444 463 

6) Estimated Interest Support at Benchmark Rate 

($) [(5)-(4)] 76 137 156 166 185 

2010

1) Benchmark Interest Rate (%) 4.24 4.96 5.23 5.46 5.97

2) Outstanding Debt ($) 7,405 7,405 7,405 7,404 7,405 

3) Average Cost of Outstanding Debt ($) 4.47 4.47 4.47 4.47 4.47 

4) Actual Interest Expense (%) Computed at 

Benchmark Rate ($) [(1)x(2)] 331 331 331 331 331 

5) Interest Expense Computed at Benchmark 

Rate ($) [(1)*(2)] 314 367 387 404 442 

6) Estimated Interest Support at Benchmark Rate 

($) [(5)-(4)] NA 37 56 74 111 

Notes: The above table represents the historic value of three smaller PMAs debt in 2010 dollars for purposes of illustrating how support values 

for 2007 and 2010 were calculated. The nominal value of debt reported on their balance sheet for the year 2007 was $7,261,961,000.

A negative estimate of interest support indicates the weighted average cost of outstanding debt exceeds the benchmark interest rate.

Sources: Southeastern Power Administration 2007 and 2010 Annual Reports, Southwestern Power Administration 2007 and 2009 Annual 

Reports, Western Area Power Administration 2009 Annual Report, Moody's Investor Service, and Federal Reserve Bank Form H-15.

authority to borrow up to $3.25 billion from the U.S. Treasury.54 Section 402 of ARRA states: “The rate of interest 

to be charged in connection with any loan made pursuant to this subsection shall be fixed by the Secretary of the 

Treasury taking into consideration market yields on outstanding marketable obligations of the United States of 

comparable maturities as of the date of the loan.”55 Section 402 also promotes construction of additional 

transmission to move renewable energy across the grid in the West. Thus far, Western is using the grant to help 

build a $213 million Montana-Alberta Tie Limited transmission project between Great Falls, Mont., and Lethbridge, 

Alberta, Canada with the purpose of bringing additional wind power to the grid. The project is the first to use our 

new borrowing authority.56

 

54 Ibid, http://www.wapa.gov/newsroom/sec402.htm. 55 American Recovery and Reinvestment Act of 2009, Public Law 111-5, Section 402. 56 Western Area Power Marketing Administration, http://www.wapa.gov/recovery/default.htm.
July 2011

52 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Before 1983, the interest rate on the debt for the three smaller PMAs debt was set below prevailing Treasury 

rates. In 1983, DOE required the PMAs to pay a rate equal to the average Treasury yield during the previous fiscal 

year for new projects. According to an OMB study on PMA debt repayment, the Treasury has made a practice of 

borrowing money for the PMAs at 6 to 12 percent and accepting repayments on that debt at 2 to 4 percent. The 

PMAs are required to retire their high-cost debt first whenever possible, an advantage unavailable to the Treasury 

itself.57 This is another reason that the PMAs can realize an effective borrowing rate lower than the Treasury.58

Southwestern Power Administration: (SWPA) Southwestern markets hydroelectric power in Arkansas, Kansas, 

Louisiana, Missouri, Oklahoma, and Texas from 24 U.S. Army Corps of Engineers multipurpose dams. Preferential 

power is offered, by law, to public bodies such as rural electric cooperatives and municipal utilities.

 

Western Area Power Administration: WAPA’s marketing region includes five different regions, the Great Plains 

Region covers Montana, North and South Dakota, eastern Nebraska, and extreme western Minnesota and Iowa. 

The Rocky Mountain Region covers Wyoming, western Nebraska, western and northern Kansas and Colorado. The 

Desert Southwest Region covers the southern tip of Nevada, all but the northeast corner of Arizona, and southern 

California. The Sierra Nevada Region covers northern California and northern Nevada. The Colorado River Storage 

Project Management Center covers northeastern Nevada, Utah, New Mexico, west Texas, and the northeastern 

corner of Arizona.

Southeastern Power Administration: SEPA is headquartered in Elberton, Georgia, has the responsibility to market 

the electric power and energy generated at reservoirs operated by the U.S. Army Corps of Engineers in the states 

of Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina, Tennessee, Virginia, West 

Virginia, and a small portion of southern Illinois.

PMA Borrowing Costs 

The three PMAs' current interest expense was compared to what they would have paid had they borrowed at longterm Treasury rates, Aaa, Aa, A, or Baa IOU rates. The federal interest rate support is estimated as the difference 

between a hypothetical interest payment based on Treasury and market interest rates and the actual interest 

expense reported by each PMA. Depending on the comparative interest rate benchmarks, the three smaller PMAs 

received federal support ranging from $37 million (2010 dollars) if their debt were priced at an Aaa rate to $111 

million (2010 dollars) at the Baa rate in 2010 (Table 22). This compares with estimated support at the Treasury rate 

of $76 million in 2007 (2010 dollars) and $185 million at the Baa rate. In 2010, the smaller PMA’s borrowing costs 

exceeded those of the Treasury’s by 60 basis points.

 

57 IOUs have the ability to issue callable bonds which allows them the same advantage. However, when a bond is called, typically the issuer of 

the bond pays the bondholder a premium above the par value of the bond. 

58 General Accounting Office, Federal Power: Options for Selected Power Marketing Administrations’ Role in a Changing Electricity Industry, 

GAO/RCED-98-43, (Washington, DC, March 1998), p. 7.
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 53

Rural Utilities Service Electric Loans, Guarantees, and Grants 

The Rural Utilities Service (RUS), a part of the U.S. Department of Agriculture, makes direct loans and loan 

guarantees used to finance the construction of electric distribution, transmission, and generating facilities that 

serve customers in rural areas. By law, a RUS borrower must be a publicly-owned cooperative utility. RUS is the 

successor to the Rural Electrification Administration (REA), which was authorized by the Rural Electrification Act of 

1936. As the name, REA, suggests, RUS’s initial focus was solely on electricity. Over the years, REA’s authority 

expanded to include making loans for water, sewage disposal, and telecommunication facilities.59

In total, RUS’s borrowers service about 12 million customers and the total generation of these firms represents 

about 7 percent of the nation’s total. Also, more than 50 percent of the total sales of RUS borrowers go to 

residential customers, indicating that the borrowers’ retail share of electricity sales is relatively high when 

compared to other providers of electricity. This is not surprising since by law the customers of RUS borrowers 

must be in rural areas which, in a relative sense, tend to have a lower concentration of industrial and commercial 

electricity consumers. Lastly, the average size of RUS’s loans is about $30 million which is very small when 

compared to the average DOE loan programs office loan of more than $1 billion, as described in Chapter 5. The 

typical RUS borrower therefore tends to be a relatively small cooperative utility that services residential 

customers.

 Additionally, 

unlike the Department of Energy’s loan program, discussed in the next chapter, RUS has a long history in providing 

government-sponsored loan support. In fact, RUS’s loan program is one of the oldest in the federal government.

RUS can make three general types of loans and loan guarantees.60 First, hardship loans are available to electric 

distribution borrowers that have experienced an unavoidable natural disaster. The interest rate on these loans is 5 

percent. Hardship loans are also available to electric distribution borrowers that meet a rate disparity and 

consumer income test. This test compares the borrower’s retail rates and its customers’ per capita or household 

income to statewide averages.61 Second, RUS can also make direct loans that are tied to municipal bond or 

Treasury rates. These loans can be used to fund the construction of distribution, and renewable generating 

facilities, as well as their operational costs. After 2008, none of these loans can be used to construct fossil fuelfired power plants. Borrowers receiving loans, that are tied to municipal bond rates, which are typically lower than 

Treasury yields, must obtain supplemental financing from other lenders for generally 30 percent of the total loan 

amount. Third, RUS can also guarantee loans made by the federal Financing Bank (FFB), the funding arm of the 

Department of the Treasury through which government agencies obtain capital or by accessing financing from 

 

59 Recently, Federal legislation has been enacted that mandates the RUS to promote broadband. See; Congressional Research Service, 

“Broadband loan and Grant Programs in the USDA’s Rural Utilities Service,” RL33816 (Washington, DC, March 17, 2009). 60 See the 2007 report for a more detailed description of the types of RUS loans and guarantees. U.S. Energy Information Administration, 

Federal Financial Interventions and Subsidies in Energy Markets 2007, DOE/EIA-SR/CNEAF/2001-01 (Washington, DC, April 2008). 61 Residential and average system rates must not be less than 120 percent of the average for all utilities in the State, and, either per capita income, 

or household income, must be less than State average per capita income or the State median household income.
July 2011

54 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

cooperative and not for profit lending institutions such as the National Rural Utilities Cooperative Finance 

Corporation (CFC). It should be noted that, in this section, loans made by RUS will be identified as direct loans and 

loans made by the FFB or CFC will be identified as guarantees. In the next chapter, loans made by the FFB and 

guaranteed by DOE will also be called direct loans while loans made by privately owned lending institutions and 

guaranteed by DOE will be called a loan guarantees.62

Estimates of the subsidy provided by RUS electric loans and loan guarantees

Since RUS administers federal credit programs, the Federal Credit Reform Act of 1990 requires that they compute a 

credit subsidy cost associated with such programs. The CSC is the expected (in a mathematical sense) cost to the 

government of direct RUS loans and guarantees, and is computed by first estimating the cash inflows and outflows 

over the entire life of the loan.63

Unlike many other federal credit programs, the CSCs for RUS’s electric loans, as reported in their budget 

submissions, is negative implying that the expected (in a mathematical sense) cost to the government is negative. 

From a purely budgetary viewpoint, RUS’s electric loans will decrease government expenditures, and thus, from a 

budgetary viewpoint there are no subsidies associated with RUS’s electric loans. There are probably two reasons 

why the CSCs are negative. First, the interest rates paid by RUS borrowers are slightly greater than the Treasury 

rates used to discount these costs back to the present. Thus, if there are no defaults, the CSCs must be negative. 

Second, the default rates assumed by RUS for their direct electric loans are about 1-2 percent, and the assumed 

recovery rates are about 80-90 percent. Since the expected costs associated with defaults are very small, negative 

CSCs are not surprising. 

 These cash inflows and outflows are then adjusted for expected (again, in a 

mathematical sense) defaults and recovery rates if the loan is not paid, and then everything is discounted back to 

the present using Treasury rates. In most cases, an appropriation equal to the CSC is needed from Congress before 

loans can be made, and thus, the CSC, and the assumed default and recovery rates are reported in agencies’ 

budget submissions to Congress. Thus, from a budgetary viewpoint, the CSC is a direct measure of the subsidy 

provided by the RUS direct loans and guarantees.

As was done with the implicit loan guarantees to the debt holders of federal utilities, another measure of the 

subsidy resulting from the explicit RUS guarantees is the reduction in interest expenses. The size of this subsidy is 

a function of the spread between the cost of borrowing with RUS backing relative to the cost of uninsured longterm debt available in commercial capital markets. The latter reflects a risk premium associated with a borrower’s 

credit worthiness. Without detailed information about the direct loans and loan guarantees that RUS holds in its 

portfolio, it is impossible to estimate this spread. Therefore, the subsidy estimates reported in this section will be 

computed by comparing the embedded yields of RUS loans and loan guarantees to a range of investment grade 

bonds for 2009. The investment grade bond rates used here are those for Aaa, Aa, A, and Baa rated investorowned utility fixed-income securities. This range is provided, because it is unclear what rate RUS electricity 

borrowers would face in private markets without the RUS guarantees.

 

62 As will be seen in the next chapter, to date, all of DOE’s guaranteed loans are made by the FFB. 63 The FCRA of 1990 and the computation of the CSC are discussed in detail in the next chapter of this report.
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 55

The most current data available from RUS is for the year 2009, and thus, embedded debt rates in 2009 are 

compared with 2009 bond yields. RUS collects detailed financial data on utilities that currently have RUS direct 

loans. Included in these data are interest expenses and the dollar value of debt for two types of loans: 1) RUS 

direct loans; and, 2) loans made by the FFB/CFC and guaranteed by RUS. What is not reported is the amount of 

RUS guaranteed debt held by utilities that receive no RUS direct loans. Since the measure of FFB/CFC loans that 

are guaranteed by RUS is incomplete, as was done in the 2008 study, only the subsidy resulting from RUS’s direct 

loans will be computed.64 Additionally, to be consistent with other annual data estimates presented in this report, 

both the actual amount of debt and interest expenses were inflated to 2010 dollars. Thus, all of the subsidy 

estimates will also be presented in 2010 dollars. Additionally, as of May 2011, the DOE has guaranteed more than 

$25 billion in loans all of which were, or will be, issued by the FFB. There are also about $15 billion in loans issued 

by FFB/CFC and guaranteed by RUS that are held by current holders of RUS direct loans. Thus, the amount of 

energy-related loans issued by RUS and by the FFB/CFC and guaranteed by RUS or DOE is in excess of $75 billion.65

The subsidy estimates are shown in Table 23. The size of the subsidy estimates will be a function of the spread 

between RUS’s embedded debt rates and the assumed rates if the loans were made by private uninsured firms. In 

general, the subsidies have fallen from 2007 to 2010. In 2007, the estimates ranged from about $93 million to 

$305 million and in 2010 they ranged from about $56 to $319. (The $800 million estimate in 2009 appears to be 

an outlier and is due to usually high yields on Baa rated bonds in 2009 of more than 7 percent.)

When judging the actual risk of RUS loans, it should be noted that the assumed default rates of 1-2 percent used to 

compute the CSC are similar to historical default rates on bonds that were initially rated Aaa. (The rating of a 

typical bond issued by an investor owned electric utility is Baa.) Additionally, several analyses have concluded that 

in the past, RUS faced a significant risk of large loan defaults. For example, a 1997 Government Accountability 

Office (GAO) study found that $618 million of the outstanding electricity loan portfolio was owed by borrowers 

who were delinquent in their payments and that $7.4 billion of the outstanding debt was owed by borrowers who 

were in financial distress. At that time the outstanding RUS electricity debt totaled $32.3 billion, of which 

approximately 25 percent was at risk of not being fully repaid. In a subsequent report, GAO found that the RUS 

wrote off more than $3.2 billion in loans made to three borrowers.66 Much of the problem debt was associated 

with loan guarantees for borrowers’ investments in high-cost nuclear plants in the early 1980s. For example, the 

Wall Street Journal reported that more than $1.5 billion in debt was written down for two borrowers in 1996. In 

2006, the RUS reported $818,000 in a loan write-down due to the default of the Vermont Electric Generation and 

Transmission Cooperative.67

 

64 Total interest expenses for RUS’s direct loans and guarantees are reported. The interest expenses for direct RUS loans were imputed using the 

ratio of RUS direct loans to total debt.

65 Again, this is a lower bound estimate since the amount of RUS guarantees held by utilities that current hold no direct RUS loans is not 

reported.

66 Government Accountability Office, Rural Utilities Service: Opportunities to Better Target Assistance to Rural Areas and Avoid Unnecessary 

Financial Risk, GAO-04-647 (Washington, DC, June 2004), p. 8 67 Conversation with Chris Tuttle of the Rural Utilities Service, July 30, 2007.
July 2011

56 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 23. Interest subsidy to RUS borrowers 2007 and 2010 

(million 2010 dollars)

Treasury 

Rate

Aaa IOU 

Rate

Aa IOU 

Rate

A IOU 

Rate

Baa IOU 

Rate

2007

1. Benchmark Interest Rate (%) NA

 

5.67 

 

5.94 

 

6.07 

 

6.33 

2. Outstanding Debt ($) NA

 

32,273

 

32,273 

 

32,273 

 

32,273 

3. Average Cost of Outstanding Debt (%) NA

 

5.39 

 

5.39 5.39 

 

5.39 

4. Actual Interest Expense ($) NA

 

1,738 

 

1,738

 

1,738 

 

1,738 

5. Interest Expense Computed at Benchmark 

Rate ($) [(1) x (2)] NA

 

1,831

 

1,917

 

1,960 

 

2,043 

6. Estimated Interest Subsidy at Benchmark 

Interest Rate ($) [(5)-(4)]

 

NA

 

93

 

180 

 

222

 

305 

2010

1. Benchmark Interest Rate (%) NA 

 

4.96 

 

5.23 

 

5.46 

 

5.92 

2. Outstanding Debt ($) NA

 

35,746 35,746

 

35,746

 

35,746

3. Average Cost of Outstanding Debt (%) NA 

 

5.07 

 

5.07 

 

5.07 

 

5.07 

4. Actual Interest Expense ($) NA 

 

1,813 

 

1,813 

 

1,813 

 

1,813 

5. Interest Expense Computed at Benchmark 

Rate ($) [(1) x (2)] NA 

 

1,773

 

1,869

 

1,951

 

2,132

6. Estimated Interest Subsidy at Benchmark Interest Rate 

($) [(5)-(4)]

 

NA

 

NA

 

56 

 

138

 

319

Note: NA indicates that some of the cost of outstanding debt exceeds the benchmark interest rate. There is no subsidy when benchmark rates are 

less than the weighted cost of capital. 
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 57

Table 24. Interest subsidy to federal utilities and RUS borrowers 2007 and 2010 

(million 2010 dollars)

Treasury 

Rate

Aaa IOU 

Rate

Aa IOU 

Rate

A IOU Rate Baa IOU 

Rate

2007

1. Benchmark Interest Rate (%) 4.84

 

5.67 

 

5.94 

 

6.07 

 

6.33 

2. Outstanding Debt ($) 83,796 83,796 83,796 83,796 83,796

3. Average Cost of Outstanding Debt (%) NA

 

5.23 

 

5.23 

 

5.23 

 

5.23 

4. Actual Interest Expense ($) NA 4,383 4,383 4,383 4,383

5. Interest Expense Computed at 

Benchmark Rate ($) [(1) x (2)] 

NA 

4,751

 

4,977

 

5,086

 

5,304

6. Estimated Interest Subsidy at Benchmark 

Interest Rate ($) [(5)-(4)]

NA 

368

 

594

 

703

 

921

2010

1. Benchmark Interest Rate (%) 

 

4.24 

 

4.96 

 

5.23 

 

5.46 

 

5.97 

2. Outstanding Debt ($) 85,988 85,988 85,988 85,988 85,988

3. Average Cost of Outstanding Debt (%) NA 

 

4.82 

 

4.82 

 

4.82 

 

4.82 

4. Actual Interest Expense ($) NA 4,146 4,146 4,146 4,146

5. Interest Expense Computed at 

Benchmark Rate ($) [(1) x (2)] NA 4,265 4,497 4,695 5,133

6. Estimated Interest Subsidy at Benchmark 

Interest Rate ($) [(5)-(4)] NA 119 351 549 987

Note: NA indicates that some of the cost of outstanding debt exceeds the benchmark interest rate. There is no subsidy when benchmark rates are 

less than the weighted cost of capital.
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58 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Summary

In 2010, the total value of support provided federal utilities and RUS borrowers is estimated at $119 million (Table 

24) at the Aaa benchmark rate, $351 million at the Aa rate, $549 million at the A rate, and, $987 million at the Baa 

rate. This compares to 2007 support values of $368 million at the Aaa rate, $594 million at the Aa rate, $703 

million at the A rate, and $921 million at the Baa rate. The estimate varies using different benchmark interest 

rates. Federal utilities and participants in RUS electricity lending programs borrow at rates typically below those 

available to non-publicly-owned power producers. In 2010, the ratio of embedded cost of debt (interest expenses) 

to the outstanding debt for federal utilities and RUS borrowers indicates that these entities have borrowed at rates 

ranging from slightly higher than the Treasury’s own costs of funds to those for a highly-rated utility with an Aaa 

bond rating.
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 59

5. Loan Guarantee Programs 

Introduction

This chapter presents a description of the Department of Energy's (DOE) loan guarantee programs and presents 

some estimates of the resulting subsidies. With the exception of RUS and the synthetic fuel program in the 1970s, 

energy-related explicit loan guarantee programs are new federal interventions in energy financial markets. DOE's 

initial loan guarantee program was authorized by the Energy Policy Act of 2005 (EPAct2005) and the first 

guarantee was issued in the fall of 2009. As of the end of calendar year 2010, the Department of Energy has 

actually issued over $25 billion in loan guarantees. Additionally, the staff of the office within DOE that administers 

the programs has grown from 0 in 2005 to roughly 85 in 2010. Thus, DOE's loan guarantee program is growing and 

is becoming an important component of the Administration's energy program.

As can be seen from Table 25, the size of federal credit programs in general have increased considerably. Here, 

the dollar value of the additional loans agencies are authorized to issue in Fiscal Year 2010 is used as the measure 

of volume. In fact, the total size of federal credit programs has more than doubled over the last 6 years. The 

growth in DOE's loan guarantee program is therefore one part of the overall trend toward the increased use of 

federal credit programs. It is also interesting to note that when compared to housing and education, energyrelated loan guarantee programs are relatively small.

Table 25. Additional lending authority for loan guarantee programs in selected government agencies, 2004 and 

2010

(thousand 2010 dollars)

Selected Agencies 2004 2010

Department of Agriculture excluding RUS $16,656,571 $50,764,352

Department of Education $91,773,139 $258,868,106

Department of Energy $0 $47,367,293

Rural Utility Service: Electricity Program $3,989,410 $7,100,000

Department of Housing and Urban Development $368,904,121 $741,988,701

Department of Veteran Affairs $48,450,960 $60,215,650

Department of Transportation $3,226,777 $2,805,510

Small Business Administration $21,918,500 $44,852,036

International Assistance programs $655,000 $4,324,879

Total for Selected Agencies $555,574,478 $1,218,286,527

Source: FY 2011 Budget Submission to Congress, Federal Credit Supplement, Spreadsheets. 
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60 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Although the size of DOE's loan guarantee program is relatively small, the dollar value of the average loan is over 

$1 billion. Excluding the Troubled Asset Relief Program (TARP), the average size of DOE's loans is the largest in the 

federal government.68

The previous chapter estimated the reduction in borrowing costs of federal utilities because of the “implicit” 

guarantees on the loans of these agencies. This chapter will estimate the total cost savings resulting from the 

explicit guarantees. Thus, there are some similarities between the analysis in that chapter and this one. There are, 

however, some major differences in the analyses. First, the implicit guarantees examined in the previous chapter 

went to publicly-owned utilities whereas the bulk of DOE's loans went to privately-owned firms. As will be seen 

later, the calculation of the cost savings of publically and privately-owned firms will be different. Second, in the 

case of explicit guarantees, federal regulations require agencies to estimate one direct measure of the subsidy

supporting those guarantees. 

 Thus, one or two defaults of DOE guaranteed loans could result in substantial losses to the 

federal government. It is not surprising that the amount of information DOE requires to process a loan request is 

rather large and the approval process can take a considerable amount of time.

In this chapter, two types of loan guarantee programs will be considered. The first type is a true guarantee by DOE 

of a loan made by a third party in the private sector such as a commercial bank or investment house. The second is 

direct loans made by the Department of Treasury’s Federal Financing Bank (FFB) to the borrower and guaranteed 

by DOE. In the latter case, in case of default, the cost would appear on DOE's rather than Treasury's accounts. 

Almost all of DOE's loan guarantees are actually direct loans made by the FFB. Thus, in this chapter, the focus will 

be on loans made by the federal government as opposed to ones made by third parties in the private sector. 

Additionally, the phrases "direct loan" and "loan guarantee" will be used interchangeably.69

The organization of the remainder of this chapter is as follows. The budgetary accounting for loan guarantees is 

unique to the federal government and is governed by the Federal Credit Reform Act (FCRA) of 1990. In fact, the 

FCRA requires that federal agencies compute the credit subsidy cost which is one direct measure of the subsidy 

provided by DOE's loan guarantee programs. The next section discusses the FCRA and describes how the credit 

subsidy cost is computed. The following section describes DOE's loan guarantee programs. Excluding RUS and 

perhaps the Export-Import Bank, there are a number of very small energy-related loan guarantee programs in the 

Departments of Agriculture and Housing and Urban Development (Due to their small size these programs are 

excluded from this analysis). The next section presents some estimates of the subsidy provided by DOE's loan 

guarantee program. Some conclusions are reached in the final section of this chapter.

 The distinction 

between direct loans and ones that are originated in the private sector and guaranteed by a federal agency is 

important because interest rates on the former tend to be slightly lower than the ones on the later.

 

68 FY 2011 Budget Submission to Congress, Federal Credit Supplement, Spreadsheets, Table 2. 69 As noted in the previous chapter, some agencies have direct lending authority. Since DOE has no such authority this type of loan will not be 

considered.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 61

The Federal Credit Reform Act of 1990 and the Computation of the Credit 

Subsidy Cost

After many years of discussions about the problems with the federal budgetary treatment of existing federal credit 

programs, in 1990 the Congress and Bush Administration agreed to change the accounting guidelines for these 

programs in the budget. The Federal Credit Reform Act (FCRA) of 1990 required the federal budget to reflect the 

“true” cost of federal credit programs. The FCRA also changed the budgetary accounting practices so that the cost 

of a credit program was consistent with the ones for other government activities.70

Before the passage of FCRA, the cost of a credit program was computed on a pure cash basis. For a direct loan, the 

budget would reflect the dollar value of the loan in the year that it was made. Any interest payments and/or 

repayment of principal would appear on the budget the year the monies were received. In case of default, the 

funds that were recovered would appear as a receipt the year the default occurred. For loans made by parties in 

the private sector that were guaranteed by the government, budgetary outlays would only occur if the loan was 

defaulted. In such cases, the outlay would equal the guarantee less any repayment of the principal. If the loan 

was not defaulted, there would be no budgetary impacts. Prior to 1990, the cost of a guarantee would be incurred 

in the future whereas the cost of a direct loan would be incurred when it was made. It was therefore not 

surprising that prior to 1990, there were relatively few direct loans.

Additionally, before 1990, many credit programs were subject to legislatively imposed limits. According to the 

Congressional Budget Office (CBO), in some cases, these limits had little effect on actual borrowing activity, 

because the limits were very high relative to actual demand. Additionally, prior to the passage of the FCRA, many 

credit programs used revolving funds, an account that was credited with payments from borrowers to finance the 

continued activity of the program. The only time an appropriation would be needed was when a fund had a 

negative balance. In such cases, Congress would appropriate enough monies to insure that the fund remained 

solvent. Thus, at least according to the CBO, Congress had limited control of an agency's actual borrowing 

activity.71

Under the FCRA, the cost of federal credit programs would be recorded on an actuarial, as opposed to a cash basis. 

In particular, the expected (in a mathematical sense) cash inflows and outflows estimated over the entire life of 

the loan are estimated. The inflows would include interest payments and repayment of the principal. The 

outflows would consist of the dollar value of the loan and in the case of guarantees, payments to the lender in case 

of default. Then, all the expected cash flows are discounted back to the present using yields on Treasury bonds as 

the discount rate. The result is called the credit subsidy cost (CSC) and is the expected cost of the loan to the 

government. An explicit appropriation from Congress equal to the CSC is needed before the loan would be made. 

(The only exception to this is when the borrower pays the CSC.) Thus, Congress now has direct control over the 

size of a federal credit program. Additionally, the CSC would appear on the federal budget as the cost of the loan 

when it was made.

 

 

70 This borrows very heavily from Congressional Budget Office Staff Memorandum, An Explanation of the Budgetary Changes Under Credit 

reform, April 1991

71 Ibid, p 7.
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62 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

The actual computation of the CSC can be complex. However, the spirit of the computations will be illustrated 

with a very simply example. In this example, the following assumptions will be made:

 1. Size of the loan-$100

 2. Length of loan-2 years

 3. Probability of default in year 1-0 percent

 4. Probability of default in year 2-25 percent

 5. Recovery rate in case of default-30 percent

 6. Treasury bond rate-5 percent.

Given these assumptions, the computation of the CSC for a direct loan is shown in Table 26. Column a shows the 

cash outflow which is simply the dollar value of the loan (-$100 in this example.). The cash inflow if the loan is not 

defaulted is shown in column b. In year 1 the government would receive $5 in interest payments, and in year 2 

they would receive the interest payment plus the repayment of the principal ($100 + $5). The expected cash 

inflow if the loan is not defaulted (column d) is the cash inflow times the probability of not defaulting on the loan 

($105 x .75=$78.75). If the loan is defaulted, by assumption, the government could recover 30 percent of the loan 

or $30. This is shown in column f. The expected cash inflow if the loan is defaulted would simple be $30 times the 

probability of default of 25 percent. Total expected cash inflows and outflows are shown in column h. The CSC is 

the sum of the expected cash inflows and outflows all discounted back to the present using yields on Treasury 

bonds as the discount rate (see column i). In this example, the CSC would be $17 dollars. Again, Congress would 

have to appropriate $17 before the loan could be made.

Table 26. An example of the computation of the credit subsidy costs

Year

Columns

a b C d e f g h i 

Cash Outflows 

Cash 

Inflows if 

no 

Default 

Probability 

of not 

Defaulting 

Expected 

Cash 

Inflows if 

Loan is 

not 

Defaulted 

(b x c)

Recovery 

Rate if 

Loan 

Defaulted 

(percent)

Cash 

Inflows 

if Loan 

Default

ed 

(100 x 

.3)

Expected 

Cash 

Inflows if 

Loan 

Defaulte

d (f x (1-

c))

Total 

Expect

ed 

Cash 

Inflow

s and 

Outflo

ws (d 

+ g)

Discounted 

Cash 

Inflows 

and 

Outflows 

0 -$100 -$100 -$100.00

1 $5 100% $5 NA $5 $4.76

2 $105 75% $79 30% $30 $8 $86 $78.23

Credit Subsidy Cost -$17.01

Totals may not equal sum of components due to independent rounding. 

Source: Office of Energy Analysis, U.S. Energy Information Administration. 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 63

The computation of the CSC for a loan that is made by a third party in the private sector and guaranteed by the 

government is straight forward. If the loan is not defaulted, the expected cost to the government would be zero (0 

x .75). If the loan is defaulted, the government would have to reimburse the lender for the principal ($100) and 

foregone interest ($5). Again, by assumption, the government would recover $30. Thus, the expected cost to the 

government would be $18.75 ((-105+30) x .25) and when this is discounted back to the present, the CSC would 

again be $17.

This example illustrates a number of important points. First, it shows the differences in the budgetary reporting of 

th costs of federal credit programs. Before the passage of FCRA, for a direct loan, the costs are shown in column a, 

and column b if the loan is not defaulted or column f if it is defaulted, would be reported in the appropriate year. 

Under FCRA, the subsidy cost, $17, would be reported the year the loan was made. Second, everything else being 

equal, under the FCRA the CSC for direct loans and guarantees would be the same. Thus, FCRA removed the builtin incentive toward making guarantees as opposed to direct loans. Lastly, many discussions about the value of the 

CSC focus on default rates. This example illustrates that recovery rates and the timing of the default are also 

important. In agencies’ budget submissions to Congress, they report the assumed default and recovery rates. 

However, timing issues are seldom discussed. 

Energy-Related Loan Guarantee Programs

Other than RUS which was discussed in Chapter 4 and possibly the Export-Import Bank, most of the energy-related 

loan guarantee programs are administered by DOE. (There are two energy-related loan guarantee programs in the 

Department of Agriculture, and one in the Department of Housing and Urban Development. All of these are very 

small.) The DOE has three programs, the oldest of which is authorized by Section 1703 of the Energy Policy Act of 

2005 (EPAct05). The second is authorized by Section 406 of the American Recovery and Reinvestment Act (ARRA) 

of 2009. This section of ARRA amended Title 17 of EPAct05 by adding Section 1705. The third program is called 

the Advanced Technology Vehicles Manufacturing (ATVM) program. It is authorized by Section 136 of the Energy 

Independence and Security Act (EISA) of 2007.

The Title 1703 Loan Guarantee Program

Title 1703 of EPAct05 authorizes the DOE to make loan guarantees to fund projects related to the generation and 

conservation of electricity, including nuclear power. These projects must avoid, reduce or sequester greenhouse 

gasses and employ new or significantly different technologies compared to ones currently in commercial operation 

in the United States. To date, participating borrowers had to pay the entire CSC for any loan authorized under 

Section 1703. This way, the 1703 program is different from the other loan programs administrated by DOE. 

After EPAct2005 was passed, to implement the program a rulemaking specifying the details was needed. The final 

DOE rulemaking, issued on October 23, 2007 (and amended on November 4, 2009), established a two step process 

for applying for a loan guarantee.72 The DOE first issues a solicitation to invite pre-applications for loan 

 

72 Federal Register, Tuesday, October 23, 2007,Part III, Department of Energy, 10 CFR Part 609, Loan Guarantees for Projects that Employ 

Innovative Technologies; Final Rule. 
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64 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

guarantees. Included in these pre-applications are construction cost estimates in reasonable detail; estimates of 

when the project will be completed; and, descriptions of any revenue generating agreements (i.e., purchased 

power contacts.). If these pre-applications pass initial screenings, full applications can then be submitted to the 

DOE. These applications will include detailed estimates of expected construction and operating costs; detailed 

descriptions of all the milestones leading up to the project's completion; and, a rating of what the project's risk 

would be without the guarantee made by one of the three major security rating firms.

One of the most controversial aspects of the final rulemaking dealt with the size of guarantee relative to the size of 

the project. Title 17 of EPAct05 stated that the DOE could guarantee up to 80 percent of total eligible costs. In 

the proposed rulemaking, the DOE said that they would only guarantee up to 90 of the debt, thus effectively 

reducing the maximum guarantee to 72 percent (90 x 80 percent) of the debt. DOE initially argued that having 

some uninsured debt would increase the incentives to successfully complete the project. After reviewing a 

number of comments to the proposed rule, especially ones made by the nuclear industry, the final rule stated that 

DOE would guarantee 100 percent of the debt. 

When the final rulemaking was passed in 2007, DOE was only authorized to issue $4 billion in loan guarantees and 

in their FY2008 budget submission DOE requested an additional $9 billion. This would bring the total loan 

authorization up to $13 billion. With the passage of the FY 2008 Appropriations Act, the Section 1703 loan 

authorization was increased by an additional $38.5 billion. The legislation allocated the additional $38.5 billion cap 

as follows: $18.5 billion to nuclear plants; $10 billion for renewable, conservation, distributed energy and 

transmission/distribution technologies; $6 billion for carbon capture technologies; $2 billion for advanced coal 

gasification; and, $2 billion for advanced nuclear facilities for the front end of the fuel cycle. This increased the 

total loan cap to $51.5 billion.73

To date, about $10.6 billion in conditional and final Section 1703 loans have been awarded. Of this, $8.33 billion 

was used to finance the construction of the Vogtle 3 and 4 nuclear units. About 45 percent of these proposed 

units will be owned by Georgia Power, and the remaining 55 percent by three publicly-owned utilities. About $3.4 

billion of the loan went to Georgia Power and the remaining $4.9 billion went to the three publically-owned 

utilities. Areva, a large French publically-owned firm, also received a $2-billion loan to build a nuclear enrichment 

facilitate in Idaho. The remaining $300 million in 1703 loans went to 2 energy efficiency projects. In sum, these 

loans will support projects with a total cost of about $16.4 billion. Thus, the dollar value of the loans made under 

Section 1703 are about 65 percent of the total costs of the projects which is far less than the maximum of 80 

percent. The remaining 35 percent would supposedly be equity financed. 

 The 2011 and 2012 budget submissions contained provisions that would have 

increased the nuclear cap by an additional $36 billion, which would have brought the nuclear total to $54.5 billion. 

In 2010, the Senate Appropriations Committee reduced the nuclear cap to $28.5 billion. However, the full Senate 

or House of Representative never voted on that bill. 

 

73 FY 2011 Budget Submission to Congress, Appendix, Department of Energy, p 441.
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 65

Title 1705 Loan guarantee program

Section 406 of the ARRA amended Title 17 of the EPAct05 by establishing Section 1705, a temporary loan 

guarantee program designed to support the rapid deployment of renewable energy and electric power 

transmission projects. Unlike Section 1703 loans, the DOE and not the borrower pays the CSC and thus DOE would 

need an explicit appropriation from Congress. Additionally, the requirement that the technology must be new was 

removed. To receive a loan under Section 1705, construction of the project must begin by September 30, 2011.

DOE has issued three solicitations under this program one of which established the Financial Institution 

Partnership Program (FIPP.) Under this program, if private sector lenders would fund eligible projects, DOE would 

guarantee up to 80 percent of the debt. In effect, the guarantee was used as “seed” money to stimulate private 

sector funding of eligible projects. However, based on information from the Loan Guarantee Office’s Web site, 

only three Title 1705 projects were funded under the FIPP. 

As of 2011, $2.5 billion in CSCs have been appropriated for Section 1705 loans As will be seen in the next section, 

the Credit Subsidy Rate (the CSC divided by the dollar value of the loan) for 1705 loans is about 10 percent.74

Table 27 shows the dollar value of the loans for various renewable and transmission technologies. There have 

been three loans with a dollar value of about $3.8 billion for large solar power plants. The total capacity of these 

power plants is about 800 megawatts. Estimated solar capacity in 2010 is about 700 megawatts.Assuming that all 

of these projects become operational, total solar capacity would more than double. About $1.3 billion of the 

$1.43 billion of guarantees for wind went to the Caithren Shepards Flat Project. The size of this wind farm would 

be 845 megawatts and upon completion one of the largest wind farms in the United States. As of January 2011, 

this was the only project funded under the FIPP.

 This 

$2.5 billion appropriation will therefore support about $25 billion in loans. As of January 2011, a total of 14 

conditional and final Section 1705 loans with a dollar value of about $7 billion have been made. The total cost of 

the projects receiving Section 1705 loans are about $11.4. Thus, the dollar value of the loan was about 64 percent 

of the total costs.

Advanced Technology Vehicle Manufacturing Loan Guarantee Program

Unlike the bulk of the Title 17 loans, the Advanced Technology Vehicle Manufacturing (ATVM) loan guarantee 

program focuses on developing the infrastructure needed to produce Advanced Vehicles. In particular, Section 

136 of authorized DOE to make grants and loan guarantees for projects that reequip, expand, or establish 

manufacturing facilities to produce advanced technology vehicles, or necessary components. Here, an advanced 

vehicle is defined as a light duty car that meets required emissions standards and has a fuel economy that is 125

percent of base year standards for automobiles with similar attributes. Thus, in this context, an advanced vehicle 

is effectively an electric powered automobile. Section 136 also authorized DOE to make grants and loan 

guarantees to cover the costs of certain engineering activities needed to produce advanced technology vehicles. 

In EIAS2007, a qualified component is one that is designed for an advanced vehicle and installed for the purpose of 

meeting the 125 percent fuel efficiency performance standards.

 

74 FY 2012 Budget Submission to Congress, Appendix, Department of Energy, p 420.
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66 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 27. Section 1705 loans by technology as of early 2011

(billions of dollars)

Technology Loan Size

Biofuels 0.241

Geothermal 0.181

Solar-generating facility 3.817

Solar Infrastructure 0.935

Wind 1.433

Storage 0.060

Transmission 0.350

Total 7.017

Totals may not equal sum of components due to independent rounding.

Source: Computed from data from U.S. Department of Energy, Loan Guarantee Program Office, https://lpo.energy.gov/?page_id=45, 

accessed March 23, 2011.

As was the case for the Title 1705 loans, under ATVM program the government will pay the subsidy costs, and, 

thus an explicit appropriation is needed. The Continuing Resolution Appropriations Act of 2009 appropriated $7.5 

billion in CSCs that would support a maximum of $25 billion in loans.75

Table 28 shows the ATVM loans made to date. The loan to Ford Motor Company will be used to upgrade factories 

across Illinois, Kentucky, Michigan, Missouri and Ohio to produce some of their hybrid and electric automobiles. 

The loan going to Nissan Motor Company will be used to retool its Smyrna Tennessee plant to produce all-electric 

automobiles, and to construct an advanced battery manufacturing facility. The loans to Fisker Automotive and 

Tesla Motors will be used for similar functions. Interestingly, the loan going to the Vehicle Production Group will 

support the development of a wheelchair accessible vehicle that will run on compressed natural gas. As of early 

2011, about $8.3 billion in ATVM loans have been made that will support projects with a total cost of about $14.4 

billion. Thus, the dollar value of ATVM loans is about 58 percent of the project's total costs.

 The rulemaking issued by DOE in November 

2008 stated that the maximum loan as a present of the total costs would be 80 percent. This is consistent with the 

rulemaking for the Title 17 loans. Lastly, DOE's authority to make loans under this program expires in 2017.

Other Energy related Loan Guarantee programs

There are four other energy-related loan guarantee programs. The largest one is under the RUS which was 

discussed in the previous chapter. The Rural Energy for American program provides loan guarantees to farmers,

ranchers, and small rural businesses to purchase renewable energy systems and make energy efficient 

improvements. The Biorefinery Assistance program provides loan guarantees to fund the development,

 

75 FY 2012 Budget Submission to Congress, Appendix, Department of Energy, p 417. 
July 2011

U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 67

Table 28. ATVM loans made as of January 2011

(billions of dollars)

Company Loan Size

Nissan 1.400

Tesla 0.465

The Vehicle Production Group 0.050

Ford 5.900

Fisker Associates 0.529

Totals may not equal sum of components due to independent rounding.

Source: Computed from data from U.S. Department of Energy, Loan Guarantee Program Office, https://lpo.energy.gov/?page_id=45, 

accessed March 23, 2011. 

construction, and retrofitting of commercial size advanced biorefineries. Both of these programs are also in the 

Department of Agriculture. The last one is the Green Retrofit Program which offers either grants or loans to 

owners of Housing and Urban Development (HUD) assisted multifamily housing properties to fund energy efficient 

retrofits. As of 2010, excluding RUS, these programs have made less than $100 million in loans. Since they are so 

small, they will not be considered in the analysis described in the next section.

Subsidies Resulting from DOE's Loan Guarantee Program

This section describes the estimation of subsidies resulting from DOE‘s loan guarantee program. Congress 

requested that EIA focus on fiscal year 2010. Thus, only loans that received conditional or final approval in fiscal 

year 2010 will be included in this analysis.

76

There are a number of ways of estimating the subsidy provided by DOE's loan guarantee program. A multi trillion 

dollar private market for insurance against loan defaults exists. In theory, a firm receiving a loan guarantee from 

the government could have instead purchased insurance from private insurers such as MBIA. In such cases, one 

direct measure of the subsidy would be the insurance premium a recipient of a government provided loan 

guarantee would have to pay if the insurance was purchased from private insurers. There is an extensive 

theoretical literature on this subject, and in the past, there have been attempts to estimate this insurance 

premium on government-provided loan guarantees.

 The total value of such loans was about $23 billion that supported 

projects with a total cost of about $37 billion. Additionally, as will be seen shortly, because of the lack of public 

information about the details of the loans that were guaranteed, the best that could be done to estimate the 

underlying costs was to estimate ranges; and, in some cases these ranges were rather large. Some of the analysis 

also deals with the effects of financial leverage. For reasons that will be discussed below, in some cases, 

cooperative and municipal utilities were excluded from the calculations.

77 This, however, it would involve a major research effort that 

is far beyond the scope of this analysis.

 

76 Ford Motors received final approval for their $5.9 billion loan in late September of 2009. Fiscal year 2010 began on October 1, 2009. Because 

of the size of this loan it was included in the calculations.

77 Robert McDonald, Derivative Markets, (New York: Addison-Wesley, 2003), Chapter 10; and, Congressional Budget Office, Estimating the 

Value of Subsidies for Federal Loans and Loan Guarantees, August 2004. 
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68 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Credit Subsidy Cost Estimates

Another way to estimate the subsidy is to use the credit subsidy cost (CSC). Again, the FCRA requires an explicit 

appropriation equal to the CSC for every loan guarantee made unless the borrower pays the CSC. Since the CSC is 

the expected cost to the government for a loan guarantee, it measures the cost paid by the taxpayer, as opposed 

to the borrower, for insuring a loan and, thus, is another direct measure of the subsidy. There are, however, a 

number of problems with using the CSC. First, since the CSC is forward looking, it is different from the other 

subsidy estimates which are estimates at a particular point in time. Second, the CBO has shown that after 

accounting for risks other than ones related to default, the CSC, whose computation is dictated by the FCRA, will 

understate the actual cost of a loan guarantee--sometimes by a large amount.78

Lastly, every year that DOE requests authorization from Congress to issue additional loan guarantees, they often 

report the estimated CSCs. DOE also reports the estimated default and recovery rates used to compute these

CSCs. In their budget submission to Congress, DOE clearly notes that the estimated CSCs are based on a portfolio 

of placeholder loans. (DOE does compute the CSCs for the loans that they actually guarantee, but they do not 

make those figures public.) The average credit subsidy rate (CSR) for the Title 1705 loans was about 11 percent 

which is based on estimated default rates in excess of 25 percent and recovery rates of about 55 percent. (The CSR 

is simply the CSC divided by the dollar value of the loan.) Additionally, on average the DOE-estimated CSRs for the 

ATVM loans are about 21 percent based on default rates of about 40-50 percent and recovery rates in excess of 25 

percent.

If the risks of the placeholder loans are at all indicative of the risks of the underlying loans, then the actual and 

estimated CSRs should not be grossly different. Given this assumption, one could use the estimated CSRs as 

proxies for the actual ones which in turn could be used to estimate the actual CSCs for the Section 1705 and ATVM

loans that are actually made. That is, the estimated CSCs for loans would simple equal the estimated CSR times the 

dollar value of the loans outstanding. Since the borrower pays the CSCs for the 1703 loans, to the extent that the 

actual CSCs reflects the expected cost to the government, there would be no subsidy resulting from these loans.

Again, the CSRs for the 1705 placeholder loans were about 10 percent which are based upon default rates in 

excess of 25 percent. Thus, the placeholder 1705 loans were assumed to be somewhat risky. The question is 

whether the actual loans will be equally risky. The four large loans for solar and wind projects are in States that 

have renewable portfolio standards, and it appears that most of these projects have some type of purchase power 

contracts. Thus, unless the renewable portfolio standards are abolished or not enforced and/or the purchased 

power contracts are short term in nature, the market-related risk associated with these loans is at best modest. 

The solar projects are some of the largest in the United States, and thus, there is always a chance of cost overruns. 

Additionally, there are uncertainties about the durability and longevity of the solar panels. 

The CSRs for the ATVM loans were about 21 percent which is consistent with default rates in excess of 40 percent. 

Again, the question here is whether the actual loans are as risky as the placeholder loans. The major uncertainties 

are with the commercial viability of electric automobiles. If it turns out that there is no future market for advanced 

vehicles, there would be no market for the components and infrastructure used to produce them. 

 

78 Congressional Budget Office, Estimating the Value of Subsidies for Federal Loans and Loan Guarantees, August 2004.
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The DOE has never reported the actual CSCs paid by the borrower for the Section 1703 loans most of which were 

for the Vogtle nuclear unit. However, the Secretary of Energy has been reported to have said that the CSR for the 

Vogtle loan could be as low as 1-2 percent@ which implies that the loan has little risk of default. Roughly 45 percent 

of Vogtle is owned by Georgia Power, which is a regulated utility. While cost recovery is not guaranteed, it is very 

likely that the State regulators would allow sufficient cost recovery to insure that the utility remains solvent. (In 

fact, this did occur in the 1980s.) Thus, the probability of Georgia Power defaulting on their part of the loan is very 

low. The other 55 percent of the Vogtle project is owned by three municipal utilities, which are much smaller that 

Georgia Power. In the 1980s, a number of publicly-owned utilities did default on their nuclear related loans, so the 

part of the loan that went to the publicly-owned utilities has a higher element of risk.

Although none of these loans are risk free, without detailed information about the underlying projects, it is 

impossible to estimate the probability of default, and thus the CSC. Two cases will therefore be developed. The 

published CSR for the Calvert Cliffs nuclear power plant was around 11 percent. The power from that nuclear 

power plant would have been sold in de-regulated markets without long- term fixed price purchased power 

contracts and, thus cost recovery was not guaranteed. The same might be true for the roughly 55 percent of the 

Vogtle project that is owned by municipal utilities. The higher case will therefore assume an additional CSC equal 

to 11 percent of the $4.9 billion in loans that went to publically-owned co-owners of the Vogtle nuclear units. The 

higher case will also use the average CSRs for the placeholder 1705 and ATVM loans.

It is quite possible that the placeholder CSRs for these placeholder loans could be greater than the ones for the 

actual loans. Thus, the lower case will assume that the actual CSRs for the section 1705 and ATVM loans are 50 

percent of the ones for the placeholder loans. The lower case will not include any additional CSC for the section 

1703 loans.

In the high case, the assumed default rates for the Title 17 and ATVM loans are around 20 and 40 percent, 

respectively, which are similar to historical default rates on bonds that are rated Ba and B by Moody’s.79 The Ba 

and B ratings are the highest and lowest non-investment grade ratinsg. In the lower case, the default rates on the 

Title 17 and ATVM loans are around 10 and 20 percent, respectively. These rates are similar to historical ratings 

for bonds that are rated Baa and Ba by Moody’s. The Baa rating is the lowest investment-grade rating and is the 

one used by EIA in the electric capacity planning part of the NEMS Model.80

The estimates of the actual subsidy costs for all DOEs loans that received either conditional or final approval in FY 

2010 are shown in Table 29. The subsidy cost for the Title 17 loans ranged from $265 million to $1.1 billion. 

Thus, the public paid (or will pay) anywhere from $265 million to $1.1 billion to insure loans used to support the 

development of clean electric related technologies. For all of DOE loans made in FY 2010, the subsidy costs range 

from $1.1 billion to $2.8 billion. The “insurance premium” paid (or will be paid) by the tax payer to guarantee 

loans leading to the development of cleaner more fuel efficient cars and clean power generating technologies 

ranged from $1.1 to $2.8 billion. The total energy related subsidies are about $23 billion. Thus, subsidies related 

to DOE loans issued in 2010 are at best about 10 percent of the total.

 

79 See Moody’s Investors Service, Global Credit Research, Historical Default Rates of Corporate Bond Issuers, 1920-1999, Exhibit 16, p 66. 80 See U.S. Energy Information Administration Documentation to the Electricity Market Model, http://www.eia.gov/analysis/modeldocumentation.cfm, Accessed June 27, 2011. 
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70 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 29. Estimated subsidy costs on DOE loan guarantees 

(millions of dollars)

 

Credit Subsidy Rate

Value of Loans 

Made 

(millions)

Estimated

Subsidy Costs 

(millions)

1703 high 5% $10,600 $530

1703 low 0% $10,600 $0

1705 high 11.76% $4,500 $529

1705-low 5.88% $4,500 $265

ATVM-high 21.21% $8,344 $1,769

ATVM-low 10.60% $8,344 $885

Total-high $23,444 $2,829

Total-low $23,444 $1,149

Title 17 high $15,100 $1,059

Title 17 low $15,100 $265

Fuel specific breakdown 

Estimated Subsidy Costs (millions)

Low High

Nuclear $0 $530

Coal $0 $0

natural gas $0 $0

Renewables $243 $487

 Solar $156 $312

 Wind $77 $153

 Geothermal $11 $21

 Biomass $0 $0

Conservation $3 $5

Transmission $19 $37

Vehicles $885 $1,769

 Total $1,149 $2,829

Totals may not equal sum of components due to independent rounding.

Source: Computed from data from U.S. Department of Energy, Loan Guarantee Program Office, https://lpo.energy.gov/?page_id=45, accessed 

March 23, 2011; and, FY2011 Budget Submission to Congress, Appendix, Department of Energy. 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 71

Estimates of the value of DOE's loan guarantee program.

Again, the CSC measures the expected cost of a loan guarantee that is paid by the taxpayer, as opposed to the 

borrower. As the name suggests, the CSC is one direct measure of the subsidy resulting from the guarantee. 

However, since the actual CSCs are not reported, the estimates shown in Table 29 are based on the assumption 

that the actual and estimated ones are not grossly different, an assumption that may or may not be valid. An 

alternative is to estimate the effects of the subsidy. Such estimates are useful if the focus is on how the loan 

guarantees affect behavior. In particular, the stated objective of the Title 17 loan guarantees is to provide financial 

incentives to develop new clean electric generating technologies. As was done in Chapter 4, another measure of 

the subsidy is the dollar value of those financial incentives. In this chapter, such incentives will be called the value 

of the subsidy to distinguish the estimates from the subsidy itself.

A loan guarantee will allow a firm to borrow at a much lower rate of interest and substitute relatively low-cost 

debt for equity financing. However, because of the following reasons the estimates reported in Chapter 4 did not 

consider the later effect. If the implicit loan guarantee was removed, federally-owned utilities, such as TVA, would 

probably reduce their amount of outstanding debt. Indeed, TVA's $30 billion debt limit was imposed by Congress 

to limit TVA’s incentive to issue too much debt because of the implicit loan guarantee. In the absence of the 

implicit loan guarantee, it is unclear whether TVA, for example, would reduce the amount of its debt by building 

less capital intensive technologies such, as natural gas, or by increasing the amount of equity financed by 

increasing electricity prices. In other words, it would be very difficult to estimate what federal utilities balance 

sheets and capital structures would look like if the implicit loan guarantees were removed. For that reason, 

Chapter 4 just considered only the reduction in costs associated with federal utilities ability to borrow at lower 

rates.

Additionally, in this chapter because of two reasons, the cost savings from both factors will just be computed for 

only the privately-owned firms. First, to incorporate both effects the weighted after-tax cost of capital will be 

computed. The tax adjustment which is crucial is included to account for the fact that payments to shareholders 

are taxed at both the corporate and individual levels, whereas payments to debt holders are just taxed at the 

individual level. Such effects are not relevant to publicly-owned companies since they pay no income taxes and 

distribute no dividends. Second, the major issue with measuring the cost savings from using more debt deals with 

the effects of financial leverage on a project's costs, and all the underlying theory that was developed for privatelyowned firms. Thus, from a conceptual viewpoint, the idea of financial leverage is only relevant for privatelyowned firms due to tax savings.

The methodology used here looks somewhat different from the ones used in traditional finance analyses, and thus 

it will be illustrated with an example. For simplicity, in this example, the tax issues are ignored. This example will 

also show the assumptions that must be made. In this example, shown in Table 30, the total cost of the project is 

assumed to equal $1,000. Without the loan guarantee, by assumption, the project would be financed with 30 

percent debt and 70 percent equity, with the assumption that the cost of debt and equity capital at 7 and 15 

percent, respectively. The cost of debt capital is very easy to estimate, it is simply the interest rate on outstanding 
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72 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

loans. However, the cost of equity capital is more difficult to determine since it is an opportunity cost which is not 

observable. That is, the cost of equity capital is the return that the equity holders could have earned if they had 

invested in another project of equal risk in the marketplace.81

Table 30. An example of the total savings from the DOE loan guarantee program

 In this example, by assumption, if the $700 of equity 

financing was invested in another project of equal risk in the marketplace, it could have earned a return of $105 

($700 x .15.) Thus, the opportunity cost of investing that equity in the project at hand is $105. With the loan 

guarantee, by assumption, the project will be financed with 70 percent debt and 30 percent equity, and then the

cost of debt would fall to 4 percent. In this example, the cost of equity would remain at 15 percent. (The 

appropriateness of this assumption is discussed below.)

 Without loan guarantee With Loan Guarantee

Change in 

Costs

Capital 

Structure

Cost of 

Capital "Costs"

Capital 

Structure

Cost of 

Capital "Costs"

Debt $300 7% $21 $700 4% $28 $7

Equity $700 15% $105 $300 15% $45 -$60

Total $1,000 $1,000 -$53

Totals may not equal sum of components due to independent rounding.

Source: Office of Energy Analysis, Energy Information Administration

Note: The Cost of Debt is an out of pocket cost while of cost of Equity is an opportunity cost. That is, the cost of equity is the returns that could 

have been achieved by investing the amounts shown in another investment of equal risk in the marketplace. Thus, the total is a hybrid cost. It is 

partly an out of pocket and an opportunity cost.

The last column in Table 30 shows the change in costs. The debt costs actually increased by $7 but the equity 

costs, which again are opportunity costs, fall by $60, and thus the total cost savings would be $53. Note that the 

$53 estimate is partly an out-of-pocket and partly an opportunity cost. Except for regulated utilities, this estimate 

could never be computed by simply observing items on a firm's income statement or balance sheet.82

Financial assumptions if the loan is guaranteed

This example shows that assumptions must be made about the capital structure, the cost of equity, and the cost of 

equity if the loan is guaranteed. Looking first at the capital structure, as already noted, the maximum loan 

guarantee is by law 80 percent of the total. However, as was noted above, the actual projects are using much less 

debt than the maximum and, thus, the actual amounts of debt will be used here. In particular, in the calculations 

the amounts of debt as a percent of the total project costs for all Title 17 and ATM were assumed to equal 64 and 

58 percent, respectively. These are averages of the actual percents for all loans made in FY 2010.83 All of the 

assumptions are shown in Table 31.

 

81 There are at least 3 or 4 different ways to compute the cost of equity. In the electric utility sector, EIA uses the Capital Asset Pricing Model 

(CAPM). See: U.S. Energy Information Administration Documentation to the Electricity Market Model, http://www.eia.gov/analysis/modeldocumentation.cfm, Accessed June 27, 2011. 82 In a regulated utility, these equity costs are called the Allowance for Other Funds used during construction. It appears as a non-cash revenue in 

the income statement. Additionally, the actual estimates reported below were computed by using the change in the weighted after tax cost of 

capital. It can be shown that using the weighed after tax cost of capital will produce the same results as the one used to the example. 83 All the data were obtained from the Loan Guarantee Office’s Web site at https://lpo.energy.gov/?page_id=45, Accessed March 23, 2011. 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 73

Table 31. Assumptions made to compute the total savings from the DOE loan guarantee program

Assumptions

Scenario

Loan guarantee not made

Risk Loan Guarantee made

Low Moderate High NA

Title 17

Bond rating A Baa B Treasury rate

Cost of Debt 5.44% 6.04% 7.00% 4.50%

Cost of Equity 13.00% 13.00% 13.00% 13.00%

Capital Structure

 Debt 55.00% 45.00% 35.00% 64.00%

 Equity 45.00% 55.00% 65.00% 36.00%

Annualized Credit Subsidy costs for 

Section 1703 Loans (millions) NA NA NA 25

ATVM

Bond rating Baa Ba B Treasury rate

Cost of debt 6.04% 7.00% 8.00% 4.50%

Cost of Equity 13.00% 13.00% 13.00% 13.00%

Capital Structure

 Debt 45.00% 35.00% 25.00% 58.00%

 Equity 55.00% 65.00% 75.00% 42.00%

Totals may not equal sum of components due to independent rounding.

Source: Office of Energy Analysis, Energy Information Administration. 

Most of the Title 17 and ATVM loans are made by the Department of Treasury's Federal Financial Bank at 12.5 

basis points above current yields on Treasury bonds, and are guaranteed by DOE. Based upon DOE budget 

submissions, the Title 17 loans have maturities of 20 plus years. Thus, the cost of debt if the loan was made was 

assumed to equal the 2010 yields on 30 year Treasury bonds (Table 30). This is noteworthy because in 2010, yields 

on 30-year Treasury bonds were a full percentage point greater than the ones for 10-year Treasury bonds.

Lastly, there is the question of the appropriate cost of equity to use if the loan guarantee was approved. By itself, 

the loan guarantees only protect debt holders in case of bankruptcy; it would have no effect on shareholders. 

However, the increased use of debt would affect shareholder risk. There is a long literature on the relationship 

between the use of financial leverage (debt capital) and the cost of equity. However, the exact relationship 

depends upon a number of factors such as how the project is structured, and thus, the exact relationship is difficult 

to estimate.84 More importantly, and as noted above, there is more equity in most of the projects than the 

 

84 See, for example, Alan Shapiro, Modern Corporate Finance,(New York: Macmillan, 1990). 
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74 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

minimum 20 percent allowed by law. Since this might be an attempt to reduce the risk to shareholders, there

might be some double accounting if the cost of equity was also increased. Thus, to simplify the presentation, no 

adjustment will be made to the cost of equity. A sensitivity analysis found that a 1-percentage point increase in the 

cost of equity resulted in a $50-million decrease in the cost savings. The maximum increase in the cost of equity is 

probably around 2- to 3 percentage points, and thus the changes would be relatively small when compared to the 

other estimates presented in this report. 

Financial assumptions if the loan was not guaranteed. 

In this chapter, three different scenarios that reflect differences in risk with the assumption that the loan was not 

made will be used. (See Table 30.) Since the ATVM loans have much higher CSRs than the Title 17 loans, the 

ATVM loans are more risky. Thus, different assumptions will be made for the Title 17 and ATVM loans.

Looking first at the Title 17 loans, in the last two solicitations, DOE required that the projects to be considered 

eligible must have a bond rating no lower than Ba.85 This is the highest of the non investment grade ratings, and 

bonds in this class are considered somewhat speculative. The higher risk scenario assumes that in the absence of 

the guarantees, the bonds used to finance the average project would be rated Ba. Historically, the default rate on 

bonds that were initially rated Ba was about 20 percent, which is similar to the assumed default rates on the 

placeholder loans used to compute the CSC for Title 1705 loans. It is also similar to the default rates implicit in the 

higher case estimates of the CSCs shown in Table 29.86

The moderate risk scenario case assumes that the bonds used to finance the average project will be investment 

grade and rated Baa by Moody’s. (EIA uses yields on investment grade bonds to compute the cost of capital for 

electric utilities in the NEMS model.)

 

87

In the lower risk scenario, it was assumed that, in the absence of the guarantee, bonds used to finance the average 

project would be rated A. This is the third highest bond rating and therefore the resulting estimates will be very 

conservative. The assumed 2010 yields are shown in Table 31.

 Historical default rates of bonds that were initially rated Baa are about 10 

percent. This assumption is consistent with the implicit default rates used in the lower cost CSC estimate shown in 

Table 29.

The moderate risk scenario's capital structure was based on the ones used by EIA in AEO2011 in the electric utility 

sector (See Table 31). Lower (higher) risk investments could use more (less) debt. In the lower risk scenario, a 10 

percentage point increase in the use of debt was assumed. In the high risk scenario a 10-percentage point 

decrease in the amount of debt was assumed. For simplicity, the same cost of equity was assumed. This simplified 

the calculations and some sensitivity analysis found that the results were not materially affected by this 

simplification.

 

85 U.S. Department of Energy, Loan Guarantee Program Office, Federal Loan Guarantees for Commercial Technology. Renewable Energy 

Generation Projects Under Financial Institution Partnership program, DE-FOA-0000166, October 7, 2009; and U.S. Department of Energy, Loan 

Guarantee Program Office, Federal Loan Guarantees for Projects that Manufacture Commercial Technology Renewable Energy Systems and 

Components, DE-SOL-0002197, August 10, 2010. 86 Since DOE uses a 55 percent recovery rate, the CSR would be roughly 50 percent of the default rate. 87 See U.S. Energy Information Administration, Documentation to the Electricity Market Model, http://www.eia.gov/analysis/modeldocumentation.cfm, Accessed June 27, 2011. 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 75

Since the ATVM loans appear to be more risky, the higher case will assume that without guarantees, bonds used to 

finance these projects would be rated B. This is the lowest of Moody’s non-investment grade bond ratings and the 

historical default rate on such bonds is around 40 percent. Because of the risk of these projects, in the higher case, 

a 7-percent equity and 25 percent debt capital structure would be used. In the Moderate and Lower risk cases for 

ATVM loans, the same bond rating and capital structures as was used in the lower and moderate risk cases will be 

employed. Again, these assumptions are shown in Table 31.

Results 

Before presenting the estimates of the cost savings, a number of points about the nature of the estimates and the 

sample must be made. First, as noted above, loans that received either a conditional or final approvals were used 

in the computations. Roughly $12 billion of the $23 billion of loans received their final approval in FY 2010, and 

based on information from the FFB's balance sheet only about $2 billion out of that $12 billion were actually made 

in that year. Thus, most of the loans will probably be made in FY 2011. Second, it appears that the DOE loans have 

fixed, as opposed to variable, rates. If the same is true of the loans that the borrower would have received in the 

absence of the guarantees, then the estimates would be time invariant. That is, the estimates shown below would 

be the same in FY 2020 than in FY 2010. However, if the loans the borrower would have received without the 

guarantees have variable rates, in the case of rising interest rates in future years the cost savings could be much 

greater than the ones shown here.

With regard to the example, roughly 55 percent of the Vogtle loan went to three publicly-owned utilities. Because 

of the reasons stated above, those three loans will be excluded from the calculations of the cost savings caused by 

the increased use of debt. Thus, the total cost savings for these three loans were limited to the ability to borrow at 

lower rates. The loan to Areva was included in the calculation of both effects since Areva does have a well defined 

capital structure and large amounts of outstanding common stock.

The estimates of the cost savings from the DOE loans approved in FY 2010 are shown in Table 32. 
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76 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 32. Total cost savings from DOE loan guarantee program.

(million dollars)

Loan Type or Fuel

Risk without the loan guarantee

Low Moderate High

Section 1703 loans $80 $193 $314

Section 1705 loans $56 $107 $158

 Total Title 17 loans $135 $300 $473

Total Non Electricity $252 $416 $565

Total DOE $388 $716 $1,037

Fuel specific breakdown 

Nuclear $77 $187 $305

Coal $0 $0 $0

Natural gas $0 $0 $0

Renewables $51 $98 $145

 Solar $33 $63 $93

 Wind $16 $31 $46

 Geo $2 $4 $6

 Bio $0 $0 $0

Conservation $3 $7 $11

Transmission $4 $7 $11

Vehicles $252 $416 $565

 Total $387 $715 $10,037

Totals may not equal sum of components due to independent rounding.

Source: Computed from data from U.S. Department of Energy, Loan Guarantee Program Office, https://lpo.energy.gov/?page_id=45, accessed 

March 23, 2011.

These estimates suggest that the cost savings resulting from Title 17 loans made in FY 2010 ranged from about 

$135 to $473 million per year. In total, the savings resulting from all of the DOEs loans made in 2010 ranged from 

$388 million to about $1 billion. The CSCs for all of DOE’s loans made in FY2010 ranged from $1 to $3 billion. 

Again, the CSC is the expected cost to the government computed over the life of the loan and thus the CSC would 

be the costs of the loan guarantees. The benefits (cost savings) of the loan program ranged from $388 million to $1 

billion per year. The payback period is number of years before the cumulative cost savings (benefits) exceeded the 

CSCs (cost). Thus, even if the CSC estimates are low by a multiple of 2, the payback period would be less than 10 

years. 

The cost savings from the nuclear loan guarantees ranged from $77 million to about $305 million. There are two 

reasons why the nuclear estimates appear to be low relative to a number of recent studies. First, all of the 

previous analyses assumed a much higher use of debt financing than turned out to be the case. Second, as was 

stated above, for the Vogtle loan, the cost savings for the municipal utilities that own 55 percent of the project was 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 77

limited to the ones caused by lower interest rates. As will be seen very shortly, these cost savings are very low. If 

the municipal utilities were treated as if they were investor-owned, the nuclear related cost savings would increase 

by $75 million and $200 million in the lower and higher cases, respectively. These results, especially at the upper 

end of the range are not out of line with previous work in the loan guarantee area.

Lastly, to show the importance of the ability to use more debt financing and the associated tax benefits, a case was 

run where it was assumed that there would be no increase in the use of debt financing. These results, shown in 

Table 33, suggest that the cost savings resulting from ability to borrow at lower costs is only about 35-40 percent 

of the total. Given this, one would expect that the firms would use as much debt as the law allowed, i.e., 80 

percent. The reason why they did not must therefore be related to the increased risk that results from highly 

leveraged investments. These increased risks would accrue to both the equity investors and the debt holders 

(DOE). It is quite possible that both parties were requiring more equity investment than the law allowed. 

Table 33. Reduction in Total Financing Costs Assuming No Change in Capital Structure

(million dollars)

 

Risk if loan guarantee is not made

Low Moderate High

Section 1703 loans $17 $44 $87 

Section 1705 loans $11 $19 $30 

 Total Title 17 loans $28 $63 $117 

Total Non Electricity (ATVM) $120 $196 $274 

Total $149 $258 $391 

Totals may not equal sum of components due to independent rounding.

Source: Computed from data from U.S. Department of Energy, Loan Guarantee Program Office, https://lpo.energy.gov/?page_id=45, 

accessed March 23, 2011.

Conclusions

The various estimates of the subsidy resulting from DOE's loans made in FY 2010 are summarized in Table 34. 

These results suggest that if the estimates of the actual credit subsidy costs were used, the subsidy resulting from 

the Title 17 loans would range from $265 million to $1,059 billion. The estimated subsidy from all of DOE's loans 

ranges from about $1 to $3 billion. These estimates would be the more appropriate ones to use if the focus was 

on the budgetary impact of these programs. One of the goals of the FCRA was to ensure that the budgetary costs 

of federal loans programs were the same as other government activities. To the extent that the placeholder CSCs 

are not grossly out of line with the actual ones, these estimates are conceptually the same as the ones presented 

in Chapters 2 and 3.
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78 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Table 34. Summary of estimates of the subsidies resulting from DOE’s loan guarantees made in FY2010

(million dollars)

Program

Credit Subsidy Costs Total Reductions in Annual Financing Costsa

Credit Subsidy Costs No Change in Capital Structure

Increased Use of Debt 

Because of DOE Loan 

Guarantee Program

Higher Lower Higher Lower Higher Lower

Section 1703 loans $530 $0 $87 $17 $314 $80

Section 1705 loans $529 $265 $30 $11 $158 $56

 Total Title 17 loans $1,059 $265 $117 $28 $473 $135

ATVM $1,769 $885 $274 $120 $565 $252

All DOE $2,829 $1,149 $391 $149 $1,037 $388

Fuel specific breakdown 

Nuclear $530 $0 $305 $77

Coal $0 $0 $0 $0

Natural Gas $0 $0 $0 $0

Renewables $487 $243 $145 $51

 Solar $312 $156 $93 $33

 Wind $153 $77 $46 $16

 Geothermal $21 $11 $6 $2

 Biomass $0 $0 $0 $0

Conservation $5 $3 $11 $3

Transmission $37 $19 $11 $4

Vehicles $1,769 $885 $565 $252

 Total $2,829 $1,149 $1,037 $388

Totals may not equal sum of components due to independent rounding.

Source: Computed from data from U.S. Department of Energy, Loan Guarantee Program Office, https://lpo.energy.gov/?page_id=45, 

accessed March 23, 2011.

If the focus of the analysis is on how the loan guarantee program affects behavior, estimates of the cost savings 

would be the more appropriate measure of the subsidy. This is similar in spirit to what was done in Chapter 4. 

These estimates would range from $135 million to slightly less than $500 million for the Title 17 loans. Estimates 

of the subsidy, as measured by the cost savings, for all of the DOE loans made in FY 2010 ranged from about $388 

million to about $1 billion. 

All of these estimates are quite modest when compared to other ones presented in this report. Under current law, 

DOE's authority to issue Title 1705 loans will expire on September 30, 2011. DOE will still have authority to issue 
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 79

about $40 billion in Section 1703 and $17 billion in ATVM loans. Thus, even without additional budget authority, 

DOE can still issue about $57 billion in loans. Over the next few years as more loans are made the estimates 

reported here will increase.

Lastly, DOE's loan program allows firms to borrow at lower costs and to use more relatively inexpensive debt. 

There are also tax advantages from using more debt. A comparison of the estimates shown in the last four 

columns in Table 34 suggests that the ability to substitute debt for equity financing is by far the more important of 

the two effects. Given this, it is very interesting that the amount of debt used to finance the actual projects is 

much less than the 80 percent maximum. 
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80 U.S. Energy Information Administration | Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010

Appendix A. Request Letter
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U.S. Energy Information Administration|Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2010 81