SR/CNEAF/2008-01 

Federal Financial Interventions and 

Subsidies in Energy Markets 2007 

April 2008 

Energy Information Administration

 Office of Coal, Nuclear, Electric, and Alternate Fuels 

 U.S. Department of Energy 

 Washington, DC 20585 

This report was prepared by the Energy Information Administration, the independent statistical and analytical agency 

within the Department of Energy. The information contained herein should be attributed to the Energy Information 

Administration and should not be construed as advocating or reflecting any policy position of the Department of 

Energy or of any other organization. Service Reports are prepared by the Energy Information Administration upon 

special request and are based on assumptions specified by the requestor. 

Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Federal Financial Interventions and Subsidies in Energy Markets 2007 i 

Preface and Contacts 

The Energy Information Administration (EIA) is the independent statistical and analytical agency 

within the Department of Energy. EIA provides timely, high-quality energy information and 

prepares objective transparent analyses for use of Congress, the Administration and the public. 

EIA does not, however, take positions on policy issues. Because of EIA’s statutory 

independence with respect to the content of its energy information program, the analysis 

presented herein is strictly its own and should not be construed as representing the views of the 

U.S. Department of Energy or the Administration. 

This report responds to a request from Senator Lamar Alexander of Tennessee that the EIA 

update its 1999 to 2000 work on Federal energy subsidies, including any additions or deletions 

of Federal subsidies based on Administration and Congressional action since the previous 

report was written, and to provide an estimate of the size of each current subsidy. Subsidies to 

be included are those through which a government or public body provides a financial benefit 

with a Federal budget impact. Senator Alexander’s letter of May 17, 2007, provided as 

Appendix H, asked EIA to focus particularly on subsidies directed to electricity production, 

including an estimate of electricity subsidies on a per unit basis. 

This report was prepared by an EIA-wide project team including staff from EIA’s Office of Coal, 

Nuclear, Electric and Alternate Fuels (CNEAF), the Office of Integrated Analysis and 

Forecasting (OIAF), and the Office of Energy Markets and End Use (EMEU). General questions 

about the report may be directed to the primary point of contact, Robert Schnapp, Director, 

Electric Power Division (CNEAF), at 202-586-5114, or via e-mail at rschnapp@eia.doe.gov. 

Questions about specifics within the report may be directed to the following analysts: 

Analyst: Kevin Lillis 

Contact for: 

• Chapter 2 and Chapter 4 (Federal Utilities) 

• Appendices A, B, C, D 

Phone: 202-586-3704

Email: klillis@eia.doe.gov

Analyst: Robert Eynon 

Contact for: 

• Chapter 3 

• Appendix A Fact Sheets 38 through 42, 45 through 49, and 55 

Phone: 202-586-2392

Email: reynon@eia.doe.gov

Analyst: Mark Gielecki 

Contact for: 

• Renewable Fuels 

• Bibliography 

• Appendix A Fact Sheets 27,34, and 52 

Phone: 202-586-1264

Email: mgielecki@eia.doe.gov
Federal Financial Interventions and Subsidies in Energy Markets 2007 

ii Energy Information Administration / Federal Financial Interventions and Subsidies in Energy Markets 2007 

Analyst: Tom Leckey 

Contact for: 

• Executive Summary

Phone: 202-586-3548

Email: tleckey@eia.doe.gov

Analyst: Jim Diefenderfer 

Contact for: 

• Quality Assurance

Phone: 202-586-2432

Email: jdiefenderfer@eia.doe.gov 

Analyst: Robert Schmitt 

Contact for: 

• Appendix A Fact Sheets 7, 18, 19, 25, 26, 31

Phone: 202-586-8644

Email: rschmitt@eia.doe.gov 

Analyst: Howard Stone 

Contact for: 

• Chapter 1 

• Chapter 4 (Rural Utilities Service)

• Chapter 5 

• Appendix E 

Phone: 202-586-3189

Email: hstone@eia.doe.gov 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Federal Financial Interventions and Subsidies in Energy Markets 2007 iii 

Within its Independent Expert Review Program, EIA arranged for leading experts in the fields of 

energy and economic analysis to review this report and provide comment. The reviewers 

provided comments on a draft version of the report, after an earlier meeting with EIA to discuss 

the methodology and preliminary results. All comments from the reviewers either have been 

incorporated or were considered for incorporation. As is always the case when peer reviews 

are undertaken, not all the reviewers are in agreement with all the methodology, inputs, and 

conclusions of the final report. The contents of this report are solely the responsibility of EIA. 

The assistance of the following reviewers in preparing the report is gratefully acknowledged: 

Dr. Timothy J. Brennan, University of Maryland Baltimore County 

Dr. Linda R. Cohen, University of California, Irvine 

Dr. Gilbert E. Metcalf, Tufts University 

Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Federal Financial Interventions and Subsidies in Energy Markets 2007 v 

Table of Contents 

Executive Summary xi

Background xi

Summary of Findings xi

Findings Regarding Electricity Production-Related Subsidies xiv

Findings Regarding Energy Subsidies Not Related to Electricity Production xvii

1. Introduction 1

Background and Purpose 1

Scope of the Report and Measurement of Subsidies and Support 1

Definition of Subsidy and Types of Subsidies and Support Addressed 2

Valuing Energy Subsidies and Support: Theoretical Issues 4

The Incidence Theory 5

Marginal Versus Inframarginal Effects of Subsidies and Support 5

Measurement of Financial Support to Federal Utilities’ Customers and Rural Utilities Service 

Borrowers 6

Impacts of Subsidies and Support in Electricity Markets 8

Organization of Report 10

2. Tax Expenditures and Direct Expenditures 11

Overview 11

Tax Expenditures 11

Tax Expenditures Caveats 11

Background and Definitions 15

Tax Expenditures’ Role in the Economy 15

Tax Expenditures in Energy 16

Coal-Related Tax Expenditures 16

Electricity Transformation-Related Tax Expenditures 18

Renewable-Related Tax Expenditures 21

Natural Gas and Petroleum-Related Tax Expenditures 23

Energy Efficiency and Conservation-Related Tax Expenditures 25

Alcohol and Biofuels Tax Provisions 26

Section 29: The Alternative Fuel Production Credit 29

New Technology Credit 31

Unreported Tax Expenditures 35

Direct Expenditures 36

Renewable Energy Production Incentive 36

Low Income Home Energy Assistance Program 36

Building Technology Assistance Program 38

3. Federal Energy Research and Development 39

Defining Federal Research and Development 39

Energy Research and Development as a Subsidy 40

Energy Research and Development Trends 42

Federal Energy R&D Subsidies to Renewable and Other Technologies 44

Federal Energy R&D Subsidies to Nuclear Energy 46

Federal Energy R&D Subsidies to Coal 49

Federal Energy R&D Subsidies to Natural Gas and Petroleum Liquids 51

Federal Subsidies to End Use Energy R&D 51

4. Federal Electricity Programs 55

Introduction 55

Federal Power Programs 55

Areas Excluded from the Analysis 57

Federal Policies Affecting Power Costs and Pricing 58

Measuring the Support 59

Interest Rate Support 60

Selection of a Market Interest Rate 65

Tennessee Valley Authority 71

The Power Marketing Administrations 74

BPA’s Borrowing Costs 75

BPA’s Federal Interest Support 77

The Smaller Power Marketing Administrations 78

PMA Borrowing Costs 79

Rural Utilities Service Electric Loans, Guarantees, and Grants 80
Federal Financial Interventions and Subsidies in Energy Markets 2007 

vi Energy Information Administration / Federal Financial Interventions and Subsidies in Energy Markets 2007 

Hardship Loans 82

Municipal Rate Loans 83

Treasury Direct Loans 83

FFB Guaranteed Loans 83

Guarantees for Bonds and Notes Issued for Electrification and Telephone Purposes 84

Assistance to High Energy Cost Communities 85

Cost of Loan Support Provided to RUS Electricity Borrowers 85

Summary 88

5. Subsidies Per Unit of Production 91

Definition of Electricity Production 92

Electricity Production Subsidies 92

Allocation of Subsidies 93

Subsidies Unrelated to Electricity Production 94

Subsidies Allocated by Fuel Type 96

Derivation of Fuel Ratios 97

Subsidies Allocated by Fuel Type 98

Interest Rate Support to Federal Utilities and RUS Borrowers 101

Transmission, Distribution, and Other Subsidies and Support for Electricity Production 103

Per-Unit Electricity Subsidies by Fuel Type 105

Perspectives on Electricity Subsidy Estimates 109

List of Appendices 

Appendix A Fact Sheets 111

1. 30-Percent Credit for Purchase of Residential Solar and Fuel Cells 112

2. 84-Month Amortization of Certain Pollution Facilities 113

3. Alcohol Fuel Credit 114

4. Allowance for the Deduction of Certain Energy-Efficient Commercial Building Properties 116

6. Biodiesel and Small Agri-Biodiesel 120

7. Capital Gains Treatment of Royalties on Coal 122

8. Credit for Business Installation of Qualified Fuel Cells and Microturbine Power Plants 124

9. Credit for the Construction of New Energy-Efficient Homes 125

10. Credit for Energy Efficiency Improvements of Existing Homes 126

11. Credit for Efficient Appliances 127

12. Credit for Holding Clean Renewable Energy Bonds 128

13. Credit for Investment in Clean Coal Technologies 130

14. Credit for the Production from Advanced Nuclear Power Facilities 132

15. Tax Credit and Deduction for Clean-Fuel, Alternative-Fuel, and Electric Vehicles 133

16. Deferral of Gain from Disposition of Transmission Property to Implement Restructuring 136

17. Enhanced Oil Recovery 137

18. Exception from Passive Loss Limitation for Working Interests in Oil and Natural Gas Properties 139

19. Excess of Percentage over Cost Depletion: Oil, Natural Gas, and Other Fuels 141

20. Renewable Transportation Fuels and Volumetric Ethanol Excise Tax Credit (VEETC) 144

21. Exclusion of Utility-Sponsored Conservation 145

22. Exclusion of Interest Income on Energy Facility and Local Bonds 147

23. Exclusion of Special Benefits for Disabled Coal Miners 149

24. Expensing of Capital Costs with Respect to Complying with EPA Sulfur Regulations 150

25. Expensing of Exploration and Development Costs: Oil, Natural Gas, and Other Fuels 152

26. Natural Gas Distribution Pipelines Treated as 15-Year Property 154

27. New Technology Credit 155

28. Nuclear Production Tax Credit 157

29. Modification to Special Rules for Nuclear Decommissioning Costs 158

30. Partial Expensing for Advanced Mine Safety Equipment 159

31. Temporary 50-Percent Expensing for Equipment Used in the Refining of Liquid Fuels 160

32. Transmission Property Treated as 15-Year Property 161

33. Treatment of Income of Certain Cooperatives 162

34. United States Department of Agriculture Energy Programs 164

35. Building Technology Assistance Program 166

36. Low Income Home Energy Assistance Program 167

37. Renewable Energy Production Incentive (REPI) 169

38. Advanced Turbine Systems 172

39. Basic Energy Research 173

40. Building Technology, State and Community Programs Research and Development 174

41. Clean Coal Power Initiative 175
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Federal Financial Interventions and Subsidies in Energy Markets 2007 vii 

42. Fusion Energy Sciences 176

43. FutureGen 177

44. Fuel and Power Systems 178

45. Industrial Sector Research and Development 179

46. Nuclear Energy Research Initiative and Energy Policy Act of 2005 Related Research and 

Development 180

47. Oil Technology Research and Development 182

48. Renewable Energy Technology Research and Development 183

49. Environmental Management 185

50. Clean Cities Program 186

51. Army Corps of Engineers/Bureau of Reclamation Hydropower Projects 187

52. ENERGY STAR Program 188

53. Federal Energy Management Program 189

54. Loan Guarantees for Innovative Technologies 191

55. Nuclear Power Plant Construction Delay Support 193

56. Nuclear Waste Fund 194

57. Power Marketing Administrations 195

58. Price-Anderson Fund 197

59. Tennessee Valley Authority 199

60. Uranium Facilities Maintenance and Remediation Fund 201

Appendix B Alternative Methods of Estimating Federal Electricity Subsidies and Interventions 203

Alternative Methods of Estimating Federal Electricity Financial Support 204

Market Price Support 204

TVA’s Prices Relative to Neighboring IOUs 206

BPA’s Prices Relative to Neighboring Investor-Owned Utilities 206

PMA Prices Relative to Neighboring Investor-Owned Utilities 208

Return on Asset Support 209

TVA’s Return on Capital 210

BPA’s Return on Capital 210

PMA Returns on Capital 211

Appendix C Historic Perspectives on Energy Tax Expenditures 213

Historic Perspectives on Energy Tax Expenditures 214

The Energy Policy Act of 2005 and Other Recently Enacted Energy Tax Expenditures 220

Synthetic Fuels Corporation 222

Appendix D Description of Bond Ratings 225

Appendix E Types of Loans Available Through the Rural Utilities Service 227

Hardship Loans 228

Municipal Rate Loans 228

Treasury Rate Loans 228

FFB Guaranteed Loans 229

Eligible Borrowers 229

Rates 229

Appendix F Table of Authorizations and Regulations 231

Public Laws: 232

United States Codes of Federal Regulations 233

Appendix G Bibliography 235

Appendix H Letter from Senator Lamar Alexander 253

List of Tables 

Table ES1. Energy Subsidies and Support by Type and Fuel, FY2007 and FY1999 (million 2007dollars) xii

Table ES2. Total Energy Subsidies and Support, Selected Indicators,1999 and 2007 xiii

Table ES3. Allocation of Electricity Production and Other Energy Subsidies (million 2007 dollars) xiv

Table ES4. Fiscal Year 2007 Electricity Production Subsidies and Support (million 2007 dollars) xv

Table ES5. Subsidies and Support to Electricity Production: Alternative Measures xvi

Table ES6. Energy Subsidies Not Related to Electricity Production: Alternative Measures xviii 

Table 1. Estimates of Tax Expenditures by Fiscal Year (million 2007 dollars) 14

Table 2. Coal-Related Tax Expenditures (million 2007 dollars) 17

Table 3. Electricity Transformation-Related Tax Expenditures (million 2007 dollars) 20

Table 4. Renewable-Related Tax Expenditures (million 2007 dollars) 21

Table 5. Natural Gas and Petroleum-Related Tax Expenditures (million 2007 dollars) 23

Table 6. Conservation, Efficiency, and End-Use Tax Expenditures (million 2007 dollars) 25
Federal Financial Interventions and Subsidies in Energy Markets 2007 

viii Energy Information Administration / Federal Financial Interventions and Subsidies in Energy Markets 2007 

Table 7. Laws Promoting Ethanol as a Transportation Fuel 28

Table 8. U.S. Renewable Fuels Electricity Generating Capacity (Gigawatts) 32

Table 9. Fuel Allocation for New Technology Credit Fiscal Year 2007 Estimated Expenditure 34

Table 10. History of the New Technology (Production Tax) Credit and Related Development Activity 35

Table 11. Direct Expenditures in Energy (million 2007 dollars) 36

Table 12. Summary of U.S. DOE R&D Expenditures, 1978 to 2007 (million 2007 dollars) 40

Table 13. Federal Energy R&D by Type and Function (million 2007 dollars) 43

Table 14. Renewables and Other R&D Expenditures (million 2007 dollars) 44

Table 15. Nuclear Power R&D Expenditures (million 2007 dollars) 47

Table 16. Coal R&D Expenditures (million 2007 dollars) 49

Table 17. Federal Funding for End-Use R&D (million 2007 dollars) 52

Table 18. Interest Rates used to Estimate Federal Utilities and RUS Interest Subsidies, 1998 and 2006 (percent) 65

Table 19. Median Financial Ratios: Investment Grade Rated Wholesale Public Power Suppliers 68

Table 20. Estimate of Federal Electricity Interest Rate Support to TVA, 1998 and 2006 (million 2007 dollars) 74

Table 21. Estimate of Federal Electricity Interest Rate Support to BPA, 1998 and 2006 (million 2007 dollars) 78

Table 22. Estimate of Federal Electricity Interest Rate Support to the Three Smaller PMAs, 1998 and 2006 (million 

2007 dollars) 80

Table 23. Key Statistics for the Rural Utilities Service Electricity Program, 1998 and 2005 82

Table 24. Interest Support to RUS Borrowers, 1998 and 2006 (million 2007 dollars) 87

Table 25. Interest Support to Federal Utilities and RUS Borrowers 1998 and 2006 (million 2007 dollars) 89

Table 26. Allocation of Electricity Production and Other Energy Subsidies (million 2007 dollars) 93

Table 27. Subsidies not Allocated to Electricity Production (million 2007 dollars) 95

Table 28. Fuel Allocation Factors (percent) 97

Table 29. Fiscal Year 2006 CREB Authorized Allocation by Fuel Type 98

Table 30. Fuel-Specific Energy Subsidies (million 2007 dollars) 100

Table 31. Allocation of Federal Utilities’ Interest Support by Fuel Type (million 2007 dollars) 102

Table 32. Allocation of RUS Interest Support by Fuel Type 103

Table 33. FY 2007 Electricity Transmission, Distribution, and Other Subsidies and Support (million 2007 dollars) 104

Table 34. Fiscal Year 2007 Electricity Production Subsidies and Support (million 2007 dollars) 105

Table 35. Subsidies and Support to Electricity Production: Alternative Measures 106

Table 36. Energy Subsidies Not Related to Electricity Production: Alternative Measures 108 

Table A1. Estimated Revenue Loss: Residential Solar and Fuel Cell Credit, 2006 to 2008 (million nominal dollars)112

Table A2. Estimated Revenue Loss: Alcohol Fuel Credit, 1984 to 2012 (million nominal dollars) 115

Table A3. Estimated Revenue Loss: Energy-Efficient Buildings Deduction, 2006 to 2012 (million nominal dollars) 116

Table A4. Estimated Revenue Loss: Alternative Fuel Production Tax Credit, 1987 to 2012 (million nominal dollars)119

Table A5. Estimated Revenue Loss: Coal Royalties Capital Gains Treatment, 1987 to 2012 (million nominal dollars)123

Table A6. Estimated Revenue Loss: Qualified Fuel Cells and Microturbines, 2006 to 2012 (million nominal dollars)124

Table A7. Estimated Revenue Loss: Energy-Efficient Homes Credit, 2006 to 2009 (million nominal dollars) 125

Table A8. Estimated Revenue Loss: Existing Home Efficiency Improvement Credits, 2005 to 2011 (million nominal 

dollars) 126

Table A9. Estimated Revenue Loss: Efficient Appliances Credit, 2006 to 2007 (million nominal dollars) 127

Table A10. Estimated Revenue Loss: Clean Renewable Energy Bonds, 2006 to 2012 (million nominal dollars) 129

Table A11. Estimated Revenue Loss: Clean Coal Investment Credit, 2006 to 2012 (million nominal 

dollars) 131

Table A12. Estimated Revenue Loss: Alternative-Vehicle Credit, 1998 to 2012 (million nominal dollars) 135

Table A13. Estimated Revenue Loss: Deferred Gain on Transmission Asset Sales, 2005 to 2012 (million nominal 

dollars) 136

Table A14. Estimated Revenue Loss: Enhanced Oil Recovery Credit, 1993 to 2011 (million nominal dollars) 138

Table A15. Estimated Revenue Loss: Oil and Natural Gas Passive Loss Limitation Exception, 1988 to 2012 (million 

nominal dollars) 140

Table A16. Estimated Revenue Loss: Excess of Percentage of Cost over Depletion, 1987 to 2012 (million nominal 

dollars) 142

Table A17. Estimated Revenue Loss and Outlay Equivalent: VEETC, 2006 to 2012 (million nominal dollars) 144

Table A18. Estimated Revenue Loss: Utility-Sponsored Conservation, 1987 to 2012 (million nominal dollars) 145

Table A19. Estimated Revenue Loss: Interest Exclusion on Energy Facility Bonds, 1987 to 2012 (million nominal 

dollars) 148

Table A20. Estimated Revenue Loss: Exclusion of Disabled Coal Miner Benefits, 2001 to 2011 (million nominal 

dollars) 149

Table A21. Estimated Revenue Loss: Expensing EPA Sulfur Compliance Capital Costs, 2005 to 2012 (million 

nominal dollars) 150

Table A22. Estimated Revenue Loss: Expensing of Exploration and Development Costs, 1987 to 2012 (million 

nominal dollars) 153

Table A23. Estimated Revenue Loss: 15-Year Life for Natural Gas Pipelines, 2006 to 2012 (million nominal dollars)154

Table A24. Estimated Revenue Loss: New Technology Credit, 2006 to 2012 (million nominal dollars) 156
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Federal Financial Interventions and Subsidies in Energy Markets 2007 ix 

Table A25. Estimated Revenue Loss: Partial Expensing of Mine Safety Equipment, 2006 to 2012 (million nominal 

dollars) 159

Table A26. Estimated Revenue Loss: Temporary 50-Percent Expensing of Refining Equipment, 2006 to 2012

(million nominal dollars) 160

Table A27. REPI Appropriations (Dollars) 171

Table B1. Average Price per Kilowatthour for the United States, Selected States by End-Use Sectors, 2006 (2007 

Cents per kWh) 207

Table B2. Implied Support for BPA Based on Market Rates,1998 and 2006 (million 2007 dollars) 207

Table B3. Computation of Implied Support for Small PMAs on a Market Price Basis, 1998 and 2006 (millions 2007 

dollars) 209

Table B4. Tennessee Valley Authority's Return On Assets Estimates, 1998 and 2006 210

Table B5. Return On Assets Estimates for Bonneville Power Administration, 1998 and 2006 211

Table B6. Three Smaller PMAs Returns on Net Power Plant and Equipment (million 2007 dollars) 212 

Table C1. Current and Historic Tax Expenditures, Selected Years, 1967 to 2007 (million 2007 dollars) 215

List of Figures 

Figure 1. Coal Delivered and Used in Refined Coal Production, Fiscal Year 2002 to 2007 30

Figure 2. Annual and Cumulative Wind Power Capacity Additions, 1997-2007 (megawatts) 34

Figure 3. LIHEAP Funding, Fiscal Years 1982-2007 38 

Figure A1. TVA Electricity Shares by State & Operating Revenue Shares by Customer 199 

Figure B1. TVA Net Generation by Energy Source (percent) 206

Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Executive Summary xi 

Executive Summary 

Background 

In May 2007, Senator Lamar Alexander asked the Energy Information Administration (EIA) to 

develop an analysis of Federal energy subsidies focusing on subsidies to electricity production. 

Senator Alexander also specified that the analysis should be limited to subsidies provided by 

the Federal government, those that are energy-specific, and those that provide a financial 

benefit with an identifiable budget impact. Federal energy subsidies and interventions 

discussed in the body of this report take four principal forms: 

• Direct Expenditures. These are Federal programs that directly affect the energy 

industry and for which the Federal government provides funds that ultimately result in a 

direct payment to producers or consumers of energy.

• Tax Expenditures. Tax expenditures 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 in ways deemed to be in the public interest. 

• Research and Development (R&D). Federal R&D spending focuses on a variety of 

goals, such as increasing U.S. energy supplies, or improving the efficiency of various 

energy production, transformation, and end-use technologies. R&D expenditures do not 

directly affect current energy production and prices, but, if successful, they could affect 

future production and prices. 

• Electricity programs serving targeted categories of electricity consumers in 

several 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.” 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). 

With the exception of the Federal electricity programs, this report measures subsidies and 

support on the basis of the cost of the programs to the Federal budget provided in budget 

documents. Support associated with Federal electricity programs is measured by comparing the 

actual cost of funds made available to these entities to EIA estimates of the cost of funds that 

they might otherwise have incurred in the absence of Federal support. 

Summary of Findings 

Total Federal energy-specific subsidies and support to all forms of energy are estimated 

at $16.6 billion for fiscal year (FY) 2007 (Table ES1). Total energy subsidies have more than 

doubled in real terms (2007 dollars), increasing from an estimated $8.2 billion in FY 1999. Tax 

expenditures have more than tripled since 1999, rising from $3.2 billion that year to more than 

$10.4 billion in 2007. 

The increase in energy subsidies and support since 1999 is distributed widely across all 

energy groups (Table ES1). Changes in the distribution of subsidies by fuel type between 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

xii Energy Information Administration / Executive Summary 

1999 and 2007 reflect a redirection of priorities. For example, subsidies for renewables 

increased from 17 percent of total subsidies and support in 1999 to 29 percent in 2007. Natural 

gas and petroleum related subsidies declined as a share of total subsidies primarily as a result 

of the expiration of the Alternative Fuels Production Tax Credit for the production of 

unconventional natural gas in 1999, whereas refined coal was the principal beneficiary of this 

tax expenditure in 2007. Coal-related subsidies, excluding refined coal, experienced a modest 

decline from 7 percent in 1999 to 6 percent in 2007. 

Recent Federal legislation, including the Energy Policy Act of 2005 (EPACT2005) (Public 

Law 109-58) and the Energy Independence and Security Act of 2007 (EISA 2007) (Public 

Law 110-140) suggest that certain energy-related tax expenditures are likely to increase.

Table ES1. Energy Subsidies and Support by Type and Fuel, FY2007 and FY1999 

(million 2007dollars) 

Beneficiary 

Direct 

Expenditures 

Tax 

Expenditures 

Research & 

Development 

Federal 

Electricity 

Support Total 

2007 Subsidies 

Coal - 290 574 69 932 

Refined Coal1 - 2,370 - - 2,370 

Natural Gas and Petroleum Liquids - 2,090 39 20 2,149 

Nuclear - 199 922 146 1,267 

Renewables 5 3,970 727 173 4,875 

Electricity (Not fuel specific) - 735 140 360 1,235

End Use 2,290 120 418 - 2,828 

Conservation 256 670 - - 926 

Total 2,550 10,444 2,819 767 16,581 

1999 Subsidies 

Coal - 79 489 - 567 

Natural Gas and Petroleum Liquids2 - 1,878 198 - 2,077 

Nuclear - - 740 - 740 

Renewables 5 1,000 412 - 1,417 

Electricity (Not fuel specific) - 139 175 - 314 

End Use 1,545 103 487 - 2,135 

Conservation 191 - - - 191 

Federal Electricity Programs - - - 753 753 

Total 1,741 3,199 2,500 753 8,194 

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

1

Tax expenditures attributable to the Alternative Fuels Production Tax Credit. 

2 In 1999, the Alternative Fuels Production Credit was realized mostly from the production of coalbed methane; 

valued at $1.2 billion, that subsidy is reported in Natural Gas and Petroleum Liquids. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Executive Summary xiii 

 

Some of the most significant subsidy provisions in EPACT2005 concern nuclear power. Given 

that no new nuclear power plants are expected to produce electricity before the middle of the 

next decade, this report provides no estimates for the value of these provisions. EPACT2005 

also included mandates for the use of renewable motor fuels that were significantly expanded in 

EISA 2007. EISA 2007 mandates are not considered in this report given its focus on historical 

and current tax expenditures. The EISA renewable fuel mandates could become binding in the 

near future. 

Notwithstanding the doubling of Federal energy-related subsidies and support between 

1999 and 2007, and a significant increase in most energy prices over that period, U.S. 

energy production is virtually unchanged since 1999 (Table ES2). Basic economic 

principles suggest that higher real energy prices together with the significant incentives provided 

to various production segments of the energy sector would tend to raise domestic energy 

production. A variety of factors unrelated to prices or subsidy programs such as State and 

Federal statutory limitations imposed on onshore and offshore oil and natural gas exploration in 

environmentally sensitive areas, uncertainty regarding future environmental policies possibly 

restricting future emissions of greenhouse gases, and declines in future production from 

previously developed domestic oil and natural gas resources may have impeded growth in 

energy production despite modest growth in consumption. 

In response to Senator Alexander’s specific request, this report focuses on subsidies that 

provide benefits to the electric power industry in one of three ways, specifically that: 

• affect a fuel used as input for the generation of electricity; 

• are directed to technological components of the industry, such as generation, 

transmission, or distribution; 

• are directed to, or are applied by, a business enterprise whose primary purpose is the 

generation, transmission, and/or distribution of electricity. 

Table ES3 summarizes the split between electricity production subsidies, support to Federal 

utility programs, and other energy subsidies deemed to be unrelated to electricity production. 

Table ES2. Total Energy Subsidies and Support, Selected Indicators,1999 and 2007 

Item 1999 2007 

Percent 

Change 

1999 to 

2007 

Average 

Annual 

Growth 

(Percent) 

Energy Subsidies and Support (million 2007 dollars) 8,194 16,581 102.4 9.2 

Energy Expenditures (billion 2007 dollars) 674 1,269 88.1 8.2 

Energy Consumption (quadrillion Btu) 97 101 4.6 0.6 

Energy Production (quadrillion Btu) 72 72 0.1 * 

NOTE: * Value is less than one-tenth of one percent. 

Sources: Energy Information Administration, Annual Energy Review 2006, DOE/EIA-0384(2006) (Washington, DC, 

June 2007), Tables 1.1, 1.2, 1.3, 1.5, and D1; Short-Term Energy Outlook (Washington DC, January 8, 2008 release), 

http://www.eia.doe.gov/emeu/steo/pub/contents.html; Annual Energy Outlook 2008 (Early Release), 

http://www.eia.doe.gov/oiaf/aeo/index.html, and this report. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

xiv Energy Information Administration / Executive Summary 

Findings Regarding Electricity Production-Related Subsidies 

Subsidies and support related to electricity production are estimated at $6.7 billion 

(Table ES3), or about 41 percent of total energy subsidies. A significant portion of 

electricity subsidies and support ($1.2 billion, or 18 percent of total electricity subsidies and 

support) is directed to electric plant or infrastructure, such as transmission. Another $407 

million consists of capital cost support associated with electric generation assets of Federal 

utilities and RUS loans. The beneficiaries of this support are electricity consumers who 

purchase power produced by the Federal utilities and RUS borrowers. The estimated interest 

subsidy associated with these assets is allocated by fuel type. The remaining $5.1 billion of 

electricity subsidies are either directed at specific types of electricity production, based on fuel 

type or investment, or expenses associated with upstream production and transportation of 

fuels used in electricity production—all of which either affect the cost of the input fuel or reduce 

the cost of generating equipment used to produce electricity. 

Table ES3. Allocation of Electricity Production and Other Energy Subsidies (million 2007 

dollars) 

Subsidy and Support Category 

FY 2007 

Electricity 

Production 

Subsidies 

and Support 

FY 2007 

Other 

Energy 

Subsidies 

and Support 

FY 2007 

Total Energy 

Subsidies 

and Support 

Fuel Specific1 5,105 2,330 7,435 

Transmission and Distribution 2 1,235 - 1,235 

Federal Utilities and RUS Borrowers Capacity3 407 - 407 

Energy Subsidies Unrelated to Electricity Production

4 - 7,504 7,504 

Total 6,747 9,834 16,581 

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

1

Includes fuel-related tax expenditures, R&D, and direct expenditures applicable entirely to a specific type of 

electric generation, or primary fuel production-related subsidies allocated to either electricity or other sectors 

based on each sector’s proportionate consumption of the applicable fuel. Excludes fuels that have no role in 

electricity production such as ethanol and other biofuels. 

2 Includes transmission and distribution-related tax expenditures, R&D, and $360 million of estimated financial 

support attributable to Federal utilities’ and RUS borrowers’ debt associated with transmission and distribution 

assets. 

3Reflects the estimated portion of Federal utilities’ and RUS borrowers’ interest support attributable to long-term 

debt associated with capacity and certain TVA and BPA regulatory assets. This support is then assigned by 

fuel-type. 

4

Includes tax and direct expenditures for end-use activities and transportation-related alternative fuels. Among 

these subsidies are conservation programs, residential and commercial energy efficiency programs, and 

ethanol and biofuels tax credits. 

Sources: See Table 26, Table 27 and Table 30.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Executive Summary xv 

Tax expenditures comprise about two-thirds of the total subsidies and support related to 

electricity production (Table ES4). The alternative fuel production tax credit,1

 which is largely 

directed to producers of coal-based synthetic fuels, also referred to as refined coal, accounted 

for about one-half of total tax expenditures related to electricity production in FY 2007. 

Nuclear programs, renewable programs, and non-fuel-specific electricity production 

subsidies and support each ranged from $1 billion to $1.3 billion. 

Natural gas and petroleum liquids receive a lower level of support from electricity 

production-related subsidies and support than other fuel groups. Overall, electricity 

production-related subsidies are spread broadly across the various fuel groups, probably more 

so than in the past.2

Electricity production subsidies and support per unit of production (dollars per 

megawatthour) vary widely by fuel. Coal-based synfuels (refined coal) that are eligible 

for the alternative fuels tax credit, solar power, and wind power receive, by far, the 

highest subsidies per unit of generation, ranging from more than $23 to nearly $30 per 

megawatthour of generation (Table ES5). Subsidies and support for these generation 

sources are substantial in relationship to the price or cost of electricity at the wholesale or enduser level. The average U.S. electricity price was about $53 per megawatthour at the 

wholesale level in 2006 and about $92 per megawatthour to end users in all sectors in FY 

2007.3

 

 

1

 The alternative fuel production tax credit was initially established in the Windfall Profit Tax Act of 1980 (Public Law 96-223). The 

provision was codified in Section 29 of the Internal Revenue Code. It was subsequently modified by Section 710 of the American 

Jobs Creation Act of 2004 (Public Law 108-357) to include synthetic coal, which was redefined as refined coal and recodified in 

Section 45 of the Internal Revenue Code. The expiration date to qualify for the credit was extended in EPACT2005. 

2

 EIA did not analyze electricity production subsidies in particular in its 2000 report. However, a line item comparison of various 

energy subsidies indicates that newer subsidy programs have been directed toward fuel groups and activities, such as renewables, 

conservation, and transmission that previously received less attention. 

3

 Energy Information Administration Form EIA-861 “Annual Electric Power Industry Report,” 2006; and Energy Information 

Administration, Electric Power Monthly December 2007, DOE/EIA 0026(0712) (Washington, DC, December 2007), Table 5.6.B. 

Table ES4. Fiscal Year 2007 Electricity Production Subsidies and Support (million 2007 dollars) 

Fuel End Use 

Direct 

Expenditures 

Tax 

Expenditures 

Research & 

Development 

Federal 

Electricity 

Support Total 

Coal - 264 522 68 854 

Refined Coal - 2,156 - - 2,156 

Natural Gas and Petroleum 

Liquids

- 203 4 20 227 

Nuclear - 199 922 146 1,267 

Renewables 3 724 108 173 1,008 

Transmission and 

Distribution - 735 140 360 1,235 

Total 3 4,281 1,696 767 6,747 

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. The Rural Utilities Service estimate is 

based on calendar year 2005 data. 

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

Sources: See Table 34. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

xvi Energy Information Administration / Executive Summary 

The differences between rankings of subsidies and support based on absolute amounts 

and amounts per megawatthour are driven by substantial differences in the amount of 

electricity generation across fuels. Capital-intensive, baseload generating technologies, 

such as coal-fired steam generators and nuclear generators, together produce about 70 

percent of total net generation,4

 which tends to reduce their subsidies and support per unit of 

production compared to the other fuel groups (Table ES5). For the same reason, electricity 

subsidies for solar and wind show a relatively large subsidy per unit of production, as these 

groups account for less than 1 percent of total net generation in the country. It is important to 

recognize that the subsidies-per-megawatthour calculations are a snapshot taken at a particular 

point in time. Some electricity sources, such as nuclear, coal, oil, and natural gas, have 

received varying levels of subsidies and support in the past which may have aided them in 

reaching their current role in electricity production.5 The impacts of prior subsidies, some of 

which may no longer be in effect, are not measured in the current analysis. 

A per-unit measure of electricity production subsidies and support may provide a better 

indicator of its market impact than an absolute measure. For example, even though coal 

receives more subsidies in absolute terms than wind power, the use of wind is likely to be more 

dependent on the availability of subsidies than the use of coal. 

 

4

 In fiscal year 2007, nuclear and coal accounted for 68 percent of total net generation. 

5

 See Energy Information Administration, Federal Financial Interventions and Subsidies in Energy Markets 1999: Primary Energy,

SR/OIAF/99-03 (Washington, DC, September 1999); Energy Information Administration, Federal Energy Subsidies: Direct and 

Indirect Interventions in Energy Markets, SR/EMEU/92-02 (Washington, DC, November 1992). 

Table ES5. Subsidies and Support to Electricity Production: Alternative Measures 

Alternative Measures of Subsidy and Support 

Fuel/End Use 

FY 2007 Net 

Generation 

 (billion 

kilowatthours) 

FY 2007 Subsidy and 

Support 

 (million 2007 dollars) 

Subsidy and Support per 

Unit of Production 

(dollars/megawatthour) 

Coal 1,946 854 0.44 

Refined Coal 72 2,156 29.81 

Natural Gas and Petroleum Liquids 919 227 0.25 

Nuclear 794 1,267 1.59 

Biomass (and biofuels) 40 36 0.89 

Geothermal 15 14 0.92

Hydroelectric 258 174 0.67

Solar 1 14 24.34

Wind 31 724 23.37

Landfill Gas 6 8 1.37

Municipal Solid Waste 9 1 0.13

Unallocated Renewables NM 37 NM

Renewables (subtotal) 360 1,008 2.80

Transmission and Distribution NM 1,235 NM

Total 4,091 6,747 1.65 

NOTES: Unallocated renewables include projects funded under Clean Renewable Energy Bonds and the Renewable 

Energy Production Incentive. 

NM=Not meaningful. Totals may not equal sum of components due to independent rounding. 

Sources: See Table 35
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Executive Summary xvii 

Other factors can also play an important role in determining the market impact of a 

particular production subsidy. For example, generation using refined coal whose production 

is made possible by its eligibility for the Alternative Fuel Production Tax Credit would probably 

be replaced entirely by conventional coal generation if the tax credit were unavailable. In 

contrast, generation resulting from the growth in wind power capacity that is supported by 

renewable production tax credits would likely be replaced with generation from a broad mix of 

generation sources if that credit were unavailable.

Findings Regarding Energy Subsidies Not Related to Electricity Production 

Based on the subsidy categories used in this report, 59 percent of energy-related 

subsidies are associated with end-use applications or with fuel consumed outside the 

electric power sector. These subsidies totaled $9.8 billion in FY 2007 (Table ES6). 

About one-third of energy subsidies unrelated to electricity production are related to the 

promotion of alternative fuels, particularly ethanol and biodiesel, both of which are 

eligible to receive a blender’s credit under the Volumetric Ethanol Excise Tax Credit 

(VEETC). Blenders receive a $0.51 per gallon credit for each gallon of ethanol that is blended 

with gasoline for use as a motor fuel.6

 The benefit provided by the credit is equivalent to that 

provided by the reduced excise tax rate for gasohol in effect prior to the enactment of VEETC in 

late 2004. 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 reduction in excise tax revenues for FY 

2007. For purposes of this report, it is classified as a tax expenditure. 

Non-fuel specific subsidies totaling $3.6 billion focus on energy efficiency, conservation, 

and energy-related financial assistance to residential, commercial, and industrial end 

users. Conservation and energy efficiency subsidies can affect electricity consumption in the 

long run by reducing the need for investment in additional generating capacity, with a resultant 

decline in fuel use. While these subsidies can affect electricity markets, they do not provide a 

direct or indirect subsidy to electricity production and are therefore classified separately from 

the electricity production-related subsidies estimated for purposes of this report. 

 

6

 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.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

xviii Energy Information Administration / Executive Summary 

Table ES6. Energy Subsidies Not Related to Electricity Production: Alternative Measures 

Alternative Measures of Subsidy and 

Support 

Category 

Fuel 

Consumption 

(quadrillion Btu) 

FY 2007 Subsidy and 

Support 

 (million 2007 dollars

Subsidy per 

million Btu 

(2007 dollars) 

Coal 1.93 78 0.04 

Refined Coal 0.16 214 1.35 

Natural Gas and Petroleum Liquids 55.78 1,921 0.03 

Ethanol/Biofuels 0.57 3,249 5.72 

Geothermal 0.04 1 0.02 

Solar 0.07 184 2.82 

Other Renewables 2.50 360 0.14 

Hydrogen * 230 NM 

Total Fuel Specific1 60.95 6,237 0.10 

Total Non-Fuel Specific NM 3,597 NM 

 Total End-Use and Non-Electric Energy NM 9,834 NM 

NOTES: Non-electric power refined coal consumption is based on the sum of monthly deliveries, in short tons, reported 

in the EIA publications cited below for FY 2007. Delivered refined coal to non-electric customers is converted to 

equivalent Btu consumption based on EIA’s estimate of the average Btu content for refined coal deliveries to generators 

reported to EIA. Other renewables includes hydroelectric, wood, biomass losses and co-products, and hydroelectric 

power as reported in the sources noted below. 

1

Subsidy shown differs from that shown in Table ES3 due to inclusion of fuels that have no role in electricity production, 

such as ethanol and other biofuels. 

*Less than 500 trillion Btu. 

NM = Not meaningful 

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

Sources: See Table 36. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 1: Introduction 1

 

1. Introduction 

Background and Purpose 

In May 2007, Senator Lamar Alexander asked the Energy Information Administration (EIA) to 

develop an analysis of Federal energy-specific subsidies that provide a financial benefit with an 

identifiable budget impact. His request letter of May 12, 2007, provided as Appendix H, asked 

EIA to focus particularly on subsidies directed to electricity production, including an estimate of 

electricity subsidies on a per unit basis. 

In 2000, EIA enumerated and summarized energy subsidies and support generally; this report 

focuses on electricity production, specifically those subsidy and support programs that affect 

the production of primary fuels used to generate electricity (coal, natural gas, petroleum, and 

nuclear fuel), and the development of generating technologies including renewable generating 

technologies, and the development and maintenance of the electricity infrastructure. 

Scope of the Report and Measurement of Subsidies and Support 

Federal energy subsidies discussed in the body of this report take four principal forms: 

• Direct Expenditures. These are Federal programs that provide direct financial benefits to 

targeted producers and consumers of energy to promote investment in critical 

infrastructure, develop and diversify domestic energy supplies, foster efficient end-use 

consumption, and reduce energy costs incurred by economically-disadvantaged 

consumers. 

• Tax Expenditures. Tax expenditures are provisions in the Federal tax code that reduce 

the tax liability of firms or individuals who engage in specific economic activities that 

affect energy production, consumption, or conservation in ways deemed to be in the 

public interest. 

• Research and Development (R&D). Federal R&D spending focuses on a variety of 

goals, from increasing U.S. energy supplies, to improving the efficiency of various 

energy production, transformation,7 and end-use technologies. R&D expenditures do not 

directly affect current energy production, prices, and environmental quality, but, if 

successful, they could affect future energy production, prices, and environmental quality. 

• Federal programs that indirectly support electricity production. 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.”8

The Federal government also provides direct financial support and credit enhancement 

for construction and generation, transmission, and distribution facilities by entities 

eligible to participate under the U.S. Department of Agriculture’s Rural Utilities Service 

(RUS) loan programs.

 

7

 Energy transformation consists of network infrastructure and delivery systems. Electricity is the primary transformation sector 

analyzed in this report. The electricity sector consists of generation, transmission, and distribution. 

8

 Flood Control Act of December 2, 1944 (58 Stat. 890; 16 U.S.C. 825s). Surplus Federal utility power is sold to investor-owned 

utilities. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

2 Energy Information Administration / Chapter 1: Introduction 

In measuring the cost to the Federal government of the subsidies (and financial support 

provided TVA and PMA customers and RUS borrowers) this report uses the measure of budget 

cost or revenue losses to the greatest extent possible; in some cases, budget outlays—the 

actual expenditures by Federal agencies—are cited. For many R&D programs, however, the 

available outlay data are less disaggregated than the appropriations data. Hence, using the 

appropriations data provides a more detailed understanding of Federal R&D efforts by type of 

energy supported. There are also several programs for which the Federal budget itself is not a 

meaningful measure of the concept of budget costs. Tax expenditures are not line items in the 

budget. The Treasury Department estimates the cost of tax expenditures as revenue foregone 

as a result of a provision in the tax code that reduces or defers tax liability and, therefore, tax 

receipts. The Treasury Department’s estimated revenue losses associated with energy-related 

tax expenditures are used in this study.9 EIA measures support provided by Federal electricity 

programs through a cost-of-capital analysis. 

Using the Federal budget has the advantage of ease of measurement; however, budget values 

may understate both the economic costs and the market impacts of specific programs, 

especially where small subsidies are applied to large existing markets.10 On the other hand, 

some large subsidies are applied to small markets and have a substantial impact on certain 

forms of energy production and consumption. Some subsidies offer relatively large payments to 

producers using certain energy technologies that otherwise would be uneconomical at present. 

In these cases, the immediate effects on markets may be small, but the impact on specific 

technologies may be significant now and in the future. 

Definition of Subsidy and Types of Subsidies and Support Addressed 

There is no universally-accepted definition of subsidy. For the purposes of this report, a subsidy 

is defined as a transfer of economic resources by the Federal government to the buyer or seller 

of a good or service that has the effect of reducing the price paid, increasing the price received, 

or reducing the cost of production of the good or service with incentives that reduce the 

producers’ taxable income. A subsidy is conditioned on a particular economic outcome. The net 

effect of such a subsidy is to alter the production or consumption of a commodity over what it 

would otherwise have been.11 In some instances subsidies may also result in a transfer of 

wealth because they change the behavior of the recipient of the subsidy.12 Subsidies are 

measured in terms of monetary value. They exist when government intervention either lowers 

energy prices for consumers or supports producers when their production costs prohibit sales at 

market prices. There are a number of Federal interventions in energy markets that fall outside 

the framework of this report, an important one being government regulation. The cost of 

spillovers, such as the effects that certain forms of energy production and consumption have on 

the environment and public health, is another. 

This report quantifies direct and indirect energy subsidies and support to Federal electricity 

programs. Direct subsidies include (a) payments from the government directly to producers or 

consumers and (b) tax expenditures. Tax expenditures are provisions in the tax code that 

reduce the Federal tax liability of qualifying firms or individuals who have undertaken particular 

 

9

 Previously, the Treasury Department estimated revenue impacts using an additional method, outlay equivalents. EIA used outlay 

equivalents to measure budget impacts in its previous reports. 

10 This is true particularly in the context of comparing the aggregate and the relative share of subsidies for a long-standing energy 

supply chain (e.g., coal) versus a nascent energy supply chain (e.g., bioenergy). 

11 See C. Shoup, Public Finance (Chicago, IL: Aldine Publishing Company, 1969), p. 145. 

12 Direct assistance provided by the Low Income Heating Assistance Program (LIHEAP) could be viewed as falling into this 

category, since the primary purpose of the program is to assist the economically disadvantaged in meeting high energy bills. Thus, 

this element of the LIHEAP program is not for the purpose of inducing a change in behavior, e.g., conservation or investment in 

energy efficiency. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 1: Introduction 3

 

actions. Energy-related examples include tax credits for certain kinds of activity (e.g., producing 

refined coal) or favorable treatment of capital recovery (e.g., excess of percentage over cost 

depletion for independent oil producers). 

Indirect energy subsidies consist of other forms of Federal financial commitment that affect the 

cost of consumption or production of some form of energy. Indirect subsidies include the 

provision of energy or energy services at subsidized prices through several means: loans or 

loan guarantees; insurance services; R&D activities and expenditures; and the unreimbursed 

provision by the Federal government of environmental, safety, or regulatory services. The 

market risk and opportunity cost of capital borne by the Federal government through the 

Federal electricity programs is estimated as the difference between the incurred cost of capital 

relative to a range of risk adjusted market interest rates. 

The budgetary cost of government-funded R&D is relatively easy to measure. Determining the 

extent to which government R&D is a subsidy to energy is more problematic. Although R&D 

funding often consists of direct payments to producers or consumers, the payments are not tied 

to the actual production or consumption of energy in the present, and thus do not fall within the 

definition of direct energy subsidies. Federal funding for energy R&D may, in some instances, 

act as a subsidy to the extent that it serves as a substitute for private R&D expenditures that 

would have been made in the absence of government outlays. This is why much Federal 

government-funded R&D is directed at the early stages of technological advances which are 

undertaken long before any resulting innovative good makes its way into the marketplace. 

In addition to quantified energy subsidies and support for Federal electricity programs, this 

report discusses other indirect subsidies in Appendix A (Fact Sheets), which include 

descriptions of programs such as loan guarantees, insurance programs, and certain trust funds. 

When the Federal government assumes actual or potential liabilities of private-sector entities or 

government entities that compete with private sector entities, it transfers risk to the government. 

For instance, the default risk associated with loan guarantees represents a potential cost to the 

government if the borrower defaults and the government must honor the guarantee.13 In the 

case of trust funds and insurance programs the funds needed to cover the liability may be 

collected through a levy on the industry. If the expected present value of the cost of the liability 

assumed by the government exceeds the present value of the levy on the industry, it is 

considered to be an indirect subsidy. 

This report provides a snapshot of Federal subsidies and support for Federal electricity 

programs in domestic energy markets. To be included in this report, a subsidy or support must 

derive from a Federal program, be specific to energy markets, and provide a financial benefit to 

its recipients. 

Certain programs considered as subsidies by others are not included. Because this report 

focuses exclusively on subsidies and support for Federal electricity programs that involve direct 

intervention in markets for primary energy sources and electricity, Federal regulatory activities 

are excluded from the analysis.14 State and local government programs are excluded by 

 

13 Under the Federal Credit Reform Act of 1990 (Public Law 101-508), the budgetary cost of Federal loan and loan guarantee 

programs are measured in terms of the present value of debt service payments based upon the government’s cost of capital, the 

default risk associated with the borrower or class of borrowers, and loan recovery rate. This measure also includes the Treasury’s 

exposure to duration risk, i.e., the subsidy is recalculated annually to adjust for changes to Treasury Constant Maturities applicable 

to the cohort of loans. 

14 For example, the Price-Anderson Act, which provides liability limits for nuclear plant operators, is excluded from this analysis 

(See Appendix A). Other examples include the import tariff on ethanol, and the statutory mandate for blending alternative fuels with 

gasoline. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

4 Energy Information Administration / Chapter 1: Introduction 

definition. Subsidies which arise from broad provisions in the Federal tax code are not 

considered to be "energy specific." Therefore, for example, economic impacts from accelerated 

depreciation and tax exempt status for municipal entities are not analyzed. Since trust funds are 

funded by user fees, they are not included in the analysis.15 Tax-free bonds used by municipal 

electric utilities are excluded because non-energy companies such as municipal water and 

sewer facilities can also use them. Similarly, accelerated depreciation used by investor-owned 

utilities is also excluded because of its use by non-energy companies. However, tax exempt 

bonds that are targeted to specific types of energy entities, which are available to multipleownership classes, are included in the study.16

Public interest in energy subsidies arises in part from concerns that the subsidies may affect 

competition between energy and non-energy investments or between different forms of energy. 

Concerns also arise when subsidies lead to higher prices or taxes, either direct or indirect. 

Because all government programs have costs and benefits, there has been a tendency for the 

term "subsidy" to lose specificity and acquire derogatory connotations. This study does not 

ascribe normative values (negative or positive) to subsidies. The report does not attempt to 

weigh the benefits of each subsidy, nor does it revisit the original considerations—correcting 

perceived market problems or achieving social objectives—which are the domain of 

policymakers. It should be noted that in the U.S. economy a wide array of industries and 

individuals benefit from various subsidies, not just energy producers and consumers. This study 

identifies and attempts to quantify certain energy subsidies for fiscal year (FY) 2007. For FY 

2007, this report used the value of energy-specific subsidies and R&D expenditures from actual 

budget data and estimates of tax expenditures prepared by the Treasury Department and the 

congressional Joint Committee on Taxation (JCT).17 Once the subject of these energy subsidies 

in FY 2007 is identified and quantified, the study concludes with an examination of fuel-specific 

impacts of these subsidies on electricity production. 

Valuing Energy Subsidies and Support: Theoretical Issues 

EIA considered several theoretical issues in developing an analytical approach that would 

provide information responsive to the request for this report. Those theoretical issues included: 

• The Incidence Theory, which recognizes that the statutory beneficiaries of a subsidy or 

support may not necessarily be the economic beneficiary. The division of benefits 

between statutory and economic beneficiaries is dependent on economic behavior that 

requires an analytical assessment generally beyond the scope of this report. 

• Marginal versus inframarginal benefits of subsidies and supports addresses the extent 

to which a subsidy induces the marginal behavior intended by the particular subsidy or 

simply transfers wealth to an entity already behaving in the “desired” manner. EIA 

 

15 For example, nuclear decommissioning trust funds for which the plant owner is responsible for funding from revenue collected 

from wholesale and retail customers are excluded. 

16 In this report two tax expenditures take the form of bond issuances, both of which are specifically directed towards energy 

entities, i.e., the exclusion of interest income on certain energy facility bonds from taxable income and the tax credit to holders of 

Clean Renewable Energy Bonds. 

17 The use of JCT estimates was limited to certain tax expenditures directed at the electric utility industry in EPACT2005 that were 

not itemized by the Treasury Department in FY 2007 budget documents. The JCT prepares annually a 5-year projection of tax 

expenditures. Other than for the exception noted, EIA relied on the Treasury Department estimates and determined that a 

comparison of Treasury Department and JCT tax expenditure estimates would not be appropriate because, according the JCT, 

they are not “necessarily comparable .” The methods and assumptions used by the Treasury Department differ from those used by 

the JCT. For example, the JCT uses an economic forecast by the Congressional Budget Office, whereas the Treasury Department 

relies on the Administration’s economic forecast. See, “Estimates of Federal Tax Expenditures for Fiscal Years 2007-2011,” Staff 

of the Joint Committee on Taxation, (Washington, DC, September 24, 2007), pp. 21-22. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 1: Introduction 5

 

recognizes that benefits may be divided in this fashion. However, an analysis of 

marginal and inframarginal effects was beyond the scope of this analysis. 

• The study examines the market risk and opportunity costs to the Federal government 

incurred through its participation in Federal electricity programs. While these programs 

may not be reflected in the Federal budget as direct expenditure line-items, market risk 

and opportunity costs, while difficult to quantify, are real. 

The Incidence Theory 

A rigorous economic and financial analysis of energy-related subsidies that directly impact 

electricity production requires an empirical examination of the underlying behavior of market 

participants in the product markets to which a subsidy is directed to determine who ultimately 

receives the benefit.18 In other words, the statutory beneficiary of a tax or direct subsidy may 

not be the economic beneficiary, depending on economic behavior of market participants. The 

literature on public finance and taxation refers to this as the Theory of Incidence.19 

Subsidies for which fuel producers or transporters (e.g., natural gas pipelines) are the statutory 

beneficiaries may pass forward, i.e., transfer, in whole or part to electricity generators based on 

a variety of economic circumstances. EIA recognizes that a pass forward of economic 

incidence may occur with many subsidies described in this report. The number and variety of 

subsidies provided to segments of the energy industry that are upstream of electricity 

production makes it impractical to perform a quantitative estimate of tax incidence on a subsidyspecific basis which distinguishes between statutory and economic incidence for subsidies. 

Accordingly, for purposes of this report, EIA adopted an allocation method based on fuel 

consumption by the electric industry to allocate the value of these subsidies to electric 

generation by fuel-type as described in Chapter 5. This method was adopted in recognition of 

the potential presence of economic incidence, but should not be construed as being an 

estimate of actual economic incidence. 

Marginal Versus Inframarginal Effects of Subsidies and Support 

A second economic consideration associated with subsidies is the extent to which the subsidy 

leads to the desired marginal behavior such as increased production of a preferred fuel or 

renewable resource, or a subsidy that results simply in a transfer of resources or wealth, often 

described as an inframarginal effect. For example, ethanol producers and fuel blenders benefit 

from three Federal interventions: (1) a tariff imposed on ethanol imports, (2) a mandate that 

requires the blending of renewable fuels with gasoline, and (3) the Volumetric Ethanol Excise 

Tax Credit (VEETC). While the latter is a tax subsidy estimated by the Treasury Department 

 

18 Methods include partial equilibrium analyses, static general-equilibrium analyses, dynamic equilibrium analyses and empirical 

analyses using micro-data sets to investigate the impacts of an individual subsidy on behavior. These alternative methods are 

described in the context of examining where the ultimate burden of a tax falls, as opposed to a tax subsidy in the article “Incidence 

of Taxes” written by George Zidrow that appears in the Urban Institute Encyclopedia of Taxation and Tax Policy, 

http://www.urban.org/UploadedPDF/1000534.pdf. 

19 A cogent example of the difference between statutory and economic incidence, and the quantitative analysis (regression 

analysis) required to thoroughly investigate this issue appears in a recently published paper that examined the hybrid vehicle tax 

credit included in the Energy Policy Act of 2005. The author used data on the sales of the Toyota Prius to assess whether 

consumers (the statutory beneficiary) of the tax credit realized the benefit, or whether it was transferred to Toyota as a result of its 

economic behavior in response to the tax credit. Specifically, the author sought to quantitatively determine whether Toyota raised 

prices to clear the market and capture the majority of the benefit of the tax credit that statutorily was directed to consumers. Based 

on the results of the analysis, the author concluded, that Toyota did not raise prices, despite capacity constraints out of a concern 

that raising current prices would dampen future demand. See, Sallee, James M. “The Incidence of Tax Credits for Hybrid 

Vehicles,” University of Michigan, January 22, 2008, http://www-personal.umich.edu/~jsallee/Homepage/Home.html. The Incidence 

Theory suggests that normally when a product market is supply or capacity constrained, a supplier receiving a tax credit is likely to 

retain the benefit of the tax credit. If the product market is not constrained and market entrance is relatively easy for new suppliers 

seeking to capture the tax credit, i.e., statutory incidence, the price of the product will be bid down by competition. This economic 

behavior results in the transfer of the benefit to consumers, i.e., economic incidence. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

6 Energy Information Administration / Chapter 1: Introduction 

and discussed in Chapter 2, the first two interventions are not assumed to be subsidies in this 

report. Interactions between these three interventions in ethanol markets, or other energy 

products and services for which multiple subsidies may be available under Federal law, are not 

analyzed in this report, and the extent to which the current level of ethanol production would 

have occurred in the absence of VEETC because of the tariff on ethanol imports and the 

renewable fuels mandate is not addressed. To the extent the current levels of production could 

have been achieved without VEETC, it would result in a wealth transfer to the beneficiaries of 

the excise tax credit. EIA considered the examination of the marginal and inframarginal effects 

of energy-related subsidies to be outside the scope of this report. 

Measurement of Financial Support to Federal Utilities’ Customers and Rural Utilities 

Service Borrowers 

A final consideration relates to the inclusion of Federal financial support to Federally-owned 

utilities and direct loans and loan guarantees provided by the Rural Utilities Service (RUS) to 

eligible borrowers for investment in generation, transmission and distribution facilities. RUS 

borrowers are primarily generation and transmission cooperatives (G&T) and distribution 

cooperatives. The Federal utilities included in this report include the Tennessee Valley 

Authority (TVA), a wholly-owned government corporation, and the Federal Power Marketing 

Administrations (PMA), which include the Bonneville Power Administration (BPA), the Western 

Area Power Administration (WAPA), the Southwestern Power Administration (SWPA) and the 

Southeastern Power Administration (SEPA). For convenience, WAPA, SWPA and SEPA are 

collectively referred to as the small PMAs. 

As discussed in more detail in Chapter 4, the PMAs market electricity from hydroelectric 

facilities owned by the Army Corps of Engineers and the Bureau of Reclamation. These 

facilities were financed by the Federal government. The small PMAs finance capital 

improvements with internally generated funds and limited, but ongoing borrowing from the 

Treasury. BPA continues to maintain a revolving fund with the Treasury for financing certain 

capital activities. However, the bulk of its outstanding debt was restructured pursuant to the 

Bonneville Administration Refinancing Section of the Omnibus Reconciliation Act of 1996,20

which required that it pay a higher ongoing rate of interest. The economic effect of the 

restructuring reduced BPA’s outstanding principal, but increased its interest expense such that 

the present value of debt service payments, plus a required $100 million upfront payment 

equals its original outstanding obligations. TVA has refinanced its Federal debt with bonds sold 

to private investors, and meets its incremental capital requirements through the issuance of 

bonds to private investors. It is important to note that while Federal utilities have had access to 

low-cost Federal financing; it is pursuant to a statutory framework that requires them to operate 

on a cost-basis, such that any Federally-provided financial benefit is reflected in the cost of 

power charged to their customers.21

 

The statutory provisions under which Federal utilities operate provide them with independent 

authority to establish electric rates on a cost basis, including the repayment of debt. Therefore, 

it can be argued that the benefit of low-cost capital that flows through to their customers is not a 

 

20 16 U.S.C. 838(l). 

21 From their inception and over time, Congress has defined the duties of TVA and the PMA’s, particularly BPA, to include nonelectric related functions ranging from supporting agriculture, industrial development, and environmental stewardship. These 

activities have resulted in Federal investment in non-electric facilities and the incurrence of ongoing operating expense. Some of 

these costs are joint and common that may or may not be recovered through electric rates. For example, BPA operates Federallyfinanced irrigation projects for which it is not fully compensated by irrigation customers. However, it is required to make payments 

to the Treasury for the original construction costs only if in doing so it does no require an increase in electric rates. These 

payments are made from accumulated net revenues. According to BPA’s 2007 Annual Report, these payments could total $689 

million over time. The analysis in Chapter 4 has not excluded the portion of financial support associated with joint and common 

costs. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 1: Introduction 7

 

subsidy in the absence of a default. The contrary argument is that notwithstanding the statutory 

framework under which the Federal utilities operate, their customers are receiving financial 

support because there is neither explicit recognition of the market risk that is borne by the 

Federal government in the event of a default, nor of the opportunity cost to the Federal 

government’s stakeholders, i.e., taxpayers which include the customers of the Federal utilities. 

The value of this financial support is a cost to the Federal government which is not quantified 

and assigned to the Federal utilities in the budget. To the extent it is a significant and 

measurable cost, it is reflected in the interest rate set in the market for Treasury securities and 

in the annual interest expense on Federal debt included in the budget. 

In order to estimate the value of the financial support provided to the customers of the Federal 

utilities, EIA has adopted a cost-of-capital approach that estimates the value based on the 

difference between the interest expense that Federal utilities actually paid in 2006 versus what 

they would have paid by applying a range of contemporaneous interest rates to their 

outstanding debt. The interest rates range from the risk-free Treasury rate to the full range of 

interest rates for investment grade investor-owned utility (IOU) bonds. In order to express the 

value of Federal financial incentives provided directly and indirectly to electricity production on a 

unit of production basis, EIA compared Federal utilities’ weighted average cost-of-capital to the 

market interest rate associated with an A-rated IOU bond. 

The 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 present value of each 

loan or bond issue at the market rate of interest at the time the obligation was incurred. The 

data required to perform this analysis were not available to EIA. 

Opinions vary with respect to the extent to which there is a significant risk premium between the 

risk-free Treasury rate and the market rate of interest that Federal utilities would be required to 

pay in the absence of their ownership status and the statutory framework under which they 

operate. This is true with respect to TVA and BPA, both of which have received ratings ranging 

from AA- to AAA from the nationally recognized credit rating agencies. As discussed in 

Chapter 4, the nationally recognized credit rating agencies have issued credit rating reports that 

offer different perspectives on this issue. For example, Fitch Ratings stated in a January 2008 

issue rating for TVA Global Power Bonds that: 

“TVA's outstanding debt is not a full faith and credit, or limited obligation 

of the U.S. Government. However, Fitch believes that U.S. authorities 

would use extraordinary efforts to support their operations and senior 

debt obligations in the unlikely event that TVA encountered financial 

difficulties. This analysis takes into account TVA's ownership by the U.S. 

government, the sizeable role that TVA plays in the Tennessee Valley 

and broader economies, and the level of its obligations that are held by 

domestic and other foreign based investors (similar to that of government 

sponsored entities (GSE)).” 22

 

 

22 “Fitch Rates Tennessee Valley Auth's $500MM Global Power Bonds 2008 Series A 'AAA',” BusinessWire, January 18, 2008, 

 http://www.businesswire.com/portal/site/google/index.jsp?ndmViewId=news_view&newsId=20080118005746&newsLang=en, 

Accessed February 23, 2008.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

8 Energy Information Administration / Chapter 1: Introduction 

In order to develop a point estimate of the value of the support provided to the customers of the 

Federal utilities, EIA performed a financial ratio analysis that compared TVA and the PMAs to 

comparably structured governmentally-owned wholesale power suppliers. The financial ratios 

measure an entity’s ability to meet its debt and fixed obligations, i.e., liquidity and cash flow. 

This approach was adopted in order to neutralize any actual or perceived credit enhancement 

that financial markets attribute to Federal ownership and/or the ability to borrow at the Federal 

government’s cost of funds or at interest rates comparable to GSE interest rates. This resulted 

in the adoption of a market interest rate associated with an A rating. Limiting the derivation of 

the market interest rate to consideration of only financial ratios allowed for uniformity in EIA’s 

analysis and eliminated the effects of actual or perceived credit enhancement attributed to 

Federal support provided in accordance with Federal statutes applicable to the Federal utilities. 

Therefore, the rating used to develop a point estimate of the value of Federal support should 

not be construed as an alternative to actual credit ratings issued by the nationally recognized 

credit rating agencies. The rating agencies consider a multitude of factors in addition to 

financial performance in developing credit ratings that were not considered by EIA. 

Impacts of Subsidies and Support in Electricity Markets 

The process of transforming a primary fuel to electricity is not uniform. Electric generators 

acquire input fuels in a variety of markets23 using delivery systems that differ by fuel type (e.g., 

coal transported by rail or barge; natural gas by pipeline; or oil by pipeline or tanker trucks). 

Once at the electric plant, different technologies convert the fuels with different rates of 

efficiency.24 Certain primary fuels used in electricity production are consumed broadly, while 

others have no practical application other than electricity production. Most electricity is 

produced for retail sale, but some electricity is produced at regulated prices to maintain system 

reliability. These factors make it difficult to state with certainty the exact impacts of the 

subsidies that are the subject of this report on production by each specific fuel type. 

A simplified approach is adopted in this analysis to assess the impacts arising from subsidies to 

primary fuels used in electricity generation. All primary fuel subsidies are assumed to impact 

electricity production in proportion to the amount of primary fuel consumed by electricity 

producers, unless it is clear that the entire subsidy should be directly assigned to a specific fuel 

type. Most coal is consumed for electricity generation, but only an estimated 29 percent of 

natural gas consumption and estimated 1 to 2 percent of petroleum consumption are used to 

generate electricity. All nuclear fuel is consumed by the electric power industry. Power sector 

consumption of renewable fuels varies greatly by type of fuel.25

 

Many subsidies are directed to aspects of the electricity industry which occur after the electricity 

is produced, such as conservation programs, programs directed to energy efficiency (end-use 

R&D), or direct grant programs such as the Low Income Home Energy Assistance Program 

(LIHEAP), which provides States with funds to help defray the heating and cooling bills for 

lower-income households. Since these programs do not affect electricity production directly, 

they are classified as non-electricity subsidies. 

Four electricity subsidies are associated with transmission: a tax expenditure program which 

enables transmission companies to defer income realized from the sale of transmission 

property; an accelerated investment recovery period; a 5-year net operating loss carryforward 

for transmission investment; and an R&D program directed toward improving transmission 

 

23 Long-term contracts, spot markets, tolling agreements, and options. 

24 Identical technologies may also differ in their relative efficiency due to the quality of fuel (i.e., coal), ambient atmosphere 

conditions, and quality of equipment and facility maintenance. 

25 Wind energy is consumed wholly in the power sector, but solar energy is consumed almost entirely in the residential sector. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 1: Introduction 9

 

infrastructure reliability and performance. Since electricity consumption and production occur 

with rough simultaneity, and since transmission directly enables ultimate consumption, 

transmission activities are included as non-fuel specific electricity production subsidies. 

Similarly, support to Federal electricity programs are generally realized as benefits to ultimate 

consumers of Federal power. Federal electricity programs involve all three segments of the 

electricity industry (generation, transmission, and distribution), and it is not always feasible or 

informative to allocate all aspects of these subsidies to fuel specific groups. Therefore, some of 

the support associated with Federally-owned and RUS-financed transmission and electric plant 

are analyzed as non-fuel specific support. 

Although electricity prices are affected by Federal intervention in energy markets, the impact of 

this intervention is not always clear. A consumer surplus arises when Federal utilities price 

power at below market prices. This creates additional demand, a point evidenced by the high 

concentration of aluminum smelters receiving electricity from Federally-owned utilities in the 

Pacific Northwest. On the other hand, government intervention in global fuel markets probably 

has little impact on electricity prices or on demand. This is particularly true of petroleum, and, to 

a lesser extent, coal. Today, Canadian and American natural gas markets are relatively 

integrated and current liquefied natural gas developments portend a future global natural gas 

market. 

It is unclear as to how much the value of a particular subsidy will benefit producers or 

consumers.26 In most States, ultimate consumers of electricity face cost-of-service tariffs, so 

that most electricity is sold at average cost rather than marginal cost. Because so little 

electricity is sold at market-based rates to retail consumers, it is not clear what effect a subsidy 

to primary fuel has on consumer behavior. In those regions of the country where competitive 

centralized wholesale markets and competitive retail markets co-exist (e.g., California, New 

England, and Texas), the effects of subsidies may be more pronounced than in other areas. 

In regions of the country where retail markets remain regulated or are returning to rate 

regulation, producers may attempt to engage in rent-seeking by trying to capture the producer 

surplus related to a particular subsidy. This is more likely to occur if the retail supplier 

purchases wholesale power from an independent power producer at a market-based wholesale 

rate, as opposed to building a plant and placing the asset in the rate base itself. In the latter 

case, State regulators are likely to set retail rates that transfer potential producer surplus to 

ultimate consumers. 

However, some electricity subsidies and support could affect long-term decision making in the 

selection of generation technologies. They could also affect retail consumption decisions to the 

extent customers receive inefficient price signals. For instance, the production tax credit,27

which provides producers with a credit per unit of electricity production, is often recognized as 

having given rise to much of the recent additions to wind generation capacity. Still, given wind 

generation’s small share of the overall electricity market, it is doubtful that this added capacity 

has had much of an impact upon overall electricity prices. 

 

 

26 TVA and the PMAs are required to operate on a cost-basis. Similarly, electric cooperatives must operate on the basis of cost as 

that term is defined by the Internal Revenue Service in order to preserve their cooperative status. Accordingly, there is greater 

certainty that the benefits of Federal support to electricity programs are passed through to customers. However, an increase or 

decrease in one expense, such as interest expense, may be offset by a change in other expenses. Therefore, a rate change may 

not be necessary if borrowing costs go up or down. 

27 The new technology credit is a tax expenditure discussed in Chapter 2. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

10 Energy Information Administration / Chapter 1: Introduction 

Organization of Report 

In addition to this introductory chapter, this report contains four 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 electricity subsidies and their association 

with specific fuel groups in electricity production. 

The report also includes several appendixes. Appendix A contains Fact Sheets that summarize 

Federal energy-related programs and tax expenditures, not all of which are discussed in the 

body of the report. Appendix B provides alternative estimates of energy subsidies to Federal 

utilities. Appendix C provides an historical perspective on tax expenditures. Appendix D 

provides a description of credit ratings criteria and interpretation of credit ratings; Appendix E 

describes the RUS Electric Program, including direct and hardship loans and loan guarantee 

programs. Appendix F contains a list of energy-related statutes and Federal regulations 

referred to in this report. Appendix G contains a bibliography; and Appendix H contains the 

request letter from Senator Alexander. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 11 

2. Tax Expenditures and Direct Expenditures 

Overview 

This chapter focuses on Federal tax expenditures and Federal direct expenditures that 

subsidize activities of energy producers and consumers. For FY 2007, energy-related tax 

expenditures are estimated at $10.4 billion (Table 1). This represents sizable growth in real 

terms from the estimated $3.2 billion (2007 dollars) in energy-related tax expenditures 

conferred in 1999. 28 Another means by which the Federal government can intervene in energy 

markets is through Federal direct expenditures. The direct expenditures covered in this chapter 

that impact energy markets are the Low Income Home Energy Assistance Program (LIHEAP), 

the Building Technology and Assistance Program, and the Renewable Energy Production 

Incentive. Direct expenditures for FY 2007 are estimated at $2.6 billion versus $1.7 billion in 

1999 (2007 dollars). 

Tax Expenditures 

Since the beginning of the last century, the United States has used the Internal Revenue Code 

(the Code, or IRC) as a tool for implementing energy policy.29 Energy tax expenditures are 

broadly defined as provisions in the Code that provide beneficial tax treatment to taxpayers who 

produce, consume, or economize on energy in ways that are judged to be in the public 

interest.30 Tax expenditures are not treated in budgetary terms as spending even though they 

have a similar impact on the budget. That is, the revenue foregone that is attributable to tax 

expenditures can be equated to direct appropriations included in the budget to achieve the 

same result. 

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.”31 The concept of what 

constitutes a tax expenditure is widely understood. However, the determination of what exactly 

is a preferential provision is subject to interpretation. In preparing this section on energy-related 

tax expenditures, the EIA relied on the definitions of tax expenditures incorporated in the 

Federal budget and the associated tax expenditures estimated by the Treasury Department that 

are itemized in Section 19 of Budget of the United States Government, Fiscal Year 2008, 

Analytical Perspectives. To a lesser extent, this table includes data estimates by the 

congressional Joint Committee on Taxation (JCT). 

Tax Expenditures Caveats 

Each year the Treasury Department estimates tax expenditures for the upcoming fiscal year 

budget. The Treasury Department also publishes a forecast of tax expenditures, usually for 

about 5 years going forward. It is important to recognize that tax expenditure data are estimates 

 

28 Current and prior year’s tax expenditures are expressed in 2007 dollars (2007 dollars) for comparative purposes. 

29 The option to expense intangible drilling costs (and dry hole costs) of oil and natural gas wells was originally established in 1916, 

based in Treasury regulation number 45, article 223, which stated such costs be treated as an ordinary operating expense. See, 

General Accounting Office, Petroleum and Ethanol Fuels: Tax Incentives and Related GAO Work, GAO/RCED-00-301R, 

(Washington, DC, September 2000) , p. 8. 

30 The House of Representatives defines tax expenditures as: ”loosely, a tax exemption or advantage, sometimes called an 

incentive or loophole; technically, a loss of governmental tax revenue attributable to some provision of Federal tax laws that allows 

special exclusion, exemption, or deduction from gross income or that provides a special credit, preferential tax rate, or deferral of 

tax liability. The tax exemption or advantage is usually intended to assist a certain group or to encourage a certain activity, such as 

the purchase of homes. In their impact on the Federal budget, tax expenditures are, in effect, subsidies provided through the tax 

system. Instead of making direct payments to beneficiaries, the government permits certain taxpayers to pay lower taxes than they 

otherwise would have to pay.” See: http://www.rules.house.gov/archives/glossary_fbp.htm. Accessed March 12, 2008. 

31 Office of Management and Budget, Budget of the U.S. Government Analytical Perspectives , Fiscal Year 2008, p.285. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

12 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

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. These 

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

This report uses expenditure estimates for FY 2007, projections for the period 2008 through 

2012, and historical data dating back to 1967 (see Appendix C). Although all of these estimates 

were produced by the Treasury Department and the JCT, some secondary sources of data 

were used to compile some of the historical data. Due to the limitations just cited, the historical 

tax expenditure data used in this report are less precise than more current data. However, 

historical data are useful in illustrating the magnitude of various tax programs affecting energy 

production and consumption over time. The value of particular tax expenditure programs can be 

compared to other energy-related tax expenditure programs and relative to where these 

expenditures stood historically. 

For the most part tax expenditures are linked to either energy production, consumption, or 

investment. 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 the eligible party receiving the full 

value of the tax expenditure is the alternative minimum tax, from which most tax expenditures 

are not exempt. The alternative minimum tax becomes effective when deductions become too 

large relative to income. Another mitigating factor is that the expenditure, in many cases, may 

not be received in the year in which the investment or production took place, but may be 

“carried back or forward” a number of years.32

 

Tax expenditures arise from special exclusions, exemptions, deductions, credits, and deferrals 

in Federal tax laws. 

Tax Credit. A tax credit is an amount deducted directly from income tax liability. 

 

Tax Deduction. A tax deduction is deducted from total income to arrive at taxable income. 

Tax Deferral. A tax deferral allows for payment of a tax in a later year. The Office of 

Management and Budget (OMB) reports the cash value of deferrals as expenditures 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 deferral 

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.”33

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

favorably than other income. 

Tax Exclusion. A tax exclusion excludes a portion of income from taxation. 

 

32 In many cases, tax deductions may be transferred to a year other than the current year because they exceed certain limits. 

These deductions may be carried back to earlier years or carried forward to later years until the eligibility period is valid or the 

deduction is used up. 

33 Office of Management and Budget, Analytical Perspectives of the United States Budget, Fiscal Year 2008 (Washington, DC, 

2007). 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 13 

Sizable changes in the dollar value of particular expenditures over time can generally be viewed 

as an indication of the relative importance of these programs (Table 1). 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. Further, most of the tax expenditure data highlighted in this report reflect 

estimates for FY 2007, which are based upon incomplete Treasury tax receipts. In all likelihood, 

these estimates will be revised in subsequent years. This report sums annual tax expenditures 

across various programs. These summations should be treated with care as the Treasury 

Department cautions that there are interactions among tax expenditure provisions, which can 

result in some double counting. 

Oil and natural gas royalty payments are an important source of Federal government revenue. 

To the extent that the Federal government is forgoing revenues by not “optimizing” royalty 

payments, the Federal government may be providing a subsidy similar to a tax expenditure. 

About 35 percent of U.S. oil and natural gas production is produced on Federally-owned or 

Native American lands.34 To the extent that these payments treat resources extracted from 

Federal lands used in the production of energy differently from resources used for other 

purposes, a subsidy may be present. Further, to the extent that certain royalty payments from 

some resources used in the production of energy are treated differently from other resources 

used in the production of energy might also constitute a subsidy. However, royalty rates are 

based upon a number of factors. One critical factor involves the costs of extracting minerals 

from areas that are difficult to access, such as oil and natural gas lying in deepwater offshore 

sections of the Gulf of Mexico. In recent years, favorable royalty payments provided to offshore 

Outer Continental Shelf (OCS) oil and natural gas production have been targets of criticism 

because royalty payments have not kept pace with sharply higher oil and natural gas prices. 

However, designing “optimal” royalty payments should, in theory, be based upon a number of 

factors such as maximizing revenue and oil and natural gas production over the years during 

which production takes place. This makes estimating the value of “favorable” oil and gas leases 

dependent on forecasting future oil and gas prices and production. Moreover, the existence of 

“favorable” royalty payments —again, in theory— should be offset by higher bids for leases. 

Favorable royalty payments, to the extent that they exist, were not considered within the scope 

of this analysis. A Government Accountability Office study released in May 2007 reported that 

an increase in royalty rates by the Federal government on oil and natural gas production from 

12.5 percent to 16.67 percent on future leases sold in the deepwater regions of the Gulf of 

Mexico will, according to the Minerals and Management Service, increase overall Federal 

revenues by $4.5 billion over the next twenty years, but will also cause reductions in some fees 

and in oil and gas production. Offsetting revenue losses were reported at $820 million.35

 

34 Government Accountability Office, Royalty Revenues: Total Revenues Have Not Increased at the same Pace as Rising Oil and 

Natural Gas Prices due to Decreasing Production Sold, GAO-060786R, (Washington, DC, June, 2006). 

35 Government Accountability Office, Oil and Gas Royalties,: A Comparison of the Share of Revenues Received from Oil and Gas 

Production by the Federal Government and Other Resource Owners, GAO-07-676R (Washington, DC, May 2007). 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

14 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures Table 1. Estimates of Tax Expenditures by Fiscal Year (million 2007 dollars)

Historical Data 

Tax Expenditures 1999 2005 2006 2007 

Capital Gains Treatment of Royalties in Coal 79 95 164 170 

Expensing of Exploration and Development Costs (97) 410 695 860 Exception from Passive Loss Limitation for Working Interests in Oil and Natural Gas Properties 36 42 31 30 Enhanced Oil Recovery 273 316 - - Expensing of Tertiary Injectants - - - - Alternative Fuel Production Credit 1,242 2,441 3,046 2,370 New Technology Credit 61 253 521 690 Alcohol Fuel Credit 18 42 51 50 Alternative Fuel and Fuel Mixture Credit - 158 - - Excess of Percentage over Cost Depletion 321 621 777 790 Temporary 50-Percent Expensing for Equipment Used in the Refining of Liquid Fuels - - 10 30 Amortization of All Geological and Geophysical Expenditures Over 2 Years - - 10 60 Natural Gas Distribution Pipelines Treated as 15-Year Property - - 20 50 Exclusion of Interest on Bonds for Certain Energy Facilities 139 84 41 40 Exclusion for Utility-Sponsored Conservation Measures 103 84 112 110 Credit, Deduction for Clean Fuel Vehicles 103 74 112 260 Credit for Holding Clean Renewable Energy Bonds - - 20 60 Credit for Business Installation of Qualified Fuel Cells and Stationary Microturbine Power Plants - - 82 90 Credit for Production from Advanced Nuclear Power Facilities - - - - Deferral of Gain from Disposition of Transmission Property to Implement FERC Restructuring Policy - 516 634 530 Credit for Investment in Clean Coal Facilities - - - 30 Pass Through Low-Sulfur Diesel Expensing to Cooperative Owners - 42 - - Credit for Energy-Efficiency Improvements to Existing Homes - - 235 380 Credit for Energy-Efficient Appliances - - 123 80 Credit for Construction of New Energy-Efficient Homes - - 10 20 30-Percent Credit for Residential Purchases/Installations of Solar and Fuel Cells - - 10 10 Deduction for Certain Energy-Efficient Commercial Building Property - - 82 190 Partial Expensing for Advanced Mine Safety Equipment - - - 10 Expensing of Capital Costs with Respect to Complying with EPA Sulfur Regulations - 11 10 10 Biodiesel and Small Agri-Biodiesel Producer Tax Credits - 32 92 180 Exclusion of Special Benefits for Disabled Coal Miners - - 51 50 Electric Transmission Property Treated as 15-Year Property - - 3 18 5-Year Net Operating Loss Carryover for Electric Transmission Equipment - - 74 43 Treatment of Income of Certain Electric Cooperatives - - - 14 84-Month Amortization of Certain Pollution Control Facilities - 2 10 30 Nuclear Decommissioning - - 123 199 Excise Taxes (Alcohol Fuels Exemption/Volumetric Ethanol Excise Tax Credit) 921 1,578 2,627 2,990 Total (Tax Expenditures) 3,199 6,798 9,775 10,444 NOTE: Total 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 Years 2001 and 2008, Tables 5-1 and 

Committee on Taxation, “Description of the Technical Explanation of the Conference Agreement of H.R. 6, Title XIII, The Energy Tax Incentives Act of 2005,” J28, 2005. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 15 

Historical tax expenditure data used in this report are taken from a number of government 

sources. For the FY 2007, the Treasury Department is the primary provider of estimates for tax 

expenditures, supplemented by data provided by the JCT. For earlier years, this report uses 

U.S. Treasury tax expenditure estimates appearing in the OMB publication Analytical 

Perspectives of the U.S. Budget for tax expenditures starting in 1995. A Congressional Budget 

Office publication, Tax Expenditures: Current Issues and Five-Year Budget Projections for 

Fiscal Years 1982-1986, was relied upon for data for the years 1967 through1981, and values 

appearing in the EIA service report Federal Energy Subsidies for the years 1987 through 

1992.36

Background and Definitions 

Energy-related tax expenditures take many different forms. One example is the immediate 

expensing of intangible drilling costs (IDCs). IDCs are geological and geophysical expenditures 

made by oil and natural gas companies incurred in connection with oil and natural gas 

exploration and development.37 The intention behind this tax expenditure is that by accelerating 

the expensing of IDC, taxable income is lowered which increases internally generated funds 

which can be used for investment. This investment, in turn, stimulates additional production. 

This chapter presents a detailed discussion of some of the more significant energy-related tax 

expenditures in effect during FY 2007. Tax expenditures of smaller monetary value are 

discussed briefly. This latter group of tax expenditures is discussed at greater length in the Fact 

Sheets appearing in Appendix A. 

Tax expenditures account for a large and rapidly growing proportion of the U.S. budget. In a 

2005 study on tax expenditures, the Government Accountability Office (GAO) reported that the 

sum of tax expenditures exceeded discretionary spending for most years in the prior decade.38

The GAO also noted that, since 1974, the number of tax expenditures more than doubled and 

the sum of tax expenditure revenue loss estimates tripled in real terms to nearly $791 billion 

(2007 dollars) by 2004. In 2004, tax expenditures equaled about 7.5 percent of gross domestic 

product.39 

Tax Expenditures’ Role in the Economy 

At $10.4 billion, energy-related tax expenditures are relatively small compared with other tax 

expenditures and overall Federal spending in FY 2007. For instance, the exclusion of employer 

contributions for medical insurance premiums and medical care for income tax purposes totaled 

$144 billion in FY 2007. Second in size to the employer medical care deduction, the home 

mortgage interest rate deduction was valued at $82 billion in FY 2007. Overall Federal 

on-budget spending in FY 2007 was expected to total over $3 trillion, making energy tax 

expenditures equal to roughly 0.3 percent of total government expenditures. Energy 

expenditures, i.e., money spent by consumers to purchase energy, totaled $1.3 trillion in FY 

2007, making energy-related tax expenditures equal to roughly 1 percent of total energy 

expenditures for that year.40

 

36 Energy Information Administration Service Report, Federal Energy Subsidies: Direct and Indirect Interventions in Energy 

Markets, SR/EMEU/02-02 (Washington, DC, 1992). The values appearing in this report were obtained from United States budget 

documents. The original source data were not available for this report. 

37 These expenditures include some administrative costs, survey and seismic costs, drilling costs, equipment transportation costs, 

and road construction costs. 

38 Pursuant to the GAO Human Capital Reform Act of 2004 (Public Law 108-271), the General Accounting Office was renamed the 

Government Accountability Office. Citations to reports issued prior to the name change shall be attributed to the General 

Accounting Office. The acronym GAO is used interchangeably in this report. 

39 Government Accountability Office, Government Performance and Accountability, Tax Expenditures Represent a Substantial 

Federal Commitment and Need to be Examined, GAO-05-690, (Washington, DC, September 2005). 

40 Energy Information Administration, Short Term Energy Outlook (Washington DC, January 8, 2008, release), 

http://www.eia.doe.gov/emeu/steo/pub/contents.html.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

16 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

Tax Expenditures in Energy 

Both the value and the composition of energy-related tax expenditures have changed 

significantly since EIA’s prior analyses of Federal subsidy and support programs specific to 

energy. Between 1992 and 2007, tax expenditures have grown from $2.8 billion to $10.4 billion, 

while there was relatively little change between the values reported in the 1992 and 1999-2000 

reports. In 1992, the two biggest tax expenditures were excess of percentage over cost 

depletion ($1.0 billion) and the alternative fuel production credit ($618 million). In FY 2007, the 

largest tax expenditure was the Volumetric Ethanol Excise Tax Credit41 (VEETC), at $3.0 billion, 

followed by the alternative fuel production credit ($2.4 billion), and the expensing of oil and 

natural gas exploration and development costs ($0.9 billion). VEETC’s predecessor, the excise 

fuel tax exemption, though technically not a tax expenditure, had a value of $747 million in 

1992, which at the time was second only to the excess of percentage over cost depletion, 

whose value equaled $1.0 billion. The excess of percentage over cost depletion42 was the 

fourth largest in FY 2007 at $0.8 billion. The number of tax expenditures has increased since 

the first EIA subsidy analysis was performed. There were 10 tax expenditures identified in the 

1992 EIA study, 12 in the 1999 and 2000 EIA reports, and 37 in the current study. In the past, 

some tax expenditures have come and gone. A number of the EPACT2005 tax provisions 

included sunset dates. Unless they are extended (as many tax expenditures’ sunset dates have 

been in the past), the value of tax expenditures is expected to decline to $2.6 billion by 2012. 

The remainder of this chapter is organized as follows. First, an analysis of energy tax 

expenditures by fuel type is presented. This analysis includes a description of tax expenditures 

affecting both electricity and non-electricity, although energy–related sectors. After that, some 

of the highest-value tax expenditures are discussed, two of which affect the electricity sector 

(the new technology credit and the alternative fuel production sector). This is followed by a 

discussion of VEETC, a tax expenditure affecting transportation, which in FY 2007 is the largest 

energy-related tax expenditure. A discussion of Federal direct expenditures affecting electricity 

production and consumption follows. 

Coal-Related Tax Expenditures 

Coal production was estimated to be the largest recipient of electricity-related tax expenditures 

in FY 2007. Over 90 percent of coal is consumed by the electricity sector. Coal-related tax 

expenditures have an estimated value of $2.7 billion in FY 2007. The alternative fuel production 

tax credit for refined coal was the largest tax expenditure related to coal use. The estimated 

value of this tax expenditure in FY 2007 is $2.4 billion (Table 2).

 

41 OMB does not define VEETC as a tax expenditure. OMB presents this reduction in tax receipts as a footnote to the Tax 

Expenditure Table appearing in OMB, Analytical Perspectives of the United States Budget 2008. Table 19-1. Table 19-1 reports a 

$50 million tax expenditure for fuel alcohol tax credits and $2.99 billion in foregone excise tax revenue due to VEETC. See EIA’s 

Monthly Energy Review, DOE/EIA-0035(200712) (Washington, DC, December 2007), Table 10.3 for fuel ethanol production data. 

42 Under cost depletion, outlays are deducted over the productive life of the property based on the fraction of the resources 

extracted. Under percentage depletion, taxpayers can deduct a percentage of gross income from mineral production at rates of 22 

percent for uranium; 15 percent for oil, natural gas, and shale oil; and 10 percent for coal. The deduction is limited to 50 percent of 

net income from the property, except for oil and gas where the deduction can be 100 percent of net property income. Production 

from geothermal deposits is eligible for percentage depletion at 65 percent of net income. Source: Office of Management and 

Budget, Analytical Perspectives of the United States Budget, Fiscal Year 2008 (Washington, DC, 2007). 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 17 

Table 2. Coal-Related Tax Expenditures (million 2007 dollars) 

Tax Expenditure Type FY 1999 FY 2007 

Exclusion of Special Benefits for Disabled Coal Miners Exemption - 50 

Partial Expensing for Advanced Mine Safety Equipment Expense Deduction - 10 

Credit for Investment in Clean Coal Facilities Credit - 30 

Capital Gains Treatment of Royalties in Coal 

Preferential Tax 

Rate 79 170 

84-Month Amortization of Pollution Control Equipment Expense Deduction - 30 

Subtotal Coal Tax Expenditures 79 290 

Alternative Fuel Production Credit (Refined Coal) Credit - 2,370 

Total Coal and Refined Coal Tax Expenditures 79 2,660 

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

Sources: Office of Management and Budget, Analytical Perspectives, 2001 & 2008, Tables 5-1 & 19-1.

The Alternative Fuel Production Credit was initiated with the passage of the Windfall Profit 

Tax of 1980 (Public Law 96-223). It was originally codified in the Code as Section 44(d), but it 

was later recodified as Section 29. The alternative fuel credit is production-based. At $2.4 

billion, it is estimated to be the second largest energy-related tax expenditure in FY 2007. The 

credit was designed to encourage the production of domestic energy from certain 

unconventional sources to reduce the Nation’s dependence on energy imports. Barring its 

extension, which has occurred a number of times in the past, the value of this credit is expected 

to decline to about $10 million in 2009 and then disappear. In EIA’s 1999-2000 subsidy reports, 

the primary beneficiaries of this tax expenditure were coalbed methane producers. However, 

coalbed methane’s eligibility for the credit expired December 31, 2002. Refined coal is now the 

largest beneficiary of this tax expenditure. Refined coal was defined in Section 710 of the 

American Jobs Creation Act of 2004 (AJCA) (Public Law 108-357). Prior to defining refined coal 

in the AJCA, the Section 29 credit was applied to synthetic fuels, one of which used coal as a 

fuel stock.43

Other smaller tax credits affecting the coal sector include: 

The Credit for Investment in Clean Coal Facilities was added to the Code with EPACT2005, 

Section 1307. This credit has an estimated value of $30 million in FY 2007. A 20-percent credit 

is applied to coal gasification a project using integrated gasification combined-cycle (IGCC) 

technology and a 15-percent credit is applied to other advanced coal technologies. The credit is 

 

43 As a result of the AJCA, Section 29 was moved into Section 45(k), which defines refined coal as: 

 

a liquid, gaseous, or solid synthetic fuel produced from coal (including lignite) or high carbon fly ash, including 

such fuel used as a feedstock, (ii) is sold by the taxpayer with the reasonable expectation that it will be used 

for purpose of producing steam, (iii) is certified by the taxpayer as resulting (when used in the production of 

steam) in a qualified emission reduction, and, (iv) is produced in such a manner as to result in an increase of at 

least 50 percent in the market value of the refined coal (excluding any increase caused by materials combined 

or added during the production process), as compared to the value of the feedstock coal. 

Refined coal must meet certain emission reductions. Qualified emission reduction means a reduction of at least 20 percent of the 

emissions of nitrogen oxide and either sulfur dioxide or mercury released when burning the refined coal (excluding any dilution 

caused by materials combined or added during the production process), as compared to the emissions released when burning the 

feedstock coal or comparable coal predominantly available in the marketplace as of January 1, 2003. Prior to the AJCA, under 

Section 29, coal was deemed eligible for the credit if the refining process produced a "significant chemical change." 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

18 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

capped at $1.3 billion of which $800 million is allocated towards electricity-related IGCC 

projects and $500 million towards other advanced coal technologies. An additional $350 million 

is applied to coal gasification technologies for industrial use. 

The Capital Gains Treatment of Royalties on Coal Credit was established with the 1951 

Revenue Act (Public Law 82-183, Section 177 (j) and Section 117 (k)). The estimated value of 

this credit in FY 2007 was $170 million. 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. 

The Exclusion of Special Benefits for Disabled Coal Miners in the Department of Labor, 

Health and Human Services, and Education and Related Agencies Appropriation Act, 1986, 

(Public Law 99-178) allows for the payment of medical-related travel expenses. This 

expenditure involves payments to disabled miners out of the Black Lung Trust Fund. These 

benefits are 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 $50 million in FY 2007. 

The Expansion of Amortization for Certain Atmospheric Pollution Control Facilities in 

Connection with Plants Placed in Service After 1976 was added with EPACT2005, Section 

1309. This provision modifies Section 169 of the Code, which permitted a 60-month 

amortization of qualifying pollution control facilities used in connection with plants placed in 

service before January 1, 1976. The modification extends the amortization period to 84 months 

and eliminates the applicability of the provision to plants placed in service prior to the end of 

1975. The revised amortization period is now applicable to qualifying pollution control facilities 

placed in service after April 11, 2005. The JCT estimated the value of this expenditure to be 

$30 million for FY 2007. 

The Partial Expensing of Mine Safety Equipment Section 404 of the Tax Relief and Welfare 

Act of 2006 (Public Law 109-432) allows qualified mine safety equipment to be expensed rather 

than capitalized. Its value for FY 2007 is estimated at $10 million. 

Electricity Transformation-Related Tax Expenditures

Overall, it is estimated that the electric power industry tax expenditures in FY 2007 have a value 

of $735 million (Table 3). For purposes of this report, electricity-related tax expenditures include 

those applicable to all segments of electricity production and delivery (i.e., generation, 

transmission, and distribution of electricity), but not of the fuel used to produce electricity. 

Seven tax expenditures were directed at electricity transformation during FY 2007. One tax 

expenditure, the exclusion of interest on bonds for certain energy facilities, traces its origins 

back to 1968. The six remaining tax expenditures were enacted in the AJCA and EPACT2005, 

which amended the Code to provide utilities with incentives to (1) make infrastructure 

investments in transmission and pollution control facilities and (2) engage in transactions that 

will increase the amount of transmission facilities subject to non-discriminatory open access 

transmission. 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.44 One tax expenditure, the credit for the production from advanced nuclear power 

 

44 Joint Committee on Taxation, "Description of the Technical Explanation of the Conference Agreement of H.R. 6, Title XIII, The 

Energy Tax Incentives Act of 2005," JCX-60-50 and JCX-59-05, July 28, 2005. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 19 

facilities, had no value in 2007, as this credit does not go into effect until qualifying new nuclear 

power plants produce electricity. 

The Deferral of Gain from Disposition of Transmission Property to Implement Federal 

Energy Regulatory Commission (FERC) Restructuring Policy is the largest tax credit 

directly affecting the provision of electricity, as opposed to an electricity-related fuel. This tax 

expenditure was provided for in Section 1305 of EPACT2005. The value of this deferral in FY 

2007 is estimated at $530 million. Tax deferrals are frontloaded benefits, which are offset in 

later years when the deferral reverses. The Treasury Department projects a $1.4 billion 

cumulative deferral between 2006 and 2008. The deferral begins to reverse in 2009, as 

reflected by projected net revenue loss of $104 million in 2009.45

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

Power Plants (EPACT2005, Section 1336) has an expected value of $90 million in FY 2007. 

EPACT2005 provides a 30-percent energy tax credit for the purchase of qualified fuel cells with 

a maximum of $500 for each 0.5 kilowatt of capacity. For qualified microturbine property, the 

nameplate capacity must be less than 2000 kilowatts and the electricity-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. 

The Exclusion of Interest on Bonds for Certain Energy Facilities was established by the 

Revenue Expenditure and Control Act of 1968 (Public Law 90-364), which exempts from 

Federal income tax interest on private activity bonds issued by State or local governments to 

finance certain energy facilities. Private activity bonds may be used to finance a variety of 

infrastructure projects such as airports, port facilities, and public housing, as well as facilities for 

the local provision of electricity and natural gas. The IRS determines the maximum amount that 

each State may issue annually through a solicitation process. The States determine which 

eligible projects may issue bonds from their respective allocations. The Treasury has estimated 

that the value of this expenditure is $40 million in FY 2007. 

The Credit for the Production of Advanced Nuclear Generation was established under 

EPACT2005 (Section 1306) and has no value in FY 2007 due to the fact that no nuclear power 

plants are currently under construction. Over the Treasury Department’s 2007 through 2012 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 a 

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 Transmission Property Treated as 15-Year Property set forth in Section 1308 of 

EPACT2005 modifies 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 

 

45 A negative value for tax expenditures indicates that the Treasury actually gains more revenue than it would have in the absence 

of the tax expenditure. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

20 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

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. For FY 2007, the estimated value of 

accelerating the recovery period by 5 years is $18 million. 

Table 3. Electricity Transformation-Related Tax Expenditures (million 2007 dollars) 

Tax Expenditure Type FY 1999 FY 2007 

Deferral of Gain from Dispositions of Transmission 

Property to Implement FERC Restructuring Policy Deferral - 530 

Credit for Business Installation of Qualified Fuel Cells and 

Stationary Microturbine Power Plants Credit - 90 

Credit for Production from Advanced Nuclear Power 

Facilities Credit - - 

Exclusion of Interest on Bonds for Certain Energy 

Facilities Exemption 139 40 

Transmission Property Treated as 15-Year Property Expense 

Deduction - 18 

5-Year Net Operating Loss Carryover for Transmission 

Investment 

Enhanced Tax 

Attribute - 43 

Treatment of Certain Electric Cooperative Income Exemption - 14 

Total 139 735 

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

Sources: Office of Management and Budget, Analytical Perspectives of the United States Budget Fiscal 

Year 2001 and 2008, Tables 5-1 and 19-1, respectively. Joint Committee on Taxation, "Description of the 

Technical Explanation of the Conference Agreement of H.R. 6, Title XIII, The Energy Tax Incentives Act of 

2005," JCX-60-50 and JCX-59-05, July 28, 2005.

The Five-Year Net Operating Loss Carryover for Electric Transmission Equipment 

(EPACT2005, Section 1311) allows 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.46 The 5-year 

carryover applies to losses included in 2003, 2004, and 2005. Regardless of the taxable year in 

which an eligible NOL arose, refund claims resulting from the extended carryover period can be 

made during any taxable year ending after December 31, 2005, and before January 1, 2009. 

The refund claimed during any one taxable year may not exceed the amount of the electric 

utility company’s investment in electric transmission property and pollution control facilities. The 

amount of an 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. 

The estimated value of this tax benefit for FY 2007 is $43 million. 

The Treatment of Income of Certain Electric Cooperatives (EPACT2005, Section 1304)

was enacted in the AJCA, Section 319. It contained a sunset provision, which would have 

applied in all years after December 31, 2006. Section 1304 of EPACT2005 eliminated the 

sunset provision. The provision applies to tax-exempt electric cooperatives that are organized 

under Section 501(c) (12) of the Code. Among the requirements to qualify for tax-exempt status 

is the 85-percent test. The 85-percent test provides that in order to qualify for tax-exempt status 

 

46 Carryback refers to the practice of using an NOL from taxable income for a prior tax period. Carryforward refers to using an NOL 

in a future taxable period. Normally, a taxpayer is permitted a 2-year carryback and a 20-year carryforward for NOLs to reduce 

taxable income during the carryback and carryforward period. NOLs must be applied on a first-in-first-out basis. NOLs expire if they 

are not used within the applicable periods. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 21 

a cooperative may receive no more than 15 percent of its income from business conducted with 

non-members (i.e., at least 85 percent of income must come from conducting business with 

members). It is a "bright-line" test. FERC Policy requires Regional Transmission Organizations 

(RTOs) and Independent System Operators (ISOs) to be independent of market participants. 

Consistent with the requirement, the cost of, and the charges for, use of facilities placed under 

the operational control of an RTO/ISO are administered under the RTO/ISO’s FERC-approved 

tariff. Therefore, if an exempt cooperative were to join an RTO/ISO, transmission-related 

income received from members would be reclassified as non-member income received from the 

RTO/ISO for purposes of computing the 85-percent test, potentially resulting in the loss of taxexempt status. Similarly, any income from transmission and ancillary services a cooperative 

might provide voluntarily to a non-member would be classified as non-member income. The 

amendment to Section 501(c)(12) also excludes non-member income a cooperative may 

receive from providing transmission service under a nondiscriminatory open access tariff for 

purposes of calculating the 85-percent test. The provision also allows cooperatives to exclude 

nuclear decommissioning trust income, which is classified as non-member income for purposes 

of computing the 85-percent test. The JCT estimated the value of this tax expenditure at $14 

million for FY 2007. 

The Modification to Special Rules for Nuclear Decommissioning Costs (EPACT2005 

Section 1310). Section 1310 changes 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 permits 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 requires 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 2007, the estimated value of this tax expenditure is $199 

million. 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. While the 

discussion of this tax expenditure is included with other electricity-related tax expenditures, it is 

not reported in Table 3. It is included as a subsidy to nuclear fuel in Table 1 and in the estimate 

of subsidies by fuel type in Chapter 5. 

Renewable-Related Tax Expenditures 

Renewable-related tax expenditures in FY 2007 are estimated at $4.0 billion (Table 4). There 

were two tax expenditures directed at renewable-related electricity production and three nonelectricity related tax expenditures directed at transportation. 

Table 4. Renewable-Related Tax Expenditures (million 2007 dollars) 

Tax Expenditure Type FY 1999 FY 2007 

Excise Taxes/VEETC (ethanol fuel) Credit 921 2,990 

New Technology Credit Credit 61 690 

Biodiesel and Small Agri-Biodiesel Producer Tax Credit Credit - 180 

Credit for Holding Clean Renewable Energy Bonds Credit - 60 

Alcohol Fuel Credit Credit 18 50 

Total 1,000 3,970 

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

Sources: Office of Management and Budget, Analytical Perspectives of the United States Budget, Fiscal 

Years 2001 and 2008, Tables 5-1 and 19-1, respectively.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

22 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

The Volumetric Ethanol Excise Tax Credit (VEETC) was implemented with the American 

Jobs Creation Act of 2004 (Public Law 108-357, Title 3, Sections 301-302). It is estimated to be 

the largest energy-related tax credit in FY 2007. Its predecessor, the alcohol fuel excise tax 

exemption, was estimated to be the largest tax-related benefit in the 1999-2000 EIA subsidy 

reports. VEETC is directed at the production of transportation-related fuels. The alcohol fuels 

excise tax exemption first appeared in Section 221 of the Energy Tax Act of 1978 (Public Law 

95-618). This exemption was replaced in 2004 with VEETC by Section 301 of the AJCA. The 

AJCA extended the benefit through 2010. VEETC provides ethanol blenders/retailers with 51 

cents per pure gallon of ethanol or $.0051 per percentage point of ethanol blended in motor 

gasoline. The value of VEETC is estimated at $3.0 billion in FY 2007. By 2010, the value of this 

credit is expected to exceed $5 billion. 

The New Technology Credit is the next largest energy-related tax credit. The new technology 

credit is also known as the production tax credit (PTC).47 The new technology credit is 

estimated to be $690 million in FY 2007. By 2008, the new technology credit is expected to be 

both the second largest energy-related tax expenditure and the second largest renewable 

energy tax expenditure. Wind power is estimated to be the primary beneficiary of the credit in 

FY 2007. Other eligible energy sources include: closed and open-loop biomass facilities, 

geothermal, solar, municipal solid waste, landfill gas resources, certain hydroelectric facilities, 

and coal produced on Indian (Native American) lands. Initially, tax benefits for renewable 

generation were established in the Energy Tax Act of 1978 (Public Law 95-618) via a 10-

percent investment tax credit for solar, wind, geothermal, and ocean thermal technologies. 

The Biodiesel and Small Agri-Biodiesel Producer Tax Credit has an expected value of $180 

million in FY 2007. Section 313 of the AJCA created a $1-per-gallon credit for the sale of agribiodiesel fuel. The credit applies to "virgin" agricultural feedstock such as soybeans or 

cottonseed. A 50-cent credit is provided to biodiesel produced from recycled grease. The credit 

was due to expire at the end of 2006. Section 1344 of EPACT2005 extended the credit though 

the end of 2008. This is primarily a transportation-related tax expenditure. 

The Alcohol Fuel Credit is directed at the transportation sector. The alcohol fuel credit 

originated in the Crude Oil and Windfall Profit Tax of 1980 (Public Law 96-223). The credit has 

an estimated value of $50 million in FY 2007. 

The Credit for Holding Clean Renewable Energy Bonds was established in Section 1303 of 

EPACT2005. It provides for the issuance of Clean Renewable Energy Bonds (CREBs) through 

December 31, 2007. Taxpayers holding CREBs are entitled to a tax credit in lieu of interest 

payments from the bond issuer. Prior to passage of EPACT2005, only investor-owned utilities 

(IOUs) qualified to receive tax incentives for producing electricity from renewable energy 

resources. EPACT2005 placed an $800 million cap on the issuance of CREBs. CREBS allows 

non-IOU electricity providers to issue interest free bonds to finance qualified energy projects. 

The value of this tax credit is estimated at $60 million in FY 2007. 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, 2008.48

 

47 The new technology credit is a term defined by the Treasury Department. It appears in Office of Management and Budget, 

Analytical Perspectives of the United States Budget Fiscal, Year 2008, Table 19-1. 

48 The U.S. House of Representatives Ways and Means Committee: 

http://waysandmeans.house.gov/media/pdf/taxdocs/hr6408taxdetailedsummary.pdf, accessed October 16, 2007. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 23 

Natural Gas and Petroleum-Related Tax Expenditures

Of the 10 natural gas and petroleum-related tax expenditures identified, five are allocated to 

electricity production, one was not in effect in FY 2007, and three are primarily transportationrelated in FY 2007. The alternative fuel production credit applied to natural gas in FY1999 

(coalbed methane), but is now directed to refined coal, which for FY 20007 appears in Table 2. 

The total value of these tax expenditures is estimated at $1.8 billion in FY 2007 (Table 5). 

Table 5. Natural Gas and Petroleum-Related Tax Expenditures (million 2007 dollars)

Tax Expenditure Type FY 1999 FY 2007 

Expensing of Exploration and Development Costs Deferral (97) 860 

Excess of Percentage over Cost Depletion Deferral 321 790 

Amortization All Geological and Geophysical 

Expenditures over 2 Years Deferral - 60 

Natural Gas Distribution Pipelines Treated as 15-Year 

Property Deferral - 50 

Exception from Passive Loss Limitation for Working 

Interests in Oil and Natural Gas Properties Deferral 36 30 

Temporary 50-Percent Expensing for Equipment Used in 

the Refining of Liquid Fuels Deferral - 30 

Expensing of Capital Costs with Respect to Complying 

with EPA Sulfur Regulations Deferral - 10 

Enhanced Oil Recovery Credit 273 - 

Alternative Fuel Production Credit Credit 1,242 - 

Credit and Deduction for Clean Fuel Vehicles Credit 103 260 

Total 1,878 2,090 

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

Sources: Office of Management and Budget, Analytical Perspective of the United States Budget, Fiscal 

Years 2001 and 2008, Table 5 and 19-1. 

The Expensing of Exploration and Development Costs Deferral originated in 1916. 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. The most important of these expenditures consist of intangible drilling costs 

associated with oil and natural gas investments. In FY 2007, this tax expenditure is estimated at 

$860 million. 

The Excess of Percentage over Cost Depletion Deferral dates back to World War I. 

Depletion on a discovery basis became an accepted practice between 1918 and 1926. 

Percentage depletion for oil and natural gas properties became law with the passage of the 

1926 Revenue Act. Under cost depletion, the annual deduction is equal to the non-recovered 

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 2007, the value of this tax expenditure is estimated at 

$790 million. 

The Tax Credit and Deduction for Clean-Fuel, Alternative Fuel, and Electric Vehicles was 

initiated with Section 1913 of the Energy Policy Act of 1992 (EPACT1992, Public Law 108-486). 

EPACT 1992 provided an electric vehicle (EV) tax credit for up to 10 percent of the vehicle cost 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

24 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

(capped at $4,000) for purchases of qualified EVs and hybrid-electric vehicles (HEVs). Section 

1913 also provided a tax deduction of $2,000 for alternative fueled vehicles (AFVs) up to 

$2,000 for light-duty vehicles (LDVs), and $5,000 to $50,000 for medium-duty vehicles (MDVs) 

and heavy-duty vehicles (HDVs). Section 1341 of EPACT2005 provides tax credits for fuel cell 

vehicles of $8,000 to $40,000, and advanced lean-burn technology vehicles (limited to LDVs) 

and hybrid motor vehicles of up to $3,400. The value of the tax credit is estimated at $260 

million in FY 2007. 

The Amortization of all Geological and Geophysical Expenditures Over 2 Years 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 $60 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. 

The Natural Gas Distribution Pipelines Treated as 15-Year Property Deferral was 

established by EPACT2005 (Section 1308) and is estimated to have a value of $50 million in FY 

2007. Section 1308 accelerates the recovery period for natural gas distribution lines from 20 

years to 15 years. 

The Exception from Passive Loss Limitation for Working Interest in Oil and Natural Gas 

Properties Deferral was established with the Tax Reform Act of 1986 (Public Law 99-519). 

The value of this tax credit in FY 2007 is estimated at $30 million. 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 passive income in future years. The exception from passive 

loss limitation provisions 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 was established by Section 1323 of EPACT2005. It is estimated to be $30 million in 

FY 2007. It is a transportation fuel subsidy. 

The Expensing of Capital Costs with Respect to Complying with Environmental 

Protection Agency Sulfur Regulations Deferral was provided for in Section 1324 of 

EPACT2005. It allows small refiners to deduct 75 percent of qualified capital costs related to 

complying with EPA sulfur regulations. The estimated value of this tax expenditure is $10 million 

in FY 2007. Section 1324 is a transportation fuel subsidy. 

The Enhanced Oil Recovery Credit enables taxpayers to claim a general business credit for 

enhanced oil recovery (EOR) investment. The credit was provided by Section 11511 of the 

Omnibus Budget Reconciliation Act of 1990 (Public Law 101-508). The EOR credit applies to 

15 percent of the cost of one or more tertiary recovery methods. EOR involves the extraction of 

the 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) or $39 per barrel (in 2007 dollars) in the preceding year. Due to the average price of oil 

in 2007 being above the cap, the value of this credit was zero in FY 2007. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 25 

The Alternative Fuel Production Credit was established with the Windfall Profits Tax of 1980 

(Public Law 96-223). The credit did not impact natural gas or petroleum-related expenditures in 

2007, as the credit went mostly to producers of coalbed methane and natural gas from 

unconventional sources, whose eligibility expired at the end of 2002. The credit did, however, 

have an effect on refined coal production in 2007 (see Table 2). 

The Credit for the Deduction of Clean Fuel Vehicles was established with the Clean Air Act 

Amendments of 1990 (CAAA90) (Public Law 101-549) and the Energy Policy Act of 1992 

(EPACT1992) (Public Law 102-486), which mandated that vehicle fleets owned by fuel 

providers and State governments, as well as certain vehicle fleets operating in air quality 

nonattainment areas, gradually acquire and use low-emission vehicles in increasing 

percentages through the year 2010. The value of the credit was ascribed by EIA to 

transportation in 2007. 

Energy Efficiency and Conservation-Related Tax Expenditures 

EPACT2005 contained a number of provisions that are designed to promote energy 

conservation. One conservation-related tax expenditure dates back to EPACT1992. The 

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. 

Conservation-related tax expenditures are estimated at $790 million in FY 2007 (Table 6).

The Credit for Energy-Efficiency of Existing Homes (EPACT2005, Section 1333) has an 

estimated value of $380 million in FY 2007. This credit applies to windows, furnaces, boilers, 

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

appropriated pigmented coatings. The credit is available to houses constructed before 

December 31, 2007. 

The Credit for Efficient Appliances (EPACT2005, Section 1334) has an estimated value of 

$80 million in FY 2007. Appliance manufacturers receive a tax credit for manufacturing energyefficient dishwashers, clothes washers, and refrigerators. The credits apply to appliances 

manufactured between December 31, 2005, and January 1, 2008. The tax credit is limited to 2 

Table 6. Conservation, Efficiency, and End-Use Tax Expenditures (million 2007 dollars) 

Tax Expenditure Type FY 1999 FY 2007 

Credit for Energy-Efficiency Improvements of Existing 

Homes Credit - 380 

Allowance of Deduction for Certain Energy-Efficient

Commercial Building Property Deduction - 190 

Exclusion for Utility-Sponsored Conservation Measures Exclusion 103 110 

Credit for Energy-Efficient Appliances Credit - 80 

Credit for Construction of New Energy-Efficient Homes Credit - 20 

Pass Through Low-Sulfur Diesel to Cooperative Owners Credit - - 

30-Percent Credit for Residential Purchases/Installations 

of Solar and Fuel Cells Credit - 10 

Total 103 790 

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

Sources: Office of Management and Budget, Analytical Perspectives of the United States Budget Fiscal 

Years 2001 and 2008, Tables 5-1 and 19-1, respectively; and, Joint Committee on Taxation, “Description 

of the Technical Explanation of the Conference Agreement of H.R.6, Title XIII, The Energy Tax Incentives 

Act of 2005,” JCX-60-05 and JCX 59-05, July 22, 2005. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

26 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

percent of the gross revenue for the 3 taxable years prior to the taxable year in which the credit 

occurs. 

The Allowance of Deduction for Certain Energy-Efficient Commercial Building Property

was established with EPACT2005 (Section 1331). Taxpayers are permitted to take a deduction 

of $1.80 per square foot 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 and Air Conditioning Engineers (ASHRAE). The 

value of this credit is estimated at $190 million for FY 2007. Section 201 of The Tax Relief and 

Health Care Act of 2006 extended the credit to December 31, 2008. 

The Credit for Construction of New Energy-Efficient Homes was established by 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 $20 million for FY 2007. Initially, the credit was 

available to houses constructed before December 31, 2007. The eligibility window was 

extended to December 31, 2008, in the Tax Relief and Health Care Act of 2006. 

The Exclusion for Utility-Sponsored Conservation Measures 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 

individual consumers receive 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 $110 million for FY 2007. 

The 30-Percent Credit for Residential Purchases/Installations of Solar and Fuel Cells has 

an estimated value of $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). 

Alcohol and Biofuels Tax Provisions 

At $3.2 billion in 2007, Federal government support of alcohol fuels is estimated to be the 

largest energy-related tax expenditure for 2007. In 2006, ethanol accounted for 6 percent of 

U.S. energy consumption. Currently, the United States is the world’s largest producer of ethanol 

in the world, having surpassed Brazil in 2005. (Unlike corn-based U.S. ethanol production, 

sugarcane is the primary feedstock for Brazilian ethanol production.) Support for alcohol fuels 

originated in the Energy Tax Act of 1978. Subsequently, at least seventeen pieces of legislation 

have been directed at this fuel (Table 7). Currently, there are three ethanol-related tax 

expenditures.49

 

49 The Federal government also promotes ethanol production through mandatory blending of ethanol with gasoline. EPACT2005 

included a Renewable Fuels Standard that required that 4 billion gallons of renewable fuel be blended with gasoline in 2006, 

increasing to 7.5 billion gallons in 2012. The Energy Independence and Security Act of 2007 increased the volumes of renewable 

fuels to be blended with gasoline to 9 billion gallons in 2008, increasing to 36 billion gallons in 2022. Ethanol production is also 

supported by a 54-cent-per-gallon tariff on imported ethanol, exclusive of ethanol produced by countries participating in the 

Caribbean Basin Initiative. The tariff is slated to be lifted on December 31, 2008. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 27 

The Volumetric Ethanol Excise Tax Credit (VEETC) was established by the Energy Tax Act 

of 1978, which allowed for a 4-cent-per-gallon exemption from excise taxes for motor fuels that 

contained a minimum of 10-percent biomass-derived alcohol. Subsequent legislation both 

raised and lowered this exemption. In 2004, this exemption was replaced by AJCA Section 301. 

The AJCA replaced the excise tax exemption with VEETC and extended the benefit through 

2010. The VEETC is available to ethanol blenders and is equal to an amount of 51 cents per 

gallon of ethanol blended with gasoline based upon the volume of ethanol, not on the blend 

rate. The value of this expenditure in FY 2007 is estimated at $3 billion. 

The Biodiesel and Small Agri-Biodiesel Producer Tax Credit was included in the AJCA. It 

provides a $1-per-gallon credit for the sale of agri-biodiesel fuel. Section 313 of the Act applies 

the credit to "virgin" agricultural feedstock such as soybeans or cottonseed. A 50-cent credit 

was provided to biodiesel produced from recycled grease. Initially, the credit was due to expire 

at the end of 2006. EPACT2005 extended the credit though 2008. The value of this tax 

expenditure is estimated at $180 million for FY 2007. 

The Alcohol Fuel Credit is the third tax expenditure for ethanol production. This tax 

expenditure originated in the Crude Oil Windfall Profit Tax Act of 1980 (Public Law 96-223), 

which introduced an alcohol fuel blenders’ tax credit. This credit was made available to blenders 

and to users or retail sellers of straight alcohol fuels. The credit was initially 40 cents per gallon

for alcohol that was at least 190 proof and 45 cents per gallon for alcohol that was between 150 

and 190-proof. The credit was available through December 31, 1992. The Deficit Reduction Act 

of 1984 (Public Law 98-369) increased the credit from 40 cents to 60 cents per gallon of blend 

for 190-proof alcohol. The Transportation Efficiency Act of the 21st Century of 1998 (Public Law 

105-178) extended the credit through 2007 and reduced its value to 51 cents per gallon. This 

tax credit was not used to any significant degree until 2007. In FY 2007, it amounts to about 

$50 million. Blenders generally use the excise tax exemption rather than the tax credit, because 

the excise tax exemption provides them with an immediate cash flow. When used, this credit is 

offset by the VTEEC described above. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

28 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

Table 7. Laws Promoting Ethanol as a Transportation Fuel 

Public 

Law Name Provisions 

95-618 Energy Tax Act of 1978 

Exempted 10-percent ethanol/gasoline blends from the 4-cents-

Federal gasoline excise tax. Provided 10-percent of the energy credit for biomass-ethanol conversion equipment. 

96-126 Interior & Related Agencies Appropriation Act of 1980 Provided grants for the economic feasibility of commercial-scale 

production and cooperative agreements. 

96-223 Crude Oil Windfall Tax Act of 1980 Extended ethanol excise tax exemption through 1992. Establish

gallon tax credit for ethanol fuel use. 

96-294 Energy Security Act of 1980 Authorized loan guarantees for ethanol production facilities. 99-499 Omnibus Reconciliation Tax Act of 1980 Placed a 54-cent-per-gallon tariff on imported ethanol.96-304 Supplemental Appropriation & Rescission Act of 1980 Provided additional grants for feasibility studies and cooperative 97-424 Surface Transportation Assistance Act of 1982 Raised excise tax exemption for 10-percent ethanol blends to 5-98-369 The Deficit Reduction Act of 1984 Raised the excise tax exemption for 10-percent ethanol/gasoline 

cents-per-gallon and the ethanol tax credit to 60-cents-per-gallo

100-494 Alternative Motor Fuels Act of 1988 Enacted Corporate Average Fuel Economy credits for alternativ

100-647 Technical and Miscellaneous Revenue Act of 1988 Liberalized the excise tax rule. 101-508 Omnibus Budget Reconciliation Act of 1990 

Reduced ethanol excise exemption to 5.4 cents per gallon; redu

credit to 54 cents per gallon. Extended ethanol fuel tax incentiveEstablished small ethanol producers’ tax credit of 10 cents per g

101-549 Clean Air Act Amendments of 1990 

Mandated winter use of oxygenated fuels in 39 nonattainment amonoxide (where EPA emissions standards for carbon dioxide h

met); required year-round use of oxygenates in 9 severe ozone areas in 1995. 

102-486 Energy Policy Act of 1992 

Modified excise tax exemption to accommodate blends of less t

ethanol resulting from more sophisticated blending strategies focontrol. Tax exemption was set at 4.2-cents-per-gallon for mixtu7.7-percent ethanol and 3.1-cents-per-gallon for mixtures contaethanol. 

105-178 Transportation Equity Act for the 21st Century of 1998 Extended ethanol tax incentives thru 2007. Reduced value of th

5.1-cents-per-gallon and the tax credit to 51 cents per gallon. 

108-357 The American Jobs Creation Act of 2004 Extended ethanol subsidies through 2010 and introduced VEET109-58 Energy Policy Act of 2005 See Appendix C. 110-140 Energy Independence and Security Act of 2007 

Expands existing biofuels programs including increasing the vol

alternative fuels blended with gasoline. Requires 36 billion galloby 2022. 

Source: Library of Congress, http://thomas.loc.gov/ 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 29 

Section 29: The Alternative Fuel Production Credit 

The Alternative Fuel Production Credit (IRC Section 29) was established by the Windfall Profit 

Tax of 1980 (Public Law 96-223) and became operational in the same year. The credit applied 

to qualified fuels from wells drilled or facilities placed in service between January 1, 1980, and 

December 31, 1992. Production from qualifying wells could receive the credit for volumes 

produced through December 31, 2002. Thus, producers operating qualifying wells or facilities 

were eligible for credits over a period of not less than 10 years or more than 22 years. The 

initial qualified fuels were: 

• oil produced from shale and tar sands; 

• natural gas from geopressurized brine, Devonian shale, coal seams, tight 

formations, and biomass; 

• liquid, gaseous, or solid synthetic fuels produced from coal; 

• fuel from qualified processed formations or biomass; and 

• steam from agricultural products. 

The principal changes that have occurred since 1980 include extending the qualifying in-service 

date for wells and other alternative fuel production facilities and the types of fuel that are eligible 

for the credit. The initial January 1, 1980, and December 31, 1992, qualification period has 

been extended several times by subsequent legislation. In 1989, legislation allowed a 1-year 

extension of the time limits. The Omnibus Budget Reconciliation Act of 1990 (Public Law 101-

508) provided an additional 2-year extension. The 1990 Act also eased the qualifying 

requirements for natural gas produced from tight sands after 1990. The qualification has at 

times been sharply constrained by Executive Branch rulings and judicial decisions. However, 

EPACT1992 extended the placed-in-service deadline for synfuel facilities. For synfuel facilities 

placed in service after December 31, 1992, and before July 1, 1998, the credit can continue to 

be claimed for qualifying synfuel sold through December 31, 2007. Due to favorable private 

letter rulings (PLR) issued by the IRS in the late 1990s, an increasing number of coal synfuel 

facilities claiming the credit came into existence. By the beginning of 2007, 59 qualifying coal 

synfuel plants were producing about 140 million tons of coal synfuel per year. All of these 

plants meet the placed-in-service window of December 31, 1992, to July 1, 1998 and, therefore, 

are eligible for the credit through 2007. Because the credit expires for all of these facilities at 

the end of 2007, it is anticipated that most, if not all, of the 59 plants operating in 2007 will have

shut down at the end of 2007. 

The tax credit for nonconventional fuels is $3.00 (1979 dollars) per barrel of oil equivalent 

produced.50 The credit is fully effective when the price of crude oil is less than $55.06 (2006 

 

50 All prices as well as the credit are specified in 1979 dollars, but for actual use they are indexed for inflation relative to that base. 

Conversion factors are used to convert the various fuels into their crude oil equivalent for purposes of calculating the credit. 

The formula for calculating the credit for 2006 is as follows: ($3.00*2.3429)*[($59.68-($23.50*2.2349))/($6.0*2.2349))] = $2.31. 

Where: 

• the benchmark oil price is $59.68, the first purchase price of crude in 2006; 

• the Section 29 credit is $3 per barrel oil equivalent (1979 dollars); 

• the inflation adjustment factor for 2006 is 2.3429; 

• the upper factor cap is $6, which is adjusted for inflation, and 

• the inflation factor for 2006 is 2.3429. 

• the $2.31 is subtracted from the unadjusted tax credit of $7.03 per barrel of oil equivalent to produce. 

the adjusted tax credit for 2006 is $4.72. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

30 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

Sources: Energy Information Administration, Quarterly Coal Report JulySeptember 2007, DOE-EIA-0121 (2007/3Q) (Washington, DC, 2007) and prior 

editions starting with 2002 fourth quarter report.

dollars) per barrel and phases out gradually as the price rises to $69.12 in 2006 dollars51. The 

credit is reduced if the taxpayer receives certain other energy subsidies such as government 

grants and tax-exempt financing. Per IRS instructions, the credit is calculated in current dollars 

using the Commerce Department gross national product (GNP) implicit price deflator for the 

calendar year. In 2006, the maximum credit was $3 times 2.3429 or $7.03 per barrel of oil 

equivalent. For typical bituminous coal with 24 million Btu, the maximum credit for a ton of coal 

synfuel was the quotient of 24 million Btu and 5.8 million Btu times $7.03 or $29.08. The IRS 

defines a barrel of oil equivalent to mean an energy content of 5.8 million British thermal unit 

(Btu). The credit varies as actual coal Btu content varies relative to the 5.8 million Btu value. 

The credit in 2006 is reduced when the price of oil (average wellhead price for all domestic 

crude oil) exceeds $55.06 per barrel. 

Figure 1. Coal Delivered and Used in Refined Coal Production, 

Fiscal Year 2002 to 2007 

For 2006, the Department of 

Energy (DOE) published an 

average wellhead price for 

all domestic crude oil of 

$59.68 per barrel, which 

reduced the 2006 credit to 

$19.53 per ton (assuming 24 

million Btu per ton). In the 

middle of 2006, some coal 

synfuel plant operators 

incorrectly anticipated that 

rising oil prices would wipe 

out the entire credit, and 

they reacted by shutting 

down some operations, 

leading to a decline in 

synfuel plant output (Figure 

1). 

The credit expired for coalbed methane at the end of 2002. Credits for synthetic coal, landfill 

gas, and coke and coke oven gas were still in effect in 2007, but the synthetic coal credit for the 

59 qualifying synfuel plants expired at the end of 2007. Most synthetic coal projects are owned 

by institutional investors such as insurance companies, banks, utilities, and large corporations 

with substantial net revenues against which the tax credits can be taken. Between 2002 and 

2007, synthetic coal production nearly doubled (Figure 1). Production fell between 2005 and 

2006 when high oil prices caused some plant operators into shutting down their facilities for part 

of the year. 

 

Source: U.S. Internal Revenue Service, Notice 2007-38; 2007-18 I.R.B. 1103 (2007), Nonconventional Source Fuel Credit, Section 

45K Inflation Adjustment Factor and Section 45K Reference Price (Washington, DC, April 30, 2007). EIA first published data on 

synthetic coal production in 2001. 

51 The value of the credit is provided in this report in 2007 dollars based upon an estimate of the 2007 GNP implicit price deflator. 

At the time of this estimate, applicable IRS oil price band data were unavailable. 

0 25,000 50,000 75,000 100,000 125,000 150,000

2002

2003

2004

2005

2006

2007

Thousand Short Tons

Delivered Used in Production
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 31 

The American Jobs Creation Act of 2004 (AJCA, Section 710, Public Law 108-357) introduced 

additional criteria for facilities producing synthetic (also referred to as "refined coal").52 Under 

AJCA, qualifying facilities must meet two tests applicable to environmental performance and 

economic value: (1) a qualifying facility must achieve a 20-percent reduction in the emissions of 

nitrogen oxides and either sulfur dioxide or mercury compared to the emissions released when 

burning the original feedstock coal or comparable coal; and, (2) the refined coal product must 

be at least 50 percent higher in economic value than the feedstock. Under AJCA, new facilities 

placed in service after October 22, 2004, and prior to January 1, 2009 qualify for the tax credit if 

they meet the tests outlined in the previous paragraph. Qualified refined coal facilities are 

eligible to receive a tax credit for the first 10 years of operation. Compared to Section 29 

guidelines, which expired at the end of 2007, the AJCA guidelines for qualifying facilities are 

more restrictive. Thus far, no facilities are receiving the refined coal credit. 

Section 1322 of EPACT2005 moved Section 29 to Section 45 as a new section 45K. Section 

45K allows old Section 29 credits to be combined with other general business credits. As an 

alternative fuel product credit, it may be carried forward 20 years and carried back one year. 

Section 1321 of EPACT2005 expanded the credit to coke and coke gas produced in certain 

facilities placed in service before January 1, 2010. The credit for coke or coke gas is $3.00 per 

barrel of oil equivalent, indexed for inflation using 2004 as the base year with a credit-available 

production limit of an average barrel-of-oil equivalent of 4,000 barrels per day. Section 211 of 

the Tax Relief and Heath Care Act of 2006 removed the phase-out provision for coke and coke 

gas. 

New Technology Credit 

The new technology credit promotes electricity production from renewable resources. 

The new technology credit is also referred to as the section 45 credit because it is 

codified in Section 45 of the Code. Renewable generating sources include conventional 

hydropower, wind, geothermal, biomass,53 and solar thermal and photovoltaic energy. 

The primary energy sources for renewable generation tend to be intermittent (e.g., 

dependent on weather conditions). Renewable energy, excluding conventional 

hydropower, is a fairly new contributor to U.S. electricity supply. The electric power sector 

accounted for about 56 percent of renewable energy consumption in 2006.54 Because of 

the intermittent nature of many forms of renewable generation, the per-unit production 

cost tends to be higher than conventional forms of generation that operate at higher 

capacities. This is exacerbated by the higher capital costs associated with emerging 

renewable generation technologies.55 This differential has decreased over time. 

Renewable generating capacity has grown considerably over the last 4 decades (Table 

8). Non-hydro renewables accounted for 3 percent of electricity production in 2006. EIA’s 

Annual Energy Outlook 2008 (Revised Early Release) projects nonhydroelectric 

renewables to account for 7 percent of electricity production by 2030.56

Renewable technologies, however, are acknowledged to have favorable environmental 

attributes (or fewer negative externalities) relative to conventional technologies; these include 

 

52 Although the terms "synthetic" and "refined" have been defined somewhat differently in various legislative provision, they are 

used interchangeably in this report. 

53 Biomass includes wood/wood waste, biogenic municipal solid waste (MSW), landfill gas (LFG), agricultural byproducts/crops, 

sludge waste, and other biomass solids, liquids, and gases. 

54 Energy Information Administration, Annual Energy Review 2006, DOE/EIA-0384(2006) (Washington, DC, June 2007), p. 281. 

55 Capital costs include the cost of field development, plant construction, and plant equipment. 

56 Energy Information Administration, Annual Energy Outlook 2008 (Revised Early Release), DOE/EIA-0383 (2008) (Washington, 

DC, March 2008), Table 8 and Table 16, http://www.eia.doe.gov/oiaf/aeo/index.html. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

32 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

low or zero emissions and a replenishable energy supply.57 Over the years, incentives and 

mandates for renewable energy have been used to advance different energy policies, such as 

ensuring energy security or promoting environmentally benign energy sources.58

Tax incentives directed toward nonconventional electric generation originated with the Energy 

Tax Act of 1978 (Public Law 95-618), which established a business energy tax credit of 10 

percent of investment in technologies such as solar, wind, geothermal, and ocean thermal. This 

was in addition to an existing standard 10-percent investment tax credit available to related 

technologies. The Tax Reform Act of 1986 (Public Law 99-514) eliminated the standard 10-

percent investment tax credit and extended the energy tax credit to 1988, but it reduced that 

credit from 15 percent to 10 percent and eliminated wind as a candidate for any credits. 

The business tax credit was extended on a year-to-year basis until passage of EPACT1992. 

The term "new technology credit" was first introduced as part of EPACT1992 when it became a 

production tax credit. It was defined as a 1.5-cents-per-kilowatthour payment (adjusted annually 

 

57 Attempts to measure the value of such benefits and add them to the market price by regulatory fiat (known as "full-cost pricing") 

have been proposed but not implemented in the United States. Recently, some States have instituted Renewable Energy 

Certificate/Credit programs that monetize these environmental attributes. 

58 Energy Information Administration, Renewable Energy 2000: Issues and Trends, "Incentives, Mandates, and Government 

Programs for Promoting Renewable Energy," DOE/EIA-0628(2000) (February 2001, Washington, DC), pp. 1-17. 

Table 8. U.S. Renewable Fuels Electricity Generating Capacity 

(Gigawatts) 

Fuel 1970 1980 1990 2000 2006 2007 

Conventional 

Hydroelectric

64 82 74 79 78 78 

Other 

Renewables 

(subtotal)

NA NA 13 16 24 27 

Wood NA * 6 6 6 6 

Waste NA NA 3 4 4 4 

Geothermal * 1 3 3 2 2 

Solar/PV NA NA * * * * 

Wind NA NA 2 2 11 15 

Total 64 83 87 95 102 105 

NOTE: Total may not equal sum of components due to independent rounding. 

The capacity values for 2007 are an EIA estimate based on renewable capacity additions 

reported for calendar year 2007 on the EIA, Form 860-M, “Monthly Update to the Annual 

Electric Generator Report.” 

NA=Not Available. 

* Indicates less than .5 gigawatts of capacity. 

Source: Energy Information Administration Annual Energy Review, 2006, DOE/EIA-0384 

(Washington, DC, June 2007) Table 8.11a; Energy Information Administration, Electric 

Power Monthly, Historical Excel Tables, February 2008, 

http://www.eia.doe.gov/cneaf/electricity/epm/epm_ex_bkis.html 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 33 

for inflation), available for 10 years to private investors, as well as to investor-owned electric 

utilities. The credit applied to electricity produced from wind and closed-loop (dedicated crops) 

biomass facilities placed in service between 1994 and June 30, 1999. 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 in-service 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 open-loop biomass, geothermal, solar, and small irrigation power facilities, the credit 

period was expanded from 5 to 10 years. 

Estimation of the Production Tax Credit 

In order to estimate the energy effects of the production tax credit and allocate those impacts to 

renewable fuel groups, qualified capacity at the generating unit level was identified through the 

end of FY 2007.AThe portion of qualified capacity at each plant was assumed to produce 

electricity in proportion to its share of total plant capacity. Capacity eligible to claim the credit 

was determined for all years through FY 2007 and grouped by renewable technology. 

Renewable capacity placed in service in 2007 was identified from the latest available monthly 

information compiled from EIA survey dataB and FY 2007 net generation was reported to EIA.C 

Applying the credit by technology type yields an estimate of the maximum credit which might be 

claimed by qualifying technology type. The credit shares for each technology type were applied 

to the Treasury Department’s FY 2007 $690-million estimated value for this tax expenditure to 

obtain an estimate for each technology (Table 9). With approximately 10 gigawatts of new 

capacity built or expected over the 3-year period ending in 2007, wind technology dominates 

the allocation of the credit, claiming about 97 percent of the total credit. Compared to wind, 

other major sources eligible for the credit saw relatively little incremental capacity additions 

during their eligibility window. Based on the reported wind generation for FY 2007, wind 

generators were eligible to claim at least an estimated $526 million in tax credits, significantly 

less than the estimated $666-million tax expenditure estimated by the Treasury Department, 

i.e., the value of credit used to reduce tax liability. One plausible explanation for the difference 

is that during the initial years of operation wind generators may be accumulating credits while 

incurring tax losses. This may occur because wind energy property has a 5-year life for tax 

depreciation purposes. Wind generators that have been in operation for more than 5 years, 

having fully depreciated their property for tax purposes, may now be realizing taxable income to 

which they are applying prior-period tax credits that they are permitted to carry forward. 

For purposes of this report, the subsidy estimates are based on the Treasury Department’s 

aggregate New Technology Credit estimated expenditures. EIA adopted the methodology 

described above to allocate the Treasury Department’s aggregate estimate of the New 

Technology Credit to specific technologies because of the lack of publicly-available financial 

data and tax-related data from which fuel-specific estimates could be derived. 

___________________________________ 

A

. Energy Information Administration, "Annual Electric Generator Report," Form EIA-860 (2006). 

B. Energy Information Administration, "Monthly Update to the Annual Electric Generator Report," Form EIA-860M (September 

2007). 

C. Energy Information Administration, "Power Plant Report," Form EIA-906, and "Combined Heat and Power Plant Report," Form 

EIA-920. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

34 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

Sources: Energy Information Administration, Form EIA-860, “Annual Electric Generator 

Report” (2006); Form EIA-860, “Monthly Update to Annual Electric Generator Report,” 

January-December, 2007; Form EIA-906, “Power Plant Report,” and Form EIA-920 

“Combined Heat and Power Plant Report,” January-December, 2007. 

The historical growth of wind generation, which correlates with the periods in which the PTC 

has been available to wind power producers, supports the method EIA used to allocate the 

estimated $690-million New Technology Tax credit to the various forms of renewable 

generation. Wind power has grown rapidly, especially since 1998 (Figure 2). 

Figure 2. Annual and Cumulative Wind Power Capacity Additions, 

1997-2007 (megawatts)

In part, this has been 

due to declining 

production costs, which 

has made wind more 

competitive as fuel costs 

have increased for 

conventional fossil-fired 

generation. In 2006, 

wind capacity increased 

at record levels both in 

terms of capacity 

additions and its share 

of total electricity 

production. 

Table 9. Fuel Allocation for New Technology Credit Fiscal Year 2007 Estimated Expenditure 

Renewable 

Technology 

 Estimated 

Qualified 

Capacity 

(Megawatts) 

 Estimated 

Eligible 

Generation (FY07 

Megawatthours) 

 Average 

Capacity 

Factor 

(percent) 

 Value of 

Credit (cents 

per 

kilowatthour) 

EIA Estimate 

Based on 

FY07 

Generation 

(Thousand 

dollars) 

 Treasury’s 

Estimated 

Credit Allowed 

(Thousand 

dollars) 

Biomass (open 

loop) 

 

188 351,139 

 

21.3 0.95 

 

3,336 

 

4,223 

Geothermal 

 

68 346,945 

 

58.7 1.90 

 

6,592 

 

8,345 

Hydroelectric 

 

44 85,318 

 

22.3 0.95 

 

811 

 

1,026 

Landfill Gas 

 

193 705,341 

 

41.7 0.95 

 

6,701 

 

8,482 

Municipal Solid 

Waste 

 

37 89,988 

 

27.9 0.95 

 

855 

 

1,082 

Solar 

 

87 31,143 

 

4.1 1.90 

 

592 

 

749 

Wind 

 

15,312 

 

27,694,360 

 

20.6 1.90 

 

526,193 

 

666,093 

Total or 

Weighted 

Average

 

15,928 

 

29,304,234 

 

21.0 1.86 

 

545,078 

 

690,000 

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

Sources: Office of Management and Budget, Analytical Perspectives of the United States Budget, Fiscal Year 2008, 

Table 19-1. Energy Information Administration, "Power Plant Report," Form EIA-906, and "Combined Heat and Power Plant 

Report," Form EIA-920. 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

19971998199920002001200220032004200520062007

Annual Capacity Additions (MW)

0

4,000

8,000

12,000

16,000

Cumululative Capacity Additions 

(MW)

Net Summer Capacity Additions (MW) Cumulative Capacity
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 35 

The PTC for wind has expired and has been reinstated several times since it first went into 

effect in June of 1994 (Table 10). It has been estimated that the PTC reduces wind costs by 

roughly one-third. On the basis of megawatthours generated by fuel type, wind power was the 

second largest beneficiary of electricity-related subsidies after solar. Most of the subsidy 

allocated to wind is attributable to the $666-million estimate of PTC tax expenditures. 

Table 10. History of the New Technology (Production Tax) Credit and Related Development 

Activity 

Legislation 

Date 

Enacted 

PTC Eligibility 

Window 

Effective Duration 

(with lapses) 

Wind Capacity 

Built in PTC 

Window 

(Megawatts) 

Section 1914, Energy Policy Act of 

1992 (P.L. 102-486) 

10/24/92 1994-June 1999 80 Months 894 

Section 507, Ticket to Work and 

Work Incentives Act of 1999 (P.L 

106-170) 

12/19/99 July 1999-2001 24 Months 1,764 

Section 603, Job Creation and 

Workers Assistance Act of 2002, 

(P.L. 107-147) 

03/09/02 2002-2003 22 Months 2,078 

Section 313, The Working Families 

Tax Relief Act of 2004, (P.L. 108-

311) 

10/04/04 2004-2005 15 Months 2,796 

Section 1301, Energy Policy Act of 

2005 (P.L. 109-58) 

08/08/05 2006-2007 24 Months 5,454 

Section 201, Tax Relief and Health 

Care Act of 2006 (P.L. 109-432) 

12/20/06 2008 12 Months 3,000E

Source: "Wind Power and the Production Tax Credit: An Overview of Research Results,” Prepared Testimony of 

Dr. Ryan Wiser, Lawrence Berkeley National Laboratory, before the Senate Finance Hearing on Clean Energy: 

From the Margins to the Mainstream, March 29, 2007, p. 5. 

E=Estimate 

Unreported Tax Expenditures 

The Congressional Budget Act of 1974 (Public Law 93-344) mandates reporting of tax 

expenditures. The Budget of the U.S. Government defines tax expenditures as "revenue losses 

due to preferential provisions of the Federal tax laws, such as special exclusions, exemptions, 

deductions, credits, deferrals, or tax rates." Although the concept of what constitutes a tax 

expenditure is clear, the determination of what exactly is a preferential provision is subject to 

interpretation. In preparing this chapter on energy-related tax expenditures, the EIA relied 

primarily on the definitions of tax expenditures presented in OMB documents. EIA relied on 

estimates of the value of certain tax expenditures contained in EPACT2005, which were 

prepared by the JCT. These provisions were described in the discussion on electricity-related 

tax expenditures. The JCT estimated the total value of these tax expenditures for FY 2007 to be 

$304 million. 

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. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

36 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

This report does not quantitatively address energy legislation that has recently been passed 

and for which the budgetary impact has not yet been assessed by the OMB for FY 2007 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 before 2012 because 

no eligible plant is expected to be producing electricity before that time. 

Direct Expenditures 

There has been renewed growth in direct expenditures in recent years, as a result of higher 

levels of spending to assist low income consumers with rising energy costs (Table 11). 

This is reflected in the increase in funding for LIHEAP. LIHEAP expenditures have increased 

from $1.5 billion in FY 1999 to $2.2 billion in FY 2007. Funding for DOE conservation programs 

has increased by 34 percent over the same period. 

Renewable Energy Production Incentive 

The Renewable Energy Production Incentive (REPI) is part of an integrated strategy to promote 

the generation of electricity from renewable energy sources and to advance renewable energy 

technologies. This program was authorized under Section 1212 of EPACT1992. It provides 

financial incentive payments for electricity produced and sold by new qualifying renewable 

energy generation facilities. DOE is responsible for managing REPI. EPACT1992 designated 

eligible electricity production facilities that started operations between October 1, 1993, and 

September 30, 2003, that are owned by State and local government entities (such as municipal 

utilities and Tribal governments) and not-for-profit electric cooperatives. The REPI provides 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 PTCs. Initially, qualifying

facilities were eligible for annual incentive payments of 1.5 cents per kilowatthour (1993 dollars 

and indexed for inflation) for the first 10-year period of their operation. The availability of 

incentive payments is subject to the annual appropriations process. Criteria for qualifying 

facilities and the application procedures were contained in the rulemaking for this program.59

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 $4.9 million. 

Low Income Home Energy Assistance Program 

In FY 2007, the Federal government’s Low Income Home Energy Assistance Program 

(LIHEAP) funding totaled $2.2 billion. LIHEAP was established in 1981 as a block grant 

 

59 10 C.F.R. 451 (2007) – Renewable Energy Production Incentives. 

Table 11. Direct Expenditures in Energy (million 2007 dollars) 

Direct Expenditure FY 1999 FY 2007 

Renewable Energy Production Incentive 5 5 

Low Income Home Energy Assistance Program 1,545 2,188 

DOE Conservation (Weatherization and State Energy) 191 256 

Rural Business Service Programs and RUS High Energy Cost 

Grant Program - 101 

Total 1,741 2,550 

Sources: Department of Energy Budgetary Documents and Department of Health and 

Human Service Budget Documents. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 37 

program. The Federal government gives States, the District of Columbia, U.S. territories, and 

Indian tribal organizations annual grants to provide home energy assistance to low-income 

households primarily to subsidize heating and cooling costs. LIHEAP is administered by the 

U.S. Department of Health and Human Services (HHS), but program implementation is 

generally managed by the grantees. LIHEAP assistance does not reduce eligibility or benefits 

under other aid programs. 

LIHEAP establishes a standard of 60 percent of a State’s median income to become eligible. 

LIHEAP grantees have some flexibility as the program allows "maximum policy discretion to 

grantees." For a four-person family in FY 2007, 60 percent of the mean national income is 

$66,111.60 Federal law defines income eligibility as the greater of 60 percent of the State's 

median income or 150 percent of the HHS poverty income guidelines.61,

Federal rules also require outreach activities, coordination with DOE’s Weatherization 

Assistance Program, and annual audits. Grantees decide the mix and dollar range of benefits, 

choose how benefits are provided, and select the agency or agencies responsible for 

administering the program. In addition to funds used for heating and/or cooling assistance, 

funds must be set aside by grantees for energy crisis intervention. Fifteen percent of grantees’ 

allotments (up to 25 percent with a waiver) may be used for low-cost residential weatherization 

or other energy-related home repair. 

Payments may be made directly to eligible households or to retail energy suppliers. Assistance 

may be in the form of cash, vouchers, or payments by the entity administering the program to 

retail energy suppliers such as utility companies or fuel dealers. In practice, the majority of the 

funds are paid directly to energy providers. LIHEAP funds are only used by a fraction of eligible 

participants. In 2004, between 5 and 6 million households were recipients of heating, cooling, 

and weatherization assistance out of an eligible population of 35.4 million households under the 

Federal LIHEAP income maximum standard and 24.1 million households under the States' 

LIHEAP maximum standard.62

In the early years of the program, LIHEAP funding averaged around $3.5 billion. Since 1998, 

annual funding for LIHEAP has ranged from $1.4 billion to $2.4 billion (Figure 3), with the 

exception of FY 2006 when funding exceeded $3 billion. In 2006, Congress appropriated an 

additional $1 billion in emergency LIHEAP expenditures due to the spike in energy prices. A 

portion of the funding was also directed at Gulf Coast States most affected by the Hurricane 

Katrina. 

 

60 In 2007, a family with annual income of under $20,000 is considered to fall beneath the Federal Government’s poverty level. 

61 Department of Health and Human Services: Low Income Home Energy Assistance Program, LIHEAP Disaster Relief, 

http://www.acf.hhs.gov/programs/liheap/guidance/special_topics/disaster_relief.html, last updated: January 31, 2006. 

62 Leon Lithow, Lead Program Analyst, Division of Energy Assistance, Low Income Home Energy Assistance Program, November 

20, 2007. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

38 Energy Information Administration / Chapter 2: Tax Expenditures and Direct Expenditures 

 Figure 3. LIHEAP Funding, Fiscal Years 1982-2007 

The program sought to help 

lower-income families 

maintain their standard of 

living. The aging of the 

population and increased 

independence of 

handicapped persons 

means that these groups will 

account for a growing share 

of LIHEAP payments. In 

2002, according to HHS, "of 

the 4.1 million households 

receiving heating 

assistance, approximately 

1.4 million households had 

at least one member 60 

years or older; 

approximately 1 million of 

these households had at 

least one child 5 years or 

under. Some of these households contained both an elderly person and a young child. Although 

available, State data on households with disabled members are not comparable as each State 

can use its own definition of ‘disabled.’"63

Building Technology Assistance Program 

Federal appropriations for the DOE conservation program increased from $191 million in FY 

1999 to $256 million in FY 2007. DOE provides conservation assistance in a number of areas, 

primarily through the Building Technology Assistance Program. It complements DOE’s R&D 

efforts and accelerates the deployment of new technologies and the adoption of advanced 

building practices through technical and financial assistance, outreach, and selective 

demonstration projects. According to the Office of Energy Efficiency and Renewable Energy, 

"The Building Technology Assistance Program works to improve the energy efficiency of the 

nation’s buildings through innovative new technologies and better building practices." The 

Building Technology Assistance Program supports two grant programs: the Weatherization 

Assistance Program, which provides support for the weatherization of low-income homes, and 

the State Energy Program, which provides grants to promote innovative State energy efficiency 

and renewable energy activities. 

The Weatherization Assistance Program engages State and local partners to increase the 

efficiency of homes occupied by low-income citizens who can least afford rising energy bills. 

The State Energy Program provides grants to State and local governments to create a network 

for energy efficiency.

 

63 Department of Health and Human Services, 

http://www.acf.hhs.gov/programs/opre/acf_perfplan/ann_per/apr2005/apr_sg3_73.html. 

Source: Department of Health and Human Services, Low Income Home 

Energy Assistance Program, 

http://www.acf.hhs.gov/programs/liheap/funding/approp.html.

0

0.5

1

1.5

2

2.5

3

3.5

4

Billion 2007 Dollars

19821983198419851986198719881989199019911992199319941995199619971998199920002001200220032004200520062007
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 3: Federal Energy Research and Development 39 

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. Since 1949, the 

largest R&D outlays have been for defense and, to a lesser extent, space and health 

programs.64 In the 1980s, total Federal R&D spending rose by more than 100 percent. The 

growth was primarily associated with defense-related R&D. In the late 1980s, spending on 

health research also increased in relative importance. During the 1990s, the growth in R&D 

expenditures was less than in the past. After 2000, R&D outlays have grown rapidly, particularly 

for defense and health care. According to the Office of Management and Budget (OMB), the FY 

2007 appropriations for energy-related R&D (basic and applied research) amounted to about 5 

percent of all Federally-funded R&D. Total Federal R&D for fiscal year (FY) 2007 exceeded 

$125 billion, 60 percent of which was defense-related. 

The scale and focus of energy-related R&D expenditures have changed over time (Table 12). 

In the late 1970s, funding was influenced strongly by the decade’s two oil crises. As oil prices 

abated through much of the 1980s, Federal R&D funding levels fell considerably. Funding 

levels fell from $6.5 billion in 1978 to $1.2 billion in 1987. Funding levels have picked up since, 

averaging $1.9 billion to $2.5 billion over the last decade. Since the last EIA subsidy report was 

released in the year 2000, energy-related R&D expenditures for biofuels, advanced nuclear, 

and advanced coal technologies have substantially increased. Like the growth in tax 

expenditures, EPACT2005 has had a significant impact on energy-related R&D expenditures. 

Due in part to EPACT2005, funding for hydrogen-related R&D grew from zero to $230 million 

between 1999 and 2007. Title VIII of EPACT2005 authorizes $3.3 billion in hydrogen-and-fuelcell-related R&D for the period 2006 through 2010. Title IX of EPACT2005 authorized R&D 

funding for energy efficiency, distributed generation, nuclear energy, and renewable energy. 

For example, EPACT2005 authorized funding for nuclear-related R&D totaling $2.4 billion over 

the years 2007 through 2009. Due in part to widespread power outages in the eastern United 

States during the summer of 2003, EPACT2005 contained provisions directed at improving 

transmission and distribution system reliability. 

Since 1978, funding for energy-related R&D has totaled $75 billion, of which $30 billion has 

been devoted to nuclear, $20 billion to coal, $13 billion to renewable energy, $4 billion to other 

fossil fuels, and $8 billion to end-use technologies. 

Defining Federal Research and Development 

For purposes of this report Federal energy-related R&D is divided into three categories: basic 

research, research that seeks to develop new energy technologies, and research that enhances 

existing technologies. 

 

64 See http:/www.whitehouse.gov/omb/budget/fy2008/pdf/hist.pdf. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

40 Energy Information Administration / Chapter 3: Federal Energy Research and Development 

Research to Develop New Technologies. R&D expenditures in this category attempt to 

discover new scientific knowledge for which there is potential for commercial application. 

Although reaching the point of technology transfer to the private sector for commercialization is 

the objective this type of R&D, the probability of success is uncertain. 

Research to Improve Existing Technologies. These expenditures use scientific knowledge to 

design and test new processes that may have substantial technical and cost uncertainties. The 

immediate beneficiaries are generally well defined, i.e., current producers and consumers of 

particular fuels, or operators and customers of the technology being improved. 

Energy Research and Development as a Subsidy 

It is easier to measure energy R&D spending than to characterize it as a subsidy. R&D 

spending is intended to create useful knowledge and develop technologies that have potential 

Table 12. Summary of U.S. DOE R&D Expenditures, 1978 to 2007 (million 2007 dollars)

Fiscal 

Year 

Renewable 

Energy Coal 

Other 

Fossil Nuclear End Use 

Clean Coal 

Technology Total 

1978 1,046 1,709 275 2,938 561 0 6,529 

1979 1,302 1,685 322 2,614 541 0 6,464 

1980 1,367 1,657 203 2,373 413 0 6,011 

1981 1,196 1,464 184 2,018 377 0 5,239 

1982 588 975 97 1,954 155 0 3,769 

1983 454 497 68 1,313 99 0 2,432 

1984 346 500 80 1,110 106 0 2,142 

1985 328 523 71 702 81 0 1,705 

1986 270 504 63 586 61 0 1,484 

1987 224 430 55 450 55 0 1,213 

1988 253 502 63 422 55 309 1,603 

1989 159 383 75 492 64 284 1,457 

1990 155 435 78 494 47 796 2,004 

1991 223 439 105 463 60 543 1,833 

1992 277 513 95 500 54 563 2,002 

1993 282 331 122 419 61 0 1,216 

1994 355 231 222 441 64 291 1,604 

1995 416 224 238 471 61 47 1,456 

1996 314 335 208 289 45 185 1,377 

1997 289 258 202 980 42 (3) 1,768 

1998 300 182 192 1,218 398 (124) 2,166 

1999 344 174 218 900 438 (49) 2,024 

2000 326 172 244 742 595 (173) 1,905 

2001 468 400 150 643 634 120 2,415 

2002 317 486 144 570 632 48 2,197 

2003 319 482 123 570 603 (52) 2,045 

2004 298 535 105 754 498 (106) 2,083 

2005 376 511 81 1,124 502 (168) 2,424 

2006 356 530 64 1,062 470 (20) 2,462 

2007 444 470 0 946 414 0 2,273 

Total 13,392 17,537 4,147 29,558 8,186 2,491 75,302

Source: U.S. Department of Energy, Budget Authority History Table by Organization. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 3: Federal Energy Research and Development 41 

commercial benefits to society. Thus, all Federal R&D spending could, in a general way, be 

considered a subsidy to knowledge and technology. However, the extent to which specific R&D 

programs actually affect energy markets is more difficult to ascertain. 

The results of R&D are inherently uncertain. Many programs are intended to advance 

knowledge across a range of energy and non-energy applications, rather than in the context of 

a particular fuel or form of consumption. Furthermore, the knowledge obtained may not be of 

value, in the sense that the research may only reveal technical or economic dead ends to be 

avoided in the future.65 Thus, only a portion of Federal energy R&D is likely to achieve results in 

the form of changes in energy production costs or consumption that can be attributed to a 

specific R&D program. Moreover, to the extent that R&D yields commercial technologies, they 

are likely to be measurable only years after the funded research effort is initiated. 

Federal R&D is intended to support research that the private sector will not undertake. It is not 

supposed to substitute for private sector R&D. However, the creation of a Federally-funded 

R&D program could, under some circumstances, displace private-sector R&D. In that case, the 

Federal program would not produce new knowledge that could not be developed by the private 

sector, but would simply reduce private R&D costs. It is impossible to know with certainty what 

R&D private-sector firms would have performed in the hypothetical absence of a Federal 

program. In general, the less "basic" the R&D program and the more focused on near-term 

commercialization, the greater the risk that the program will be a substitute for private-sector 

R&D. As R&D projects approach commercial viability, the justification for government 

participation lessens.66

 

Federal government energy-related R&D spending often represents a first stage of Federal 

intervention in energy markets. The rationale for government intervention in technology 

development lessens as products approach commercialization, because private investors at 

later stages of product development face fewer barriers towards successful commercialization. 

Other forms of Federal interventions in energy markets may complement the preliminary work 

done at the R&D stage. 

For example, in promoting planned construction of advanced nuclear power, recent Federal 

intervention has involved new programs and changes to programs already in place. While this 

chapter describes Federal interventions supporting nuclear-related R&D, other chapters and the 

appendix to this report describe nuclear-related Federal energy interventions as they relate to 

tax expenditures, such as EPACT 2005’s nuclear production tax credit, or loan guarantees, 

construction insurance, enhanced accident insurance, and regulatory changes. The 

combination of these programs suggests that the nuclear industry, in order to expand, faces 

several difficult hurdles, technological advancement being only one. For instance, 

preapproved technologies may reduce some of the regulatory risk associated with the 

 

65 Several studies suggest that the return on overall Federal R&D investment is much lower than the return on private-sector R&D, 

implying relatively high failure rates. See, Terlecyyj, N., "Effects of R&D on the Productivity Growth of Industries: An Exploratory 

Study (Washington, DC: National Planning Association, 1974), and Griliches, Z., "Returns to R&D in the Private Sector," in 

Kendrick, J. and Vaccara, B. (eds.), "New Developments in Productivity Measurement and Analysis," NBER Studies in Income and 

Wealth No. 44 (Chicago, IL: University of Chicago Press, 1980), pp. 419-454. This result need not be surprising, as the Federal 

Government's research portfolio may be much riskier than the private sector’s. 

66 One recent study, “Energy Research at DOE: Was It Worth It? Energy and Fossil Energy Research 1978 to 2000,” concluded 

that: “DOE’s R&D programs in fossil energy and energy efficiency have yielded significant benefits (economic, environmental, and 

national security-related), important technological options for potential applications in a different (but possible) economic, political 

and/or environmental setting, and important additions to the stock of engineering and scientific knowledge in a number of fields.” 

The committee also found that DOE has not employed a consistent methodology for estimating and evaluating the benefits from its 

R&D programs in these and presumably other areas.” National Research Council Committee on the Benefits of DOE R&D on 

Energy Efficiency and Fossil Energy, Washington, DC: National Academy Press (2001), p. 5. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

42 Energy Information Administration / Chapter 3: Federal Energy Research and Development 

construction of new nuclear power plants. Potential investors in new nuclear power units may 

also need assurances that sufficient economies of scale will be undertaken so as to make new 

builds financially viable and that any construction delays will not result in financial losses and 

abandoned projects. However, most Federal government programs directed at reviving nuclear 

power have sunset provisions which are intended to become effective as advanced nuclear 

power becomes a commercially viable investment. 

Therefore, tax expenditures directed toward developers, manufacturers, and end-use 

consumers of emerging technologies may act as a substitute for Federal R&D programs, 

allowing manufacturers (and others) to gather useful information and introduce modifications to 

improve performance and reliability, and lower costs. In the end, there are no means to 

determine conclusively whether or not particular Federal energy R&D projects are substitutes or 

complements for private-sector activities. Moreover, because research is risky, with the 

prospects of failure an inherent part of the process, the effectiveness of Federal R&D cannot 

easily be assessed. This report makes no judgments on either of these issues. Rather, it 

surveys the current composition of Federal R&D spending and provides an historical 

perspective on changes in the composition of Federal energy R&D efforts in response to 

changes in national priorities. Because Federal energy R&D programs may sponsor both fuelconsuming capital equipment, particularly power generation technologies, and fuel production 

technologies, e.g., biofuels, Federal R&D may produce conflicting benefits. Such projects may 

be more properly viewed as a subsidy to capital equipment manufacturers, rather than to fuel 

producers or consumers. Because generation technologies aided by Federal R&D may become 

more energy efficient, they will only benefit producers if they help to expand the market for their 

fuel. Thus, if one seeks to understand the effects, rather than the intent, of R&D spending, the 

success of the programs must be evaluated with the understanding that considerable time and 

resources may be expended as a new technology moves from the R&D stage through 

demonstration to commercialization. Only then can the full consequences of any new 

technologies be ascertained. 

Finally, much of what is defined as energy R&D in the Federal government's budget accounts is 

not directly expended on energy research or development. Rather, a portion of the funds are 

expended on environmental restoration and waste management associated with the byproducts 

of energy-related research facilities, e.g., nuclear waste disposal. 

Energy Research and Development Trends 

Currently, about 57 percent ($3.8 billion) of total Federal energy R&D is allocated to basic 

research. DOE's largest basic research outlay is the General Science Program, funded at $1.9 

billion in FY 2007. This program supports research and operates facilities to provide the 

foundation for new and improved energy technologies. This program also provides funding for 

understanding environmental impact of these technologies. Basic Research also includes the 

Fusion Energy Sciences Program which is funded at $319 million in FY 2007. It is the National 

research effort to advance plasma science, fusion science, and technology needed for a fusion 

energy source in the future. Basic research is difficult to characterize as an energy subsidy 

because it cannot be allocated between energy and non-energy benefits or among forms of 

energy. Therefore, these programs, including Fusion Energy Sciences, are not included as 

subsidies in this analysis. 

The balance of this chapter focuses on applied energy R&D. Federal energy R&D that is 

unrelated to basic research, or Applied R&D, accounts for $2.8 billion (Table 13). This includes 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 3: Federal Energy Research and Development 43 

energy programs in the FY 2007 DOE Operating Plan, as well as energy programs in other 

Federal agencies. 

Table 13. Federal Energy R&D by Type and Function (million 2007 dollars) 

R&D Program Category FY 1999 Appropriation FY 2007 Operating Plan 

Basic R&D

General Science 1,968 1,942 

General Energy Science 996 1,292 

Environment, Safety, and Health 57 28 

Other Allocated 60 250 

Fusion Energy Sciences 270 319 

Basic R&D Sub Total 3,352 3,831 

Applied R&D 

Coal 489 574 

Natural Gas and Petroleum Liquids 198 39 

Nuclear Power 740 922 

Renewable and Other Electric Technologies 587 867 

End Use 487 418 

Applied R&D Sub Total 2,500 2,819 

Total 5,853 6,650 

NOTE: Total may not equal sum of components due to independent rounding. 

Sources: U.S. Department of Energy FY 2007 Operating Plan by Appropriation; Energy Information 

Administration, Federal Financial Interventions and Subsidies in Energy Markets 1999: Primary Energy, 

SR/OIAF/99-03 (Washington, DC, September 1999); Federal Financial Interventions and Subsidies in Energy 

Markets 1999: Energy Transformation and End Use, SR/OIAF/2000-02, (Washington, DC, May 2000). 

Applied R&D focuses on turning knowledge and concepts into useful products. Applied energy 

R&D expenditures are about $2.8 billion in FY 2007. The largest programs are the renewable 

technologies ($905 million)67 and nuclear power ($922 million). Funding for coal is $574 million. 

Natural gas and petroleum liquids are funded at about $39 million for geologic assessments 

and expenses incurred in connection with the phase-out of existing programs. 

The largest funding category for renewables technologies is for biofuels and biomass ($246 

million) followed by hydrogen technologies (Table 14). The hydrogen technologies program, 

which did not exist when EIA prepared its report in 1999, is funded at $230 million in FY 2007.68

Solar programs are funded at $187 million. These renewable programs, unlike others, such as 

wind, are not yet considered commercially viable because of cost and performance issues. 

Technologies receiving smaller funding levels include wind ($58 million) and geothermal ($6 

million). There are no R&D funds allocated to hydropower for FY 2007. Geothermal R&D 

funding was $35 million in FY 1999, compared to $6 million in FY 2007. The Electricity Delivery 

and Energy Reliability programs have increased from $54 million in FY 1999 to $140 million in 

FY 2007. The Nuclear Power program includes new nuclear plants ($319 million), Waste/Fuel 

and Safety ($350 million), and Program Direction and Termination Costs ($253 million). These 

programs are discussed in more detail in the balance of this chapter. 

 

67 Technical system reliability R&D totaling $137 million is included in this portion of Applied R&D. It is classified as "Electricity" in 

the Executive Summary and Chapter 5. 

68 Although hydrogen R&D programs are not renewables, they are included here because they are administered by the DOE Office 

of Energy Efficiency and Renewable Energy. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

44 Energy Information Administration / Chapter 3: Federal Energy Research and Development 

Table 14. Renewables and Other R&D Expenditures (million 2007 dollars) 

R&D Program FY 1999 

 Appropriation 

FY 2007 

 Operating Plan 

Wind 42 58 

Solar 120 187 

Hydrogen Technology - 230 

Biofuels and Biomass 116 246 

Geothermal 35 6 

Hydroelectric 4 - 

Other Allocated 95 - 

 Total Renewables 412 727 

Electricity Deliverability and Energy Reliability 54 140 

Total 466 867 

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

Sources: U.S. Department of Energy FY 2007 Operating Plan by Appropriation, U S Department of 

Agriculture, FY 2007 Budget Summary and Annual Performance Plan, pp. 32 and 78; Defense Logistics 

Agency, The Defense Logistics Agency Hydrogen and Fuel Cell Program, September 12, 2007, 

leo.plonsky@dla.mil; http://www.rita.dot.gov/agencies_and_offices/research/hydrogen_portal/. Energy 

Information Administration, Federal Financial Interventions and Subsidies in Energy Markets 1999: 

Primary Energy, SR/OIAF/99-03 (Washington, DC, September 1999); Federal Financial Interventions 

and Subsidies in Energy Markets 1999: Energy Transformation and End Use, SR/OIAF/2000-02, 

(Washington, DC, May 2000),

Federal Energy R&D Subsidies to Renewable and Other Technologies 

Renewable R&D 

The Office of Energy Efficiency and Renewable Energy (EERE) conducts research, 

development, and deployment activities in partnership with industry to advance a diverse supply 

of reliable and affordable, efficient and clean power technologies.69 The FY 2007 budget 

emphasizes research on alternatives that are intended to reduce the Nation’s dependence on 

foreign oil and accelerate development of clean electricity supply options. 

The Hydrogen Technology program, created by EPACT2005, focuses on hydrogen production, 

delivery, storage, and fuel cell technologies. This program supports the Bush Administration’s 

5-year, $1.2-billion Hydrogen Fuel Initiative intended to reverse America’s growing dependence 

on foreign oil by accelerating the development of hydrogen fuel cell vehicles and infrastructure 

technologies. The program is intended to enable a commercialization decision by industry on 

fuel cell vehicles and hydrogen infrastructure by 2015. A positive commercialization decision in 

2015 could lead to the introduction of hydrogen fuel cell vehicles in the market by 2020. The 

responsibility for implementing the Hydrogen Fuel Initiative rests with a number of 

organizations. Basic hydrogen research is managed by the Office of Science. The Office of 

Fossil Energy oversees coal-based hydrogen production research. Nuclear-based hydrogen 

production research resides with the Office of Nuclear Energy, Science and Technology. The 

Department of Transportation manages activities related to hydrogen safety. The fuel cell 

program is under the direction of the Defense Logistics Agency of the Department of Defense. 

 

69 The text in this section is extracted from the Department of Energy FY 2007 Congressional Budget Request Budget Highlights 

DOE/CF-009. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 3: Federal Energy Research and Development 45 

The Biomass and Biorefinery Systems R&D program includes a new Departmental Initiative that 

is funded at $234.2 million and a program at the United States Department of Agriculture 

(USDA) funded at $12 million in FY 2007. The DOE Biofuels Initiative is intended to accelerate 

research, development, and deployment of industrial-scale biorefinery operations. The program 

focuses on three areas: (1) Platforms R&D, to reduce the cost of outputs and byproducts from 

biochemical and thermochemical processes; (2) Utilization of Platform Outputs, to develop 

technologies and processes that co-produce liquid and gaseous fuels, chemicals and materials, 

and/or heat and power, and integrate those technologies and processes into biorefinery 

configurations; and, (3) Feedstock Infrastructure, to develop cost-effective biomass harvesting, 

storage and delivery systems, and to develop energy crops suitable for diverse regions and 

climates. 

There is also funding for Biomass Research and Development within the USDA Natural 

Resources Conservation Service that is coordinated with the DOE Biofuels Initiative.70 The 

funding level for FY 2007 is $12 million. The total funding for the DOE and USDA programs is 

$246.2 million in FY 2007. Biofuels and bioenergy research performed by USDA, including the 

Agricultural Research Service, are included in Renewable R&D expenditures. Biofuels and 

bioenergy R&D within the USDA Research, Education and Extension Mission Area excluding 

the $12 million are reported in Table 14. This additional funding totaled $29 million in FY 2007 

(see Table 17). 

The Solar Energy program is funded at $186.9 million in FY 2007. It focuses on R&D to enable 

cost-effective development of solar power that will reduce the demand for natural gas during 

peaking hours and promote a cleaner environment. Through DOE’s new Solar America 

Initiative (SAI), the Solar Program is intended to help accelerate the competitiveness of solar 

electricity from photovoltaic (PV) systems. Under the SAI, industry-led teams will compete to 

deliver future PV systems that are less expensive, more efficient, and highly reliable. By 

focusing on PV technology manufacturing issues while advancing systems integration, SAI 

intends to promote deployment of 5 to10 gigawatts (GW) of new grid-connected solar electricity 

generating capacity by 2015. The Solar Energy programs also focus on lowering the cost of 

solar power through larger-scale centralized generation. 

The Wind Energy program is funded at $57.8 million in FY 2007. This program develops and 

promotes the use of advanced technologies to harness kinetic wind energy. The program is 

developing low wind speed utility scale technology through leveraged partnerships with industry 

to substantially increase the economically viable wind resource base across the country. The 

program explores innovative applications that will open new markets for wind technology, 

including offshore development. 

Since 1974, the Geothermal Technology program has worked in partnership with U.S. industry 

to establish geothermal energy as an economically-competitive contributor to the U.S. energy 

supply. DOE planned to conclude the Geothermal Technology program in FY 2007 and 

transfer program R&D results to industry and State and local governments. The program is 

funded at $5.9 million in FY 2007. However, the program was funded in DOE’s FY 2008 budget 

at $20 million, with an additional request for $30 million in FY 2009. In 2006, the Massachusetts 

Institute of Technology (MIT) issued a DOE-sponsored study in which MIT researchers 

concluded that enhanced geothermal systems could provide 100 gigawatts (GW) or more of 

 

70 U.S. Department of Agriculture, Fiscal Year 2007 Budget Summary and Annual Performance Plan, p. 78. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

46 Energy Information Administration / Chapter 3: Federal Energy Research and Development 

cost-competitive geothermal generating capacity over the next 50 years with a reasonable 

amount of R&D investment.71

Electricity Delivery and Energy Reliability R&D 

The Office of Electricity Delivery and Energy Reliability (OE) leads the national effort to 

modernize and expand the U.S. electricity delivery system to ensure a reliable and robust 

electricity supply. In addition to its policy and regulatory functions, OE is engaged in a variety of

R&D initiatives related to transmission and distribution reliability, technology, and system 

control. FY 2007 funding totals $140 million for the following programs (Table 14). 

The High Temperature Superconductivity R&D program is intended to pursue improvements 

in the efficiency and reliability of the Nation’s electric delivery system. The goal of this research 

is to develop by 2016 operational wire and power prototypes that are physically smaller than 

current infrastructure and deliver energy with half of the losses of conventional equipment with 

the same power rating. 

The Visualization and Controls R&D program is intended to develop communication and 

control systems that support adaptive, intelligent grid operations, which integrate distributed 

energy devices. These advances will improve electric delivery system reliability and maximize 

efficiency by increasing the use of transmission and distribution assets. 

The Energy Storage and Power Electronics R&D program pursues advancements that 

reduce the adverse effects of electricity disturbances. 

The Distributed Energy R&D program aims to develop a diverse array of cost-competitive, 

integrated distributed-generation and thermal energy technologies. It also supports the use of 

these technologies in residential, business, and industrial applications to improve electricity 

reliability and reduced negative environmental impacts. The FY 2007 program consists of three 

activities: Research and Development Permitting, Siting and Analysis, and Infrastructure 

Security and Energy Restoration. 

The Permitting, Siting and Analysis subprogram supports Federal initiatives authorized in 

EPACT2005, including a national analysis of electric transmission congestion, the designation 

of national interest electric transmission corridors, and the designation of multi-purpose energy 

corridors on Federal lands. 

Direct Thermal to Electric Conversion program is conducted by the Defense Advanced 

Research Projects Agency (DARPA). The program focuses on research to significantly reduce 

the gap between practically-achievable thermal to electric conversion efficiencies and 

theoretically-achievable thermodynamic efficiencies. The program is funded at $2.5 million in 

FY 2007. Table 14 includes the aggregate of funding for Electricity Deliverability and Energy 

Reliability among OE’s R&D programs. FY 2007 funding is nearly three times the FY 1999 

funding level. 

Federal Energy R&D Subsidies to Nuclear Energy 

DOE’s Office of Nuclear Energy, Science and Technology (NE) mission is to develop new 

nuclear energy generation technologies to meet energy and climate goals; develop advanced, 

proliferation-resistant nuclear fuel technologies that maximize energy from nuclear fuel; and 

 

71 Massachusetts Institute of Technology, prepared under Idaho National Laboratory Subcontract No. 6300019 for the U.S. 

Department of Energy, Assistant Secretary for Energy Efficiency and Renewable Energy, Office of Geothermal Technologies, 

ISBN: 0-615-13438-6, 2006. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 3: Federal Energy Research and Development 47 

maintain and enhance the national nuclear infrastructure. DOE’s nuclear energy R&D program 

collaborates with international research communities in planning and conducting applied 

research to further the course of nuclear technology advancement. 

Through the Advanced Fuel Cycle Initiative, DOE seeks to develop advanced, proliferation 

resistant nuclear fuel technologies that maximize the energy produced from nuclear fuel while 

minimizing resulting wastes. Associated with this program, the Global Nuclear Energy 

Partnership (GNEP) aims to further provide for the expansion of nuclear power plants in the 

United States and around the world, in addition to promoting nuclear nonproliferation goals and 

helping resolve nuclear waste disposal issues. 

NE is funded in two accounts within the Energy and Water Development Appropriations: Energy 

Supply and Conservation and Other Defense Activities. All funding for R&D and landlord 

activities for the Idaho National Laboratory (INL) is included in the Energy Supply and 

Conservation account. Funding for Safeguards and Security is within the Other Defense 

Activities account. DOE received an appropriation of $922 million for civilian nuclear R&D in FY 

2007 (Table 15). Nearly 40 percent of the appropriation ($350 million) is allocated to the 

cleanup of contaminated nuclear energy and research sites.72

Table 15. Nuclear Power R&D Expenditures (million 2007 dollars) 

R&D Program 

FY 1999 

Appropriation 

FY 2007 

Operating Plan 

New Nuclear Plants (Nuclear Energy Research Initiative) 36 319 

Waste/Fuel/Safety (Environmental Management) 530 350 

Other Allocated (Termination Costs and Program Direction) 173 253 

Total 740 922 

NOTE: Totals may not equal sum of components due to independent rounding. Space and defense infrastructure

and medical isotopes infrastructure programs are not included in this table. 

Source: U.S. Department of Energy FY 2007 Operating Plan by Appropriation. 

Improving Existing Power Plants and Enhancing Nuclear Power 

DOE created the Nuclear Energy Research Initiative (NERI) to address and help overcome the 

technical and scientific obstacles to the future use of nuclear energy in the United States. NERI 

is also expected to help preserve the nuclear science and engineering infrastructure within the 

Nation’s universities, laboratories, and industry to advance the state of nuclear energy 

technology and to maintain a competitive position worldwide. 

The FY 2007 allocation of $319 million supports innovative applications of nuclear technology to 

develop new nuclear generation technologies and advanced energy products. It is also 

supporting the development of advanced proliferation-resistant nuclear fuel technologies that 

maximize energy output, and maintain and enhance national nuclear capabilities (Table 15). 

The Advanced Fuel Cycle Initiative (AFCI), which is integral to the Generation IV Nuclear 

Energy Systems effort, aims to develop a better, more efficient and proliferation-resistant 

nuclear fuel cycle. This R&D program is focusing on methods to reduce the volume and longterm toxicity of high-level waste from spent nuclear fuel, reduce the long-term proliferation 

threat posed by civilian inventories of plutonium in spent fuel, and provide for proliferation-

 

72 U.S. Department of Energy Fiscal Year 2007 Operating Plan by Appropriation. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

48 Energy Information Administration / Chapter 3: Federal Energy Research and Development 

resistant technologies to recover the energy content in spent nuclear fuel. The focus of this 

initiative will be Global GNEP, which consists of 16 member nations which promote the 

expansion of peaceful applications of nuclear power.

73

GNEP is intended to accelerate the work being done under the AFCI program. Advanced 

recycling technologies can extract highly radioactive elements of commercial spent nuclear fuel 

and use that material as fuel in fast spectrum reactors to generate additional electricity. The 

extracted material, which includes all transuranic elements (e.g., plutonium, neptunium, 

americium and curium), would be consumed by fast breeder reactors to significantly reduce the 

quantity of material requiring disposal in a repository. The plutonium would remain bound with 

other highly radioactive isotopes, thereby improving its proliferation resistance and reducing 

security concerns. With the transuranic materials separated and used for fuel, the volume of 

waste that would require disposal in a repository whose size would be reduced by 80 percent. 

The Nuclear Power 2010 program operating plan is funded at $80.3 million in FY 2007 for 

purposes of obtaining three early site permits by the NRC. In addition, the program will 

complete the industry cost-shared project initiated in FY 2003 to develop generic guidance for 

the Construction and Operating License (COL) application preparation, to resolve generic COL 

regulatory issues, and to continue the implementation phase of the two New Nuclear Plant 

Licensing Demonstration Projects awarded in FY 2005. 

The goal of the Generation IV Nuclear Energy Systems Initiative (Gen IV) is to address the 

fundamental R&D issues necessary to establish the viability of next-generation nuclear energy 

system concepts. The 2007 budget provides $35.6 million for the Gen IV initiative to expand 

R&D that could help achieve the desired goals of sustainability, economic feasibility, and 

proliferation resistance. The Nuclear Hydrogen Initiative (NHI), with funding of $19.3 million, 

intends to conduct R&D on enabling technologies, and develop technologies that will apply heat 

from Generation IV nuclear energy systems to produce hydrogen through electrolysis. The 

budget level for nuclear R&D in FY 2007 is 25 percent greater than it was in FY 1999. A 

substantial part of the increase is for the Nuclear Energy Research Initiative which increased by 

$283 million compared with FY 1999. 

Environmental Management 

A substantial portion of Federally-funded nuclear R&D is used for managing and addressing the 

environmental legacy resulting from past nuclear energy and research activities. Thousands of 

contaminated areas and buildings exist throughout the United States. The goal of the program 

is to decommission. Upon completing the clean up of these facilities, DOE’s presence and 

associated costs will be limited to long-term surveillance and maintenance. 

Other Allocated Expenditures 

Other allocated expenditures amount to $253 million in FY 2007 (Table 15). The largest portion 

of this amount is for Idaho facilities management and safeguards and security ($190 million). 

The Idaho Facilities Management program provides site-wide infrastructure needed to support 

R&D while the Safeguards and Security Program protects DOE interests. The remaining $62.6 

million is allocated to nuclear energy program direction, which provides Federal staffing 

resources and associated funding required to execute DOE’s nuclear energy program. 

 

73 GNEP member countries include the United States, Australia, Bulgaria, China, France, Ghana, Hungary, Japan, Jordan, 

Kazakhstan, Lithuania, Poland, Romania, Russia, Slovenia, and the Ukraine. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 3: Federal Energy Research and Development 49 

Federal Energy R&D Subsidies to Coal 

The Fossil Energy Research and Development program started in the late 1980s. The program 

goal is to ensure that economic benefits of moderately-priced coal-fired generation are 

compatible with public expectations for environmental quality with the intent of achieving energy 

security derived from reliance on abundant domestic coal-resources. The program pursues 

these goals by: (1) managing and performing energy-related research that reduces market 

barriers to the reliable, efficient, and environmentally sound use of fossil fuels for power 

generation and conversion to other fuels such as hydrogen; (2) partnering with industry and 

others to advance the commercialization of clean and efficient fossil energy technologies; and, 

(3) supporting the development of information and policy options that benefit the public by 

ensuring access to adequate supplies of affordable and clean energy.74

EPACT2005 Section 962 directs DOE to conduct a coal and power systems research, 

development and demonstration program to facilitate the production and generation of coalbased power. Cost and performance goals are to be established to insure the continued 

competitiveness for electricity generation, transportation fuel, and chemical feed stocks. 

Section 963 establishes a program for carbon capture technologies to be used in conjunction 

with combustion based systems with the intent of reducing future greenhouse gas emissions. 

Table 16 compares FY 1999 and FY 2007 expenditures for DOE’s Office of Fossil Energy coal 

R&D program. 

 

The program focuses on near-zero atmospheric emissions coal-based electricity and hydrogen 

production. The President’s Coal Research Initiative is aimed at meeting these objectives. The 

programs included in this initiative are the Clean Coal Power Initiative (CCPI), FutureGen, and 

Fuel and Power Systems. The total FY 2007 appropriation for the R&D program is $574 million. 

The CCPI is a cooperative, cost-sharing program between the Federal government and industry 

intended to demonstrate emerging technologies in coal-based power generation. The objective 

of CCPI is to collaborate with the Nation’s power generators, equipment manufacturers, and 

coal producers to help identify the most critical barriers to using coal in the power sector. 

Technologies will be selected with the goal of accelerating development and commercial 

deployment of coal technologies that will economically meet environmental standards. 

 

74 The Department of Energy Fiscal Year 2007 Congressional Budget Request Budget Highlights, DOE/CF-009. 

Table 16. Coal R&D Expenditures (million 2007 dollars) 

R&D Program FY 1999 

Appropriation 

FY 2007 

Operating Plan 

Clean Coal Power Initiative 106 61 

Advanced Clean Fuels 19 - 

Future Gen Advanced Clean Fuels - 54 

Fuel and Power Systems 24 311 

Clean Coal Technology Adjustment 222 - 

Other Allocated 118 148 

Total 489 574 

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

The Clean Power Initiative was previously referred to as Advanced Clean Efficient Power Systems. Advance Clean 

Fuel funding now falls under Fuel and Power Systems. Source: U.S. Department of Energy FY 2007 Operating 

Plan by Appropriation. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

50 Energy Information Administration / Chapter 3: Federal Energy Research and Development 

FutureGen aimed to establish the capability and feasibility of co-producing electricity and 

hydrogen from coal with near-zero atmospheric emissions. Carbon sequestration is an integral 

component of the project. 75 FutureGen is intended to employ a public/private partnership 

aiming to demonstrate technology with the goal of developing near-zero atmospheric emission 

plants that are fuel-flexible and capable of multi-product output with electrical efficiencies of 

over 60 percent. The cost of the electricity produced is to amount to no more than a 10-percent 

increase over comparable plants, without carbon sequestration, that use coal, biomass, or 

petroleum coke. The project is intended to retain the strategic value of coal. 

The Fuel and Power Systems program provides funding for research in connection with 

FutureGen. The Fuel and Power System program focuses on how to reduce coal power plant 

emissions, especially mercury, and significantly improve efficiency in terms of carbon emissions 

per unit of electricity produced, leading to a viable near-zero atmospheric emissions coal 

energy system. 

The Innovations for Existing Plants (IEP) program focuses on the near-to-mid-term task of 

retrofitting existing power plants to improve overall power plant efficiency and develop 

advanced cost-effective environmental control technologies. It focuses on reducing mercury 

emission and other coal technologies, including those developed in the FutureGen project that 

can be deployed when retrofitting existing power plants. 

The Integrated Gasification Combined Cycle (IGCC) program continues the development of 

technologies for gas stream purification to meet quality requirements for use with fuel cells and 

conversion processes. The program also focuses on impurity tolerant hydrogen separation 

technology, enhanced process efficiency, and reductions in costs, including energy required to 

produce oxygen for gasification. 

The Advanced Turbines program focuses on creating the technology base for turbines that will 

permit the design of near-zero atmospheric emission IGCC plants and a class of FutureGen 

plants with carbon capture and sequestration. The Advanced Turbine program research 

focuses on developing technology for high-efficiency hydrogen and syngas turbines for 

advanced gasification systems to be incorporated in FutureGen plants. 

The Carbon Sequestration program is developing a portfolio of technologies with potential to 

reduce greenhouse gas emissions. The program focuses on developing capture and separation 

technologies that may dramatically lower the costs and energy requirements for reducing 

carbon dioxide emissions from fossil-based (especially coal) power plants. The program goal is 

to research and develop a portfolio of safe and cost-effective greenhouse gas capture, storage, 

and mitigation technologies by 2012. 

The mission of the Advanced Clean Fuels program is to conduct the research necessary to 

promote the transition to a hydrogen economy. Research will target cost reduction and 

increased efficiency of hydrogen production from coal feedstocks. 

 

75 The prospects of the FutureGen grew uncertain when, in January 2008, the U.S. Department of Energy announced that it 

intended to restructure FutureGen. The DOE’s new FutureGen vision called for “Federal-funding to demonstrate cutting edge CCS 

(Carbon Capture and Storage) at multiple commercial-scale integrated gasification combined-cycle (IGCC) demonstration 

plants...Under this new approach multiple plants would produce at least 3000 megawatts of electricity and jointly these projects will 

capture and safely sequester at least double the amount of carbon dioxide annually compared to the concept announced in 2003.” 

Source: DOE, Fact Sheet, “DOE to Demonstrate Cutting-Edge Carbon Capture and Sequestration Technology at Multiple 

FutureGen Clean Coal Projects.” The DOE cited higher than expected costs for the restructuring. The DOE also stated that the 

program would be revamped so that DOE would only fund the carbon sequestration element of the program. The restructuring cast 

strong doubts over whether the prototype plant, selected in December 2007 for Mattoon, Illinois, would continue. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 3: Federal Energy Research and Development 51 

Advanced Research projects seek a greater understanding of the physical, chemical, biological, 

and thermodynamic barriers that limit the use of coal and other fossil fuels. The program funds 

two types of activities. The first includes applied research programs to develop the technology 

base needed for the development of super clean, high efficiency coal-based power and coalbased fuel systems. The second is a set of crosscutting studies and assessment activities in 

environmental, technical and economic analyses, coal technology export, and integrated 

program support. 

The objectives of the Fuel Cells program are to provide for the development of low-cost, 

scalable fuel flexible fuel cell systems that can operate in central, coal based power systems in 

distributed or dispensed generation applications. 

The Other Allocated funding includes several other expenditures, the largest of which is 

program direction funded at $125.6 million in FY 2007. Other expenditures include plant and 

capital equipment, fossil energy environmental restoration, and special recruitment programs. 

The total funding for this category in FY 2007 is $148 million (Table 16). 

The overall funding for coal R&D in FY 2007 has increased by $85.1 million compared with FY 

1999. The largest increase is in Fuel and Power Systems which has increased by $287 million. 

About one-third of the increase in this program is R&D for carbon sequestration.76

Federal Energy R&D Subsidies to Natural Gas and Petroleum Liquids 

The United States relies on fossil fuels for approximately 85 percent of the energy it consumes. 

EIA's Annual Energy Outlook 2008 (Revised Early Release) forecast projects that reliance on 

fossil fuels will modestly decline to 82 percent by 2030.77 To address this situation, the Natural 

Gas and Petroleum Liquids program promotes the development of environmentally-sensitive 

and economically-efficient fossil fuel energy systems for the benefit of current and future energy 

users. R&D funding for oil and natural gas is $39 million in FY 2007 (Table 13). 

The United States Geological Survey (USGS) is funded at $20.1 million in FY 2007 to conduct 

research to enhance exploration, development, and production of oil, natural gas, coal, and 

other resources such as geothermal. EPACT2005 calls for a focus on all energy sources with 

an emphasis on assessment of geothermal resources and alternative energy sources such as 

gas hydrates and oil shale. Section 351 of EPACT2005 directed USGS to create the 

Preservation of Geological and Geophysical Data Program to rescue, curate, and preserve 

materials and data related to energy and minerals. Section 351 also directs USGS to assess 

the oil and gas underlying Federal lands in the United States. 

DOE's FY 2007 oil research efforts are funded at $3.5 million for management costs associated 

with the closeout of the program. The program addressed new technologies that improve 

exploration, drilling, reservoir characterization, and extraction. Similarly, the Natural Gas 

Program received $15.4 million in FY 2007 for the closeout of the program. It focused on 

natural gas research and fuel cells. 

Federal Subsidies to End Use Energy R&D 

The End Use Energy program develops technologies, techniques, and tools for making 

residential and commercial buildings more energy efficient, productive, and affordable. The 

 

76 Although there is no legislation mandating reductions in carbon dioxide emissions, the carbon sequestration program is included 

because it meets the definition of a subsidy used in this analysis. 

77 Energy Information Administration, Annual Energy Outlook 2008 (Revised Early Release), DOE/EIA-0383 (2008) (Washington, 

DC, March 2008), Year-by-Year Reference Case Table 1, http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

52 Energy Information Administration / Chapter 3: Federal Energy Research and Development 

portfolio of activities includes: (1) efforts to improve the energy efficiency of building 

components and equipment; (2) advancement of solid state lighting technologies for general 

illumination; (3) integration of advanced light systems using whole-building-system-design 

techniques; (4) development of energy efficient building codes and equipment standards; and 

(5) integration of clean renewable energy systems into building design and operation. 

The Building Technologies Program works in partnership with States, industry, and, particularly, 

manufacturers, to improve the energy efficiency of buildings. Through new technologies and 

systems-engineered building practices, the design, construction, and operation of 

approximately 15 million new buildings projected to be constructed by 2015 is expected to be 

improved. Funding for this program was $103 million in FY 2007 (Table 17).

The program advances the R&D of energy-efficient building technologies and practices for both 

new and existing residential and commercial buildings. It works with State and local regulatory 

groups and others to improve building codes, appliance and equipment standards, and 

guidelines for efficient energy use and promotes market transformation by educating 

homeowners, builders, and developers about the returns they can achieve by adopting energyefficient technologies and practices. 

The Industrial Technologies program focuses on reducing the energy intensity of the U.S. 

industrial sector through a coordinated program of R&D, validation, and dissemination of 

energy-efficiency technologies and best practices. During FY 2007, activities with specific 

industries (forest products, glass, metal casting, aluminum, mining, chemicals, and supporting 

industries) and crosscutting activities (materials and Industrial Assessment Centers) were 

aimed at focusing on the successful completion of existing projects with the highest potential 

energy efficiency gains and environmental benefits. New projects were selected that were 

unlikely to be undertaken without Federal support, and that significantly were expected to 

reduce energy intensity, consistent with DOE’s R&D Investment Criteria.78 Funding for this 

program was $66 million in FY 2007. 

The Vehicle Technologies program supports the FreedomCAR and Fuel Partnership and the 

21st Century Truck Partnership, to enable light- and heavy-duty highway transportation to 

become more fuel efficient. Technology research includes advanced lightweight materials, 

 

78 Pursuant to President Bush’s Management Agenda, the three primary criteria applicable to all R&D programs are relevance, 

quality, and performance. See Memorandum for the Heads of Executive Departments and Agencies, Executive Office of the 

President Office of Management and Budgets, M-05-18, July 8, 2005. 

Table 17. Federal Funding for End-Use R&D (million 2007 dollars) 

R&D Program 

FY 1999 

Appropriation

FY 2007 

Operating Plan

Building Technology, State and Community Programs 117 103 

Industrial Sector 201 66 

(Less Advanced Turbine Systems) (121) - 

Industrial Sector Net 80 66 

Vehicle Technologies 245 221 

Research, Education and Extension Service (USDA) - 29 

Other Allocated (Policy and Management) 46 - 

Total 487 418 

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

Source: U.S. Department of Energy FY 2007 Operating Plan by Appropriation. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 3: Federal Energy Research and Development 53 

advanced batteries, improved power electronics, electric motors, and advanced combustion 

engines and fuels. These technologies are intended to contribute to reducing oil consumption. 

In FY 2007, the program is increasing research on technologies needed for cost-effective plugin hybrid vehicles. At $221 million, the Vehicle Technologies program accounted for more than 

half of end-use R&D funding in FY 2007. 

 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 55 

4. Federal Electricity Programs 

Introduction 

The Federal government provides Federal utilities and electric utilities (primarily cooperatives), 

participating in the RUS electric program, access to capital at reduced interest rates resulting 

from Federal government support. 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).79 Even 

though Federal ownership is not a factor, lending subsidies provided through the RUS loan 

programs are included due to the advantages that these programs provide to eligible borrowers. 

Federal Power Programs 

Federal utilities are a conduit for and not the ultimate beneficiaries of low-cost capital. The 

customers for whom they have a statutory obligation to serve are the primary beneficiaries of 

low-cost Federal power, the price of which includes capital cost recovery. They are generally 

cooperatives and government-owned utilities (State and local) that resell the power to their 

customers at cost. These benefits derive from the Federal utilities' ability to borrow directly from 

the Treasury, sell bonds to the public in the case of TVA, or assume payment of debt 

obligations of third parties in the case of BPA, at interest rates that reflect investors’ perception 

that such obligations are guaranteed by the Federal government. Even though TVA and BPA 

bond issuances state that no Federal government guarantees exist, the Nationally Recognized 

Statistical Rating Organizations, i.e., credit rating agencies recognized by the Securities and 

Exchange Commission, indicate that perceived implicit Federal government support and the 

ability to borrow from the Treasury enhances their creditworthiness. However, due to the less 

than unconditional nature of this support, this report refers to Federal utilities’ advantaged 

access to capital as “support” rather than “subsidy.” 

In the early years of Federal power, its proponents asserted that publicly-supported electricity 

was essential in order to electrify large parts of rural America. Critics at the time argued that 

Federal power was a subsidy provided by urban taxpayers to rural areas.80 For example, 

investor-owned utilities (IOU) mounted a legal challenge to the creation of the TVA out of 

competitive concerns.81 Moreover, the original and primary purpose of TVA, BPA, and the 

smaller PMAs, as utilities, was to market the surplus output of hydroelectric facilities that was 

incidental to flood control, navigation, and irrigation operations. In the early years of their 

operations, however, the provision and marketing of electricity has evolved as a core function of 

TVA, BPA and the smaller PMAs. 

Federal utilities do not directly service residential or commercial customers. They make 

wholesale sales to municipals and cooperatives and some direct sales to large industrial 

customers. In 2006, TVA, for instance, sold 87 percent of its power to municipalities and 

 

79 The United States Department of Interior, Bureau of Indian Affairs owns or has interests in irrigations 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. DE-AC65-91WA07849, January 1996. Any subsidies 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. 

80 Shapiro, D. "Public Power Policy: The Controversial Origins," in Generating Failure (New York, NY: University Press of America, 

1989). 

81 In Ashwander v. Tennessee Valley Authority, 297 U.S. 288 (1936) minority shareholders of the Alabama Power Company 

claimed that TVA lacked the authority to sell its energy and that the creation of the TVA was unconstitutional. The Supreme Court 

upheld the constitutionality of TVA's (i.e., the Federal Government’s) right to dispose of electricity and property (in this case, the 

sale of surplus electricity by TVA and the purchase of transmission lines from Alabama Power Company). 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

56 Energy Information Administration / Chapter 4: Federal Electricity Programs

cooperatives, 12 percent directly to industrial customers, and 1 percent to Federal agencies.82

In 2006, about one-half of BPA's sales for power and transmission services were to public utility 

districts, city light departments, and cooperatives, another 15 percent was sold to IOUs, and 

roughly one-quarter was sold to aluminum companies and other large industrial concerns. 

WAPA sold nearly half of its power to municipalities and cooperatives, 18 percent to State 

agencies, 6 percent to IOUs, 12 percent to public utility districts, 4 percent to Federal agencies, 

and the remaining 1 percent to other customers.83 In 2006, cooperatives accounted for 57 

percent of SWPA’s power sales, municipals, 25 percent. Two percent was sold to Federal 

agencies.84 

The Federal role in providing electric power is at least a century old and was very prominent in 

the early years of the Nation’s electrification. Federal interventions in electricity markets started 

with the Reclamation Act of 1902 (Public Law 57-161). In large measure, these interventions 

were related to electricity produced at hydropower generation facilities as a byproduct of 

Federally-supported irrigation projects for reclamation of arid lands. At the time, hydroelectric 

power was the Nation’s dominant source of electricity. The Reclamation Act was amended in 

1906 to permit the lease of surplus power to towns and the revenue credited to repay irrigation 

costs.85 The Federal role in marketing electricity from Federally-owned facilities grew rapidly 

during the 1930s. The recipients of preference power were largely municipals and cooperatives. 

Some of the largest hydroelectric power plants were placed in service during this era including 

the Hoover Dam in 1936, the Bonneville Dam in 1938, and the Grand Coulee Dam in 1941. 

Between 1933 and 1941, Federal power accounted for half of the Nation’s new generating 

capacity.86 These projects facilitated electrification and regional economic development.

Federal utilities rely more heavily on hydroelectric power than other electricity producers which 

in general makes their power relatively inexpensive. Although Federal power is widely sold 

throughout the contiguous United States, with the exception of most of the Midwest and 

Northwest, Federal power sales are concentrated in particular geographic areas. The States 

located in the Pacific Northwest87 and the Tennessee River Valley are the largest recipients of 

Federal power.88 This chapter primarily focuses on the Federal utilities, which consist of the four 

PMAs and TVA. 

Federal electric utilities are primarily transmitters and wholesale marketers of electricity 

generated by Federally-owned generating facilities. As required by law, they are not-for-profit 

and are obligated to offer power to statutorily defined preference customers first. Federallyowned utilities are by Federal statute obligated to recover costs and enjoined by law from 

pricing power to make a profit. Preference customers include municipal utilities, cooperatives, 

Indian tribes, State utilities, and irrigation districts. They may also include State governments 

and Federal agencies. After meeting commitments for electricity to preference customers, the 

Federal utilities can and do sell surplus electricity to IOUs in wholesale markets or directly to 

industry. 

 

82 Tennessee Valley Authority, SEC 10-K, 2005, p. 8. 

83 Western Area Power Administration, Statistical Appendix to the 2004 Annual Report. 

84 Southwestern Power Administration, Annual Report 2004-2006, p. 14. 

85 Town Sites and Power Development Act of 1906 (34 Stat.116), codified as 43 USC 522 provided surplus electricity produced at 

hydro projects constructed for irrigation purposes be sold to preference customers. 

86 Ibid, p. 6. 

87 The genesis of Federal power in the Northwest relates in part to the regional strength of the public power movement in the early 

days of electrification. The public power movement during the 1930s was very strong in the State of Washington. In 1936, 15 

districts voted to establish public utility districts. 

88 Most of this hydroelectric power was constructed long ago. Currently, prospects for the expansion of hydroelectric power are 

limited. Particularly in the case of TVA, future expansion of electric generation is likely to be thermal resources. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 57 

The PMAs' electricity generation facilities are owned and operated by the U.S. Department of 

the Interior’s Bureau of Reclamation, the U.S. Army Corps of Engineers, and the International 

Boundary and Water Commission.89 Most of the electricity produced by these facilities is 

marketed by the four PMAs. The yearly financial and operational results for the power purpose 

activity of the Corp of Engineers, the Bureau of Reclamation, and the International Boundary 

and Water Commission are reported in each of the four PMAs’ annual reports as consolidated 

operations. For an example, the SEPA balance sheet, income, and cash flow statements 

consolidate SEPA’s financial data with the Corp of Engineers. TVA, the largest producer of 

Federal power, owns, operates, and markets its own electricity. 

Rural cooperative electric utilities are member-owned, i.e., a cooperative's members and 

customers are one and the same. They are established in rural areas to provide electricity to 

those members. Cooperatives are organized under State law. They are governed in 

accordance with the principles of cooperative operation, which includes: (1) operation on the 

basis of cost; (2) members are entitled to receive a return of, but not a return on, capital they 

contributed to the organization; and (3) governance based on one-member-one vote. The 

organization is governed by a board of directors elected by the membership. Electric 

cooperatives also may qualify as tax-exempt organizations under Section 501(c)(12) of the 

Internal Revenue Code (IRC or Code). There are a number of requirements in the Code and 

Internal Revenue Service (IRS) pronouncements required to qualify for tax-exempt status. The 

most significant requirement is that cooperatives receive at least 85 percent of their income 

from business conducted with members. Cooperatives that meet RUS eligibility requirements 

have access to low-cost Federal government loans and loan guarantees. Cooperatives account 

for roughly 10 percent of electricity sales to ultimate consumers. 

This chapter examines support provided by the Federal government to certain electric power 

customers. This support differs significantly from the subsidies 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 (such as the Low Income Home Energy Assistance 

Program expenditures discussed under direct expenditures in Chapter 2). 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.

Areas Excluded from the Analysis 

This report examines the support that the Federal government provides to electricity that is 

unique to electricity producers. Hence, some means of support provided to electricity is 

excluded because it is not exclusively applied to electricity or it is not Federal in nature. These 

include: 

The ability of publicly-owned utilities to issue tax-exempt debt is not considered in this 

analysis because this benefit is available to government-owned enterprises outside of the 

electric utility industry. Additionally, government entities, including State and municipal 

utilities may issue tax-exempt debt for the benefit of third parties to finance eligible utility 

plant and equipment (e.g., pollution control equipment). 

 

89 Federal utilities provide consolidated financial and operational data for their own operations, as well as for the operations of 

related Bureau of Reclamation and U.S. Army Corps of Engineers power facilities. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

58 Energy Information Administration / Chapter 4: Federal Electricity Programs

The tax-exempt status of electric cooperatives and publicly-owned utilities pursuant to 

Federal tax law and State tax law and corporate law permitting utilities to organize as 

cooperatives or governmentally-owned enterprises is not included in this analysis. These 

benefits exist under Federal and State law for other enterprises operated on a 

cooperative basis and governmentally-owned enterprises. They are not unique to the 

electric utility industry. 

Federal Policies Affecting Power Costs and Pricing 

The prices charged by Federal utilities and RUS borrowers are generally lower than those 

charged by IOUs.90 Prices are generally lower because Federal utilities and cooperatives have 

a distinct legal status and access to low-cost capital. These long-established Federal programs 

include: 

Access to Low-Cost Credit. As a result of a number of Federal government programs (some 

of which date back to the inception of Federal power), in some instances, Federal utilities and 

RUS borrowers have been able to borrow funds at interest rates below prevailing Treasury 

rates.91 In some instances, Federal utilities have been able to borrow at rates linked to Treasury 

rates for debt of comparable maturity or at rates available to government agencies. In other 

instances, Federal utilities borrow at private-sector interest rates, but their creditworthiness is 

enhanced by an implicit Federal guarantee that they will not default on their debt obligations. All 

of these interest rate advantages constitute Federal government support for the Federal 

utilities. 

Access to Low-Cost Generation. Federal utilities are required to sell their electricity 

preferentially to certain users. By law, PMA electricity is sold "at the lowest possible rates 

consistent with sound business principles,"92 which today is less than what the price of power 

would be under competitive market conditions. The "lowest possible rates" require Federal 

utilities to price electricity so as not to earn a profit. Essentially, Federal utilities pass lower 

prices on to statutorily defined preference customers in lieu of profits.93 Charging prices below 

market constitutes price support to particular groups of customers, i.e., preference customers. 

The RUS Electric Program. Rural electric cooperatives, under a program dating from 1935, 

are eligible for low-interest long-term loans from the Federal government, which were made at a 

2-percent interest rate until 1973. Direct loans made between 1973 and 1993 were made at a 

5-percent interest rate, with up to a 35-year term to maturity.94 At the same, the RUS loan 

guarantee program was initiated. Under this program, eligible RUS power supply borrowers 

may obtain loan guarantees to finance generation and transmission projects. Loans made by 

the Federal Financing Bank (FFB) are made at the Treasury’s cost of money plus one-eight of a 

 

90 The exception being the Tennessee Valley Authority, which EIA estimates to have had higher wholesale prices than neighboring 

utilities in 2006. 

91 In general, the extent to which Federal utility average cost of funds is less than the U.S. Treasury’s own cost of raising capital is 

due to the more favorable treatment of past Federal treatment of debt. 

92 The Flood Control Act of 1944 (58 Stat. 887, 890); Department of Energy Delegation Order No. 00-37.00, which is applicable to 

the three smaller PMAs was issued in December of 2001. Delegation Order 00-37.00 directs the Federal Energy Regulatory 

Commission ascertain whether PMA rates are" (a) whether the rates are the lowest possible to customers consistent with sound 

business principles, (b) whether the revenue levels generated by the rates are sufficient to recover the costs of producing and 

transmitting electric energy including the repayment, within the period of cost recovery permitted by law, of the capital investment 

allocated to power and costs assigned by Acts of Congress to power for repayment; and (c) the assumptions and projections used 

in developing the rate components that are subject to Commission review. 

93 The PMAs’ rates fluctuate on the basis of hydrological conditions. In lower water years, they often must purchase higher priced 

wholesale power to meet their contractual obligations. 

94 Rural Utilities Service: http://www.usda.gov/rus/electric/loans/loan_types041118.pdf. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 59 

point.95 In 1993, the Municipal Rate Loan program replaced 5-percent interest rate loans. 

Interest rates for these loans are based on an index of interest rates for municipal bonds. Debt 

remains on the balance sheets of RUS borrowers at interest rates that applied at the time funds 

were advanced, including 2-percent and 5-percent loans.96 At the end of 2005, RUS borrowers 

had roughly $30 billion (2007 dollars) in Federal loans and guarantees.97

Measuring the Support 

For purposes of this report, EIA measured Federal support to TVA, the PMAs, and RUS 

borrowers in term of the their reduced borrowing costs relative to current market interest rates 

stemming from their ability to benefit from (1) borrowing from the Treasury, (2) accessing low 

cost Federal loans and loan guarantees, and (3) the financial markets’ perception of an implied 

Federal guarantee of non-Federal obligations of TVA and BPA. This measure consists of 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 

interest rates. These interest rates include the Treasury’s cost of money and interest rates that 

reflect the variations in credit quality within the general category of investment grade debt (i.e., 

AAA to BBB-) for IOU bonds rated by nationally-recognized rating agencies.98

 

Two other methods for measuring the effect of Federal support to these enterprises include a 

comparison of the prices charged for electricity under Federal programs and an estimate of 

relevant "market" prices. That is, the quantifiable benefit received by preference customers is 

defined as the difference between the cost-based rates charged for Federal power versus the 

rates that would be estimated to prevail in competitive wholesale markets. The third method 

addresses the question: if Federal utilities were allowed to achieve a competitive rate of return 

(similar to IOUs), how much higher would their revenues (and associated electricity prices) be? 

Of the three, the chosen measure of support is the most direct, because interest rate subsidies 

directly reduce the utilities’ borrowings costs. This method is discussed in this chapter. The 

other two methods appear in Appendix B "Alternative Methods of Estimating Federal Electricity 

Subsidies and Interventions.” 

 

95 These loans have up to a 35-year term to maturity. The interest rate is based on the Treasury Department’s cost of money at the 

comparable term to maturity. The interest rate is established when loan funds are advanced. 

96 1987 regulations permitted RUS borrowers to "buyout" their debt at a discount. Thus, the amount of 2-percent and 5-percent 

funds has significantly diminished. 

97 Rural Utilities Service, 2005 Statistical Report Rural Electric Borrowers, I.P. 201-1, Tables 3 and 5. 

98 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 Federal Statistical 

Release H-15 (FRB: 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, FRB: H-15 lacks historical data on constant-maturity 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 debt issuances that go back 50 

years or more, corresponding data are unavailable for U.S. Treasuries and IOUs. For instance, FRB: H-15 reports long-bond 

Treasury rates going back no earlier than 1977. 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. Moreover, 

Federal utilities issue debt with maturities ranging well in excess of 30 years. For instance, for 2007, the TVA reported that 15 

percent of its total debt had a maturity ranging from 31 to 50 years. Furthermore, a portion of BPA’s ENW debt has variable 

interest rates (See: Energy Northwest 2007 Annual Report, p. 54. 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 comparison 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. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

60 Energy Information Administration / Chapter 4: Federal Electricity Programs

Interest Rate Support 

An important element of Federal aid to Federal utilities and RUS borrowers is access to lowcost credit. Low-cost credit means more than raising capital advantageously. It also means a 

potential shift of capital from bond issuers and commercial borrowers with market-based risk 

profiles to entities whose risk is being underwritten by the Federal government. For instance, 

the three smaller PMAs are currently carrying debt at interest rates that result in their average 

cost of embedded debt being less than the Treasury’s current cost of money. In the case of 

RUS borrowers, some past interest paid on insured loans was fixed by statute. Thus, at various 

points in time they were able to borrow at rates below the Treasury’s cost of money.99,100 Some 

Federal utilities receive appropriations, to be repaid as if they were borrowings at, or near, 

Treasury rates or U.S. Government agency rates. Even when Federal utilities borrow by issuing 

bonds, they receive higher credit ratings than would be attained if it were not for the widely-held 

view by the financial community that this debt carries an implicit Federal guarantee. That is, 

notwithstanding that both TVA and BPA state that debt issued to the public is not supported by 

a government guarantee, financial markets believe the government would intervene to prevent 

a default. The magnitude of the resulting support can be computed by comparing the actual 

interest paid with interest that would be paid at various market interest rates. When Federal 

utilities are able to raise funds in capital markets at interest rates lower than those at which they 

could borrow were it not for their Federal government status, a measure of support is conferred. 

Although some Federal utilities borrow at various interest rates under various legal authorities, 

on balance they pay lower rates than privately-owned utilities. In the case of their private sector 

borrowings, the credit markets view Federal utility debt as having an implicit Treasury 

guarantee, although no guarantee in fact exists.101 In its issuer rating of TVA bonds sold in 

2003, Standard and Poor’s assigned the debt an AAA rating. In doing so, Standard and Poor’s 

noted that: "Status (TVA’s) as government agency affords implicit support, monopoly service 

territory, legal authority to set rates without regulatory oversight, low-variable-cost generating 

units leading to competitive rates..." 102 According to Standard and Poor’s, only six U.S. nonbank companies carry an AAA bond rating.103

 

 

99 In general, loans made below the Treasury cost of funds, pursuant to statutory interest rates are of an older vintage and many 

have been paid down. In the case of the RUS lending, loans made prior to 1973 were made at a rate of 2-percent. Between 1973 

and 1993 direct loans were made at a 5-percent statutory interest rate. After 1993, the RUS interest rate structure was tied to rates 

on municipal bonds. 

100 In debt financing the timing of debt issuance and maturities can have an impact upon embedded interest costs. For instance, 

under unusual assumptions, it is theoretically possible for an advantaged borrower, with access to debt financing at interest rates 

lower than those available to an unadvantaged borrower at any particular point in time, to have higher embedded interest costs. In 

such a case, there would be a significant difference in the vintage of each entity’s debt portfolio This might occur if, say, the 

advantaged borrower consistently issued debt during high interest periods, while the unadvantaged borrower consistently issued 

debt during periods when interest rates were low. Practically, this possibility is very remote, as utilities (both Federal and nonFederal) issue debt during most years, with both entities trying to avail themselves of credit in periods when interest rates are 

relatively low. Moreover, both have the ability to restructure their outstanding debt to adapt to changes in interest rate 

environments, such as by refinancing or by paying down high cost debt early. 

101 In its offering statements, TVA discloses in bold print that its bonds: " Will not be obligations of, nor will payment of the principal 

thereof or the interest thereon be guaranteed by, the United States of America.” Source: www.tva.gov/finance/opportun/pdf. 

Accessed February 26, 2008. TVA also states that: “TVA bonds are backed solely by the net power proceeds of the TVA power 

system and are neither obligations of nor guaranteed by the U.S. Government." Source: Tennessee Valley Authority, 

http://www.tva.gov/finance/opportun/. n a Fitch Ratings, Public Power New Issues for Energy Northwest, BPA notes that: “BPA’s 

obligations are not general obligations of the United States government and are not secured by the full faith and credit of the United 

States.” Source: www.bpa.gov/corporate/finance/debt_management/reports_articles_docs/Fitch_03_02_06.pdf, Sourced: February 

25, 2008. 

102 Standard and Poor’s, 

http://www2.standardandpoors.com/portal/site/sp/en/us/page.search/search/0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,0.htmlH. Accessed 

October 15, 2007. 

103 The Economist, "AAAsking for Trouble," July 12, 2007. 
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 Energy Information Administration / Chapter 4: Federal Electricity Programs 61 

As a result, even publicly-issued debt of the Federal utilities is priced at rates below those paid 

by all but the IOUs with ratings at the higher side of the range of the investment grade category. 

TVA- and BPA-backed debt have outstanding debt rated between AA- and AAA. 

A long-standing issue in financial markets has been the degree to which the Federal 

government would prevent a default by government corporations such as the TVA or the 

Federal Deposit Insurance Corporation (FDIC);104 and government-sponsored entities (GSE) 

such as the Federal National Mortgage Association (FNMA) and financial institutions within the 

Farm Credit System (FCS). The debt of these entities carries no explicit guarantee by the 

Treasury. In fact, TVA explicitly states that its debt is not a legal obligation of the Federal 

government.105,106 However, financial markets perceive otherwise, believing that the Federal 

government would not allow TVA to default on its obligations. Although the financial 

community’s assumptions are subject to debate, there is evidence suggesting that their view is 

correct. 

According to a study completed by the Federal Reserve Bank of Richmond, Virginia, twice 

during the 1980s, the Treasury Department provided support to two GSEs—the FNMA and the 

FCS—during times of financial difficulty. The Federal Reserve Bank study noted that in both 

cases the Treasury Department acted to mitigate the increased yield spread between GSE and 

Treasury securities from increasing the Treasury's borrowing costs. In both cases, the Treasury 

made the "implicit guarantee explicit by providing Federal government loans to the GSEs. Once 

the loans were made, the interest spread of the GSE securities and comparable Treasury 

securities narrowed.”107

When rating TVA’s debt, the nationally-recognized credit agencies assume that the government 

will provide support if needed. According to Moody’s Credit Service: "Although TVA’s debt is not 

an obligation of the U.S. Government, the company’s status as an agency and the fact that the 

Government is TVA’s only shareholder, indicates strong ‘implied support’ [that] would afford 

assistance in times of difficulty . . . . This implied support provides important bondholder 

protection." Similarly, according to Standard and Poor’s: "The [AAA] rating reflects the U.S. 

Government’s implicit support of TVA and Standard and Poor’s view that, without a binding 

legal obligation, the Federal government will support principal and interest payments on certain 

debt issued by entities created by Congress. The rating does not reflect TVA’s underlying 

business or financial conditions." Standard financial texts also describe Federal agency debt as 

carrying a "de facto backing from the Federal government." 108 Fitch Ratings notes that its AAA 

rating “reflects TVA’s status as a wholly-owned corporation of the U.S. government and Fitch’s 

assessment of the likelihood and degree of government support for TVA and similarly rated 

institutions. The rating also takes into account “TVA’s strong historical operating and financial 

performance, its solid competitive position (compared to the other highly rated public power 

utilities in the “’AA’” category) and its integral role in developing and supporting the regional 

economy...TVA’s outstanding debt is not a full faith and credit, or limited obligation of the U.S. 

government. However, Fitch believes that U.S. authorities would use extraordinary efforts to 

 

104 OMB characterizes Federal insurance programs as an alternative to direct spending. See, Analytical Perspectives of the 

Budget of the United States, Fiscal Year 2008, p. 67. 

105 General Accounting Office, Tennessee Valley Authority: Financial Problems Raise Questions About Long-Term Viability, 

GAO/AIMD/RCED-95-134 (Washington, DC, August 1995), p. 29. 

106 For example, TVA clearly states that its securities receive no credit enhancement from the Federal government on page 41 of 

its 2006 SEC 10K. “Although TVA is a corporate agency and instrumentality of the United States government, TVA securities are 

not backed by the full faith and credit of the United States. Principal and interest on TVA securities are payable solely from TVA’s 

net power proceeds.” 

107 T.Q. Cook and R.K. Laroche, eds.,” Instruments of the Money Market,” (Richmond, VA: Federal Reserve Bank, 1993). 

108 M. Stigum, “The Money Markets: Myth, Reality, and Practice,” (Homewood, IL: Dow Jones-Irwin, 1978), p. 161. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

62 Energy Information Administration / Chapter 4: Federal Electricity Programs

support their operations and senior debt obligations in the unlikely event that the TVA 

encountered financial difficulties.”109

In addition, TVA’s former chairman has acknowledged the implicit guarantee arising from 

potential pressure on the Treasury to prevent any agency default. According to a quote 

appearing in the March 5, 1997, Wall Street Journal, then TVA chairman Craven Crowell stated: 

"If Congress does anything that devalues us, you always have the potential for the Treasury 

having to get involved."110 Were the Federal government to allow a default by an agency or 

GSE, the ability of all Federal agencies and GSEs to borrow money at favorable rates could be 

affected. The failure of the Federal government to remedy a default could cause financial 

markets to downgrade the value of all government corporations, government agency and GSE 

debt, an action that could significantly affect their borrowing costs and their ability to carry out 

their government mandates. In all likelihood this potential hazard weighs heavily on the Federal 

government to prevent even one default. TVA may have an even closer relationship with the 

Federal government than do the GSEs, which may increase whatever implicit support its debt 

derives. For instance, unlike the GSEs, the Treasury Department treats TVA debt as gross 

Federal debt. TVA’s borrowings accounted for 98 percent of $26 billion in Federal government 

agency debt outstanding as of the end of 2006.111 GSEs had, however, $1.3 trillion in debt 

(2005 dollars) outstanding at the end of 2005, which makes them a considerable component of 

total U.S. credit markets.112 Total Treasury obligations, for instance, equaled $7.9 trillion in 

2005.113,114 In this report, "implicit support" is included in the estimates of total support provided 

by the Federal government to TVA and the PMAs, because the ratings and yields on their debt 

instruments would be different in the absence of Federal government support. 

There are alternative viewpoints on the issue of implicit interest support. These viewpoints 

question whether the Federal government support truly exists in the absence of a binding legal 

obligation to intervene to preclude a TVA default. According to these views, market 

expectations that the Federal government would act to prevent default are a perception and not 

necessarily a reality. Although the market views a TVA debt default as "highly unlikely," there is 

no absolute guarantee that the market is infallible. On the other hand, the Federal government 

ownership of TVA and the overall statutory framework in which it operates appears to be 

sufficient to justify the highest of investment grade credit ratings and attendant lower borrowing 

costs than lesser quality bonds. 

According to a Congressional Budget Office report on GSEs and their implicit Federal subsidy: 

"Agency or GSE status substantially enhances the debt rating of these enterprises...The 

subsidy conveyed is the avoided cost of meeting the standards of credit worthiness. In concept, 

the subsidy has a cost to government equal to the insurance premiums that would be charged 

by a group of highly-rated insurers to guarantee the timely payment of interest and principal on 

GSE debt in the absence of government sponsorship...The implicit guarantee of GSE debt has 

never required a cash outlay by the Federal government. The subsidy that never leads to a 

cash payment may appear not to be ‘real’–that is, not costly. The implicit guarantee of GSE 

 

109 “Fitch Rates Tennessee Valley Auth’s $500 Global Power Bonds 2008 Series A “AAA,” Reuters, 

http://www.reuters.com/article/pressRelease/idUS241174+18-Jan-2008+BW20080118, accessed March 10, 2008

110 J. Ball, "TVA Plan Seen by Critics as Unfair Grab for Power," Wall Street Journal (March 5, 1997), p. 1. 

111 Office of Management and Budget, Analytical Perspectives of the United States Budget 2008, (Washington, DC, 2007), p. 229. 

112 Office of Management and Budget, Analytical Perspectives of the United States Budget 2007, (Washington, DC, 2006), p. 223. 

113 Office of Management and Budget, Analytical Perspectives of the United States Budget 2007, (Washington, DC, 2006), p. 86. 

114 The term "agency debt" is defined more narrowly in the budget than customarily in the securities market, where it includes not 

only the debt of the Federal agencies but also the debt of government sponsored agencies. See, Office of Management and 

Budget, Analytical Perspectives of the United States Budget, Fiscal Year 2006, p. 222. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 63 

debt is costly in terms of alternatives that must be necessarily, if unconsciously, given up by the 

economy."115

 

Larger corporations or financial institutions may also benefit from an implicit guarantee against 

failure. There have been periodic episodes of Federal intervention to prevent their demise, 

giving rise to the “too-big-to-fail” argument. For instance, during the late 1970s, the Federal 

government intervened to assist the Chrysler Corporation, and in 1984 the Federal government 

intervened to help Continental Illinois Bank. In the late 1980s and early 1990s, Federal 

intervention was used to assist the Nation’s Savings and Loan industry, costing the Federal 

government in excess of $100 billion. In all cases, concerns that the failure of these entities 

would have widespread economic repercussions motivated government action. 

 

Unlike TVA, the PMAs are not government corporations; they are line agencies within DOE. 

They submit annual budgets to Congress. Like the TVA, however, one PMA the Bonneville 

Power Administration (BPA) -- does benefit from the implicit support which results from its 

government status. Bonneville Power Administration has nuclear-related obligations. BPA has 

a contractual obligation to pay the debt service on bonds issued by Energy Northwest, the 

successor to the Washington Public Power Supply System. Payments are based on cash flow 

generated from a net billing arrangement between BPA and utilities in the Pacific Northwest.116

In Moody’s High Profile New Issue April 2004 issue, Moody’s states: "Contributing to the Aaa 

rating on the Energy Northwest (ENW) bonds are the evident implicit support by the Federal 

government for Energy Northwest bonds through BPA and BPA’s established record of full cost 

recovery from its business operation and rates."117 Both Standard and Poor’s and Fitch Ratings 

assign AA- issue ratings to BPA’s ENW debt. Standard and Poor’s notes that BPA’s rating is 

based upon the fact that BPA is the obligor for ENW debt and that this debt is “senior to the 

more than $7 billion in Treasury obligations at Bonneville.118 Fitch noted in its 2006 AA-issue 

rating that BPA’s “Payments to the U.S. Treasury are subordinate to ENW bonds, providing 

added security to these instruments.”119

The three smaller PMAs’ (SEPA, SWPA, and WAPA) average embedded cost of outstanding 

debt is below the current cost of borrowing by the U.S. Treasury. In part, this is because DOE 

allows them to repay higher cost debt early whenever possible, a privilege not held by the 

Treasury Department.120 Moreover, before 1983, the three smaller PMAs were allowed to 

finance capital projects at rates lower than the Treasury's cost of money, which also lowers the 

average embedded cost of combined debt currently carried on the PMAs’ books.121

 

115 Congressional Budget Office, Government-Sponsored Enterprises and Their Implicit Government Subsidy: The Case of Sallie 

Mae, (Washington, DC, December 1985), pp. 29-30. 

116 Rating agencies rate both bond issuers and bond issuances. In the case of bond issuers, it is the creditworthiness of the issuer 

that is being rated. In the case of bond issuances, it is the creditworthiness of an obligor with respect to a specific financial 

obligation that is being rated. In this latter category, rating agencies would consider such matters as whether the bond were 

insured, or other forms of credit enhancement. While Moody’s provides Energy Northwest Bonds with an Aaa rating based upon 

the issuer, Fitch and Standard and Poor’s provide Energy Northwest bonds with an AA- rating based upon the issuance. 

117 Moody’s Investors Service, High Profile New Issue, April 2004. 

118 Standard and Poor’s, Ratings Direct, Summary: Bonneville Pwr Admin, or: Utility, Wholesale Electric, March 16, 2006. 

119 Fitch Ratings, Public Power New Issue, Energy Northwest (Bonneville Power Administration, March 21, 2006. Fitch also noted 

that “Positive support for the rating is BPA’s position as a leading provider of electricity and transmission in the Pacific Northwest 

and its highly competitive wholesale power rates derived from its hydro-based system.” 

120 General Accounting Office, Power Marketing Administrations: Cost Recovery, Financing, and Comparison to Nonfederal 

Utilities, GAO/AIMD-96-145 (Washington, DC, September 1996), p. 7. 

121 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. 
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64 Energy Information Administration / Chapter 4: Federal Electricity Programs

In addition to being able to pay off their high-cost debt first, the PMAs also have discretion in 

deciding how to make the annual payments for their appropriated debt to the Treasury.122

These borrowings do not have to be amortized on a straight-line basis, but can occur anytime 

over the maturity of the debt instrument, which can be as long as 50 years for electric 

generating assets. These are appropriations for capital projects only and not appropriations for 

operations, which generally need to be repaid in the current operating year.123 Typically, unless 

the bonds of IOUs, publicly-owned utilities, and a few cooperatives, are callable, interest is paid 

on a current basis, and principal is paid based on the terms of each specific bond issue.124

The analysis in this report 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 constant yield to maturity for 30-year obligations. For the privatesector rates, the benchmarks used are the interest rates paid by utilities using various 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 or otherwise unable to issue tax-exempt debt. This 

measure of support compares the borrowing costs of the Federal utilities with the cost of funds 

realized 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 from 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 2006, interest rates were 

generally lower than in 1998 (Table 18).125 However, in measuring interest support for a single 

year, what matters is the interest rate spread, which reflects the risk premium. Table 18 

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 2006, the average yield on 30-year Treasury bonds was 4.91 percent while the average 

yield on Aaa-rated utility bonds was 5.59 percent, producing a spread of 68 basis points; in 

contrast, the spread between the 5.58 percent 30-year Treasury and the 6.77 percent investorowned Aaa rate in 1998 equaled 119 basis points. 

 

122 Of the 4 PMAs, Bonneville is an exception. Since 1974, Bonneville has not received appropriations from the Congress but 

instead relies on a revolving fund with the Treasury. 

123 A GAO study concluded that the PMAs pay off their high interest debt first and defer repayment of lower interest rate debt. See: 

General Accounting Office, Power Marketing Administrations, Their Ratesetting Practices Compared with Those of Nonfederal 

Utilities, GAO/AIMD-00-114, March 2000, pp. 27-30. 

124 In the Southeastern Power Administrations 2004 Annual Report, it states: "Annual net revenues available for repayment are 

generally applied first against investments in projects bearing the highest interest rates. To the extent that funds are not available 

for payment of such operating expenses and interest, such amounts become payable from the subsequent year’s revenue prior to 

any repayment of the Federal investment." Source: Southeastern Power Administration, 2004 Annual Report, p, 40. 

125 Changes over time in the spread between interest rates of Federal utilities and the benchmark rates they are being measured 

against do not reflect intended changes in Federal support for these electricity programs. Rather, they reflect supply and demand 

conditions in credit markets prevailing in 1998 and in 2006. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 65 

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 2006, the difference in yield between a 30-year Treasury and a Baa IOU rated bond was 

141 basis points. The difference in yield between an Aaa utility rating and Baa utility was 73 

basis points versus 49 basis points in 1998. The level of support therefore rises and falls 

depending on three developments: (1) changes in the yield spread between different debt 

instruments (e.g., Treasuries and utilities); (2) changes in the level of outstanding debt; and, (3) 

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 

The statutory provisions under which Federal utilities operate provide them with independent 

authority to establish electric rates on a cost basis, including the repayment of debt. Similar 

considerations apply to RUS borrowers. Cooperatives set their rates on the basis of cost to 

meet the requirements of IRC Section 501(c)(12). The board of directors is responsible for 

setting rates, subject to regulatory approval in some States. Therefore, it can be argued that 

the benefit of low-cost capital that flows through to Federal utilities’ customers is not a Federal 

support in the absence of a default. With respect to RUS borrowers, the Federal Credit Reform 

Act requires that the interest subsidy associated with RUS loans be included in the budget. The 

methodology used to calculate the subsidy incorporates a default rate and recovery rate. 

Therefore, one can argue that there is no additional support over and above the subsidy 

reflected in the budget. 

The contrary argument is that notwithstanding the statutory framework under which the Federal 

utilities operate, their customers are receiving financial support because there is neither explicit 

recognition of the market risk that is borne by the Federal government in the event of a default 

nor of the opportunity cost to the Federal government’s stakeholders, i.e., taxpayers and the 

customers, in the capital cost associated with the electricity sold by Federal utilities. The value 

of this financial support is a cost to the Federal government which is not quantified and 

assigned to the Federal utilities in the budget. To the extent it is a significant and measurable 

cost, it is reflected in the interest rate set in the market for Treasury securities and in the annual

interest expense on Federal debt included in the budget, compared with the interest rate that 

would otherwise be obtained. 

Table 18. Interest Rates used to Estimate Federal Utilities and RUS Interest Subsidies, 

1998 and 2006 (percent)

 Comparison Debt 1998 2006 

30-Year Treasury 5.58 4.91 

Investor-Owned Aaa 6.77 5.59 

Investor-Owned Aa 6.91 5.84 

Investor-Owned A 7.04 6.07 

Investor-Owned Baa 7.26 6.32 

Sources: The Investor-Owned Aa, A, and Baa Utility rates: Global Insight; Original Source: Moody's Investor 

Services. The Aaa Investor-Owned rate was obtained from the Federal Reserve Bank's Statistical Release H-15 

(FRB: H-15) with the following note: Moody's Aaa rates through December 6, 2006, are averages of Aaa utility 

and Aaa industrial bond rates. As of December 7, 2001, these rates are averages of Aaa industrial bonds only. 

The Municipals were provided by Global Insight. The U.S. Treasury 30-year rate was also obtained from 

FRB: H-15. Treasury rates reflect constant maturities. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

66 Energy Information Administration / Chapter 4: Federal Electricity Programs

In order to estimate the value of the financial support provided to the customers of the Federal 

utilities, EIA has adopted a cost-of-capital approach that estimates the value based on the 

difference between the interest expense that Federal utilities actually paid in 2006 versus what 

they would have paid under a range of contemporaneous interest rates to their outstanding 

debt. The interest rates range from the risk-free Treasury rate to the highest interest rate for 

IOU bonds. For purposes of estimating the value of Federal financial incentives provided 

directly and indirectly to electricity production be expressed on a unit of production basis, EIA 

used the interest rate associated with an A-rated IOU bond to compare with Federal utilities’ 

weighted average cost-of-capital. 

The 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 face amount of each original loan or bond and present value of each loan 

or bond issue at the market rate of interest at the time the obligation was incurred. The data 

required to perform this alternative analysis would be extremely complex, and in any event, 

were not available to EIA. 

Opinions vary with regard to the extent to which there is a significant risk premium between the 

risk-free Treasury rate and the market rate of interest that Federal utilities would be required to 

pay in the absence of their ownership status and the statutory framework under which they 

operate. This is true with respect to TVA and BPA, both of which have received AAA and AA 

ratings, as well as imputing a market interest rate to the smaller PMAs. In order to develop a 

point estimate of the value of the support provided to the customers of the Federal utilities, EIA 

performed a financial ratio analysis that compared TVA and the PMAs to comparably structured 

governmentally-owned wholesale power suppliers. The financial ratios measure an entity’s 

ability to meet its debt and other fixed obligations, such as lease payments. This approach was 

adopted in order to neutralize any actual or perceived credit enhancement that financial 

markets attribute to Federal ownership and/or the ability to borrow at the Federal government’s 

cost of funds or at interest rates comparable to GSE interest rates. This resulted in the 

adoption of a market interest rate associated with an A credit rating. Limiting the derivation of 

the market interest rate to consideration of only liquidity-related financial ratios allowed for 

uniformity in EIA’s analysis and eliminated the effects of actual or perceived credit 

enhancement attributed to Federal support provided in accordance with Federal statutes 

applicable to the Federal utilities. Therefore, the rating used to develop a point estimate of the 

value of Federal support should not in any way be construed as an alternative to actual credit 

ratings issued by the nationally-recognized credit rating agencies. The rating agencies’ 

consider a multitude of factors in addition to financial performance in developing credit ratings 

that were not considered by EIA. 

The interest support associated with the benchmark A rated IOU bond is used only for purpose 

of estimating the generation portion of the support by fuel type. The benchmark A rating was 

selected for purposes of calculating the support based on a comparison of financial metrics for 

the Federal utilities and RUS borrowers to data compiled by Fitch Ratings for comparable 

wholesale public power entities (i.e., rated generation and transmission cooperatives (G&T), 

and public power agencies) and retail public power systems that purchase their power supply 

requirements. The financial metrics are standard measures used by the financial community to 

assess creditworthiness. Fitch Ratings defines the debt service coverage ratio (DSC) as the 

ratio of funds available to meet debt service payments (FADS) to annual debt service 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 67 

payments, i.e., principal and debt service. Numerically, it illustrates how much free cash flow is 

available to meet debt service payments and other fixed obligations after taking into account 

operating expenses. A 1.0 DSC indicates that a business has FADS exactly equal to annual 

debt service payments. A DSC of less than 1.0 indicates the enterprise is not generating 

sufficient cash flow to meet its debt service payments and other fixed obligations treated as 

debt for purposes of assessing creditworthiness. It should be noted that government-owned 

utilities such as Federal utilities and G&T cooperatives financed by RUS borrowers, by virtue of 

their ownership structure, rely primarily on long-term debt to finance capital investments, unlike 

investor-owned utilities that finance capital investment through a combination of debt and 

equity. The Federal utilities and G&Ts’ rates are set with the intention of insuring that sufficient 

free cash flow is available after operating expenses to cover annual debt service payments and 

to accrue equity.126 Accordingly, their DSC ratios are typically lower than that of IOUs. 

Days of cash on hand provides a gauge of the amount of cash immediately available to 

respond to unforeseen events such as the purchase of replacement power due to an 

unscheduled outage of a power plant, or increases in other operating expenses. Days of 

liquidity adds other sources of cash such as commercial paper and credit lines. High levels of 

unrestricted cash and liquidity on hand provide a measure of the enterprises ability to meet 

contingencies from cash generated by 

operations and short-term borrowing, and 

still be able to meet debt service and other 

fixed obligations. Variable rate exposure 

(VRE) quantifies the net amount of 

outstanding debt and the VRE-tocapitalization measures the portion of total 

capitalization that is subject to interest rate 

risk. The higher the ratio, the greater the 

exposure to an increase in interest rates 

and interest expense. If all other factors 

remain constant, i.e., revenue, operating 

expenses and depreciation expense 

(which is a source of cash) financial risk 

increases. This is because free cash flow 

will decline. 

The ratio of total debt to funds available for 

debt service (Debt/FADS) measures the 

factor by which total debt exceeds cash and 

short-term credit instruments. In effect it 

measures how much cash is available to 

meet total debt and fixed obligations in the 

event of default and an acceleration of the 

payment of such obligations. A low 

Debt/FADS ratio indicates the enterprise 

has adequate cash and liquidity and lower 

financial risk relative to comparable 

businesses with higher ratios. 

 

126 The PMAs’ audited financial statements refer to equity as Accumulated Net Revenue. For example, in 2006, BPA reported $1.9 

million in Accumulated Net Revenue. Fitch Ratings refers to the same value as equity in its March 16,2007 issue rating for Energy 

Northwest 2007 A-D refunding and revenue bonds which BPA is obligated to pay. 

Fitch Ratings Definitions of Selected Financial Terms 

• Debt Service Coverage (DSC): Funds Available for Debt Service 

Divided by Total Annual Debt Service. 

• Funds Available for Debt Service (FADS): The sum of operating 

income, depreciation and amortization, and interest income. 

• Total Annual Debt Service: Sum of scheduled long-term principal 

and annual short- and long-term debt interest payments. 

• Total Debt (Debt): Sum of long-term debt (including capital leases) 

plus commercial paper, notes payable, current maturity of long-term 

debt (including capital leases). No adjustment is made for 

unamortized discounts or premiums. 

• Debt- to-FADS: The ratio of total debt to funds available for debt

service. 

• Unrestricted Cash: Cash that is available for immediate liquidity 

needs, with flexible (e.g., board or management policy) or no 

limitations on use.

• Days of Cash on Hand: 

Numerator = Unrestricted cash and investments. 

Denominator = Operating expenses less depreciation.

Multiplied by 365. 

• Days Liquidity on Hand: 

Numerator = Unrestricted cash + available lines of credit + 

commercial paper capacity. 

Denominator = Operating expenses less depreciation.

Multiplied by 365. 

• Capitalization: The sum of total debt and total equity.

• Variable Rate Exposure (VRE): The sum of variable rate debt, 

outstanding commercial paper and fixed-to-variable-rate swaps less 

variable-to- fixed-rate swaps. 

• Variable Rate Exposure-to-Capitalization: Ratio of VRE to 

Capitalization 

Source: Fitch Ratings, U.S. Public Power Peer Study, June 2007, 

pp.27-28. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

68 Energy Information Administration / Chapter 4: Federal Electricity Programs

Fitch Ratings classifies its bond ratings according to the primary activity of the rated entity. 

Entities such as joint municipal action agencies, public power authorities, G&Ts, TVA and BPA 

are classified as wholesale systems. Fitch Ratings provides financial statistics that measure the 

ability of wholesale systems to meet their fixed obligations based on certain measures of 

liquidity. The definitions of formulas and financial inputs to the formulas developed by Fitch 

Ratings that are used in EIA’s analysis are provided (see text box: Fitch Ratings Definitions of 

Selected Financial Terms). 

 

The comparison of TVA’s financial metrics to all wholesale suppliers rated by Fitch Ratings 

shows that with the exception of its DSC and debt as a percentage of funds on hand, TVA’s 

remaining metrics are consistent with median values for wholesale systems in the A to BBB 

range (Table 19). An A rating appears to be a reasonable benchmark comparison for TVA 

when its high debt service coverage ratio and days’ liquidity on hand are balanced against the 

remaining metrics that in some instances fall below the median value for the lowest investment 

grade rating (BBB). 

The comparison of BPA’s financial metrics to all wholesale suppliers rated by Fitch Ratings 

shows that with the exception of the DSC and equity as a percentage of total capitalization, 

BPA’s financial metrics are consistent with the median values of wholesale systems within the A 

to AA range (Table 19). The DSC at 1.26 is slightly below that of the median value for A rated 

Table 19. Median Financial Ratios: Investment Grade Rated Wholesale Public Power Suppliers

Debt 

Service 

Coverage 

Equity as 

Percent of 

Total 

Capital 

Debt/FADS 

Ratio 

Days 

Cash On 

Hand 

Days 

Liquidity 

on Hand 

VRE as 

Percent of 

Capitalization 

BPA (FY ending 2006) 1.26 13 8.0 204 235 NA 

TVA 1.95 10 8.2 32 183 9.0 

Median Value for All Rated Wholesale Suppliers 

AA (All Wholesale 

Systems 1.70 27 7.0 98 200 3.0 

A (All Wholesale Systems) 1.29 17 8.6 74 126 5.0 

BBB (All Wholesale 

Systems) 1.18 5 9.8 92 143 4.0 

Median Value for All Rated G&Ts 

AA (G&Ts) 1.42 30 6.1 135 199 5.0 

A (G&Ts) 1.10 18 8.2 29 139 1.5 

BBB (G&Ts) 1.15 11 9.0 52 155 8.0 

NOTE: A borrower’s desired liquidity on hand can in turn be affected by its credit status in that having a higher 

credit rating might allow the borrower more ready access to borrowing short-term funds. 

NA: No ratio provided by Fitch Ratings. 

Sources: Fitch Ratings, U.S. Public Power Peer Group Study, June 2007, p. 18; Fitch Ratings, Public Power New 

Issue, Energy Northwest (Bonneville Power Administration), March 16, 2007, 

www.bpa.gov/corporate/Finance/Debt_Management/reports_articles/ 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 69 

wholesale systems (1.29).127 However, BPA’s days of cash on hand and days of liquidity 

exceed the median values for AA-rated wholesale systems. This tends to mitigate against the 

low DSC. Based on this analysis, EIA has also adopted an A rating for purposes of 

benchmarking BPA’s Federal interest rate support in this report. 

With respect to the smaller PMAs, EIA also selected the benchmark A rating based on a review 

of their audited financial statements. SEPA reported its DSC ratio has ranged from 0.38 to 1.30 

between 2001 and 2005. It has exceeded 1.0 for the 3-year period ending in 2005. During this 

period, SEPA’s DSC was within a range consistent with that of the median DSC for wholesale 

systems rated with BBB to A ratings by Fitch Ratings.128 SWPA and WAPA reported operating 

losses in 2005. However, they were able to meet their obligations to the Treasury and appear to 

have adequate cash reserves. Accordingly, an A rating was assumed for purposes of 

estimating the market value of their respective interest support levels. 

The ratings data suggest an A rating is appropriate for the RUS loans for generation and 

transmission facilities made to G&Ts. Fitch Rating’s financial data include 39 public power 

authorities and G&Ts. Among these 39 entities are 14 G&Ts. Of these 14 G&Ts, 10 received 

Secured Debt ratings ranging from A- to A+. Three received AA Secured Debt ratings 129 and 

1 received a BBB+ ratings.130 Their total RUS debt was $8.5 billion, which was equivalent to 55 

percent of RUS loans to G&T at the end of 2005.131

The benchmark interest rate for an A-rated IOU bond is also used to estimate the support 

associated with the distribution cooperative segment of the RUS loan portfolio. This is based on 

the use of the National Rural Utilities Cooperative Finance Corporation’s (CFC) credit ratings as 

a proxy for the creditworthiness of RUS distribution borrowers. CFC provides interim 

construction, permanent financing, and loan guarantees to G&Ts. It also provides supplemental 

loans to RUS distribution cooperatives and total financing to former RUS distribution borrowers. 

For its fiscal year ending May 31, 2006, CFC reported $12.9 billion of distribution loans and 

$3.7 billion of power supply loans and loan guarantees. Collectively, these loans and loan 

guarantees accounted for 86 percent of its total portfolio.132 CFC’s Senior Secured and Senior 

Unsecured debt received A1 and A2 ratings, respectively, from Moody’s and A ratings from 

Standard & Poor's and Fitch. Given that CFC’s secured debt is secured by its loan portfolio, and 

given the breadth of its electric cooperative loan portfolio, it is reasonable to use CFC’s A rating 

as a proxy for RUS distribution debt.133

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 

 

127 Fitch Ratings reports that BPA’s 2006 DSC was 4.93 for non-Federal Project debt issued by Energy Northwest. The terms 

under which BPA has assumed the payment obligation for this debt provides that debt service payments to the Federal government 

are subordinated to Energy Northwest, i.e., Energy Northwest bondholders have payment priority over the Federal government. 

The 1.26 DSC includes BPA’s Federal and non-Federal obligations. 

128 Southeastern Power Administration, Annual Report 2005, p. 26. 

129 Georgia Transmission Corporation, an RUS financed transmission cooperative received an AA rating by Fitch. 

130 Three of the G&Ts rated by Fitch, Old Dominion Electric Cooperative (A rated Senior Debt), Great River Energy (A- rated Senior 

Debt), and Golden Spread Electric Cooperative (A- rated Senior Debt), are no longer RUS borrowers. 

131 The credit rating agencies’ criteria for wholesale systems include an examination of the financial strength and service territories 

of the members of a G&T. Basin Electric Power Cooperative and Associated Electric Cooperative members include 14 G&Ts, of 

which 12 are RUS borrowers. Collectively, the outstanding RUS debt of these 12 G&Ts, excluding Tri-State Generation and 

Transmission Association which is included in the $8.5 billion of rated G&T debt, in 2005 was $296 million. Associated and Basin 

are rated AA and AA- , respectively, by Fitch Ratings. 

132 National Rural Utilities Cooperative Finance Corporation, 2007 SEC 10-K, p. 33. 

133 For Moody's rating see, www.nrucfc.org/investors/pdfs/cfc_credit_opinion.pdf. For Standard and Poor's rating see 

www.nrucfc.org/investors/pdfs/cfc_sp_analysis.pdf. For Fitch's rating see, www.nrucfc.org/investors/pdfs/fitch_02-23-07.pdf, 

accessed December 10, 2007. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

70 Energy Information Administration / Chapter 4: Federal Electricity Programs

analysis. A more complicated method would be to measure the interest paid by Federallysupported 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 bonds are callable, which means it may not 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 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.134

 

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.135 In lease/lease back arrangements, the TVA "leases" TVA generation assets 

to investors for a one-time cash payment used to retire debt.136 In turn, the TVA leases back the 

plants and makes periodic lease payments.137 The second 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. 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. 

TVA’s debt in 2006 received an Aaa bond rating. The imputed interest expense in 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 obligation 

and the unamortized balance of the prepayment which is TVA’s power supply obligation to 

those who prepaid. The Aaa interest rate expense was then compared to what the TVA would 

pay in interest with a lower bond rating. 

 

134 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. 

135 In general, lease/leaseback 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. 

136 TVA’s lease/leaseback arrangements also include a secondary lease with structured payments over time.

137 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 its 

value in this report. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 71 

For the PMAs, the debt values and interest expenses were obtained from their 2006 annual 

reports. Having actual data on both PMAs' long-term debt and interest on long-term debt allows 

for a comparison of what that interest might be if PMA’s borrowed at IOU rates. The three 

smaller PMAs have embedded cost of debt below the current 30-year Treasury rate. Although 

currently all new debt issued by the three smaller PMAs is at or near prevailing Treasury rates, 

much of their old debt bears interest well below that of similar Treasury debt with comparable 

maturities at today’s rate. Furthermore, unlike TVA, the three smaller PMAs have an advantage 

unavailable to the Treasury itself in that DOE allows the retirement of high-interest debt first. 

Therefore, borrowing costs for the 3 smaller PMAs were also measured against borrowing costs 

at the Treasury rate along with the interest rates for investment grade IOU bonds rated Aaa, 

Aa, A, and Baa. However, the comparison with an A rating is used as the benchmark. 

Tennessee Valley Authority 

The TVA was established in 1933 under the Tennessee Valley Act (Public Law 73-17). Its 

original purpose was to promote economic development in the Tennessee Valley, to improve 

navigation, and to aid in flood control. TVA is far and away the largest of the Federal utilities, 

having an asset base greater than that of the four PMAs combined. TVA is operated as an 

independent government-owned corporation. Its nine-member board of directors is solely 

responsible for setting rates and for policymaking.138 The board is appointed by the President of 

the United States. Unlike the other Federal utilities, TVA’s hydropower accounts for a relatively 

small share of its total generation. In 2006, generation from fossil fuels accounted for 64 

percent of TVA’s total generation, while nuclear generation accounted for 29 percent, and 

hydroelectric generation accounted for 6 percent.139 TVA’s service territory covers 8.7 million 

people located in nearly all of Tennessee and parts of Alabama, Kentucky, North Carolina, 

Mississippi, Georgia, and Virginia. Tennessee accounted for 64 percent of TVA’s electricity 

sales in 2006. Its wholesale customers include 108 utilities and 20 electric cooperatives. TVA 

received 87 percent of its revenue from cooperatives in 2006. Memphis Light Gas and Water 

Division and Nashville Electric Services are the largest utility customers of TVA. The United 

States Enrichment Corporation is the largest direct service industrial customer.140

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 2006, long-term debt stood at $26 

billion.141 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 programs. Funding for these 

programs has been derived from user fees, other revenues, and electricity sales. 

A number of explicit and implicit benefits are received by TVA due to its status. For example, 

TVA receives implicit interest rate support via a favorable debt rating since it is owned by the 

 

138 Unlike the PMA administrators who receive their appointments through the Department of Energy, the TVA’s commissioners 

receive their appointments from the President. The Consolidated Appropriations Act of 2005 restructured the board to include nine 

part time commissions from the previous three full time commissioners. The commissioners are appointed for 5-year terms as 

compared to the 9-year term appointments under the previous regime. A Chief Executive Officer is to be chosen by the ninemember board. The board is responsible for establishing the broad goals, objectives, and policies of the Corporation and approving 

an annual budget. Source: Public Law 108-447. 

139 Tennessee Valley Authority, SEC 10-K, 2006, pp. 6, 14, 11, 18. 

140 Tennessee Valley Authority, SEC 10-K, 2006, pp. 9 and 11. 

141 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. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

72 Energy Information Administration / Chapter 4: Federal Electricity Programs

Federal government. In general, TVA borrows at rates comparable to those of Federal 

government agencies. In addition, TVA’s customers are required to provide up to 10-years 

notice before they are allowed to switch their service to another utility. This provides for stability

in TVA’s revenue from electricity generation. It is also exempt from antitrust laws, an exemption 

IOUs and the other Federal utilities do not enjoy. EPAct1992 provided an exemption for TVA 

from amendments to the Federal Power Act that enhanced the Federal Energy Regulatory 

Commission’s (FERC) authority to order utilities to provide transmission service. This exemption 

is referred to as the "anti-cherry picking" advantage.142,143 The anti-cherry picking provision 

although regulatory (and not included as a Federal support in this report) reinforces the 

financial community’s perception that TVA bonds are virtually a risk-free investment.144

However, the TVA Act of 1959 places strict limits on how much power the 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. 

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.145 

Based on these factors, EIA adjusted TVA’s outstanding debt to reflect two obligations, which 

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 (1) obligations 

pursuant to two lease/lease back transactions associated with 24 generating plants and other 

system electric system facilities and (2) future 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.146 

In 2006, the TVA carried over $1.1 billion (2007 dollars) in lease/lease back liabilities on its 

balance sheet and energy prepayment obligations totaling $1.2 billion (2007 dollars). 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.147 In the FY 2008 budget, the OMB determined "that each of these methods 

(lease/lease back obligations and prepayment financing methods) is a means of financing the 

 

142 General Accounting Office, Tennessee Valley Authority, Debt Reduction Efforts and Potential Stranded Costs, GAO-01-327, 

(Washington, DC, February 2001), p. 6. 

143 General Accounting Office, Tennessee Valley Authority, Assessment of 10-year Business Plan, GAO/T-AIMD-99-295, 

(Washington, DC, September 1999), p. 2. 

144 In July 2005, a bill was introduced (S.1499) that would effectively remove any area within Kentucky from coverage by the anticherrypicking provision. This bill would require the FERC to mandate that the TVA wheel power from a supplier other than TVA for 

use inside that portion of TVA’s service area that is within Kentucky. 

145 Tennessee Valley Authority: http://www.tva.gov/foia/readroom/policy/prinprac/bun24.htm, accessed October 11, 2007. 

146 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 2006, TVA reported $1.2 billion (2007 dollars) liability in energy prepayment 

obligations. 

147 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; accessed October 11, 2007. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 73 

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."148 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."149 GAO also noted that GAAP does not 

require that the lease/lease back arrangements be classified as debt. 

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."150 TVA records lease/lease back transactions and power

prepayment obligations—along with more traditional forms of debt—as Total Financial 

Obligations (TFOs). In the President’s 2007 budget, the TVA indicated that it intended to reduce 

its TFOs by $7.8 billion by 2016.151

In 2006, TVA had outstanding long-and short-term debt of $26 billion (Table 20), which 

compares to the $33 billion in debt it reported in 1998 (2007 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 presents a measure of the value of TVA’s interest rate support. This report 

uses TVA’s Aaa bond rating as a comparison to other interest rates for purposes of measuring 

Federal support. In other words, if TVA borrowed money at the Aa rate rather than the Aaa rate, 

its borrowing costs in 2006 would increase 25 basis points, or result in $65 million (2007 dollars) 

in additional interest expense. This is one measure of Federal support. An A bond rating would 

raise TVA’s 2006 borrowing costs by $124 million (2007 dollars), and the Baa rating by $189 

million (2007 dollars). In 1998, an Aa rating would have raised TVA’s borrowing costs by $46 

million (2007 dollars), an A rating by $88 million (2007 dollars), and a Baa rating by $160 million 

(2007 dollars). Although the basis point spread between the 30-year Treasury and 

corresponding utility rates narrowed between 1998 and 2006, the spread between the Aaa 

utility bonds and all other investment-grade rated utility bonds increased, thereby increasing the 

estimated support going to the TVA despite lower interest costs and lower debt outstanding. 

For purposes of a point estimate for this report, the comparison with an A rating yield support of 

$124 million is used. 

 

148 Office of Management and Budget, Analytical Perspectives of the United States Budget, Fiscal Year 2008, (Washington, 2007), 

p. 229. 

149 General Accounting Office, Information on Lease-Leaseback and Other Financing Arrangements, GAO-03-784, (Washington, 

DC, June 2003). 

150 Tennessee Valley Authority, SEC 10-K, 2006, p. 42.

151 Tennessee Valley Authority, http://www.tva.gov/news/reduction_tfo.htm, accessed October 11, 2007. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

74 Energy Information Administration / Chapter 4: Federal Electricity Programs

Table 20. Estimate of Federal Electricity Interest Rate Support to TVA, 1998 and 2006 

(million 2007 dollars)

Treasury 

Rate 

Aaa IOU 

Rate 

Aa IOU 

Rate A IOU Rate 

Baa IOU 

Rate 

1998 

1. Benchmark Interest Rate (%) 5.58 6.77 

 

6.91 

 

7.04 

 

7.26 

2. Outstanding Debt ($) 32,678 32,678 

 

32,678 

 

32,678 

 

32,678 

3. Average Cost of Outstanding Debt (%) 6.77 6.77 

 

6.77 

 

6.77 

 

6.77 

4. Actual Interest Expense ($) 2,212 2,212 2,212 2,212 2,212 

5. Interest Expense Computed at Benchmark Rate 

($) [(1) x (2)] 

 

1,823 

 

2,212 

 

2,258 

 

2,301 

 

2,372 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] (389) 0 

 

46 

 

88 

 

160 

2006 

1. Benchmark Interest Rate (%) 4.91 5.59 

 

5.84 

 

6.07 

 

6.32 

2. Outstanding Debt ($) 25,848 25,848 

 

25,848 

 

25,848 

 

25,848 

3. Average Cost of Outstanding Debt (%) 5.59 5.59 

 

5.59 

 

5.59 

 

5.59 

4. Actual Interest Expense ($) 1,445 1,445 

 

1,445 

 

1,445 

 

1,445 

5. Interest Expense Computed at Benchmark Rate 

($) [(1) x (2)] 1,269 1,445 

 

1,510 

 

1,569 

 

1,634 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] (176) 0 65 124 189 

NOTES: The table above presents the historic value of TVA’s debt in 2007 dollars for purposes of illustrating how the 

support values for 1998 and 2006 were calculated. The nominal value of debt reported on TVA’s balance sheet was at 

$26,582 million in 1998. 

 

A negative value for estimated interest support indicates that the weighted average cost of outstanding debt exceeds the 

benchmark interest rate. 

Sources: Tennessee Valley Authority Annual Report 1998 and SEC 10-K, 2006, Moody's Utility Manual, Federal 

Reserve Bank Form H-15, and Table 18. 

The Power Marketing Administrations 

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 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 75 

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." 

The PMAs sell about 5 percent of the Nation’s electricity, virtually all of it wholesale. BPA's 

service territory covers Washington, Oregon, and small pieces of western Montana and western 

Wyoming. WAPA covers California, Nevada, Utah, Arizona, New Mexico, Utah, most of 

Montana, most of Wyoming, west Texas, North and South Dakota, Nebraska, western and 

southern Kansas, and the western edges of Minnesota and Iowa. The SWPA serves the rest of 

Kansas, Missouri, and Oklahoma, the rest of Texas, Arkansas, and Louisiana. The SEPA 

serves Illinois, West Virginia, Kentucky, Tennessee, Mississippi, Alabama, Georgia, and the 

Florida panhandle, North and South Carolina, and Virginia. 

BPA’s Borrowing Costs 

BPA receives no direct payment from the Treasury. Rather, the support it receives is implicit, 

involving 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 contribute. 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, as discussed below. For purposes of a point estimate for 

this report, a comparison with A-rated debt is used (Table 20). 

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.152 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 1996153 (The Refinancing Act), BPA reduced its principal 

obligation of the debt by $2.5 billion based on the present values 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 1996.154 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 

 

152 This includes some funding for fish and wildlife recovery. 

153 16 U.S.C. 838l. 

154 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 2006, BPA’s appropriated debt stood at $6.4 billion. This includes a capitalization adjustment of $2.1 

billion, which was included under appropriated debt prior to 1997. In 1997, the principal on BPA’s appropriated debt was reduced by 

$2.6 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. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

76 Energy Information Administration / Chapter 4: Federal Electricity Programs

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 to amortize 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. 

In 2006, BPA’s appropriated debt plus the Capitalization Adjustment equaled $6.4 billion (2007 

dollars) versus $8.4 billion in 1998 (2007 dollars). The nominal value of BPA’s appropriated 

debt was $6.9 billion in 1998. BPA’s estimated interest rate on its average embedded cost of 

funds was 4.3 percent in 2006. 

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 2006, BPA’s long-term debt equaled 

approximately $1.9 billion versus $2.8 billion in 1998 (2007 dollars). The nominal value of 

BPA’s debt equaled $2.4 billion in 1998. 

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 1980s, WPPSS defaulted on nuclear units 4 and 5.155 WPPSS is 

now known as Energy Northwest. 156 Energy Northwest is responsible for the financing of 

Nuclear Projects 1, 2, and 3.157 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 plant158,159

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.160 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.161 

 

155 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 

156 Unit 4 is located at Richland, Washington while unit 5 is located at Satsop, Washington. 

157 The only operating unit among these is Project 2, the Columbia Generating Station. 

158 The Trojan project is among Bonneville’s terminated nuclear plants along with Energy Northwest Nuclear Projects 1 and 3. 

159 BPA charges preference customers’ entitlement shares of output from the abandoned Trojan project. BPA became responsible 

for Trojan’s debt service and decommissioning costs. 

160 Bonneville Power Administration: http://www.bpa.gov/Power/PSR/pbl_billing_procedures.pdf, accessed October 11, 2007. 

161 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. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 77 

In 2006, approximately $4.0 billion of BPA’s $6.6 billion (2007 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 line agency within DOE, and for its latest debt financing in 

2007, Standard and Poor’s and Fitch Ratings assigned newly issued Energy Northwest revenue 

and refinancing bonds an AA- rating.162 Moody’s rated the bonds as Aaa.163 According to 

Moody’s: "The Aaa rating is rooted in the strength of the legal arrangements between Energy 

Northwest and the Federal entity that provides the underlying security for the bonds, Bonneville 

Power Administration...Credit strength is derived from BPA’s status as a line agency of the U.S. 

Department of Energy and the strong relationship with the U.S. Government that allows for 

direct borrowing authority with the U.S. Treasury and the legal ability to defer annual Treasury 

repayment when necessary to meet commitments under the net billing agreements."164,165 In 

Moody’s High Profile New Issue, dated April 2004, the credit rating agency states: "Contributing 

to the Aaa rating on the Energy Northwest bonds are the evident implicit support by the Federal 

government for Energy Northwest bonds through BPA and BPA’s established record of full cost 

recovery from its business operation and rates."166 In providing its AA- rating to Energy 

Northwest debt, Fitch notes that payments of debt to the U.S. Treasury is subordinate to 

payment on Energy Northwest debt. Fitch also notes that the positive support for the rating is 

BPA’s position as a leading provider of electricity and transmission in the Pacific Northwest and 

its highly competitive wholesale power rates. 

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 

methodology 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 a Federally-owned 

utility.167 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. 

BPA’s Federal Interest Support 

The difference between 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 (Table 21). Borrowing at the Treasury 30-year bond rating would have 

cost BPA an additional $19 million, in 2006. Borrowing at a public utility rating of Aaa would 

have cost BPA an additional $120 million (2007 dollars); an Aa rating would have cost BPA an 

additional $157 million (2007 dollars); an A rate would have cost BPA an additional $191 million 

(2007 dollars) over its 2006 interest charges; and, a Baa rating an additional $228 million (2007 

 

162 Standard and Poor’s Public Finance, Bonneville Power Administration: 

http://www.bpa.gov/corporate/Finance/Debt_Management/reports_articles/docs/2007/S%20&%20P%20Report.pdf. Accessed 

October 15, 2007. 

163 S&P and Fitch have provide issue ratings that are applicable to the specific bonds. Moody’s has provided an issuer rating 

corporate rating that applies to the enterprise and not specific bond issues. 

164 Bonneville Power Authority, Ratings Update: Energy Northwest, WA, March 19, 2004, 

http://www.bpa.gov/corporate/Finance/Debt_Management/reports_articles/docs/Moodys_3_19_04.pdf, accessed October 11, 2007. 

165 Net billing agreements are an arrangement under which the more than 100 Northwest utilities purchased all of the project 

capability of Nuclear Project No. 1, Columbia and Energy Northwest’s 70 percent ownership of Nuclear Project No. 3. These utilities 

resold their electricity to BPA and in return BPA is required to finance the annual costs of these projects. Source: Energy 

Northwest, http://www.energy-northwest.com/annualbudgetdownloads/Final%202008%20Glossary.pdf, accessed October 11, 

2007. 

166 Moody’s Investors Service, High Profile New Issue, April 2004. 

167 Certain Energy Northwest bond issues are also enhanced with bond insurance. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

78 Energy Information Administration / Chapter 4: Federal Electricity Programs

dollars). These values represent an increase from 1998 when, for instance, borrowing at an A 

rating would have raised BPA’s borrowing costs by $138 million over the Treasury rate. A large 

portion of the reduction in borrowing costs can be attributed to the $4.7-billion reduction in debt 

between 1998 and 2006. For purposes of a point estimate for this report, the comparison with 

the A rating is used. 

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 the 2007 budget, the OMB proposed that the 

Table 21. Estimate of Federal Electricity Interest Rate Support to BPA, 1998 and 2006 

(million 2007 dollars) 

Treasury 

Rate 

Aaa IOU 

Rate 

Aa IOU 

Rate A IOU Rate Baa IOU Rate 

1998 

1. Benchmark Interest Rate (%) 5.58 

 

6.77 

 

6.91 

 

7.04 

 

7.26 

2. Outstanding Debt ($) 19,610 

 

19,610 

 

19,610 

 

19,610 

 

19,610 

3. Average Cost of Outstanding Debt (%) 6.34 

 

6.34 

 

6.34 

 

6.34 

 

6.34 

4. Actual Interest Expense ($) 1,243 

 

1,243 

 

1,243 

 

1,243 

 

1,243 

5. Interest Expense Computed at Benchmark Rate 

($) [(1) x (2)] 1,094 

 

1,328 

 

1,355 

 

1,381 

 

1,424 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] (149) 

 

85 

 

112 

 

138 

 

181 

2006 

1. Benchmark Interest Rate (%) 

 

4.91 

 

5.59 

 

5.84 

 

6.07 

 

6.32 

2. Outstanding Debt ($) 14,810 14,810 

 

14,810 

 

14,810 

 

14,810 

3. Average Cost of Outstanding Debt (%) 

 

4.78 

 

4.78 

 

4.78 

 

4.78 

 

4.78 

4. Actual Interest Expense ($) 708 708 

 

708 

 

708 708 

5. Interest Expense Computed at Benchmark Rate 

($) [(1) x (2)] 727 828 

 

865 

 

899 

 

936 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] 19 120 157 191 228 

NOTES: BPA’s debt values are exclusive of BPA’s current liabilities. BPA’s current liabilities consist of payments to the 

Treasury to fund Federal post retirement programs and irrigation assistance programs. The table above presents the 

historic value of BPA’s debt in 2007 dollars for purposes of illustrating how the support values for 1998 and 2006 were 

calculated. The nominal value of the debt reported on BPA’s balance sheet was at $15,951 million in 1998. 

A negative value for interest rate support indicates that the weighted average cost of outstanding debt exceeds the 

benchmark interest rate. 

Sources: Bonneville Power Administration 1998 and 2006 Annual Reports and Table 18.
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 79 

borrowing costs of the three PMAs be raised to those of a "government corporation.”168 This 

would raise the rate charged by the Treasury to the PMAs closer to the rate the BPA pays on its 

long-term debt. In a 2008 budget document, the Bush Administration proposed an initiative to 

charge the three smaller PMAs interest rates on new capital investments, occurring after 

September 30, 2006, at levels similar to those charged to governmental corporations.169 In 

2006, the PMAs' embedded cost of debt was more than 100 basis points below the Treasury’s 

own borrowing costs. 

Before 1983, the interest rate on 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 to12 

percent and accepting repayments on that debt at 2 to 4 percent.170 The PMAs are required to 

retire their high-cost debt first whenever possible, an advantage unavailable to the Treasury 

itself.171 This is another reason that the PMAs can realize an effective borrowing rate lower than 

the Treasury.172 

PMA Borrowing Costs 

The three PMAs' current interest expense was compared to what they would have paid had 

they borrowed at long-term Treasury rates or A, Aa, Aaa, 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 $69 million (2007 dollars) if their debt were priced at the 

Treasury rate to $164 million (2007 dollars) at the Baa rate in 2006 (Table 22). This compares 

with no estimated support at the Treasury rate173 in 1998 (2007 dollars) and $92 million at the 

Baa rate. Based upon an A utility rate, the PMA interest support rose from $77 million to $148 

million. This latter value is used as the point estimate for purposes of this report. 

 

168 Department of Energy, Budget 2007, www.cfo.doe.gov/budget/07budget/Content/Highlights/Highlights.pdf. Accessed March 5, 

2008. 

169 http://www.whitehouse.gov/omb/budget/fy2008/pdf/budget/energy.pdf 

170 Office of Management and Budget, “Fact Sheet on Reform of Federal Power Marketing Administration Debt Repayment 

Practices,” (Washington, DC, 1990). 

171 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. 

172 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.

173 When the PMA have average embedded borrowing costs below that of the U.S. Treasury, estimated Federal interest rate 

support is nonexistent. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

80 Energy Information Administration / Chapter 4: Federal Electricity Programs

Rural Utilities Service Electric Loans, Guarantees, and Grants 

RUS is an agency within USDA. In 2005, the RUS served nearly 12 million customers and 

provided 7 percent of the Nation’s electricity (Table 23). RUS is the successor to the Rural 

Electrification Administration (REA). It was established under the Federal Crop Insurance 

Table 22. Estimate of Federal Electricity Interest Rate Support to the Three Smaller PMAs, 1998 and 

2006 (million 2007 dollars)

Treasury 

Rate 

Aaa IOU 

Rate 

Aa IOU 

Rate A IOU Rate 

Baa IOU 

Rate 

1998 

1. Benchmark Interest Rate (%) 5.58 

 

6.77 

 

6.91 

 

7.04 

 

7.26 

2. Outstanding Debt ($) 7,060 7,060 7,060 7,060 7,060 

3. Average Cost of Outstanding Debt (%) 5.96 

 

5.96 

 

5.96 

 

5.96 

 

5.96 

4. Actual Interest Expense ($) 420 420 420 420 420 

5. Interest Expense Computed at Benchmark Rate 

($) [(1) x (2)] 

393 478, 488 497 513 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] (27) 57 67 77 92 

2006 

1. Benchmark Interest Rate (%) 

 

4.91 

 

5.59 

 

5.84 

 

6.07 

 

6.32 

2. Outstanding Debt ($) 

 

6,742 6,742 6,742 6,742 6,742 

3. Average Cost of Outstanding Debt (%) 

 

3.88 

 

3.88 

 

3.88 

 

3.88 

 

3.88 

4. Actual Interest Expense ($) 

 

262 262 262 262 262 

5. Interest Expense Computed at Benchmark Rate 

($) [(1) x (2)] 

331 377 394 409 426 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] 

 

69 115 132 148 164 

NOTES: 2006 data for WAPA were obtained from their 2006 Annual Report. 2006 data for SEPA were extrapolated

based on 2005 data appearing in SEPA’s 2005 Annual Report. SWPA produced a single 2004-2006 Annual Report with 

a 2006 income statement but with a balance sheet lacking U.S. Army Corp of Engineer data. SWPA’s outstanding debt 

was extrapolated from 2003 data reported in its 2003 Annual Report. 

The table above presents the historic value of 3 smaller PMAs debt in 2007 dollars for purposes of illustrating how the 

support values for 1998 and 2006 were calculated. The collective value of the debt reported on the 3 smaller PMA’s 

balance sheets has not changed due to inflation. The nominal value of their debt stood at $5,743 million in 1998. 

A negative value for interest rate support indicates that the weighted average cost of outstanding debt exceeds the 

benchmark interest rate. 

Sources: Southeastern Power Administration, Annual Reports, 1998 and 2004-2006, Western Area Power 

Administration, Annual Reports, 1998 and 2006. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 81 

Reform and Department of Agriculture Reorganization Act of 1994 (Public Law 103-354) as one 

of the Federal program agencies authorized to provide financial and technical assistance under 

the USDA Rural Development Mission Area. REA was created by Executive Order in May 1935. 

The functions and authority of the REA administrator were initially codified with the passage of 

the Rural Electrification Act of 1936 (the REAct).174 The REAct, as amended, authorizes the 

RUS to provide direct loans and loan guarantees to electric utilities serving customers in rural 

areas.175 RUS loans and loan guarantees may be used to finance the construction of electric 

distribution, transmission, and generation facilities, including system improvements and 

replacement required to furnish and improve electric service in rural areas. Borrowers may also 

submit applications to finance demand side management, energy conservation programs, and 

on-grid and off-grid renewable energy systems. Entities eligible to apply for loan and loan 

guarantees include corporations, States, territories, and subdivisions and agencies such as 

municipalities, people's utility districts, and cooperative, nonprofit, limited-dividend, or mutual 

associations that provide retail electric service needs to rural areas or supply the power needs 

of distribution borrowers in rural areas. Section 3 of the REAct176 provides that a preference be 

given to government-owned utilities (e.g., State, municipal and public power districts) and 

cooperatives. 

To qualify for loans and loan guarantees, borrowers must demonstrate financial feasibility, i.e., 

that all loans will be repaid in accordance with their terms, and provide adequate security 

pursuant to the RUS mortgage and loan contract. In addition, the borrower must demonstrate 

that it serves customers in rural areas in accordance with Section 13 of the RE Act.177

Borrowers that meet this test are referred to as REAct beneficiaries. 

The original mission of RUS was to facilitate electrification of rural America. Suburban growth 

into cooperatives’ service areas heretofore deemed rural has raised questions concerning the 

extent to which current recipients of RUS are receiving loans and loan guarantees, a portion of 

which benefits customers in non-rural areas. The results of a USDA analysis of borrower and 

community characteristics for $3.3 billion in financing approved in 2005 were in connection with 

power supply, transmission, and distribution loans in 1,682 of 2,500 non-metropolitan counties 

that included 332 counties classified as persistent poverty counties. The distribution loans 

supported investment in facilities to serve approximately 2 million consumers of which 92.5 

percent were classified as rural by the Census Bureau.178

 

The FY 2008 budget proposed two programmatic reforms. First, in recognition of the 

deregulation of wholesale electric markets, RUS will focus on providing financial assistance for 

transmission and distribution facilities. It will continue to provide funding for upgrading existing 

generation, but G&Ts should be expected to consider commercial capital markets for funding 

new generation. Second, the budget proposed that RUS promulgate rules requiring electric and 

telecommunications borrowers to recertify their rural status commencing with their first loan 

request submitted in or after 2008 and the first loan requested after each decennial Census.179

 

174 7. U.S.C. 901, et seq. 

175 In addition to the Electric Loan Program, RUS administers loan programs for infrastructure investment in rural 

telecommunications systems (i.e., telephony, broadband, distance learning, telemedicine) and water and wastewater systems. 

176 7 U.S.C. 903. 

177 7 U.S.C. 913. 

178 Office of Management and Budget, Budget of the United States Government, Fiscal Year 2008—Appendix, Department of 

Agriculture, p. 146. See, http://www.whitehouse.gov/omb/budget/fy2008/appendix.html. 

179 Ibid. In the FY 2008 budget, the Congress approved a provision precluding RUS from incurring administrative expenses, drafting 

regulations, or implementing rules that require recertification of rural status. See, House Report 110-497, Division A-Agriculture 

Rural Development, Food and Drug Administration and Related Agencies Appropriation Act of 2008, Title VII, Section 726. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

82 Energy Information Administration / Chapter 4: Federal Electricity Programs

The total population of RUS borrowers has declined as distribution borrowers and G&Ts have 

paid off their RUS loans. Since 1986, 224 distribution cooperatives prepaid their loans at a 

discount as provided in RUS regulations. The number of power supply borrowers has declined 

over the past 15 years as financially-distressed borrowers were liquidated or exited the program 

as part of debt settlement or bankruptcy reorganization plans. The number of consumers 

served by the RUS borrowers in 2005 accounted for 6.6 percent of total electricity 

sales (Table 23). 

Table 23. Key Statistics for the Rural Utilities Service Electricity Program, 1998 and 2005 

1998 2005 

Statistic RUS 

Borrowers 

RUS 

Borrowers as 

Percent of 

National 

Total 

RUS 

Borrowers 

RUS 

Borrowers 

as Percent 

of National 

Total 

Retail Consumers Served 10,858,441 8.7 11,548,604 8.2 

End-Use Sales (thousand megawatthours) 

Residential 125,210 11.1 144,944 10.7 

Commercial/Industrial 84,269 4.1 100,568 4.4 

Other 8,166 7.9 7,523 NA 

Total Sales 217,645 6.7 253,035 6.6 

NOTE: Other sales include street lighting sales, sales to public authorities, railroads and railways, and 

interdepartmental sales.

EIA no longer collects data for the “Other” sector.

Sources: Rural Utilities Service, 1998 Statistical Report Rural Electric Borrowers, IP 201-1 (Washington, 

DC, August 1999), pp. 10 and 14, and 2005 Statistical Report Rural Electric Borrowers, IP 201-1 

(Washington, DC, December 2006), pp 10. Energy Information Administration, Electric Power Annual 

1998, Volume 2, DOE/EIA-0348(89/2) (Washington, DC, December 1999) and Electric Power Annual 

2005, Table ES1: http://www.eia.doe.gov/cneaf/electricity/epa/epaxlfilees1.pdf 

The RUS Electric Program provides financial assistance to eligible borrowers by making direct 

loans and providing loan guarantees for loans made by the Federal Financing Bank (FFB) to 

distribution and power supply borrowers. Additionally, the Farm Security and Rural Investment 

Act of 2002 (2002 Farm Bill) amended the REAct by adding Section 313A,180 which authorizes 

RUS to guarantee bonds and notes to eligible cooperatives and non-profit lenders.181 RUS also 

administers a grant program to mitigate high energy costs for those entities that meet the 

eligibility criteria. The five electric loan programs and grant program administered by RUS are 

described below. 

Hardship Loans 

Hardship loans are available to electric distribution borrowers that have experienced an 

unavoidable natural disaster. They are also available to electric distribution borrowers that meet 

a rate disparity and consumer income test that compares the borrower’s retail rates and its 

 

180 7 U.S.C. 940c-1; Guarantees for bonds and notes issued for electrification and telephone purposes. 

181 Public Law 107-171. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 83 

customers’ per capita or household income to statewide values.182 The hardship loans may be 

used for distribution, subtransmission, and headquarters facilities. The loan carries a fixed 5- 

percent interest rate for a term equal to the lesser of the useful life of the facilities, or 35 

years.183

Municipal Rate Loans 

These loans are available to finance distribution, subtransmission, and headquarters facilities. 

Distribution and power supply borrowers may participate in this program. Power supply 

borrowers participation is limited to subtransmission and headquarters facilities. The interest 

rate is established quarterly by RUS based on a municipal bond market index for loans of 

comparable maturity. The interest rate is determined when loan funds are advanced. The term 

of the loan is equal to the lesser of the useful life of the facilities being financed, or 35 years. 

The borrower must obtain supplemental financing from another lender for typically 30 percent of 

the loan amount. Traditionally, cooperatives have relied upon CoBank and the CFC to meet the 

supplemental lending requirement.184

Treasury Direct Loans 

Treasury Direct loans are available to distribution cooperatives to construct distribution, 

subtransmission, headquarters facilities and renewable generating facilities. Power supply 

borrowers may participate in this program to finance renewable generating facilities. Interest 

rates are set daily by the Treasury Department based on its current cost of money over a yield 

curve with maturities ranging from 3 months to 30 years. The interest rate is set on the date of 

each advance of approved loan funds to the borrower. The term of a Treasury Direct loan is set 

at the lesser of the useful life of the facilities being financed, or 35 years. There is no 

supplement financing requirement associated with this program. 

FFB Guaranteed Loans 

RUS guarantees of FFB loans are available to distribution and power supply borrowers to 

finance distribution, transmission, generation, and headquarters facilities. The interest rate for 

FFB loans is established daily by the Treasury Department based on its current cost of money 

plus one-eighth of 1 percent. The interest rate is set on the date of each advance of approved 

loan funds to the borrower.185 The term of an FFB loan may not exceed the lesser of the useful 

life of the facilities, or 35 years.186 The wholesale power contract between power supply 

 

182 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. 

(See, 7 CFR 1714.8). 

183 The interest rate for hardship loans was increased from 2 percent to 5 percent in the Rural Electric Loan Restructuring Act of 

1993 (Public Law 103-129). 

184 The Municipal Rate loan program was created with the enactment of Rural Electric Loan Restructuring Act of 1993. 

185 Under the FFB Note, borrowers may opt for a long-term maturity date (e.g., 35 years), but select interim maturity dates to obtain 

the benefit of lower interest rates associated the Treasury Department’s lower cost of money for securities with shorter maturities. 

At the interim maturity date, the note reprices based on the applicable rate for the next interim maturity date selected by the 

borrower. Alternatively, the borrower has the option of paying off the loan. See, RUS Bulletin 1710b-1 Guide to Federal Financing 

Bank Loans Guaranteed by RUS at http://www.usda.gov/rus/regs/bulls/1710b-1, accessed October 11, 2007. 

186 The Agricultural, Rural Development, Food and Drug Administration and Related Agencies and Appropriation Act of 2006 

(Public Law 109-97) amended the RE Act by adding Section 316, which provides for the term extension of FFB loans guaranteed 

by RUS for power plants and transmission facilities. The primary purpose of this amendment was to permit power supply 

cooperatives to extend the term of loans on nuclear power plants to be coterminous with NRC license extension. In the absence of 

a term extension, the prospective reduction in depreciation expense based on the license extension can create an adverse 

mismatch between cash flow and principal payments on existing loans with a maturity date coterminous with the termination of the 

existing NRC operating license. Under Section 316, borrowers are permitted to apply for term extensions for nuclear, fossil and 

transmission facilities. Extensions are permitted subject to the borrower demonstrating financial feasibility, sufficient collateral to 

support the loan extension, and, where applicable, regulatory orders (i.e., NRC orders extending operating licenses). Borrowers are 

required to pay a modification fee based on the requirements of Section 502 of the Federal Credit Reform Act of 1990 (Public Law 

101-58), as amended (2 U.S.C. 661a). 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

84 Energy Information Administration / Chapter 4: Federal Electricity Programs

borrowers and their distribution members is pledged as security for FFB guaranteed loans. 

Accordingly, the loan may not exceed the terms of the contract. 

Guarantees for Bonds and Notes Issued for Electrification and Telephone Purposes 

Under this program, RUS guarantees bonds and notes issued by cooperatives and not-for-profit 

lenders to the FFB. Eligible cooperatives and not-for-profit borrowers participating in the 

program are required to pay a 30-basis point annual fee for the guarantee. It is applied to the 

unpaid principal. Up to one-third of the 30-basis point guarantee fee may be used to pay for the 

guarantee. This amount may be adjusted by Congress or at the mutual consent of RUS and the 

borrower to ensure sufficient funds are available to pay for the guarantee. The remaining 

portion of the guarantee is deposited in the Rural Economic Development Subaccount, which 

funds the Rural Economic Development Loan and Grant Fund (REDLG).187

Under this program, eligible applicants identify existing secured loans not previously pledged as 

collateral to secure bonds purchased by FFB. The bonds may have a maximum maturity of 20 

years. If the guaranteed lender’s credit rating, irrespective of the RUS guarantee, on senior 

secured debt falls below A, it must provide the secured loans identified as collateral to RUS. 

The guaranteed lender, RUS and FFB must execute various security agreements including a 

guarantee agreement and bond purchase agreements for an amount not to exceed the 

maximum funding authorized by Congress. The guaranteed lender must submit documentation 

for advances under the bond document at which time the interest rate and term are determined. 

Presently, the CFC is the only non-profit lender participating in the program. Congress has 

authorized RUS to guarantee $2 billion for which CFC has executed Bond Purchase 

Agreements with RUS and FFB. 

The proceeds from any advances made to CFC may not be used to directly or indirectly fund 

generation projects. The guaranteed bond proceeds may be used for electrification and 

telephony purposes or to refinance debt previously issued by the guaranteed lender. The funds 

may not be used to reduce interest rates on new or outstanding loans other than supplemental 

loans issued under the Municipal Rate program.188 CFC executed a Series A Bond Purchase 

Agreement with FFB and RUS with a loan commitment amount not to exceed $1 billion on June 

14, 2005. A Serial B Bond Purchase Agreement was executed on April 28, 2006 with a loan 

commitment amount not to exceed $1.5 billion.189 In addition to providing a source of funding for 

the Rural Development REDLG program, this loan program provides CFC with another source 

of liquidity to reduce its borrowing cost, which in turn reduces cooperatives’ cost of borrowing 

from CFC. According to CFC’s 2007 SEC Form 10-K, as of May 31, 2007, it has pledged $2.8 

billion of loans to the trust for $2 billion in notes payable to RUS. There is not sufficient data 

available to determine the benefit that CFC borrowers receive in lower borrowing costs from this 

program.190

 

187 The REDLG program provides funding to rural projects through local utility organizations. The program is administered by the 

Rural Business-Cooperative Service (RBS), which is in the USDA Rural Development Mission Area. Under the loan program, 

USDA provides zero interest loans to local utilities which they, in turn, pass through to local businesses (ultimate recipients) for 

projects that will create and retain employment in rural areas. The ultimate recipients repay the lending utility directly. The utility is 

responsible for repayment to RBS. The grant program provides funds to local utility organizations to establish revolving loan funds. 

Loans are made from the revolving loan fund to projects that will create or retain rural jobs. When the revolving loan fund is 

terminated, the grant is repaid to RBS. 

188 For a complete description of the application process, eligibility criteria, collateral and creditworthiness requirements see RUS 

Regulation Guarantees for Bonds and Notes for Electrification or Telephone Purposes, 7 C.F.R. 1720 (2004). 

189 The Bond Purchase Agreements and related documents are available on the Securities Exchange Commission website 

(EDGAR) as exhibits to CFC’s SEC 10-K. 

190 Based on the assumed default rate and recovery rate, and the 30 basis point payment over the Treasury's borrowing cost to pay 

for the guarantee, OMB estimated that the FY 2007 subsidy for this program was a negative $5 million. Accordingly, no budget 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 85 

Assistance to High Energy Cost Communities 

The High Energy Cost Grant Program provides financial assistance to communities with home 

energy costs in excess of 275 percent of the National average.191 The program provides grants 

for the improvement of energy generation, transmission, and distribution facilities serving 

eligible rural communities. Eligible applicants include legally-organized for-profit or non-profit 

organizations, sole proprietorships, State or local government, or any agency or instrumentality 

of a State or local government, including a municipal utility or public power authority, Indian 

tribes, a tribally-owned entity, an Alaska Native Corporation, or other area authorized by law to 

participate in RUS programs or under the RE Act. Eligibility may be established using average 

annual household expenditures for individual fuels or for total energy, or average per unit cost 

for home energy. 

Grants under this program may be used for the acquisition, construction, installation, repair, 

replacement, or improvement of energy generation, transmission, or distribution facilities in 

communities with extremely high energy costs. On-grid and off-grid renewable energy projects, 

energy efficiency, and energy conservation projects are eligible.192

Cost of Loan Support Provided to RUS Electricity Borrowers 

The RUS programs reduce the cost of borrowing to its borrowers relative to the 

contemporaneous cost of long-term secured debt in private capital markets. Enumerating the 

savings that flow to RUS borrowers requires assessing the administrative costs of running the 

RUS programs, the costs RUS incurs by loaning money to its borrowers at interest rates below 

the Treasury’s cost of money, the costs RUS incurs when it covers defaults on loans it has 

guaranteed, and measuring the benefit RUS borrowers receive from being able to borrow 

money below competitive market interest rates. If the RUS did not exist, many of these costs 

would be borne by the borrowers in the form of higher fees and interest rates. 

The benefit of the interest rate subsidy received by RUS borrowers is a function of the spread 

between the cost of borrowing from RUS relative to cost of long-term debt available in 

commercial capital markets. The latter reflects a risk premium associated with a borrower’s 

credit worthiness. Absent the interest rates and remaining term to maturity for all direct loans 

and loan guarantees that RUS holds in its portfolio, it is difficult to obtain a present value 

estimate of the benefit received by RUS borrowers over the life of the existing loan portfolio. 

Therefore, the interest rate subsidy estimate contained in this report provides a 1-year snapshot 

of the subsidy by comparing the embedded cost of RUS loans and loan guarantees to the 

Treasury rate and a range of electric utility investment grade bonds for 2006. The difference in 

interest rates approximates the benefit consumers served by RUS electric borrowers received 

in 2006.193

 

The measurement of financial support provided to RUS borrowers has market risk and 

opportunity cost implications for the Federal government.194 The difference between the 

 

authority is required. See, Office of Management and Budget, Budget of the United States Government, Fiscal Year 2008-

Appendix, Department of Agriculture, p. 146. 

191 The 275 percent criteria are measured on the basis of either annual expenditures per household or in unit cost of designated 

energy sources including electricity, liquefied petroleum gas, natural gas, fuel oil and total household energy consumption (dollars 

per year or dollars per Btu). The benchmark values are derived from Energy Information Administration data. 

192 On May 25, 2005, RUS provided $19.5 million in high energy cost grants. On August 17, 2007, it issued a Federal Register 

Notice of Availability of Funding for $21.9 million. 

193 Data for 2006 were extrapolated based upon RUS 2005 data and the gross domestic product (GDP) implicit price deflator. 

194 In a 2004 study the Congressional Budget Office (CBO) examined the impact of using the risk-free Treasury rate versus a riskadjusted commercial rate to measure the cost of Federal credit programs. CBO concluded that “for all programs, ignoring the cost 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

86 Energy Information Administration / Chapter 4: Federal Electricity Programs

Federal utilities and RUS is that as a Federal credit agency RUS is required to calculate the 

subsidy associated with its loan and loan guarantee programs. This calculation is required by 

the Federal Credit Reform Act of 1990 (FCRA) (Public Law 101-158) and is included in the 

budget. FCRA requires that Federal agencies are required to calculate the lifetime costs for 

direct loans and loan guarantees for a budget year based on the expected cash flows for loan 

disbursements, fees, and repayment, taking into account default risk and recovery rates. The 

difference between present value of the cash outflows (disbursements) and cash inflows 

represents the subsidy. This value constitutes the budget authority for an authorized level of 

loans and loan guarantees for that fiscal year. The cash flows are discounted using the interest 

rate for marketable Treasury securities of comparable maturity. If a loan or loan guarantee is 

truly risk-free, then the subsidy value is equal to the market value. However, if the loan or loan 

guarantee is not a risk-free loan, the use of the Treasury rate as the discount rate understates 

the market risk of the loan. This may be the case with the RUS electric loan program, 

specifically with the loan guarantee program. Under the loan guarantee program, borrowers 

pay interest at the Treasury’s cost of money at the time funds are advanced, plus 12.5 basis 

points, i.e., one-eight of 1 percent.195 Thus, under the methodology required to calculate the 

subsidy under FCRA, interest paid on FFB guaranteed loans is always computed at a rate that 

exceeds the discount rate used to determine the value of the subsidy. Therefore, unless the 

assumed default rate is very high (a reflection of a lack of creditworthiness) and the recovery 

rate is extremely low, the FCRA calculation can result in a negative subsidy. 

The actual FY 2007 subsidy estimate for the RUS electric program consisted of the $3 million 

for the Hardship Loan program and a ($36) million for the Federal Financing Bank (FFB) loan 

guarantee program. Therefore, excluding program administration costs, the loan program 

generated net income of $33 million because of the negative subsidy associated with the loan 

guarantee program.196 EIA used the same cost of capital method applied to the Federal utilities 

to estimate support provided to RUS borrowers. A range of subsidy values was estimated for 

RUS loans to G&Ts and distribution cooperatives, as well as a point estimate that reflects a 

market rate of interest for an A-rated IOU. The A rating was based on an analysis of the 

financial ratios for all rated G&Ts. 

As a surrogate measure, the weighted average interest rate, i.e., embedded cost of debt, of 

RUS borrowers is compared with the 2006 average 30-year Treasury Constant Maturity, and 

the 2006 Aaa, Aa, A, and Baa IOUs. The range is provided, because it is unclear what rate US 

 

of risk understates the federal cost of credit assistance, potentially biasing the allocation of budgetary resources.” See, Estimating 

the Value of Subsidies for Federal Loans and Loan Guarantees, Congress of the United States, Congressional Budget Office, 

(Washington, DC, August 2004), p. 4. 

195 In a 1982 report, the Congressional Budget Office stated that a borrower with an FFB guaranteed loan would have to pay 50 

basis points to issue securities in the market. See, Congressional Budget Office, The Federal Financing Bank and the Budgetary 

Treatment of Federal Credit Activities, (Washington, DC, January 1982) p. x. 

196 Office of Management and Budget, Budget of the United States Government, Fiscal Year 2009-Appendix, Department of 

Agriculture, http://www.whitehouse.gov/omb/budget/fy2009/pdf/appendix/agr.pdf, p.162. Accessed February 28, 2008. The 

estimated subsidy for FY2008 is zero for Hardship Loans. The FY2009 budget estimates no lending authority for either the 

Municipal Loan or Treasury Loan programs for either FY2008 or FY2009. Accordingly there are zero subsidy values associated 

with these programs. The negative subsidies for FY 2008 and FY 2009 for the FFB loan guarantee program are estimated to be 

($45) million and ($91) million. Therefore, based on the scoring method prescribed by the FCRA, the estimated budget impact for 

the RUS electric program, excluding administrative costs is zero for both FY2008 and FY2009. Because of the estimated negative 

subsidy calculated for the FFB loan guarantee program, the program “makes money.” 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 87 

electricity borrowers would face in private markets without RUS guarantees.197 The average 

interest rate paid on the outstanding debt of RUS electricity borrowers in 2006 is actually 

slightly above the average 30-year Treasury rate for a bond issued in 2006 (Table 24). 

Table 24. Interest Support to RUS Borrowers, 1998 and 2006 (million 2007 dollars)

Treasury 

Rate 

Aaa IOU 

Rate 

Aa IOU 

Rate A IOU Rate 

Baa IOU 

Rate 

1998 

1. Benchmark Interest Rate (%) 5.58 

 

6.77 

 

6.91 

 

7.04 

 

7.26 

2. Outstanding Debt ($) 

 

39,547 

 

39,547 

 

39,547 

 

39,547 

 

39,547 

3. Average Cost of Outstanding Debt (%) 

 

5.90 

 

5.90 

 

5.90 

 

5.90 

 

5.90 

4. Actual Interest Expense ($) 

 

2,333 

 

2,333 

 

2,333 

 

2,333 

 

2,333 

5. Interest Expense Computed at Benchmark 

Rate ($) [(1) x (2)] 2,207 

 

2,677 

 

2,733 

 

2,784 

 

2,871 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] (127) 

 

344 

 

399 

 

451 

 

538 

2006 

1. Benchmark Interest Rate (%) 4.91 

 

5.59 

 

5.84 

 

6.07 

 

6.32 

2. Outstanding Debt ($) 

 

30,134 

 

30,134 

 

30,134 

 

30,134 

 

30,134 

3. Average Cost of Outstanding Debt (%) 

 

5.06 

 

5.06 

 

5.06 

 

5.06 

 

5.06 

4. Actual Interest Expense ($) 

 

1,524 

 

1,524 

 

1,524 

 

1,524 

 

1,524 

5. Interest Expense Computed at Benchmark 

Rate ($) [(1) x (2)] 1,480 

 

1,684 

 

1,760 

 

1,829 

 

1,904 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] (45) 

 

160 

 

235 

 

305 

 

380 

NOTES: The table above presents the historic value of RUS debt in 2007 dollars only for purposes of illustrating how 

the support values for 1998 and 2006 were calculated. The value of the debt on the RUS borrower’s balance sheets 

has not changed due to inflation. The nominal value of this debt was at reported by RUS at $32,170 million in 1998. 

A negative value for interest rate support indicates that the weighted average cost of outstanding debt exceeds the 

benchmark interest rate. In FY2007, the RUS hardship loan program was scored for budget purposes by the Office of 

Management and Budget (OMB) at $3 million. The Federal Financing Bank loan guarantee program was scored at 

negative $36 million. The budgetary cost is estimated using OMB’s Credit Subsidy Calculator. See OMB, Circular A11, Part 5, Federal Credit, www.whitehouse.gov/omb/circulars/a11/current_year/a11_toc.html. 

Sources: Rural Utilities Service, 1998 Statistical Report Rural Electric Borrowers, IP 201-1 (Washington, DC, August 

1999), pp. 10 and 14, and 2005 Statistical Report Rural Electric Borrowers, IP 201-1 (Washington, DC, December 

2006). Table 18.

 

197 Fifteen G&Ts have senior debt rated by Fitch Ratings. All 15 are rated investment grade. With the exception of one, which is 

rated BBB+, all are rated above A-. (See, Fitch Ratings, Electric Cooperatives-An Industry Outlook and Primer, June 14, 2007). For 

11 of these G&Ts, outstanding debt accounted for 52.9 percent of the $21.0 billion of outstanding debt for all RUS power supply 

borrowers. Two of the rated cooperatives had no RUS debt in 2005 (Old Dominion Electric Cooperative and Chugach Electric 

Association). A third G&T, Great River Energy, completed a $1.3 billion through a bond issue on July 2, 2007 and retired all of its 

$1.1 billion in RUS guaranteed debt. The transaction was supported with bond insurance provided by MBIA. See, 

www.greatriverenergy.com/press/news/071007_capital_market.html, accessed October 11, 2007. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

88 Energy Information Administration / Chapter 4: Federal Electricity Programs

The estimated support value, using weighted borrowing rates, ranges from $160 million (based 

upon the IOU Aaa rate) to an estimated $380 million (based upon a Baa rate). 

Several analyses have concluded that the RUS faces a significant risk of large loan defaults. 

For example, in 1997 GAO 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 GAO report found that the RUS wrote off more 

than $3.2 billion in loans made to three borrowers.198 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 Vermont Electric Generation and Transmission Cooperative. 199

Summary 

The total value of support provided Federal utilities and RUS borrowers is estimated as $767 

million (Table 25) at the A benchmark rate although 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. The 

ratio of embedded cost of debt (interest expenses) to their outstanding debt for Federal utilities 

and RUS borrowers indicates that these entities have borrowed at rates ranging from below the 

Treasury’s own costs of funds to as high as a highly-rated utility with a bond rating, i.e., the Aaa 

bond rating. For a discussion on bond ratings, see Appendix D. 

Table 25 compares the cost of borrowing by Federal utilities and U.S. electricity loan 

participants to the Treasury borrowing costs and the borrowing costs of investor owned utilities 

with bond ratings ranging from Aaa to Baa for the years 1998 and 2006. The comparisons to 

the Treasury and Aaa rates in the table include only that portion of the debt that was below the 

respective interest rates. For example, only about $22 billion of the total outstanding debt of $78 

billion has an average embedded cost below the benchmark Treasury rate. The corresponding 

debt below the Aaa rate was $52 billion. For debt that has an average embedded cost above 

these rates, the implicit support is assumed to be zero. Table 25 indicates that of those 

borrowers that had debt with an embedded cost below the Treasury’s cost of funds, the value of 

those preferential interest rates was $89 million in 2006 (2007 dollars). The $89 million value for 

the year 2006 is the difference between what the interest costs would be on those particular 

loans that have an average embedded cost below the Treasury’s associated costs of funds and 

those realized by current borrowers from the Treasury. For each successively lower-graded 

utility bond rating in the table, the methodology increases the value of the support as the 

average cost of debt falls below the comparison utility bond rate. 

For instance, for electricity loans priced at rates above the Treasury’s cost of funds (as 

measured by the Treasury’s 30-year bond), but below the utility Aaa rate, the value of the 

support rises to an estimated $395 million for 2006. For loans priced below an Aa rate (all of 

them), support would equal an estimated $589 million; below an A rate, an estimated $767 

 

198 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. 

199 Conversation with Chris Tuttle of the Rural Utilities Service, July 30, 2007. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 4: Federal Electricity Programs 89 

million (which serves as the point estimate measure); and, below a Baa rate, an estimated $961 

million.

Table 25. Interest Support to Federal Utilities and RUS Borrowers 1998 and 2006 

(million 2007 dollars)

Treasury 

Rate 

Aaa IOU 

Rate 

Aa IOU 

Rate A IOU Rate 

Baa IOU 

Rate 

1998 

1. Benchmark Interest Rate (%) NA 

 

6.77 

 

6.91 

 

7.04 

 

7.26 

2. Outstanding Debt ($) 0 

 

66,217 

 

98,895 

 

98,895 

 

98,895 

3. Average Cost of Outstanding Debt (%) NA 

 

6.04 

 

6.28 

 

6.28 

 

6.28 

4. Actual Interest Expense ($) NA 

 

3,997 

 

6,209 

 

6,209 

 

6,209 

5. Interest Expense Computed at Benchmark Rate 

($) [(1) x (2)] NA 

 

4,483 

 

6,834 

 

6,962 

 

7,180 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] NA 

 

486 

 

624 

 

753 

 

971 

2006 

1. Benchmark Interest Rate (%) 

 

4.91 

 

5.59 

 

5.84 

 

6.07 

 

6.32 

2. Outstanding Debt ($) 21,552 

 

51,686 

 

77,534 

 

77,534 

 

77,534 

3. Average Cost of Outstanding Debt (%) 

 

4.50 

 

4.83 

 

5.08 

 

5.08 

 

5.08 

4. Actual Interest Expense ($) 970 

 

2,494 

 

3,939 

 

3,939 

 

3,939 

5. Interest Expense Computed at Benchmark Rate 

($) [(1) x (2)] 1,058 

 

2,889 

 

4,528 

 

4,706 

 

4,900 

6. Estimated Interest Support at Benchmark 

Interest Rate ($) [(5)-(4)] 89 

 

395 

 

589 

 

767 

 

961 

NOTE: NA indicates that some of the cost of outstanding debt exceeds the benchmark interest rate. There is no 

support when benchmark rates are less than the weighted cost of capital.

 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 5: Electricity Subsidies Per Unit of Production 91 

5. Subsidies Per Unit of Production 

The previous chapters of this report described energy-related subsidies that the Federal 

government provides through tax expenditures, direct expenditures, research and development 

(R&D), and financial assistance in the form of grants, direct loans and loan guarantees for 

energy producing industries, intermediate product market participants, and end-users. In 

considering electricity production, the electric power industry generally involves all of these 

segments. It includes producers in terms of the production of electric power. It includes 

intermediate product market participants with respect to the factor inputs to electricity 

production, e.g., capital, labor and fuel. Finally, it includes retail customers, who are 

beneficiaries of a variety of tax expenditures and direct subsidies that are intended to foster 

conservation and energy efficiency and reduce the cost of electricity to qualified low income 

consumers. 

The previous chapters of this report also quantified energy-related tax expenditures, R&D, and 

other subsidies, many of which have a direct or indirect impact on electricity production. 

However, some of those tax expenditures, R&D outlays, and other subsidies have no 

connection to electricity production. Others, such as exploration and production tax credits for 

fuel producers, have an indirect impact on electricity production in that they provide financial 

incentives to fuel producers to invest in new technologies and explore for fuel resources, which 

at current market prices may only be marginally economic. If these incentives are successful in 

terms of bringing significant supplies to market in the long run, it helps to ensure energy 

security and potentially lowers equilibrium prices as supply increases. This may affect utility and 

nonutility generators’ selection of particular forms of generation. For purposes of this analysis, 

while fuel producers are the direct beneficiary of production tax credits, electricity producers 

indirectly benefit from supply increases and diversity of fuels. Therefore, a portion of direct 

subsidies to these entities is allocated as a subsidy to electricity production in proportion to the 

amount of the fuel consumed in electricity production to which a particular subsidy applies. The 

subsidies are presented in total dollars and per megawatthour (MWh) of generation by fuel type 

based on EIA generation data for the 12-month period ending September 30, 2007 (FY2007 

MWh).200 

This chapter describes the methodology used to estimate electricity production subsidies by 

fuel type. The methodology consists of defining the electricity production to which the subsidies 

apply, identifying the subsidies for which there is a direct or indirect benefit to electricity 

production by fuel type, and allocating the estimated dollar value of each subsidy to each fuel 

type. The dollar per unit--MWh--of subsidies by fuel type is calculated as the aggregate subsidy 

in dollars for each fuel divided by the corresponding FY2007 generation (MWh). Subsidies 

provided to the electric utility industry that are unrelated to generation, such as transmissionrelated tax expenditures are expressed in dollars per MWh based on total electricity production. 

This is based on the assumption that the incentives these benefits provide to transmission 

owners to expand or upgrade their systems benefit all forms of generation in proportion to their 

use of the transmission system. Therefore, the dollar per MWh value for total nonfuel-related 

electricity subsidies is based on total electricity production. 

 

200 Energy Information Administration, Form EIA-906, "Power Plant Report" and Form EIA-920, “Combined Heat and Power Plant 

Report," October 2006 through September 2007. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

92 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

Definition of Electricity Production 

For purposes of this analysis, electricity production encompasses the principal classes of 

electric plant required to produce and deliver electricity to the end-user. This includes all assets 

associated with the three functional areas of electricity supply: generating plants, transmission 

lines and distribution facilities. Electricity production is defined as: electricity produced via 

generating plants owned by traditional utilities (investor-and publicly-owned-utilities, 

generation/transmission cooperatives, and Federally-owned utilities) and nonutility generators. 

Fuel is an operating cost that is associated with electricity production. 

Non-utility generators include independent power producers (IPPs), affiliated power producers, 

Qualifying Facilities (QFs) and combined heat and power (CHP) plants whose primary purpose 

is to sell electricity or electricity and heat to the public. Nonutility generators are included 

because these entities are direct or indirect beneficiaries of numerous subsidies identified in 

this report. 

Electricity Production Subsidies 

A number of energy-related R&D direct expenditures and tax expenditures programs described 

in the previous chapters are not included in the subsidies assigned to electricity production. 

These include direct expenditures, tax expenditures, and R&D associated with development of 

alternative transportation fuels and end-user related activities such as energy efficiency and 

conservation. Of the $16.6 billion in energy-related subsidies identified by EIA, $6.7 billion are 

classified as direct or indirect subsidies and directed to electricity production (Table 26). 

Indirect subsidies consist of fuel-specific R&D for use in electric generation. Indirect subsidies 

also include tax incentives and direct expenditures provided to entities engaged in the 

production of fuel used to produce electricity. These benefits are allocated to electricity 

production based on fuel allocation factors discussed below. Direct subsidies to electricity 

producers that provide incentives to investment in generation technology of a specific fuel type 

are assigned to electricity production in their entirety and are included in the $5.1 billion of 

subsidies allocated to electricity production by fuel type. 

The methodology used to allocate the interest rate support by fuel type is described below. The 

interest rate support for the Federal utilities and Rural Utilities Service (RUS) borrowers is 

estimated to be $767 million. Of this amount, $407 million is allocated to power sector 

generation by fuel type. The remaining $360 million, which is the interest subsidy associated 

with Federally-subsidized transmission and distribution facilities, is included in non-production 

related electricity subsidies. The interest rate support for the Tennessee Valley Authority (TVA), 

the Federal Power Marketing Administrations (PMAs) and RUS borrowers is the estimated 

subsidy calculated at the benchmark interest rate for A-rated IOU bonds described in Chapter 

4. Subsidies provided to the electric power industry that are not directly allocated to electricity 

production by fuel type are estimated at $1.2 billion. The majority of these subsidies are 

transmission-related tax incentives that modify provisions of the Internal Revenue Code (Code 

or IRC) to promote investment in transmission infrastructure and increase transmission owners’ 

participation in open access transmission. In some instances, as was described in Chapter 2, 

certain provisions of the Code acted as impediments for transmission owners to engage in 

activities and transactions that would expand the amount of transmission capacity operating 

under non-discriminatory open-access tariff or under the control of regional transmission 

organizations and independent system operators (RTOs/ISOs). 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 93 

To the extent these incentives provide benefits to all users of transmission facilities placed 

under the operational control of RTOs/ISO, all forms of generation benefit. Accordingly, these 

tax expenditures are included in non-production-related electricity subsidies. Subsidies 

unrelated to electricity production, totaling $7.5 billion, are not included in the estimate of direct

and indirect subsidies for electricity production, as are $2.3 billion in fuel-related subsidies that 

are allocated to consumers, i.e., residential, commercial, industrial and transportation, based 

their direct receipt and consumption of the applicable fuel. 

Allocation of Subsidies 

This portion of the chapter describes the method used to allocate the four categories of 

subsidies described above. The following four sections provide a description of the 

methodology and the specific subsidies that comprise the $16.6 billion of total energy-related 

subsidies and support, and the $6.7 billion assigned to electricity production. 

Table 26. Allocation of Electricity Production and Other Energy Subsidies (million 2007 dollars) 

Subsidy and Support Category 

FY 2007 

Electricity 

Production 

Subsidies and 

Support 

FY 2007 

Other Energy 

Subsidies 

and Support 

FY 2007 

Total Energy 

Subsidies 

and Support 

Fuel Specific1 5,105 2,330 7,435 

Transmission and Distribution2 1,235 - 1,235 

Federal Utilities and RUS Borrowers Capacity3 407 - 407 

Energy Subsidies Unrelated to Electricity Production

4 - 7,504 7,504 

Total 6,747 9,834 16,581 

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

1

Includes fuel-related tax expenditures, R&D, and direct expenditures applicable entirely to a specific type of electric 

generation, or primary fuel production-related subsidies allocated to either electricity or other sectors based on each 

sector’s proportionate consumption of the applicable fuel. Excludes fuels that have no role in electricity production, 

such as ethanol and other biofuels. 

2 Includes transmission and distribution-related tax expenditures, R&D, and the financial support attributable to Federal 

utilities’ and RUS borrowers’ debt associated with transmission and distribution assets with an estimated value of $360 

million (See Table 34). 

3Reflects the estimated portion of Federal utilities’ and RUS borrowers’ interest support attributable to long-term debt 

associated with capacity plant and certain TVA and BPA regulatory assets. This support is then assigned by fuel-type. 

4

Includes tax and direct expenditures for end-use activities and transportation-related alternative fuels. Among these 

subsidies are conservation programs, residential and commercial energy efficiency programs, and ethanol and biofuels 

tax credits. 

 

Sources: Office of Management and Budget, Budget of the United States Government, Fiscal Year 2008-Appendix. 

Office of Management and Budget, Analytical Perspectives Budget of the United States Government, Fiscal Year 2008, 

Federal Receipts and Collections, http://www.whitehouse.gov/omb/budget/fy2008/. Joint Committee on Taxation, 

“Estimated Budget Effects Of The Conference Agreement For Title XIII of H.R. 6, The Energy Tax Incentives Act Of 

2005," JCX59-05, July 27, 2005. (Washington, DC, November 2007). 

Energy Information Administration, Form EIA-860, "Annual Electric Generator Report," 2006; Energy Information 

Administration, Form EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report," 

October 2006 through September 2007.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

94 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

Subsidies Unrelated to Electricity Production 

Energy-related subsidies totaling $9.8 billion have not been allocated to electricity production. 

These subsidies are divided into two categories. The first category consists of subsidies 

totaling $7.5 billion (Table 27). The second category consists of the portion of fuel-specific 

subsidies that are allocated to end-use sectors, i.e., residential, commercial, industrial and 

transportation, other than the electric power sector based on their relative consumption of the 

fuels to which the subsidies applied. These fuel-specific subsidies totaled $2.3 billion FY 2007. 

The $7.5 billion in subsidies unrelated to electricity production are either related to the 

promotion of alternative transportation fuels, i.e., bioenergy/biofuels or funding for programs that 

focus on energy efficiency and conservation by residential, commercial, and industrial end users 

of electricity and other conventional energy sources. Conservation, energy efficiency, and other 

end-use subsidies reduce consumption thereby slowing the demand for capacity additions. 

While these subsidies may be related to electricity (and other forms of energy consumption, 

such as natural gas), they do not provide a direct or indirect subsidy to electricity production. 

Therefore, they are not included for purposes of allocating electricity-related subsidies. A 

second category of subsidies considered end use for purposes of this analysis are grants, 

loans, and loan guarantees made by the Rural Business-Cooperative Service (RBS) under 

various programs including the Renewable Energy and Energy Efficiency Program that was 

created under Section 9006 of the Farm Security and Rural Investment Act of 2002 (Public Law 

107-171). These subsidies include grants and loan guarantees for feasibility studies for 

renewable electric power facilities, e.g., wind, solar, and biomass, or financial assistance for the 

construction of such facilities. The recipients are farmers, ranchers, and small business that are 

planning or actually constructing electric production facilities for use at their commercial 

establishments, farms, or ranches. The electricity produced from facilities that may be 

constructed under these programs is for off-grid use. It is primarily for purposes of improving the 

efficiency of and reducing energy costs for an individual commercial enterprise. Thus, they do 

not fall within the definition of electric production used in this report. 

Energy assistance programs for low-income consumers are also excluded from electricity 

production subsidies. These include LIHEAP and the RUS Assistance to High Energy Cost 

Rural Community grant program. The LIHEAP program, at $2.2 billion, was the second-largest 

energy subsidy not allocated to electricity production.201 Arguably, LIHEAP provides an indirect 

subsidy to retail electricity suppliers by providing financial assistance to low-income consumers 

to defray heating and cooling costs through block grants provided to the States. Thus, the 

indirect benefit to retail electricity suppliers is the reduction of accounts receivable or delinquent 

accounts. 

 

201 The tax credit for alcohol fuels, at $3.0 billion, was the largest energy-related subsidy not allocated to electricity production. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 95 

Energy assistance programs do not subsidize investment in generating capacity because many 

utilities would still be required to provide service under State regulations that preclude the 

termination of service during periods of extreme temperatures.202 The RUS High Energy Cost 

Rural Community grant program provides assistance for rural utility infrastructure. However, the 

means tests for determining eligibility are such that communities and small utilities in Alaska are 

 

202 A State-by-State summary of seasonal termination protection policies is available on the LIHEAP Clearinghouse web site at 

http://liheap.ncat.org/Disconnect/SeasonalDisconnect.htm. 

Table 27. Subsidies not Allocated to Electricity Production (million 2007 dollars) 

Program 

2007 

Subsidy 

Recipient or 

End-Use 

Category 

Hydrogen R&D 230 Basic Research 

Credit for Construction of New Energy-Efficient Homes 20 Residential 

DOE Conservation (Weatherization and State Energy) 256 Residential 

RUS High Energy Cost Community Grants -171 Econ. Dev. 

RBS Small Minority Producer Grants 0.3 Small Businesses 

RBS Value Added Grants 3 Small Businesses 

30-Percent Credit for Residential Purchases/Installations of Solar and Fuel Cells 10 Residential 

RBS Section 9006 Grants 13 Small Business 

Temporary 50-Percent Expensing for Equipment Used in the Refining of Liquid Fuels 30 Refiners 

RBS Loan Guarantees 42 Small Business 

RBS Business and Industry Loan Guarantee 60 Small Business 

DOE Industrial R&D 66 Applied Research 

Credit for Energy Efficient Appliances 80 Manufactures 

Building Technology, State and Community Programs 103 Commercial 

Exclusion for Utility-Sponsored Conservation Measures 110 Residential 

Allowance of Deduction for Certain Energy-Efficient Commercial Building Property 190 Commercial 

Credit for Energy-Efficiency Improvements of Existing Homes 380 Residential 

Low Income Home Energy Assistance Program 2,188 Residential 

Expensing of Capital Costs with Respect to Complying with EPA Sulfur Regulations 10 Refiners 

USDA Research, Education, and Extension Service (REES)-Bioenergy/Biofuels 29 Applied Research 

Alcohol Fuel Credit 50 Alt. Fuels Industry 

Biodiesel and Small Agri-Biodiesel Product Tax Credits 180 Alt. Fuels Industry 

DOE Transportation R&D 221 Applied Research 

Credit, Deduction for Clean Fuel Vehicles 260 Individuals/Fleets 

Excise Taxes/VEETC (Alcohol Fuels Exemption) 2,990 Alt. Fuels Industry 

 Subtotal 7,540 

Fuel Specific Subsidies 2,330 

End-use sectors 

other than Electric 

Power 

Total 9,834 

NOTES: Total may not equal sum of components due to independent rounding. 

1Reflects a rescission of allocated grant funds from the prior fiscal year.

Sources: Office of Management and Budget, Budget of the United States Government, Fiscal Year 2008-Appendix. 

Office of Management and Budget, Analytical Perspectives Budget of the United States Government, Fiscal Year 

2008, Federal Receipts and Collections, http://www.whitehouse.gov/omb/budget/fy2008/. Joint Committee on 

Taxation, “Estimated Budget Effects Of The Conference Agreement For Title XIII of H.R. 6, The Energy Tax 

Incentives Act Of 2005," JCX59-05, July 27, 2005. Energy Information Administration, Electric Power Annual 2006, 

DOE/EIA-0348 (2006) (Washington, DC, November 2007). http://www.eia.doe.gov/fuelelectric.html. EIA analysis. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

96 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

the principal beneficiaries. Many of these systems are electrically isolated within the State of 

Alaska. 

The $2.3 billion in fuel-specific subsidies not allocated to electric production include an allocable 

portion of a variety of tax expenditures and direct expenditures including; expensing of 

exploration and development costs, excess of percentage over cost depletion, fuel-specific 

R&D, and changes in natural gas pipeline property life for tax depreciation purposes. All of the 

fuel-specific subsidies that were allocated on the basis of end-use consumption ratios are listed 

in Table 30. The derivation of the fuel allocation ratios and the division of fuel-specific subsidies

to the electric power sector are described in the following section. 

Subsidies Allocated by Fuel Type 

There are a variety of tax expenditures and R&D expenditures that provide benefits to fuel 

producers, researchers, and industry. Tax expenditures are in the form of production or 

investment tax credits, tax deferrals, preferred tax rates, and expense deductions, e.g., 

expensing all or a portion of costs that are normally capitalized. Electricity producers are not 

necessarily the direct beneficiary of these expenditures. Fuel producers, as taxpayers, are the 

direct recipient of the benefit of production tax credits, investment tax credits, and preferential 

expensing of development and capital costs allowed for the production of particular fuels. The 

attribution and allocation of these subsidies to electric generation by fuel type is premised on 

the fact that government expenditures that promote such economic activities ultimately provide 

benefits to electricity producers that consume that particular fuel. For example, the expensing of 

natural gas and oil exploration and development costs reduces producers’ current period 

taxable income, which provides an incentive to invest in capital equipment to explore and 

develop natural gas and oil resources situated in deep water or in remote and geologically 

complex onshore locations. By subsidizing the initial foray of exploration and development that 

harbor potential plentiful domestic supplies that are not commercially viable at current market 

prices, the industry is able to develop new technologies and methods that may hasten the 

commercial viability of bringing geologically remote energy supplies to market. In the long-run, 

the expectation is that these subsidies increase energy supplies. Thus, existing electricity 

generators will benefit from increased supply and lower prices. 

A similar argument applies with respect to allocating R&D expenditures for advanced clean 

fuels and power production technology to current electric production. From an intertemporal 

perspective, current generating capacity may employ more efficient production and 

environmental technologies as a result of past R&D expenditures. While the electric power 

industry invests in R&D to increase the efficiency of the production and delivery of electricity, 

e.g., the research activities of the Electric Power Research Institute, government R&D 

expenditures are typically targeted at the investigation of new technologies for which either the 

risk or the long lead time incurred prior to realization of a return on investment make such 

expenditures financially prohibitive to the private sector. Based on this theory, current electricity 

producers are deemed to be indirect beneficiaries of R&D expenditures. Therefore, fuel-related 

R&D expenditures are allocated to generation by fuel type based on the proportion of each fuel 

consumed in electricity production relative to total consumption across all market segments. 

Other subsidies are more clearly attributable to electricity production by fuel type, such as the 

production tax credit for electricity generated by newly-constructed nuclear plants and clean 

coal tax initiatives. Clean Renewable Energy Bonds and New Technology Tax Credits subsidize 

a variety of renewable fuels, e.g., biofuels, synthetic coal, wind, and biomass. Given the 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 97 

inherent uncertainty regarding technology and fuel choice of electricity producers that choose to 

take advantage of these subsidies, they are allocated based on the proportion of each fuel that 

was consumed in electricity production in 2006. In the absence of detailed information on 

individual renewable subsidies, a weighted average fuel ratio reflecting the amount of all 

renewable fuels consumed by electricity producers is used. With respect to the Section 29 and 

Section 45 production tax credits, the methodology used to allocate the value of these tax 

expenditures estimated by the Treasury Department is described in Chapter 2.

Derivation of Fuel Ratios 

The ratios used to allocate subsidies by generation fuel type represent the portion of each 

primary fuel consumed for electricity production relative to the remaining sectors of the 

economy, such as industry and transportation (Table 28). 

Natural gas and petroleum liquids are represented by a single ratio. This ratio reflects the 

weighted average of natural gas and petroleum used in electricity production relative to total 

natural gas and petroleum consumption. The Treasury Department’s published estimate of oil 

and natural gas production-related tax expenditures does not allocate the value of the tax 

expenditure between oil and natural gas. Because natural gas predominates compared to oil in 

electricity production, EIA used a weighted average of the respective amounts of each fuel

consumed by electricity producers. Additionally, in 2006, 32.4 percent of natural gas-fired 

generation for which natural gas is the primary fuel reported petroleum as a secondary fuel.

203

A composite fuel ratio and individual fuel ratios are developed for purposes of allocating 

subsidies to renewable electric generation. This is because some subsidies specifically target a 

particular technology while in other instances insufficient data were available to allocate a 

subsidy between the categories of renewables. For example, the allocation among renewable 

 

203 Energy Information Administration, Annual Energy Review 2006, DOE/EIA-0384(2006) (Washington, DC, June 2007), Table 

2.8. 

Table 28. Fuel Allocation Factors (percent) 

Fuel 

Fuel Consumed in Electricity 

Production as a Percentage of Total 

Fuel Consumption 

Coal 91.0

Natural Gas and Petroleum Liquids 11.3 

Nuclear 100.0 

Renewables 56.4 

 Wind 100.0 

 Solar 7.0 

 Biomass and biofuels 12.9 

 Geothermal 89.5 

 Hydroelectric 98.9 

NOTE: The ratio of power sector consumption for Natural Gas and Petroleum Liquids 

represents a weighted average across both fuel types. 

Source: Energy Information Administration, Annual Energy Review 2006, DOE/EIA0384 (2006) (Washington, DC, June 2007), Tables 1.3 and 2.1f. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

98 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

technologies for governmental entities and electric cooperatives that received volume cap 

allocations to issue Clean Renewable Energy Bonds (CREB) tax credit bonds pursuant to IRC 

Section 54(f) cannot be estimated with any reasonable precision because Internal Revenue 

Service (IRS) disclosure limitations preclude the release of taxpayer-specific information. In the 

case of CREBS, IRC section 54(d)(2) defines the term "qualified project" as any of the following 

qualified facilities: wind, closed-loop biomass, open-loop biomass, geothermal, solar energy, 

small irrigation power, landfill gas, trash combustion, refined coal production facility under IRC 

section 45(d)(8) and a qualified hydropower facility.204 

Furthermore, based on the data available for the results of the IRS’ most recent allocation of 

CREBs credits by fuel–type or technology, which uses a "smallest to largest method," i.e., 

projects for which the smallest amount of the dollar cap has been requested, up to the 

maximum volume cap, there are not sufficient data to allocate CREBs credits by individual 

renewable technology.205 On December 27, 2005, the IRS issued a notice requesting 

applications for allocations of CREBS. On November 20, 2006, the IRS released the results of 

the volume cap allocation process. There were a total of 610 projects approved by renewable 

fuel type, which are summarized by fuel type in Table 29. While 71 percent of the approved 

projects were solar and 18 percent were wind, in the absence of detailed tax return information 

for those projects that issued CREBs, it is not possible to determine which renewable 

technology received the largest benefit in total dollars. 

Subsidies Allocated by Fuel Type 

The total value of energy subsidies that is allocated to specific fuel types $7.4 billion (Table 30). 

EIA estimates that, of this $7.4 billion, $5.1 billion is allocable to electricity production based on

the share of each fuel consumed by the electric power sector relative to the total consumption 

of each fuel. The remainder of those subsidies for which less than 100 percent is allocated to 

electricity is assumed to be utilized by other sectors of the economy that also consume the 

particular fuel. 

EPACT2005 provides for a nuclear production tax credit of 1.8 cents per kilowatthour applicable 

to electricity produced by the first 6 gigawatts of new nuclear capacity constructed and placed in 

service by 2020. As there are no nuclear plants eligible for the credit in the year 2007, there is 

 

204 A qualifying hydroelectric project must certify that an incremental increase in capacity of an existing facility meets FERC 

efficiency requirements. Applicants must also certify that the proposed facility meets FERC licensing regulations. See IRC Sections 

45(c)(8) and 45(d)(9). 

205 On December 27, 2005, the IRS issued a notice requesting applications for allocations of CREBS. On November 20, 2006, the 

IRS released the results of the volume cap allocation process. The Secretary of the Treasury authorized 610 State and local 

governmental entities, and electric cooperatives to issue CREBs. 

Table 29. Fiscal Year 2006 CREB Authorized Allocation by Fuel Type 

Renewable Fuel Type Number of Projects 

Hydroelectric 14 

Landfill Gas 36 

Open Loop Biomass 13 

Refined Coal 1 

Solar 434 

Wind 112 

Total 610 

Source: Internal Revenue Service, Informational Release IR-2006, November 20, 

2006. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 99 

no estimate of subsidy associated with nuclear production tax credit in this analysis. The 

Federal Credit Support Supplement to the FY 2008 budget shows no loan commitments for the 

EPACT Title XVII loan guarantee for program FY 2007.

206 The anticipated commercial 

operation date for new nuclear plants that would qualify for the credit is outside this forecast 

period.207

 

206 Office of Management and Budget, Federal Credit Supplement Fiscal Year 2008, Table 2: Loan Guarantees: Subsidy Rates, 

Commitments and Average Loan Size," p.2. 

207 EIA’s AEO2007 reference case forecast assumes 9.0 gigawatts of nuclear capacity will be built by 2020 and will receive tax 

credits worth 1.2 cents per kWh, which is consistent with the allocation method prescribed by the IRS in the event the nameplate 

capacity of eligible nuclear capacity exceeds the 6-gigawatt limit. See Energy Information Administration, Annual Energy Outlook 

2007, DOE/EIA-0383 (Washington DC, February 2007), p. 84. The IRS provided guidance concerning the allocation of the nuclear 

production tax credit in Internal Revenue Bulletin 2006-18, Notice 2006-40, "Credit for Production from Advanced Nuclear 

Facilities," Section 3, May 1, 2006. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

100 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

Table 30. Fuel-Specific Energy Subsidies (million 2007 dollars) 

Subsidy Program 

2007 

Subsidy 

Electricity 

Production 

Share Fuel 

Refined Coal Alternative Fuel Production Credit 2,370 2,156 Refined Coal 

Fuel and Power Systems (Advanced Research and Technology Development) 311 283 Coal 

Capital Gains Treatment of Royalties in Coal 170 155 Coal 

Clean Coal Power Initiative (R&D) 61 55 Coal 

Future Gen Advanced Clean Fuels (R&D) 54 49 Coal 

Exclusion of Special Benefits for Disabled Coal Miners 50 46 Coal 

84-Month Amortization of Certain Pollution Control Facilities 30 27 Coal 

Credit for Investment in Clean Coal Facilities 30 27 Coal 

Partial Expensing for Advanced Mine Safety Equipment 10 9 Coal 

Unallocated (Coal R&D Programs) 148 135 Coal 

Expensing of Exploration and Development Costs 860 98 Nat. Gas and Oil 

Excess of Percentage over Cost Depletion 790 90 Nat. Gas and Oil 

Amortize All Geological and Geophysical Expenditures over 2 Years 60 7 Nat. Gas and Oil 

Natural Gas Distribution Pipelines Treated as 15-Year Property 50 6 Nat. Gas and Oil 

Exception from Passive Loss Limitation for Working Interests in Oil and Natural Gas 

Properties 30 3 Nat. Gas and Oil 

U.S. Geological Survey Energy Research and Development 20 2 Nat. Gas and Oil 

Natural Gas (R&D) 15 2 Nat. Gas and Oil 

Oil (R&D) 4 * Nat. Gas and Oil 

New Nuclear Plants (R&D) 319 319 Nuclear 

Waste/Fuel/Safety (R&D) 350 350 Nuclear 

Nuclear Decommissioning (R&D) 199 199 Nuclear 

Unallocated (Nuclear R&D) 253 253 Nuclear 

New Technology Credit (Investment Energy Tax Credit, Production Tax Credit) 690 690 Wind 

Biomass (and Biofuels) (R&D) 246 32 Biomass (and Biofuels) 

Solar (R&D) 187 13 Solar 

Credit for Holding Clean Renewable Energy Bonds 60 34 Renewables 

Wind (R&D) 58 58 Wind 

Geothermal (R&D) 6 5 Geothermal 

Renewable Energy Production Incentive 5 3 Renewables 

Total 7,435 5,105 

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

* Value less than $0.5 million. 

Sources: Office of Management and Budget, Budget of the United States Government, Fiscal Year 2008-Appendix, Office of 

Management and Budget, Analytical Perspectives Budget of the United States Government, Fiscal Year 2008, Federal Receipts 

and Collections. See, http://www.whitehouse.gov/omb/budget/fy2008/. Joint Committee on Taxation, "Estimated Budget Effects 

Of The Conference Agreement For Title XIII of H.R. 6, The Energy Tax Incentives Act Of 2005," JCX59-05, July 27, 2005. 

Energy Information Administration, Electric Power Annual 2006, DOE/EIA-0348 (2006) (Washington, DC, November 2007). 

Energy Information Administration, Form EIA-906, "Power Plant Report;" Form EIA-920 "Combined Heat and Power Plant 

Report;" October 2006-September 2007. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 101 

Interest Rate Support to Federal Utilities and RUS Borrowers 

The implied Federal support to TVA, the PMAs, and RUS borrowers is measured in terms of 

the differential between the embedded cost of debt of each entity, i.e., the quotient of current 

interest expense and current long-term debt, and a series of current interest rates for debt of 

comparable maturity. These rates include the Treasury’s cost of money and investment grade 

rated IOU bonds ranging from Aaa to Baa. Theoretically, this method is akin to TVA, the PMAs, 

and all RUS borrowers refinancing their outstanding obligations at current interest rates, 

excluding transaction costs, while assuming all other risk factors, i.e., operational, financial, 

regulatory, environmental, competition, etc., that investors would consider in pricing the new 

debt issue are consistent with a given investment grade rating. For purposes of this report, the 

A bond rate is used for a point estimate. 

Chapter 4 provides a detailed discussion of how a range of cost-of-capital support values was 

derived for each entity. The methodology considered their unique attributes and made 

adjustments to account for long-term obligations that for purposes of calculating the support 

should be treated as long-term debt. These obligations, such as TVA’s lease/lease back and 

the unamortized prepayment received from customers that reduced their future power supply 

costs through prepayments, are obligations that the nationally-recognized rating agencies 

would consider in determining the adequacy of cash flow to cover fixed obligations (i.e., a 

modified debt service coverage ratio). 

With respect to the Federal utilities, the support was allocated by fuel type on the basis of the 

reported net book cost for each type of generating capacity, as reported in their respective 

financial reports. The RUS interest support estimate, which reflects the support applicable to 

RUS generation-related insured loans and loan guarantees made to both distribution and power 

supply borrowers, was allocated on the basis of net summer capability. Based on an A-rated 

benchmark interest rate, support associated with the Federal utilities’ generating capacity (and 

therefore allocated by fuel type) is estimated at $366 million (Table 31). Of the five, BPA 

realizes the highest interest rate support based on current interest rates at $146 million, 

followed by TVA at $119 million. WAPA ranks third at $41 million. Unlike the PMAs, TVA owns 

and operates a diversified portfolio of generation, which is dominated by its investment in 

nuclear and coal-fired capacity. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

102 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

Table 31. Allocation of Federal Utilities’ Interest Support by Fuel Type (million 2007 dollars) 

 Federal Utility Interest Support by Fuel Type 

TVA Hydroelectric 8 

TVA Nuclear 63 

TVA Fossil 43 

TVA Combustion Turbine 5 

 TVA Total 119 

BPA Hydroelectric 65 

BPA Nuclear 81 

 BPA Total 145 

WAPA Hydroelectric 41 

SWPA Hydroelectric 36 

SEPA Hydroelectric 24 

 Federal Utilities Support Allocated to Generation 364 

NOTES: Total may not equal sum of components due to independent rounding. 

TVA and PMA support is calculated from their annual audited financial statements, which conform to the Federal 

government’s fiscal year. 

Sources: Based on EIA analysis and financial data obtained from Global Insight; Original Source: Moody's 

Investor Services. Federal Reserve Bank's Form H-15. Tennessee Valley Authority SEC 10-K, 2006. Bonneville 

Power Administration 2006 Annual Report. Southeastern Power Administration 2005 Annual Report, 

Southwestern Power Administration 2004-2006 Annual Report and Western Area Power Administration 2006 

Annual Report. 

Based on an A bond rating, the estimate of the RUS generation-related interest rate support is 

$43 million of which $25 million is allocated to coal-fired capacity and $15 million to natural gasfired and oil-fired capacity (Table 32). The support allocated to nuclear generation is $3 million, 

or 6 percent of the total generation-related subsidy. While RUS provided a substantial amount 

of loan guarantees for nuclear plants in the late 1970s and early 1980s, many of these assets 

were sold to investor-owned utilities in conjunction with bankruptcy reorganization plans and 

consensual debt-restructuring agreements. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 103 

Transmission, Distribution, and Other Subsidies and Support for Electricity 

Production 

Approximately $1.2 billion in subsidies and support are directed to transmission, distribution, 

and general plant (Table 33). These subsidies and support include the interest support 

associated with the transmission and distribution assets owned by the Federal utilities and 

transmission and distribution loans made by the RUS. Also included in this category are 

transmission-related tax expenditures that were created to provide incentives for transmission 

owners to invest in transmission infrastructure and restructure ownership or operational control 

of transmission facilities consistent with Federal Energy Regulatory Commission policies. A 

third component consist of R&D expenditures. The tax credit for fuel cells and microturbines, 

was included in this category. They are forms of distributed or dispersed generation that be 

used as a substitute for transmission and distribution facilities. Therefore the subsidy was 

included in this category. Finally, the exclusion from gross income of interest on certain energy 

facilities was included in this category because of a lack of data to allocate this tax expenditure 

by fuel type. 

Of the $1.2 billion of electricity subsidies not directly related to production, nearly one-half ($530

million) is associated with the favorable treatment of the gain realized from the sale of 

transmission assets to an independent transmission company (Table 33). The purpose of this 

tax expenditure was to reduce the immediate tax burden associated with the sale of 

transmission assets by deferring recognition of the gain over a 4-year period to be ratably 

recovered over 8 years. The extent to which the Treasury Department’s estimate of this subsidy 

is realized depends on the number of qualified transactions that occur prior to the provision's 

expiration on December 31, 2008. Since the enactment of this provision in Section 909 of the 

AJCA, and the extension of the sunset to December 31, 2007, in Section 1305 of EPACT2005, 

only one such transaction has been approved by FERC and closed. Another transaction is 

pending approval by various State regulatory commissions and the FERC. 

Table 32. Allocation of RUS Interest Support by Fuel Type 

Fuel Type Summer Capability 

(MW) 

Summer Capability 

(percent) 

Support by Fuel Type 

(million 2007 dollars) 

Coal 22,383 56 25 

Natural Gas and Oil 13,474 35 15 

Nuclear 2,238 6 3 

Hydroelectric 804 2 *

Renewable 55 * *

Total 38,954 100 43 

NOTE: Totals may not equal sum of components due to independent rounding. RUS support values are 

calculated on calendar year balance sheet data. 

*Less than 0.5 percent, or less than $500 million. 

Sources: Based on EIA analysis and data obtained from Rural Utilities Service, 2005 Statistical Report of 

Rural Electric Borrowers, Publication 201-1, and (December 2006). Energy Information Administration, 

Form EIA-860, "Annual Electric Generator Report," 2006. EIA analysis. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

104 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

Both transactions involve the acquisition of investor-owned utility properties by operating 

subsidiaries of ITC Holdings.208 The first transaction involved the ITC Holdings’ subsidiary ITC 

Transmission Company’s acquisition of Michigan Electric Transmission Company LLC and 

Trans-Elect NTD Path 15, LLC. The transaction was approved by the FERC on September 21, 

2006. The second transaction, which was announced in early 2007, involved ITC Midwest’s 

acquisition of the transmission facilities of Interstate Power & Light Company. FERC approval of 

the acquisition is pending, as are approvals by a number of Midwest State regulatory 

commissions. The second largest expenditure is the interest rate support applicable to the 

Federal utilities and RUS associated with transmission, distribution, and general plant. 

Collectively, the interest support for non-generation-related assets owned or financed by these 

entities totals $361 million. This is followed by transmission and delivery R&D at $137 million. 

Because all types of generation benefit from non-discriminatory open access, increased 

reliability, and new technology, this support is allocated to electricity production in general rather

than to a specific fuel or technology. 

 

208 In a September 2007 Press Release, ITC Holdings described itself as the "only publicly-traded company engaged exclusively in 

the transmission of electricity in the US Source: ITC Holdings, http://investor.itc-holdings.com/releasedetail.cfm?releaseid=264581. 

Table 33. FY 2007 Electricity Transmission, Distribution, and Other Subsidies 

and Support (million 2007 dollars) 

Program Subsidy and Support Categories 

Subsidy 

and 

Support 

RUS Other Electric Plant 262 

SWPA Other Electric Plant 8 

WAPA Other Electric Plant 40 

BPA Other Electric Plant 46 

TVA Other Electric Plant 5 

Electricity Delivery and Reliability (Electricity Technologies) 137 

Direct Thermal to Electric Conversion 3 

Treatment of Income of Certain Electric Cooperatives 14 

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

Transmission Property Treated as 15-Year Property 18 

Deferral of Gain from Dispositions of Transmission Property to Implement FERC Restructuring Policy 530

Credit for Business Installation of Qualified Fuel Cells and Stationary Microturbine Power Plants 90 

Exclusion of Interest on Bonds for Certain Energy Facilities 40 

Total 1,235 

NOTE: Total may not equal sum of components due to independent rounding. 

Sources: Office of Management and Budget, Budget of the United States Government, Fiscal Year 2008-Appendix, 

Office of Management and Budget, Analytical Perspectives Budget of the United States Government, Fiscal Year 

2008, Federal Receipts and Collections. See, http://www.whitehouse.gov/omb/budget/fy2008/. Joint Committee on 

Taxation, "Estimated Budget Effects Of The Conference Agreement on Title XIII of H.R. 6, The Energy Tax 

Incentives Act Of 2005," JCX59-05, July 27, 2005. Energy Information Administration, Electric Power Annual 2006, 

DOE/EIA-0348 (2006) (Washington, DC, November 2007). Energy Information Administration, Form EIA-906,

"Power Plant Report;" Form EIA-920 “Combined Heat and Power Plant Report;" October 2006-September 2007. 

Tennessee Valley Authority SEC 10-K, 2006. Bonneville Power Administration, 2006 Annual Report. Southeastern 

Power Administration, 2005 Annual Report, Southwestern Power Administration, 2004-2006 Annual Report and 

Western Area Power Administration, 2006 Annual Report. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 105 

Per-Unit Electricity Subsidies by Fuel Type 

When grouped by type of subsidy, tax expenditures account for $4.3 billion of the estimated 

$6.7 billion in electric production subsidies (Table 34). R&D is the second largest category of 

subsidies at $1.7 billion. When allocated by fuel type fuel type, refined coal alternative fuel 

production tax credits account for one-half at $2.2 billion, followed by nuclear at $1.3 billion and 

non-fuel specific electricity subsidies at $1.2 billion. Renewable electricity production received 

an estimated $1.0 billion in subsidies, of which $724 million consists of tax expenditures. 

Table 34. Fiscal Year 2007 Electricity Production Subsidies and Support (million 2007 dollars) 

Fuel/Other 

Direct 

Expenditures 

Tax 

Expenditures 

Research & 

Development 

Federal 

Electricity 

Support Total 

Coal - 264 522 68 854 

Refined Coal - 2,156 - - 2,156 

Natural Gas and Petroleum Liquids - 203 4 20 227 

Nuclear - 199 922 146 1,267 

Renewables 3 724 108 173 1,008 

Transmission and Distribution - 735 140 360 1,235 

Total 3 4,281 1,696 767 6,747 

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

Sources: Office of Management and Budget, Budget of the United States Government Fiscal Year 2008-Appendix, Office 

of Management and Budget, Analytical Perspectives Budget of the United States Government, Fiscal Year 2008, Federal 

Receipts and Collections. See, http://www.whitehouse.gov/omb/budget/fy2008/. Joint Committee on Taxation, "Estimated 

Budget Effects Of The Conference Agreement For Title XIII Of H.R. 6, The Energy Tax Incentives Act Of 2005," JCX59-05, 

July 27, 2005. Energy Information Administration, Electric Power Annual 2006, DOE/EIA-0348(2006) (Washington, DC, 

November 2007). Energy Information Administration, Form EIA-906, "Power Plant Report;" Form EIA-920 "Combined Heat 

and Power Plant Report;" October 2006-September 2007. Tennessee Valley Authority SEC 10-K, 2006. Bonneville Power 

Administration 2006 Annual Report. Southeastern Power Administration 2005 Annual Report. Southwestern Power 

Administration 2004-2006 Annual Report and Western Area Power Administration 2006 Annual Report. 

The per-unit subsidies are calculated as the subsidies allocated to each fuel type divided by the 

FY 2007 electricity generated by each fuel type (Table 35). Refined-coal-related generation 

receives the largest subsidy in absolute terms, at roughly $2 billion, as well as the highest perunit value at $29.81 per megawatthour. Renewable electricity production, in aggregate, 

received subsidies totaling $1.0 billion, but the per-unit subsidy in aggregate is $2.80 per 

megawatthour. On a fuel-specific basis, solar and wind subsidies receive the second-and-third 

highest per unit subsidies. However, the total value of subsidies received by each of these 

technologies was roughly in proportion to their relative share of net generation. As, a result, 

their respective per-unit subsidies are nearly equal. In the case of solar, the per-unit subsidy 

estimate of $24.34 per megawatthour is a function of the relatively high allocation of subsidies 

received, $14 million, and its low share of total electricity production. Wind received $724 million 

in subsidies, valued at $23.37 per megawatthour. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

106 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

Of the $9.8 billion in energy subsidies not related to electricity (Table 36), about one-third of the 

total promotes fuels, particularly ethanol and biodiesel, which are eligible to receive a blender’s 

credit under the Volumetric Ethanol Excise Tax Credit (VEETC). Blenders receive a $0.51 per 

gallon credit for each gallon of ethanol that is blended with gasoline for use as a motor fuel. In 

FY 2007, ethanol (and biofuels) consumption was just over half a quadrillion Btu, or about one 

half of one percent of all the energy consumed in the United States. On a consumption basis, 

ethanol is subsidized at a rate of $5.72 per million Btu, more than any other non-electric fuel. 

About 60 percent of all fuel consumed in the United States is consumed by primary end-use 

sectors, i.e., residential, commercial, industrial and transportation. In FY 2007 subsidies for 

petroleum liquids and natural gas totaled $2.1 billion. Although natural gas-fired generation has 

increased 86 percent between 1997 and 2007, power sector consumption of natural gas has 

increased only slightly as a share of total energy consumption in the United States, growing 

from around 5 percent of the national total to just under 7 percent. So, of the $2.1 billion in total

natural gas and petroleum liquids subsidies, $1.9 billion are allocated to the primary end-use 

Table 35. Subsidies and Support to Electricity Production: Alternative Measures 

Alternative Measures of Subsidy and Support 

Fuel/End Use 

FY 2007 Net 

Generation (billion 

kilowatthours) 

Subsidy and 

Support Value 

2007 

(million dollars) 

Subsidy and Support Per 

unit of Production 

(dollars/megawatthours) 

Coal  1,946  854  0.44

Refined Coal  72  2,156  29.81 

Natural Gas and Petroleum Liquids  919  227  0.25 

Nuclear  794  1,267  1.59 

Biomass (and Biofuels)  40  36  0.89 

Geothermal  15  14  0.92 

Hydroelectric  258  174  0.67 

Solar1 

 1  14  24.34 

Wind  31  724  23.37 

Landfill Gas  6  8  1.37 

Municipal Solid Waste  9  1  0.13 

Unallocated Renewables  NM  37  NM 

 Renewables (subtotal)  360  1,008  2.80 

Transmission and Distribution  NM  1,235  NM 

Total  4,091  6,747  1.65 

NOTES: Total may not equal sum of components due to independent rounding. 

Unallocated renewables include projects funded under Clean Renewable Energy Bonds and the Renewable Energy 

Production Incentive. 

NM = Not meaningful. 

1Net generation rounded to the nearest whole number. The actual value is 583 million kilowatthours. 

Sources: Energy Information Administration, Forms EIA-906, "Power Plant Report;" Form EIA-920, "Combined Heat 

and Power Plant Report;" October 2006-September 2007. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 107 

sectors with the remainder to electricity production. With over 60 percent of total energy 

consumption in the U.S. associated with natural gas and petroleum, the two fuels receive 

relatively small subsidies on a consumption unit basis, only about three cents per million Btu. 

Similarly, hydrogen, which is used in fuel cells and in a limited number of transportation pilot 

programs received $230 million in subsidies in FY 2007. However, consumption is so small that 

the subsidy per million Btu is not meaningful for comparison purposes in Table 36. 

Subsidies totaling another $3.6 billion do not directly affect fuel production or specific fuel 

consumption. These programs focus on energy efficiency, conservation, and energy-related 

financial assistance to residential, commercial, and industrial end-users. The largest of these 

programs, the Low Income Home Energy Assistance Program (LIHEAP), provided $2.2 billion 

in FY 2007 to subsidize heating and cooling costs. No program information is available to 

determine the portion of the expenditure directed to the affected fuels, which include distillate 

fuel, natural gas, coal, and electricity. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

108 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

Table 36. Energy Subsidies Not Related to Electricity Production: Alternative Measures 

Alternative Measures of Subsidy and Support 

Category 

Fuel 

Consumption 

(quadrillion Btu) 

FY 2007 Subsidy and 

Support 

 (million 2007 dollars

Subsidy per million 

Btu 

(2007 dollars) 

Coal 1.93 78 0.04 

Refined Coal 0.16 214 1.35 

Natural Gas and Petroleum Liquids 55.78 1,921 0.03 

Ethanol/Biofuels 0.57 3,249 5.72 

Geothermal 0.04 1 0.02 

Solar 0.07 184 2.82 

Other Renewables 2.50 360 0.14 

Hydrogen * 230 NM 

Total Fuel Specific1 60.95 6,237 0.10 

Total Non-Fuel Specific NM 3,597 NM 

 Total End-Use and Non-Electric Energy NM 9,834 NM 

NOTES: Non-electric power industry refined coal consumption is based on the sum of monthly deliveries, in short tons, 

reported in the EIA publications cited below for FY 2007. Delivered refined coal to non-electric customers is converted to 

equivalent Btu consumption based on EIA’s estimate of the average Btu content for refined coal deliveries to generators 

reported to EIA. Other renewables includes hydroelectric, wood, biomass losses and co-products, and hydroelectric power 

as reported in the sources noted below. 

1

Subsidy shown differs from that shown in Table 26 due to inclusion of fuels that have no role in electricity production, such 

as ethanol and other biofuels. 

*

Less than 500 trillion Btu. 

NM = Not meaningful. 

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

Sources: Energy Information Administration, Monthly Energy Review December 2007, DOE/EIA-0035 (2007/12) 

(Washington, DC, December 2007), Table 10.2a and 10.2b; Energy Information Administration, Quarterly Coal 

Report, DOE/EIA-0121 (2007/03Q) (Washington, DC, December 2007), Table 35; Energy Information Administration, 

Quarterly Coal Report , DOE/EIA-0121 (2006/04Q) (Washington, DC, March 2007), Table 38; Office of Management and 

Budget, Budget of the United States Government, Fiscal Year 2008-Appendix; Office of Management and Budget, 

Analytical Perspectives Budget of the United States Government, Fiscal Year 2008, Federal Receipts and Collections, 

http://www.whitehouse.gov/omb/budget/fy2008/; Joint Committee on Taxation, “Estimated Budget Effects Of The 

Conference Agreement For Title XIII of H.R. 6, The Energy Tax Incentives Act Of 2005," JCX59-05, July 27, 2005. 

(Washington, DC, November 2007); Energy Information Administration, Form EIA-860, "Annual Electric Generator 

Report," 2006; Form EIA-906, "Power Plant Report;" and Form EIA-920, and "Combined Heat and Power Plant Report," 

October 2006 through September 2007. 
 

Federal Financial Interventions and Subsidies in Energy Markets 2007 

Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 109 

Perspectives on Electricity Subsidy Estimates 

The issue of what constitutes a Federal government benefit is not without controversy. The 

intention of this analysis is not to assess all the cost differences faced by Federal utilities, 

cooperatives, public power, and the IOUs. There are numerous tax benefits and tax 

expenditures associated with ownership class. Electricity cooperatives are organized as taxexempt organizations under Federal tax law. Publicly-owned utilities are tax-exempt and have 

the ability to issue lower-cost tax-exempt debt. IOUs benefit from accelerated depreciation, 

which defers taxes and lowers their cost of capital by increasing cash flow. These benefits 

flowed from decisions by individuals and communities on how, and from whom, they wished to 

acquire electric service during the period in which the Nation was electrified. In essence, tax 

laws were expected to allow for different ownership classes of electric utility assets. Whether 

the basis for tax and other benefits attributable to class ownership are equal, or not, remains a 

debatable question to industry analysts. 

These tax expenditures and direct expenditures provide incentives for market participants to 

engage in behavior, e.g., capital investment decisions that will achieve a desired benefit to 

society. This includes reducing dependence on imported oil, promotion of the use of 

environmentally preferred renewable resources, and encouraging participation in transmission 

organizations that facilitate reliability and enhance competition in wholesale electricity markets. 

EIA was requested to provide an estimate of electricity subsidies with fuel-specific effects on a 

per-unit basis. In developing the analytical framework for this study, EIA adopted an inclusive 

approach that encompasses all energy-related R&D, direct expenditures, and tax expenditures 

to which there was a direct or indirect connection to current or future electricity production. This 

approach leaves a number of issues open to further discussion and analysis: 

• EIA recognizes, particularly with respect to tax expenditures that the economic sector 

that the statutory beneficiary of a specific tax expenditure may or may not be the 

economic beneficiary. However, the calculations made in this report assume full pass 

through of current subsidies and support to fuel producers and transporters to electricity 

production. The Incidence Theory suggests that if a tax credit is applicable to a good or 

service that is supply inelastic, the statutory beneficiary can be expected to retain the 

benefit of a tax-expenditure. Possibly, a more accurate result could be obtained by 

conducting either a general equilibrium or partial equilibrium analysis, or a statisticalbased micro-data analysis for individual tax expenditures. 

• Including R&D expenditures raises intertemporal equity issues when applied to current 

electricity production by fuel type. Inclusion of these subsidies can be justified on the 

basis that past R&D expenditures are reflected in generation technologies in use today. 

Moreover, these expenditures are representative of the current direction of energy policy 

of diversification of energy supply, energy security, and environmental protection. 

Additionally, the report recognizes that at times there is a continuum associated with 

applied research and tax expenditures. In certain instances, R&D produces technology 

for which there is only nascent demand because of the initial cost or perceived market 

risk that limits access to financing. Thus, tax incentives or direct expenditures may be 

necessary to overcome this barrier. The production tax credits available for the first 6 

gigawatts of advanced technology nuclear capacity is a good example of the linkage 

between R&D and tax expenditures. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

110 Energy Information Administration / Chapter 5: Electric Subsidies Per Unit of Production 

• Inclusion of Federal electricity programs is not intended to highlight or discriminate 

against a particular segment of the industry. EIA recognizes the methodology used for 

estimating the support is based on available data, and is subject to some uncertainty. 

However, generally accepted economic theory and empirical observation lead to the 

conclusion that the structure of Federal utilities confers a benefit on their customers 

through the belief by capital markets that there is an implicit Federal guarantee of their 

debt. EIA quantified this support using a capital cost method that provides an estimated 

range of interest rate support by comparing the interest expense for each entity at its 

embedded cost of debt to a range of interest rates. By providing an estimate of interest 

rate support between the Treasury rate and the lowest investment grade bond rating, 

alternative estimates of support may be inferred. Based on a comparison of the Federal 

utilities with comparably-structured government-owned wholesale producers, it was 

determined that a benchmark A rated bond interest rate was the most appropriate for a 

point estimate for this report. 
Appendix A 

Fact Sheets 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

112 Energy Information Administration / Appendix A: Fact Sheets 

Tax Expenditures 

1. 30-Percent Credit for Purchase of Residential Solar and Fuel Cells 

Description 

Section 1335 of the Energy Policy Act of 2005 (EPACT2005)(Public Law 109-58) 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, however, 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). The generator must have an efficiency 

rating of 30-percent and generate at least 0.5 kW of electricity. Installation expenditures, such as 

those for labor, are considered eligible for the credit. Solar water heating property must meet 

performance specifications certified by the Solar Rating Certificate Corporation. 

Solar swimming pools are ineligible for the credit.

To be eligible for the credit, a system must be placed in service (activated) between January 1, 

2006 and December 31, 2008. 

Revenue Loss/Outlays 

The lost revenue to the U.S. Treasury from this credit is $10 million (nominal) per year from Fiscal 

Year (FY) 2006 through FY 2008.209 The “Revenue Loss” data in the tabulation were generated 

estimated by the Treasury Department (Table A1). The Revenue Loss is the difference between 

estimated Federal income tax payments in a reference case and estimated actual Federal income 

tax payments. The reference case assumes that royalties on coal are taxed at the regular rate. 

The actual case assumes that the royalties are taxed at the capital gains tax rate to the extent 

taxpayers so choose. 

Table A1. Estimated Revenue Loss: Residential Solar and 

Fuel Cell Credit, 2006 to 2008 (million nominal dollars) 

Fiscal Year Revenue Loss-Individuals 

2006 10 

2007 10 

2008 10 

NOTE: All estimates have been rounded to the nearest $10 million. 

Provisions with estimates that rounded to zero in each year are not 

included in the table. 

Source: Office of Management and Budget, Analytical Perspectives, 

Fiscal Year 2008 (Washington, DC, 2007), Table 19-2. 

Rationale 

To reduce reliance on grid-connected electricity. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Residential distributed generation. 

 

209 Analytical Perspectives, Budget of the United States Government, Fiscal Year 2008, Table 19-1, “Estimates of Total Income 

Tax Expenditures,” Office of Management and Budget; http://www.whitehouse.gov/omb/budget/fy2008/pdf/spec.pdf; accessed 

August 13, 2007. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 113 

2. 84-Month Amortization of Certain Pollution Facilities 

Description 

To effect reductions in sulfur dioxide (SO2) and nitrogen oxides (NOX) emissions, Section 1309 of 

the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) modified Section 169 of the 

Internal Revenue Code (IRC), which permitted a 60-month amortization of qualifying pollution 

control facilities used in connection with plants placed in service before January 1, 1976. The 

modification extends the amortization period to 84 months and eliminates the applicability of the 

provision to plants placed in service prior to the end of 1975. The revised amortization period is 

now applicable to qualifying pollution control facilities placed in service as of April 11, 2005. The 

Joint Committee on Taxation estimated the value of this expenditure to be $30 million for 2007. 

Certified pollution control facilities include identifiable treatment facilities used to reduce, alter, 

dispose, store, or prevent the emission of pollutants. 

Revenue Loss/Outlay 

There is no expected revenue loss associated with this program for 2007. 

Rationale 

To reduce electricity-related emissions. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Generation. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

114 Energy Information Administration / Appendix A: Fact Sheets 

3. Alcohol Fuel Credit 

Description 

The Energy Tax Act of 1978 (Public Law 95-618) established a subsidy for alcohol-based fuels. 

Federal financial incentives for renewable fuels in the transportation sector, strictly speaking, are 

limited to ethanol. Ethanol is produced from grain crops, with corn being the primary feedstock. 

The main use of ethanol is for gasohol (a blend of 90 percent unleaded gasoline and 10 percent 

ethanol, E-10) and for lower blends of ethanol to meet oxygenated gasoline requirements. Ethanol 

used in gasohol and other oxygenated gasoline blends meets the definition of a replacement fuel, 

but not of an alternative fuel. Two higher blends of ethanol, E-85 and E-95, are being used as 

alternative fuels in limited amounts. The value of the tax expenditure for renewable transportation 

fuels is $50 million in fiscal year 2007. 

The alcohol fuel income tax credit and its associated excise tax credit (which is now the 

Volumetric Ethanol Excise Tax Credit or VEETC, see Fact Sheet 20) were initially implemented in 

the late 1970s and early 1980s. The income tax credit was initially 40 cents per gallon minus the 

amount of excise tax exemption, which was 4 cents per gallon. Some modifications to the original 

legislation have subsequently been made. The Omnibus Budget Reconciliation Act of 1990 

(OBRA) (Public Law 101-508) reduced the income tax credit from 60 cents per gallon to 54 cents 

per gallon. The 1990 OBRA also introduced the small producer income tax credit of 10 cents per 

gallon. These provisions went into effect on January 1, 1993. The value of the $3.0 billion excise 

tax exemption on taxable motor gasoline mixed with ethanol is far greater than the $50 million 

ethanol tax expenditure cited above. 

Revenue Loss/Outlays 

The “Revenue Loss” data were estimated by the Treasury Department. The Revenue Loss is the 

difference between estimated Federal income tax payments in a reference case and estimated 

actual Federal income tax payments (Table A2) is presented. The reference case assumes that 

no income tax credits are granted. The actual case assumes that the income tax credit exists and 

that the excise tax credit remains in effect. 

Rationale 

Reduced dependence on foreign sources of transportation fuels. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Ethanol production, and to a much smaller extent, petroleum production. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 115 

Table A2. Estimated Revenue Loss: Alcohol Fuel Credit, 1984 

to 2012 (million nominal dollars)

Revenue Loss 

Fiscal Year Individuals Corporations Total 

1984 (a) (a) (a) 

1985 (a) (a) (a) 

1986 (a

) (a) (a) 

1987 5 5 10 

1988 5 5 10 

1989 (a) (a) (a) 

1990 (a

) (a) (a) 

1991 (a) (a) (a) 

1992 (a

) (a) (a) 

1993 (a

) (a) (a) 

1994 10 5 15 

1995 5 5 10 

1996 5 5 10 

1997 10 10 20 

1998 5 10 15 

1999 5 10 15 

2000 10 10 20 

2001 10 20 30 

2002 10 20 30 

2003 10 20 30 

2004 10 20 30 

2005 10 30 40 

2006 10 40 50 

2007 10 40 50 

2008 10 50 60 

2009 20 50 70 

2010 20 50 70 

2011 10 60 70 

2012 0 0 0 

 NOTE: (

a

) indicates a value under $2.5 million 

All estimates have been rounded to the nearest $5 from 1984 through 

2001. Thereafter all estimates are rounded to the nearest $10 million. 

Provisions with estimates that rounded to zero in each year are not 

included in the table. 

Sources: Office of Management and Budget, Budget of the United States 

Government, Analytical Perspectives Fiscal Year 2008 (Washington, DC, 

2007), Table 19-2, and earlier versions. Energy Information 

Administration, Federal Financial Interventions and Subsidies in Energy 

Markets 1999: Primary Energy, SR/OIAF/99-03, (Washington, DC, 

September, 1999). 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

116 Energy Information Administration / Appendix A: Fact Sheets 

4. Allowance for the Deduction of Certain Energy-Efficient 

Commercial Building Properties 

Description 

Section 1331, of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58), provides for a 

new formula-based tax deduction for energy-efficient commercial properties. The formula-based 

tax deduction was added to the Internal Revenue Code at Section 179D. under the new IRS 

Code, 179D. Section 1331 provides This tax provision allows for a tax deduction of $1.80 per 

square foot on new commercial property 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 American Society of 

Heating, Refrigerating (ASHRAE) Standard 90.1-2001. In the case of properties owned by 

Federal, State, or local governments, or political divisions thereof, the U.S. Treasury Department 

is responsible for issuing regulations to allocate the deduction to the primary designer of the 

property. Section 204 of the Tax Relief and Health Care Act of 2006 extended the credit to 

December 31, 2008. 

For properties not fully meeting the 50 percent reduction, there is a provision for a deduction of 

$0.60 per square foot of property. Partial credit is allowed for qualified improvements to building 

envelope, hot water, heating, ventilation and air conditioning systems (HVAC), and lighting 

systems. These deductions apply to buildings placed in service between January 1, 2006, and 

December 31, 2007. Tax expenditures occasionally affect years outside the timeframe in which 

the law is in force. This may be due to reporting years not overlapping with fiscal years or it may 

be due to tax-loss carryforwards. When the availability of a tax deduction causes results in 

accelerated spending in the near-term, later-term revenue loses may result. The affect of this tax 

deduction is to reduced demand for electricity and natural gas by the commercial sector. 

Revenue Loss/Outlays 

Rationale 

To improve the energy efficiency of commercial buildings. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Electricity and natural gas. 

Table A3. Estimated Revenue Loss: Energy-Efficient Buildings Deduction, 

2006 to 2012 (million nominal dollars) 

Revenue Loss 

Fiscal Year Individuals Corporations Total 

2006 20 60 80 

2007 50 140 190 

2008 40 130 170 

2009 20 70 90 

2010 10 20 30 

2011 0 (10) (10) 

2012 0 (10) (10) 

NOTE: All estimates have been rounded to the nearest $10 million. Provisions with 

estimates that rounded to zero in each year are not included in the table. 

Source: Office of Management and Budget, Analytical Perspectives, Fiscal Year 2008

(Washington, DC, 2007), Table 19-2. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 117 

5. Alternative Fuels Production Tax Credit

Description 

The Alternative (or nonconventional) Fuels Credit was established with the Windfall Profits Tax of 

1980 (Public Law 96-223). It was originally codified as Internal Revenue Code (IRC or Code) 

Section 44D, but it was later redesignated as Section 29 which is what it is most commonly 

referred to today. The Alternative Fuels Credit is a production-based tax credit that originally 

applied to qualified fuels from wells drilled or facilities placed in service between January 1, 1980,

and December 31, 1992, and sold through the year 2002. The qualified fuels were: (1) oil 

produced from shale and tar sands; (2) natural gas produced from geopressurized brine, 

Devonian shale, coal seams, tight formations, or biomass; (3) liquid, gaseous or solid synthetic 

fuels produced from coal liquefaction and pressurization; (4) fuel from qualified processed wood; 

and (5) steam from solid agricultural byproducts. The Alternative Fuel Production Credit is often 

referred as a Section 29 credit based upon its former IRS Code citation. A taxpayer is entitled to 

the credit under Section 29 in the taxable year in which the qualified fuel is sold. Section 29 

cannot be used to offset the alternative minimum tax. 

The principal additional changes that have occurred since the 1980 Act have been to extend the 

time limits by which wells or facilities must be placed in service and fuels sold in order to be 

eligible for the credit. In 1989, legislation allowed a 1-year extension of the time limits. The 

Omnibus Budget Reconciliation Act of 1990 (Public Law 101-508) provided an additional 2-year 

extension. The 1990 act also greatly eased the qualification for gas produced from tight sands 

after 1990. However, subsequently, the qualification had been sharply constrained by Executive 

Branch rulings and judicial decisions. The Energy Policy Act of 1992 (EPACT1992)(Public Law 

102-486) expanded the credit for certain nonconventional fuels. 

Synthetic coal is the largest recipient of the Section 29 tax credit. Under IRC Section 48 coal was 

qualified as a synthetic fuel as defined if it differs significantly in chemical composition from the 

alternative substance used to produce it. To qualify for this credit, a taxpayer must produce and 

sell qualified fuel from a production facility that was placed in service as of July 1, 1998, pursuant

to a binding written contract in place as of January 1, 1997, and produced through December 31, 

2007. The coal may be of any rank from lignite to anthracite although bituminous coals are most 

prominently used. In order to be classified as a synthetic fuel, coal must undergo a significant 

chemical change under the criteria of Internal Revenue Service Revenue Ruling 86-100. This 

measurement takes place in a lab where feedstock coal is compared to synthetic coal to confirm 

that the chemical makeup of the synthetic fuel is not predicted from the ingredients. The liquid 

binding agents used are often such items as diesel fuel emulsions, pine tars, or latex to the blend 

of coal feedstock. The tax credits are based on the Btu value of the synthesized coal. As a 

consequence, Section 29 qualified coal synfuels using Eastern bituminous coals as a feedstock is 

more valuable than synthetic coals using lower-Btu western lignite and sub-bituminous coals. 

Companies have been claiming the credits since as early as 1998.210

Section 710 of the American Jobs Creation Act of 2004 (Public Law 108-357) required that 

synthetic coal be sold by the taxpayer with the reasonable expectation that it will be used for 

purpose of producing steam. The American Jobs Creation Act also redefined synthetic coal to 

“refined coal.” Section 710 also introduced certain restrictions concerning what coal could qualify 

as “refined coal.” Qualified new facilities were to be eligible to receive a Section 45 tax credit, as

discussed in the next paragraph, for the first 10 years of operation. Compared to Section 29 

guidelines, which expire at the end of 2007, the revised guidelines for qualifying coal synfuel 

facilities are significantly more restrictive. Qualifying facilities under the new guidelines require: 1) 

a 20-percent reduction in the emissions of nitrogen oxides and either sulfur dioxide or mercury 

compared to the emissions released when burning the original feedstock coal or comparable coal; 

and, 2) the refined coal product must be at least 50 percent higher in economic value than the 

feedstock. 

 

210 Energy Information Administration, Coal News and Markets, Week of August 10, 2003. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

118 Energy Information Administration / Appendix A: Fact Sheets 

Section 1322 of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) appended 

Section 29 to Section 45 as a new section 45K. Section 45K allows old Section 29 credits to be 

combined with other general business credits. This allows credits to be carried forward 20 years, 

with a 1-year look back. Section 1301 of EPACT2005 extended the Section 45 tax credit to Indian 

coal production. The credit is good for a 7-year period beginning in January 1, 2006. Section 1321 

of EPACT2005 expanded the credit to apply to coke and coke gas produced in certain facilities 

placed in service before January 1, 2010. The credit amount for coke or coke gas is $3.00 per 

barrel of oil equivalent, indexed for inflation using 2004 as the base year with a credit-available 

production limit of an average barrel-of-oil equivalent of 4,000 -barrels -per -day. The tax credit 

provisions set forth in the EPACT2005 extended the tax credit for “refined coal” and waste coal to 

new facilities coming on-line after October 22, 2004, and prior to January 1, 2009.Section 211 of 

the Tax Relief and Heath Care Act of 2006 (Public Law 109-432) removed the phase-out provision 

for coke and coke gas. 

The tax credit for these fuels is $3-per-barrel of oil-equivalent produced. (Conversion factors are 

used to convert the various fuels into their crude oil equivalent for purposes of calculating the 

credit.) The credit is fully effective when the price of crude oil is $23.50 per barrel or less and 

phases out gradually as the price of oil rises to $29.50 per barrel when the subsidy disappears. All 

prices as well as the credit are specified in 1979 dollars, but for actual use they are indexed for 

inflation relative to that base. For 2006, the IRS reported the credit oil price caps at $50.06 when 

the cap began and $69.12 when the cap was complete.211 Domestic first purchase price, the price 

to which the cap is applied, averaged $59.68 per barrel in 2006, indicating that the credit was 

phased down somewhat. The credit is also reduced if certain other energy subsidies, such as 

government grants and tax-exempt financing, are used. The credit applies only to fuel produced at 

a facility placed in service before July 1, 1998, and sold before January 1, 2008. 

Revenue Loss/Outlays 

The lost revenue to the Treasury related to Section 29 started to grow significantly in the early 

1990s. Revenue losses are expected to peak in 2007 before falling to zero by 2011.The “Revenue 

Loss” data in Table A4 were generated by the Treasury Department. The “Revenue Loss” is the 

difference between estimated Federal income tax payments in a reference case and estimated 

actual Federal income tax payments) is presented. The reference case assumes that the 

alternative fuels receive no production credit. The actual case assumes that the credit is granted. 

 

211 Phone interview with Jamie Parks of the IRS, August 20, 2007. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 119 

Rationale 

The alternative fuel tax credit is one of several measures adopted in the early 1980s to encourage 

the development of synthetic fuels produced by nonconventional means or sources. The credit is 

designed to encourage capital investment in alternative fuel production by protecting producers of 

those fuels against the effects of oil price reductions. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Coal bed methane and synthetic (refined) coal. 

Table A4. Estimated Revenue Loss: Alternative Fuel Production Tax Credit, 

1987 to 2012 (million nominal dollars)

Revenue Loss 

Fiscal Year Individuals Corporations Total 

1987 (a) 10 10 

1988 (a) 10 10 

1989 (a) 10 10 

1990 (a) 10 10 

1991 50 205 255 

1992 90 360 450 

1993 120 640 760 

1994 140 760 900 

1995 150 820 970 

1996 150 850 1,000 

1997 30 680 710 

1998 45 815 860 

1999 50 975 825 

2000 40 930 970 

2001 40 860 900 

2002 60 1,500 1,560 

2003 50 1,230 1,280 

2004 40 1,000 1,040 

2005 100 2,220 2,320 

2006 120 2,860 2,980 

2007 100 2,270 2,370 

2008 30 750 780 

2009 0 10 10 

2010 0 10 10 

2011 0 0 0 

2012 0 0 0 

NOTES: (a) $2.5 million or less. 

All estimates have been rounded to the nearest $5 from 1984 through 2001. Thereafter 

all estimates are rounded to the nearest $10 million. Provisions with estimates that 

rounded to zero in each year are not included in the table. 

Sources: 1987-1993: Office of Management and Budget, Budget of the United States 

Government, Fiscal Year 1993 (Washington, DC, 1992) and earlier editions. 1994-2004: 

Office of Management and Budget, Analytical Perspectives, Fiscal Year 2008. 

(Washington, DC, 2007), Table 19-2. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

120 Energy Information Administration / Appendix A: Fact Sheets 

6. Biodiesel and Small Agri-Biodiesel 

Description 

Section 302 of The American Jobs Creation Act of 2004 (AJCA) (Public Law 108-357) amended 

the Internal Revenue Code (IRC or Code) of 1986 by adding a new Section 40A212, which provides 

for a biodiesel mixture credit and a biodiesel credit.213 The estimated value of this credit is $180 

million for 2007. Initially, the credit was due to expire December 31, 2006. Section 1345 of the 

Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) further amended Section 40A to 

include a tax credit for the production and sale of agri-biodiesel by small producers and extended 

the sunset provision through December 31, 2008. 

For purposes of determining general business takes credits under Section 38 of the Code, 

Section 40A defines the biodiesel fuels credit to be the sum of (1) the biodiesel mixture credit, (2) 

the biodiesel credit, and (3) with respect to small agri-diesel producers, the small agri-diesel 

producer credit. 

Eligible taxpayers receive a 50-cents-per-gallon biodiesel mixture credit for each gallon of 

biodiesel used to produce a qualified biodiesel mixture. The taxpayer may sell the biodiesel 

mixture as a fuel or it may be used as a fuel by the taxpayer producing the mixture. The sale or 

use by the taxpayer must be in trade or business in which the taxpayer is engaged, and the credit 

is applicable in the year of the sale or use of the biodiesel mixture. The biodiesel tax credit is 50-

cents-per-gallon for each gallon that is not mixed with diesel. It is available to taxpayers during the 

taxable year that use biodiesel in a business or trade or is sold by the taxpayer as motor vehicle 

fuel.214 The same conditions apply for the agri-biodiesel credit except that it is increased to $1.00. 

The small agri-biodiesel producer credit is available to any eligible producer of agri-biodiesel. The 

producer of qualified agri-biodiesel is eligible for a 10-cent-per-gallon credit for any taxable year if 

the product is sold (1) to another person engaged in the manufacture of a biodiesel mixture, (2) 

for use by the purchaser as a fuel in a trade or business, or, (3) sold at retail as vehicle fuel. The

credit is limited to production not to exceed 15 million gallons per year and the producer may not 

have annual agri-biodiesel production capacity in excess of 60 million gallons.215

The tax credit is intended to stimulate production of renewable transportation fuels. Increased 

demand for agricultural commodities used as feedstock for the manufacture of biodiesel may 

increase the demand and prices. As a result, heightened demand for eligible feedstock 

commodities for biodiesel may increase the cost of food products (e.g., soybean products and 

vegetable oils). 

Revenue Loss/Outlays 

For fiscal year (FY) 2007, the Treasury estimates a $180 million revenue loss as a result of this 

tax credit. It is projected to grow to $200 million in FY 2008. Between FY 2009 and FY 2012, the 

cumulative revenue loss is projected to be $70 million.216 The “Revenue Loss” data in the 

estimated by the Treasury Department. The Revenue Loss is the difference between estimated 

Federal income tax payments in a reference case and estimated actual Federal income tax 

payments. The reference case assumes that tax credits are not available for biodiesel mixture, 

 

212 26 U.S.C. 40A (2006). 

213 A biodiesel mixture means a mixture of biodiesel and diesel fuel, without regard to the use of kerosene that is sold by the 

taxpayer as fuel to any person or used as a fuel by the taxpayer producing the mixture. A mixture contain at least 0.1 percent by 

volume of diesel fuel is considered a biodiesel mixture. Kerosene is not included in the volume for purposes of determining 

whether the mixture meets the minimum 0.1 percent diesel. Agri-biodiesel is defined as fuels derived solely from virgin oils 

including, but not limited to esters from corn, soybeans, cottonseeds, crambee, rapeseeds, safflowers, flaxseed, rice bran, mustard 

seeds and animal fat. See, 2005-35 I.R.B., Notice 2005-62 “Modification of Notice 2005-4; Biodiesel and Aviation-Grade Kerosene, 

pp. 446-447 (August 29, 2005). 

214 Taxpayers may not claim a credit for both the use and retail sale of biodiesel. 

215 EPACT2005, Section 1345 also modified Section 40A to provide for pass-through treatment of tax credits to S corporations and 

allocation of credits to patrons of sub-Chapter T cooperatives in proportion to their patronage with the organization. 

216 Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, Fiscal Year 2008, 

“Federal Collections and Receipts,” Table 19.1, p. 287. http://www.whitehouse.gov/omb/budget/fy2008/pdf/apers/receipts.pdf. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 121 

biodiesel or small agri-diesel. The actual case assumes that the credits are available to eligible 

taxpayers. 

Rationale 

The Section 40A tax credit provides financial incentives to producers and vehicular users of 

biodiesel mixtures, biodiesel, and agri-biodiesel. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

This subsidy affects the production and use of renewable transportation fuels. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

122 Energy Information Administration / Appendix A: Fact Sheets 

7. Capital Gains Treatment of Royalties on Coal 

Description 

The capital gains treatment of royalties on coal was established by the 1951 Revenue Act (Public 

Law 82-183, Section 177 (j) and Section 117 (k)). 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 the lower individual capital gains tax rate of 15 percent rather than at the higher 

regular individual top tax rate of 35 percent. The capital gains tax rate dropped from 28 percent to 

20 percent in 1997 and to 15 percent in 2003. This, and the gradual increase in coal prices 

starting in 2000, account for the higher estimated revenue loss beginning in 1997. 

In order to claim capital gains treatment, the royalty owner must own the property for a minimum 

of 1 year and meet other simple requirements. Owners who elect the capital gains tax rate cannot 

also elect percentage depletion. The capital gains treatment of coal royalties, one of the oldest 

energy subsidies, is provided for by law and has been in effect since the early 1950s. 

Revenue Loss/Outlays 

For the year 2007, the value of this tax expenditure equals an estimated $170 million. The 

“Revenue Loss” is estimated by Treasury Department (Table A5) as difference between 

estimated Federal income tax payments in a reference case and estimated actual Federal income 

tax payments. The reference case assumes that royalties on coal are taxed at the regular rate. 

The actual case assumes that the royalties are taxed at the capital gains tax rate to the extent 

taxpayers so choose. 

Rationale 

The capital gains treatment of coal royalties was adopted for three reasons: (1) to encourage 

additional production, (2) to place coal on the same tax footing as lumber, and (3) to provide a 

benefit to long-term lessors who might not benefit substantially from percentage depletion. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Coal production. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 123 

Table A5. Estimated Revenue Loss: Coal Royalties Capital Gains Treatment, 

1987 to 2012 (million nominal dollars)

Revenue Loss 

Fiscal Year 

Individuals Corporations Total 

1987 45 5 50 

1988 (a) (a) (a) 

1989 0 0 0 

1990 0 0 0 

1991 5 0 5 

1992 10 0 10 

1993 10 0 10 

1994 10 0 10 

1995 15 0 15 

1996 15 0 15 

1997 50 0 50 

1998 60 0 60 

1999 65 0 65 

2000 70 0 70 

2001 100 0 100 

2002 100 0 100 

2003 100 0 100 

2004 70 0 70 

2005 90 0 90 

2006 160 0 160 

2007 170 0 170 

2008 170 0 170 

2009 170 0 170 

2010 190 0 190 

2011 180 0 180 

2012 130 0 130 

NOTES: (a) $2.5 million or less. 

All estimates have been rounded to the nearest $5 million from 1984 through 2001. 

Thereafter, all estimates are rounded to the nearest $10 million. Provisions with estimates 

that rounded to zero in each year are not included in the table. 

Sources: 1987-1993: Office of Management and Budget, Budget of the United States 

Government, Fiscal Year 1993 (Washington, DC, 1992) and earlier editions. 1994-2004: 

Office of Management and Budget, Budget of the United States, Analytical Perspectives, 

Fiscal Year 2008 (Washington, DC, 2007), Table 19-2. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

124 Energy Information Administration / Appendix A: Fact Sheets 

8. Credit for Business Installation of Qualified Fuel Cells and 

Microturbine Power Plants 

Description 

Section 1336 of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) provides for a 

30-percent energy tax credit for the purchase of qualified fuel cells with a maximum of $500 for 

each 0.5 kilowatt of capacity. EPACT2005, Section 1336 amends Internal Revenue Code (IRC or 

Code) Section 48 (relating to energy credits) by adding qualified microturbines and fuel cells. In 

order to qualify for the credit, the plant must have an electricity-only efficiency of 30-percent or 

more and generate at least 0.5 kilowatts of power. For fuel cells the credit is scheduled to 

terminate on December 31, 2007. Qualified microturbine power plants are eligible for a 10-percent 

credit. In order to qualify, microturbine power plants need to have an electricity-only efficiency of 

26 percent or greater and a capacity of less than 2,000 kilowatts. The credit shall not exceed $200 

for each kilowatt of capacity. A qualified microturbine is “an integrated system comprised of a gas 

turbine engine, a combustor, a recuperator or regenerator, a generator or alternator, and 

associated balance of plant components which converts a fuel into electricity and thermal energy.” 

Revenue Loss/Outlays 

For the year 2007, the value of this tax expenditure is an estimated $90 million. The "Revenue 

Loss" data in Table A6 was prepared by the Treasury Department. The Revenue Loss is the 

difference between estimated Federal income tax payments in a reference case and estimated 

actual Federal income tax payments. The reference case assumes that there are no exceptions to 

the passive loss limitations. 

Table A6. Estimated Revenue Loss: Qualified Fuel Cells and 

Microturbines, 2006 to 2012 (million nominal dollars) 

Revenue Loss 

Fiscal Year Individuals Corporations Total 

2006 20 60 80 

2007 20 70 90 

2008 30 100 130 

2009 10 40 50 

2010 0 (10) (10) 

2011 0 (10) (10) 

2012 0 (10) (10) 

NOTE: All estimates have been rounded to the nearest $10 million. 

Sources: Office of Management and Budget, Analytical Perspectives, Fiscal Year 2008

(Washington, DC, 2007), Table 19-2. Also earlier editions. 

Rationale 

Provide greater incentives for distributive power. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Natural gas, hydrogen, and diesel demand. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 125 

9. Credit for the Construction of New Energy-Efficient Homes 

Description 

Section 1332 of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) provides a tax 

credit of $2,000 for the construction of a qualified new energy-efficient home if the home achieves 

50-percent energy savings over a comparable unit constructed to the International Energy 

Conservation Code (IECC). Energy savings must come from improved home heating and cooling 

efficiencies rather than from a more efficient hot water heater. The Secretary of the Treasury, in 

consultation with the Secretary of Energy, is to provide guidance in calculating the procedures and 

methods of estimating efficiency gains. 

For new homes realizing 30-percent savings over a comparable unit constructed pursuant to the 

IECC, a $1,000 tax credit is provided. Initially, the tax credit was available for the period January 

1, 2006, through December 31, 2007. However, the eligibility window was extended to December 

31, 2008, by the Tax Relief and Health Care Act of 2006 (Public Law 109-432). 

The credit is limited to properties within the United States used as residences and substantially 

completed by August 8, 2005. 

Revenue Loss/Outlays 

For the year 2007, the value of this tax expenditure is an estimated $20 million (Table A7). The 

"Revenue Loss" is calculated by the Treasury Department as the difference between estimated 

Federal income tax payments in a reference case and estimated actual Federal income tax 

payments. The reference case assumes there are no credits taken for qualified home 

construction. The actual case assumes that credits are taken for qualified home construction. 

Table A7. Estimated Revenue Loss: Energy-Efficient Homes Credit, 

2006 to 2009 (million nominal dollars) 

Fiscal Year Revenue Loss-Corporations 

2006 10

2007 20

2008 10

2009 10

NOTE: All estimates have been rounded to the nearest $10 million. 

Source: Office of Management and Budget, Budget of the United States 

Government, Analytical Perspectives, Fiscal Year 2008 (Washington, 

DC, 2007), Table 19-2. 

Rationale 

To reduce home-related fuel consumption. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

The major fuels affected are natural gas, home heating oil, and electricity. The stage affected is 

end use. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

126 Energy Information Administration / Appendix A: Fact Sheets 

10. Credit for Energy Efficiency Improvements of Existing Homes 

Description 

Section 1333 of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) provides a 10-

percent tax credit for expenditures made to improve the energy efficiency of existing homes that 

are principal residences located within the United States. This credit applies to windows, furnaces, 

boilers, fans, and building envelope components such as exterior doors and any metal roof that 

has appropriated pigmented coatings. The credit per dwelling is capped at $500 for all taxable 

years with the following application. Labor costs are considered eligible for the credit. In case of 

jointly-held properties, special proration rules are applied. The credit amount for each respective 

item is summarized below: 

Component Maximum Credit

• Windows $200

• Furnace $150

• Boiler $150

• Fan $50

The effective date of the subsidy is January 1, 2006, through December 31, 2007. The effect of 

this credit is to reduce U.S. demand for electricity and natural gas. 

Revenue Loss/Outlays 

In 2007, the estimated revenue loss is expected to total $380 million (Table A8). 

Table A8. Estimated Revenue Loss: Existing Home Efficiency 

Improvement Credits, 2005 to 2011 (million nominal dollars) 

Fiscal Year Revenue Loss-Individuals 

2005 

2006 

2007 

2008 

2009 

2010 

2011 

0 

220 

380 

150 

0 

0 

 0 

NOTE: All estimates have been rounded to the nearest $10 million. 

Sources: Office of Management and Budget, Analytical Perspectives of the U.S. 

Budget, Fiscal Year 2008 (Washington, DC, 2007), Table 19-2.; Internal 

Revenue Service, “Highlights of the Energy Policy Act of 2005 for Individuals,” 

http://www.irs.gov/newsroom/article/0,,id=153397,00.html, accessed October 16, 

2007. 

Rationale 

Improve the energy efficiency of existing homes. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Residential electricity and natural gas consumption. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 127 

11. Credit for Efficient Appliances 

Description 

Section 1334 of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) provides tax 

credits for the manufacturing of energy-efficient dishwashers, clothes washers, and refrigerators. 

The credits apply to appliances manufactured between December 31, 2005, and January 1, 2008. 

The tax credit is limited to 2 percent of the gross revenue for the three taxable years preceding 

the taxable year in which the credit occurs. For comparison purposes the appliance efficiency is 

measured against ENERGY STAR 2007 efficiency standards. ENERGY STAR is a joint program 

of the U.S. Environmental Protection Agency and the U.S. Department of Energy promoting the 

greater penetration of energy efficient appliances. The tax credits are calculated in the following 

manner: 

Dishwashers: $3 X (2007 standard/ 2005 standard); up to $100 per dishwasher. 

Clothes washers: $100 for each unit manufactured in 2006 and 2007 that meets ENERGY STAR 

standards. 

Refrigerators: 15 to 20-percent energy savings receive a $75 credit if manufactured in 2006. 

Refrigerators that achieve a 20 to 25-percent increase in energy savings receive a $125 credit if 

manufactured in 2006 or 2007. 

Individual manufactures are limited to claims no greater than $75 million for all years. Of the $75 

credit, manufacturers are limited to $20 million for 2006. 

Revenue Loss/Outlays 

A reduction in corporate tax receipts of $80 million in 2007 (Table A9). 

Table A9. Estimated Revenue Loss: Efficient Appliances 

Credit, 2006 to 2007 (million nominal dollars) 

Rationale 

To increase the energy efficiency of home appliances. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Residential electricity demand and to a lesser extent, natural gas demand. 

Fiscal Year Revenue Loss 

Corporations 

2006 120 

2007 80 

NOTE: All estimates have been rounded to the nearest $10 million. 

Sources: Office of Management and Budget, Analytical Perspectives of 

the U.S. Budget, Fiscal Year 2008 (Washington, DC, 2007), Table 19-2. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

128 Energy Information Administration / Appendix A: Fact Sheets 

12. Credit for Holding Clean Renewable Energy Bonds

Description 

Section 1303 of the Energy Policy Act of 2005 (EPACT 2005) (Public Law 109-58) introduced a 

provision which provided for up to $800 million in aggregate issuance of Clean Renewable Energy 

Bonds (CREBs) through December 31, 2007. Tax payers holding CREBs on a credit allowance 

date are entitled to a tax credit.217 Prior to passage of the Energy Incentives Act of 2005, only 

investor- owned utilities (IOUs) qualified to receive tax incentives for producing electricity from 

renewable energy resources. In essence, CREBS provide non-IOU electricity providers with 

interest free loans to finance qualified energy projects. 

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, 2008.218

CREBs are non-interesting bearing obligations. The taxpayer holding CREBs on a credit 

allowance date is entitled to a tax credit, which, in effect, lowers borrowing costs for investments 

in certain energy facilities. The amount of the credit is determined by multiplying the bond’s credit

rate by the face amount on the holder’s bond. The credit rate on the bonds is determined by the 

Secretary of the Treasury and is to be a rate that permits issuance of CREBs without discount and 

interest cost to the qualified issuer. The credit accrues quarterly and is included in gross income 

(as if it were an interest payment on the bond), and can be claimed against regular income tax 

liability and alternative minimum tax liability. 

The provision also imposes a maximum maturity limitation on the CREBs. The maximum maturity 

is the term which the Secretary estimates will result in the present value of the obligation to repay 

the principal on a CREB being equal to 50-percent of the face amount of such bond. Moreover, 

the provision requires level amortization of CREBs during the periods such bonds are outstanding. 

For purposes of the provision, “qualified issuers” include (1) governmental bodies (including Indian 

Tribal governments); (2) the Tennessee Valley Authority; (3) mutual or cooperative electric 

companies (described in section 501(c)(12) or section 1381(a)(c)(C), or a not-for-profit electric 

utility which has received a loan or guarantee under the Rural Electrification Act); and (4) clean 

energy bond lenders.”219 A qualified issuer is defined as a “clean renewable energy bond lender, a 

cooperative electric company or a governmental body. 

CREBs are an unique debt instrument, as only one other tax credit bond program exists that is 

similar, i.e., investment tax credit used to finance the reconstruction of school facilities, Qualified 

Zone Academy Bonds, which allow schools and educational organizations to borrow at 0-percent 

interest, with holders receiving Federal tax credits in lieu of interest. 

Revenue Loss/Outlays 

Estimated revenue losses associated with this tax expenditure equal $60 million in 2007 (Table A10). 

Rationale 

CREBs are intended to extend to governmental bodies (such as State and local governments, the 

District of Columbia, Indian Tribal governments) and rural electric cooperatives access to interest 

free loans for investment in certain qualifying facilities. Qualified facilities eligible for CREBs 

financing are the same as those which qualify under Internal Revenue Code (IRC or Code) 

Section 45: geothermal, wind, biomass, landfill gas, municipal solid waste, refined coal production, 

and hydroelectric power. This incentive is similar to that of IRC Section 45provided to investorowned utilities. 

 

217 Office of Management and Budget, Analytical Perspectives of the Budget of the United States Government, 2007. 

218 The U.S. House of Representatives Ways and Means Committee: 

http://waysandmeans.house.gov/media/pdf/taxdocs/hr6408taxdetailedsummary.pdf, accessed October 16, 2007. 

219 Joint Committee on Taxation, “Description and Technical Explanation of the Conference Agreement of H.R. 6, Title XIII, The 

Energy Tax Incentives Act of 2005,” (JCX-60-50), July 28, 2005. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 129 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Geothermal, wind, biomass, landfill gas, municipal solid waste, refined coal production, and 

hydroelectric power. 

Table A10. Estimated Revenue Loss: Clean Renewable Energy Bonds, 

2006 to 2012 (million nominal dollars) 

Revenue Loss 

Fiscal Year Individuals Corporations Total 

2006 10 10 20 

2007 30 30 60 

2008 40 40 80 

2009 50 50 100 

2010 50 50 100 

2011 50 50 100 

2012 50 50 10 

NOTE: All estimates have been rounded to the nearest $10 million. 

Sources: Office of Management and Budget, Analytical Perspectives, Fiscal Year 

2008 (Washington, DC, 2007), Table 19-2. and earlier issues. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

130 Energy Information Administration / Appendix A: Fact Sheets 

13. Credit for Investment in Clean Coal Technologies 

Description 

Section 1307 of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58), which applies 

to Internal Revenue Code Sections 46, 48a, and 48b, establishes a credit for advanced coal-fired 

power plants and qualified gasification projects. A 20-percent credit is applied to coal gasification 

projects using integrated gasification combined cycle (IGCC) technology and 15-percent for other 

advanced coal technologies. A tax credit ceiling of $1.3 billion was set with $800 million allocated 

towards IGCC projects, $500 million towards other advanced coal technologies and $350,000 

towards industrial gasification facilities. 

A qualified plant must have a designed heat rate of 8,530 Btu per kilowatt or have a 40-percent 

efficiency. In the case of retrofitted units, the resulting heat rate would achieve a minimum 35- 

percent efficiency rating. In order to qualify for the tax credit, the following emission performance 

must be met: 

• 99-percent sulfur dioxide (SO2) removal;

• 90-percent reduction in mercury;

• No more then 0.07 pounds per million Btu of nitrogen oxides (NOx) emissions; and

• No more then 0.015 pounds per million Btu of particulate matter emissions.

The allocation of the tax credit by fuel rank is as follows: 

• $267 million to bituminous coal (with no more than $134 million going to a single 

plant);

• $267 million to sub-bituminous coal (with no more than $134 million going to a single 

plant);

• $266 million to lignite coal (with no more than $133 million to a single project);

• The $500 million allocated towards other advanced coal technologies stipulates that 

no more than $125 million would go to a single project; and

• This tax credit is to be allocated in annual rounds over a 3-year time frame.

For non-IGCC projects, the selection will be based upon projects having the highest ratio of 

capacity to the requested allocation of the credit. For IGCC power projects, a priority pool will be 

created. The allocation will be based upon greenhouse gas reduction capability. 

Revenue Loss 

For the year 2007, the estimated revenue loss equals $30 million (Table A11). 

Rationale 

The objective of coal research and development is to provide scientific and engineering 

knowledge base to foster technological advances in the private sector. Also, coal-burning power 

plants are at the center of the controversies involving global warming. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Coal mining, combustion, liquefaction, and gasification. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 131 

Table A11. Estimated Revenue Loss: Clean Coal 

Investment Credit, 2006 to 2012 (million nominal dollars) 

Fiscal Year Revenue Loss-Corporations 

2006 

2007 

2008 

2009 

2010 

2011 

2012 

 0 

30 

50 

80 

130 

180 

250 

NOTE: All estimates have been rounded to the nearest $10 million. 

Source: Office of Management and Budget, Analytical Perspectives, 

Fiscal Year 2008 (Washington, DC, 2007), Table 19-2. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

132 Energy Information Administration / Appendix A: Fact Sheets 

14. Credit for the Production from Advanced Nuclear Power Facilities 

Description 

Section 1306 of Title XIII of the Energy Policy Act of 2005 (Public Law 109-58) provides for a 

credit for the production of electricity from advanced nuclear power facilities under the new 

Section 45J of the Internal Revenue Code. This tax expenditure allows the Secretary of Treasury, 

in consultation with the Secretary of Energy, to permit a production tax credit (PTC) of 1.8 cents 

(not adjusted for inflation) per kilowatthour to qualified advanced nuclear power facilities for an 8-

year period after the facility is placed in service after enactment of the Act and before January 1, 

2021. The legislation limits the national megawatt capacity for production tax credits to 6,000 

megawatts-electric (MWe). The credit limitation is based on the Secretary of Treasury's allocated 

capacity per facility with an annual limitation of $125 million per 1,000 MWe per taxable year with 

a total nationwide limit of 6,000 megawatts which would be allocated by the Secretary of Energy. 

The allowable credit is also reduced by reason of grants, tax exempt bond, subsidized energy 

financing, and other credits but such reduction cannot exceed 50 percent of the allowable credit. 

The Code defines “advanced nuclear power” as a unit technology that has been approved by the 

Nuclear Regulatory Commission after 1993. 

The Energy Information Administration’s Annual Energy Outlook 2008 (AEO2008) assumes that 

up to 9 gigawatts of new capacity will receive the Title 13 PTC and an additional 7 gigawatts of 

new capacity is expected to be built without the credit.220

Revenue Loss/Outlays 

N/A. 

Rationale 

To promote the introduction of advanced nuclear technologies. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Nuclear power. 

 

220 Energy Information Administration, Annual Energy Outlook, 2008, Early Release, EIA/DOE-0383 (2007)(Washington, DC, 

2008). 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 133 

15. Tax Credit and Deduction for Clean-Fuel, Alternative-Fuel, and 

Electric Vehicles 

Description 

The Clean Air Act Amendments of 1990 (CAAA90) (Public Law 101-549) and the Energy Policy 

Act of 1992 (EPACT1992) (Public Law 102-486) mandate that vehicle fleets owned by fuel 

providers and State governments, as well as certain vehicle fleets operating in air quality 

nonattainment areas, gradually acquire and use low-emission vehicles in increasing percentages 

through the year 2010. CAAA90 includes measures directed at reducing the amount of pollutants 

emitted from vehicles. Petroleum-based gasoline and diesel fuels are acceptable under CAAA90, 

as long as the vehicles satisfy the prescribed emissions standards. EPACT1992 requires the use 

of vehicles that operate primarily on fuels other than gasoline or diesel (called alternative-fuel 

vehicles or AFVs). The Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) encourages 

Federal and State fleets to purchase fuel cell vehicles through 2015. 

To encourage the use of clean-fuel vehicles and AFVs, Federal and State incentives are 

available, such as tax credits, deductions, and exemptions for purchases of AFVs, purchases of 

alternative fuels used in AFVs, and the costs of building and maintaining fueling and electric 

charging facilities. EPACT1992 provides Federal incentives for the purchase or conversion of 

individual AFVs through Federal income tax deductions for clean-fuel vehicles and income tax 

credits for electric vehicles (EVs).221

The amount of the tax deduction for qualified clean-fuel vehicles (in nominal dollars) is based on 

the gross vehicle weight (GVW) and vehicle type as follows: 

• $2,000 for automobiles, small vans and pickup trucks, and other small vehicles 

(excluding off-road vehicles); 

• $5,000 for trucks or vans with gvw 10,000 to 26,000 pounds; 

• $50,000 for trucks or vans with gvw more than 26,000 pounds; and, 

• $50,000 for buses with seating capacity of more than 20 adults.

The tax deduction for clean-fuel vehicles is available for business or personal vehicles, except for 

EVs, which are eligible for the separate Federal tax credit described below. The deduction is not 

amortized and must be taken in the year the vehicle is acquired. A tax deduction of up to 

$100,000 per location is available for qualified clean-fuel refueling properties and EV recharging 

properties, provided that the equipment is used in a trade or business. 

EPACT1992 also provides an Electric Vehicle Tax Credit for purchases of qualified EVs and 

hybrid electric vehicles (HEVs). The amount of the credit is 10 percent of the cost of the vehicle, 

up to a maximum of $4,000. To qualify for the credit, the vehicle must be powered primarily by an 

electric motor drawing current from batteries or other portable sources of electric current. All 

dedicated, plug-in only EVs qualify for the tax credit. All series and some parallel HEVs meet 

these qualifications. The tax credit for EVs is available for business or personal vehicles. 

Except for deductions for the purchase or conversion of AFVs and the Federal tax credits for EVs, 

most of the Federal incentives for advanced vehicle technologies are programmatic grants 

oriented toward large investments. The lead Federal agencies for AFV programs are the 

Department of Energy, the Department of Transportation, and the Environmental Protection 

Agency. 

The Transportation Equity Act of the 21st Century (TEA-21) (Public Law 105-178) was signed into 

law by the President on June 9, 1998. TEA-21 authorizes a wide range of programs, including 

 

221 Federal Energy Regulatory Commission, Energy Policy Act of 1992, http://ferc.gov/legal/maj-ord-reg/epa.pdf. Accessed 

December 6, 2007. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

134 Energy Information Administration / Appendix A: Fact Sheets 

Federal surface transportation programs for highways, highway safety, and mass transit, for the 6-

year period from 1998 to 2003. It includes initiatives to promote infrastructure development in 

support of AFVs. The Highway Trust Fund (HTF) is the source of funding for most of the 

programs in TEA-21. Federal motor fuel taxes are the major source of income for the HTF. The 

full authorizations for the highway and transit programs in TEA-21 total almost $218 billion. 

EPACT2005 contains number of provisions that affect clean-fuel, alternative-fuel, and electric 

vehicles.222 Summaries of the major provisions follow: 

Sections 721 – 723 establish a competitive grant program, administered by Clean Cities,223 to 

fund up to 30 geographically-dispersed advanced vehicle demonstration projects. EPACT2005 

authorizes $200 million (until expended) for this program. Grant recipients will be limited to State 

and local government agencies and metropolitan transportation authorities. Applications must 

include a registered participant in the Clean Cities initiative. Participants can be public or private

entities. AFVs, including neighborhood electric vehicles, fuel cell vehicles, and ultra-low sulfur 

diesel vehicles are eligible grant recipients. Projects are limited to $15 million with a 50-percent 

cost share. 

Section 1341 contains provisions for an 1) Alternative Motor Vehicle Credit; 2) Fuel Cell Motor 

Vehicle Credit; and 3) Hybrid Motor Vehicle Credit.

The Alternative Motor Vehicle Credit provides a tax credit to purchasers of new dedicated AFVs. 

The tax credit equals 50 percent of the incremental cost of the vehicle, plus an additional 30 

percent of the incremental cost for vehicles with near-zero emissions (weight-based cost limits 

apply). The credit is available on the purchase of light-, medium-, and heavy-duty vehicles and 

fuel-cell, hybrid, and dedicated natural gas, propane, and hydrogen vehicles. Light-duty lean-burn 

diesel vehicles are also eligible. For non-tax-paying entities, the credit can be passed back to the 

vehicle seller. The tax credit can be applied to vehicle purchases made after December 31, 2005. 

It expires December 31, 2010. This legislation replaces the Clean Fuel Tax Credit, which expired 

December 31, 2005. 

The Fuel Cell Motor Vehicle Credit provides a base tax credit of $8,000 for the purchase of lightduty fuel cell vehicles (less than 8,501 lb GVW). The $8,000 credit is valid until December 31, 

2009. After that, the value of the credit is $4,000. To qualify, the vehicles must meet certain 

minimal emission levels. 

Base tax credits are also available for medium- and heavy-duty fuel cell vehicles. The Internal 

Revenue Service will determine the credit amount based on a sliding scale by vehicle weight. The 

credit is available until December 31, 2014. For tax-exempt entities, the credit can be passed 

back to the vehicle seller. 

The Hybrid Motor Vehicle Credit provides a fuel economy and conservation credit for light-duty 

hybrid vehicles and trucks (less than 8,501 lb GVW). The fuel economy credit, $400 to $2,400, is 

based on a sliding scale of efficiency gains over model year 2002 baselines. The conservation 

credit increases the fuel economy credit by $250 to $1,000 based on a sliding scale of lifetime fuel 

savings. Weight-based cost limitations apply for heavy-duty hybrid vehicles. In general, the credit 

phases out after a manufacturer has sold 60,000 qualified vehicles. 

Revenue Loss/Outlays 

The estimated 2007 revenue loss associated with this credit equals $260 million (Table A12). 

 

222 U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, State & Federal Incentives & Laws, 

http://www.eere.energy.gov/afdc/incentives_laws_epact.html, accessed December 6, 2007. 

223 U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, “Clean 

Cities,”http://www.eere.energy.gov/cleancities/, accessed December 6, 2007. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 135 

Table A12. Estimated Revenue Loss: Alternative-Vehicle Credit, 

1998 to 2012 (million nominal dollars) 

Fiscal Year Tax Credit and Deduction for Clean-Fuel 

Burning Vehicles 

1998 95 

1999 105 

2000 115 

2001 130 

2002 100 

2003 90 

2004 70 

2005 70 

2006 110 

2007 260 

2008 150 

2009 130 

2010 (20) 

2011 (50) 

2012 (60) 

NOTE: All estimates have been rounded to the nearest $5 million from 1998 

through 2001. Thereafter, all estimates are rounded to the nearest $10 million. 

Sources: Office of Management and Budget, Budget of the United States 

Government, Analytical Perspectives, Fiscal Year 2000; Analytical Perspectives, 

Fiscal Year 2004; Analytical Perspectives, Fiscal Year 2005; Analytical 

Perspectives, Fiscal Year 2006; and Analytical Perspectives, Fiscal Year 2008, 

Table 19-2. 

Rationale 

EPACT1992 and EPACT2005 encouraged alternative fuels use (fuels other than gasoline or 

diesel) for domestic transportation in order to decrease the Nation's dependence on foreign oil, 

increase energy security through the use of domestically-produced alternative fuels, reduce the 

balance of payments deficit, and stimulate domestic employment. CAAA90 created several 

initiatives to reinforce one of the original goals of the Clean Air Act, to reduce vehicle emissions. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Energy Forms: alternative fuels (methanol, ethanol, and other alcohols; and fuels other than 

alcohol derived from biological materials, including neat biodiesel); natural gas; propane; 

hydrogen; electricity (including electricity from solar energy); and any other fuel the Secretary of 

Energy determines, by rule, is substantially not petroleum and would yield substantial energy 

security benefits and substantial environmental benefits. 

Fuel Cycle Stages: Energy transformation (refining and blending) and end use (light-duty and 

heavy-duty vehicles). 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

136 Energy Information Administration / Appendix A: Fact Sheets 

16. Deferral of Gain from Disposition of Transmission Property to 

Implement Restructuring 

Description 

Section 909 of the American Jobs Creation Act of 2004 (Public Law 108-357) amended Section 

451 of the Internal Revenue Service Code to permit taxpayers to realize a gain from qualifying 

electric transmission transactions ratably over an 8-year period. Section 909 states: “Sets forth a 

special rule for the recognition of gain from the sale of a qualifying electric transmission 

transaction. Taxpayer may elect to recognize gain from such sale ratably over an 8-year period if 

gain from the sale is reinvested in certain exempt utility property. A "’qualifying electric 

transmission transaction’" is defined as a sale or other disposition occurring before January 1, 

2007, to an independent transmission company of: (1) property used in the trade or business of 

providing electric transmission services, or (2) any stock or partnership interest in such a trade or 

business. Section 1305 of the EPACT 2005, extended of the deferral of gains to December 30, 

2007.” 

Section 909 defers tax on gain realized from the sale of qualified assets. The deferred taxes are 

recovered ratably. This results in some front loading of investment, which in time will reverse. 

The Treasury Department expects transactions that will result in a net deferral of tax revenue 

through 2008, which fully reverses in 2009. 

Revenue Loss/Outlays 

The revenue loss associated with this tax expenditure is estimated to equal $530 million in 2007 

(Table A13). 

Table A13. Estimated Revenue Loss: Deferred Gain on 

Transmission Asset Sales, 2005 to 2012 (million nominal dollars) 

Fiscal Year Revenue Loss-Corporations 

2005 

2006 

2007 

2008 

2009 

2010 

2011 

2012 

490 

620 

530 

230 

 (100) 

 (360) 

(510) 

 (540) 

NOTE: All estimates have been rounded to the nearest $10 million. 

Source: Office of Management and Budget, Budget of the United States 

Government, Analytical Perspectives, Fiscal Year 2008 (Washington, DC, 2007), 

Table 19-2. 

Rationale 

To improve the efficiency of bulk power markets and non-discriminatory open access 

transmission service. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Electricity transmission. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 137 

17. Enhanced Oil Recovery 

Description 

Taxpayers are able to claim a general business credit allowing for the expensing of enhanced oil 

recovery investment. The credit was provided by Section 11511 of the Omnibus Budget 

Reconciliation Act of 1990 (Public Law 101-508). The enhanced oil recovery credit applies to 15-

percent of the costs of one or more tertiary recovery methods. A credit equal to 15-percent of the 

taxpayer’s costs is provided for tertiary oil recovery on U.S. projects. The credit phases out when 

the inflation-adjusted price of oil exceeds $28-per-barrel (in 1991 dollars) or $39-per-barrel (in 

2007 dollars) in the preceding year. Enhanced oil recovery (EOR) is the extraction of the oil that 

can be produced from a petroleum reservoir greater than that which can be economically 

recovered by conventional primary and secondary methods. EOR methods usually involve 

injecting heated fluids, pressurized gases, or special chemicals into an oil reservoir in order to 

produce additional oil. 

The American Jobs Creation Act of 2004 (Public Law 108-357) applied the 15-percent credit to 

the construction of a natural gas treatment plant in Alaska to prepare Alaska for natural gas 

pipeline transportation. 

Revenue Loss/Outlays 

After oil prices began increasing in 2002, revenue losses from the enhanced oil recovery tax credit 

began to diminish. That is because the amount of the allowed credit declines as oil prices rise and 

vanishes completely when the inflation-adjusted price of oil exceeds $28-per-barrel (in 1991 

dollars). This happened in 2005, when nominal crude oil prices went above $40-per-barrel. By 

2006, revenue losses on this credit dropped to zero, where it is expected to remain unless oil 

prices drop significantly (Table A14). 

Rationale 

Significant amounts of oil and natural gas can be left in reservoirs after a field is abandoned. The 

use of enhanced oil and natural gas production methods allows for greater recovery of those 

resources. The purpose of the credit for enhanced oil recovery is to boost levels of domesticallyproduced oil and natural gas bypassed by conventional production. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Oil and natural gas production. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

138 Energy Information Administration / Appendix A: Fact Sheets 

Table A14. Estimated Revenue Loss: Enhanced Oil Recovery Credit, 1993 to 2011 

(million nominal dollars) 

Revenue Loss 

Fiscal Year Individuals Corporations Total 

1993 NA NA NA 

1994 5 80 85 

1995 5 80 85 

1996 5 75 80 

1997 5 90 95 

1998 10 130 140 

1999 20 205 225 

2000 30 280 310 

2001 30 280 310 

2002 30 300 330 

2003 40 360 400 

2004 30 300 330 

2005 30 270 300 

2006 NA NA NA 

2007 NA NA NA 

2008 NA NA NA 

2009 NA NA NA 

2010 NA NA NA 

2011 NA NA NA 

NOTES: NA = Not available.

All estimates have been rounded to the nearest $5 million from 1993 through 2001. 

Thereafter, all estimates are rounded to the nearest $10 million. 

Sources: Office of Management and Budget, Budget of the United States Government, 

Analytical Perspectives, Fiscal Year 2000; Analytical Perspectives, Fiscal Year 2004; 

Analytical Perspectives, Fiscal Year 2005; Analytical Perspectives, Fiscal Year 2006; and 

Analytical Perspectives Fiscal Year 2008, Table 19-2. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 139 

18. Exception from Passive Loss Limitation for Working Interests in 

Oil and Natural Gas Properties 

Description 

The Tax Reform Act of 1986 (Public Law 99-514) allowed owners of working interests in oil and 

natural gas properties to be exempt from the “passive income” limitations, which limit the ability of 

individuals to offset their losses from passive activities against active income. 

Passive income is income an investor derives from a rental property, limited partnership, or other 

enterprise in which he or she is typically not actively involved. A passive loss is a loss incurred in

these investments. For income tax purposes, passive losses can normally be used to offset 

income generated only from passive activities, not active income. Active income comes from such 

things as wages and salaries. 

Passive losses remaining after being netted against passive income normally can only be carried 

over to reduce passive income realized in future tax years. The exception allows passive losses 

from these activities to offset the investor’s active income. The passive loss limitation provision 

and the oil and natural gas exception to it apply principally to partnerships and individuals rather 

than to corporations. 

The major impact of the exception from the passive loss limitation is on business organizations 

that develop oil and natural gas properties. A shift toward the partnership form (which has 

unlimited liability) is encouraged, because the exception applies mainly to that form. Any shift is 

likely to be small because of the increased risk associated with unlimited liability. Nevertheless, 

some increase in exploration and development of oil and natural gas properties is likely as the 

subsidy attracts new capital. 

Revenue Loss/Outlays 

The "Revenue Loss" data is estimated by Treasury Department (Table A15). It the difference 

between estimated Federal income tax payments in a reference case and estimated actual 

Federal income tax payments. The reference case assumes that there are no exceptions to the 

passive loss limitations. The actual case assumes that passive loss limitation exception applies to 

unincorporated taxpayers. 

Rationale 

Working interests in oil and natural gas properties were exempted from the loss limitations in the 

Tax Reform Act of 1986. Factors that contributed to the adoption of the exemption included 

concern about the availability of investment funds for oil and natural gas development, given the 

collapse in oil prices that occurred during the same year the Act was passed. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Crude oil and natural gas production. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

140 Energy Information Administration / Appendix A: Fact Sheets 

Table A15. Estimated Revenue Loss: Oil and Natural Gas Passive 

Loss Limitation Exception, 1988 to 2012 (million nominal dollars) 

Fiscal Year Revenue Loss-Individuals 

1988 

1989 

1990 

1991 

1992 

1993 

1994 

1995 

1996 

1997 

1998 

1999 

2000 

2001 

2002 

2003 

2004 

2005 

2006 

2007 

2008 

2009 

2010 

2011 

2012 

55 

135 

180 

80 

80 

50 

90 

55 

60 

45 

30 

35 

20 

20 

10 

20 

20 

40 

30 

30 

30 

30 

30 

30 

30 

NOTE: All estimates have been rounded to the nearest $5 million from 1988 

through 2001. Thereafter, all estimates are rounded to the nearest $10 

million.

Sources: 1987-1993: Office of Management and Budget, Budget of the United 

States Government, Fiscal Year 1993 (Washington, DC, 1992). Also earlier 

editions. 1994-2012: Office of Management and Budget, Analytical 

Perspectives, Fiscal Year 2008 (Washington, DC, 2007), Table 19-2. Also 

earlier editions.
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 141 

19. Excess of Percentage over Cost Depletion: Oil, Natural Gas, and 

Other Fuels 

Description 

Depletion on a discovery basis became an accepted practice between 1918 and 1926. 

Percentage depletion for oil and natural gas properties became law in 1926 with the 1926 

Revenue Act. It was extended to most other minerals, including mineral fuels, in 1932. Whoever is 

eligible for percentage depletion must use it rather than cost depletion. Independent oil and 

natural gas producers and royalty earners, and all producers and royalty owners of certain other 

natural resources, including mineral fuels, may take percentage depletion deductions rather than 

cost depletion deductions to recover their capital investments. Under cost depletion, the annual 

deduction is equal to the unrecovered cost of acquisition and development of the resource 

multiplied by the proportion of the resource removed during that year. Under percentage 

depletion, taxpayers deduct a percentage of gross income from resource production at rates of 10 

percent for coal; 15 percent for oil, natural gas, oil shale, and geothermal deposits; and 

22 percent for uranium. However, two special provisions apply to oil and natural gas. First, 

percentage depletion for independent producers and royalty earners is limited to 1,000-barrels–

per-day. Second, the 15-percent rate is increased by 1 percentage point for each dollar that the 

average wellhead price of domestically produced crude oil is less than $20 a barrel. The 

maximum increase allowed is 10 percentage points. This special provision applies only to oil and 

natural gas wells with marginal production, generally defined to include production from stripper 

wells from which substantially all of the production is heavy oil. Marginal production eligible for the 

higher rate has a prior claim on the 1,000-barrel-per-day limitation. 

The percentage depletion deductions based on gross income have generally been subject to net 

income limitations. Since percentage depletion is based on gross income, the resultant 

allowances can exceed the actual acquisition and development costs for the property from which 

the resource is extracted. Oil and natural gas property has often received relatively favorable 

treatment. A limit on the annual deduction of 50-percent of net income from a property had 

applied both to oil and natural gas and to other mineral fuels, until the Omnibus Budget 

Reconciliation Act of 1990 raised the limit to 100-percent for oil and natural gas beginning in 1991. 

That Act also increased the percentage depletion rate for marginal wells-stripper wells and those 

where substantially all of the production is heavy oil to as much as 25 percent, depending on the 

price of crude oil (this has not applied during recent years with high oil prices). Further, the 100-

percent-of-net income limitation on the deduction has at times been suspended completely, with 

extensions of this suspension most recently to the end of 2005 as a result of Section 314 of the 

Working Families Tax Relief Act of 2004 (Public Law 108-311), and again, until the end of 2007, 

by the Tax Relief and Health Care Act of 2006 (Public Law 109-432). 

Excess preferences are preferences that are added back to the regular tax base in calculating 

income tax liability under the alternative minimum tax (AMT) system. The oil and natural gas 

provisions have been changed several times since they were first introduced in 1926. The Energy 

Policy Act of 2005 (EPACT2005) broadened this tax expenditure: while this provision is not 

available to vertically integrated producers, that is, those with refinery operations larger than a 

certain minimum size, EPACT2005 loosened the definition of a small refiner to include operations 

refining less than 75,000-barrels-per-day, up from 50,000-barrels-per-day. It also changed the 

calculation to a 75,000-barrel daily average over the course of the year rather than applying the 

limit to each day. 

Percentage depletion has the effect of substantially increasing the development of existing 

property, because the total depletion claimed can exceed the original investment. The increase in 

output benefits producers (operators and royalty holders) through higher after-tax profits. The 

benefits to producers were considered so substantial that beginning in 1969 percentage depletion 

rates were reduced for oil and natural gas, and eventually major oil and natural gas companies 

were excluded from the percentage depletion provisions in 1975. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

142 Energy Information Administration / Appendix A: Fact Sheets 

Revenue Loss/Outlays 

The “Revenue Loss” data is estimated by the Treasury Department (Table A16). The difference 

between estimated Federal income tax payments in a reference case and actual Federal income 

tax payments is presented. The reference case assumes that cost depletion is used. The actual 

case assumes that percentage depletion is used. In 2007 the estimated loss was $790 million. 

Between 1968 and 2007, the estimated loss was equal to $102 billion in 2007 dollars.224

Table A16. Estimated Revenue Loss: Excess of Percentage of 

Cost over Depletion, 1987 to 2012 (million nominal dollars) 

Revenue Loss 

Fiscal Year Individuals Corporations Total 

1987 595 345 940

1988 385 205 590

1989 320 205 525

1990 550 245 795

1991 470 245 715

1992 490 255 745

1993 265 830 1,095

1994 265 845 1,110

1995 265 800 1,165

1996 275 830 1,105

1997 285 860 1,145

1998 50 200 250

1999 45 220 265

2000 50 290 340

2001 30 220 250

2002 510 100 610

2003 110 530 640

2004 110 1210 1320

2005 60 530 590

2006 80 680 760

2007 80 710 790

2008 80 710 790

2009 80 710 790

2010 80 700 780

2011 80 680 760

2012 70 670 740

NOTE: All estimates have been rounded to the nearest $5 million from 1987 

through 2001. Thereafter, all estimates are rounded to the nearest $10 

million. 

Sources: 1987-1993: Office of Management and Budget, Budget of the United 

States Government, Fiscal Year 1993 (Washington, DC, 1992). Also earlier 

editions. 1994-2012: Office of Management and Budget, Analytical 

Perspectives, Fiscal Year 2008 (Washington, DC, 2007), Table 19-2. Also 

earlier editions.

 

224 Based upon estimates for 1968 to 2000 appearing in General Accounting Office publication, Petroleum and Ethanol Fuels: Tax 

Incentives and Related GAO Work, GAO/RCED-00-301R (Washington, DC, September 2000) and EIA estimates based upon data 

appearing in the Office of Management and Budget’s Analytical Perspectives of the U.S. Budget, Fiscal Years 2008, 2006, 2004, 

and 2002. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 143 

Rationale 

To increase domestic oil and gas production and to reduce the nation’s reliance on petroleum 

imports. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Crude oil, natural gas, and coal production, as well as minor energy forms, including uranium, oil 

shale, and geothermal. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

144 Energy Information Administration / Appendix A: Fact Sheets 

20. Renewable Transportation Fuels and Volumetric Ethanol Excise 

Tax Credit (VEETC) 

Description 

At nearly $3 billion, the Volumetric Ethanol Excise Tax Credit (VEETC) is estimated to be the 

largest energy-related tax credit in 2007. Its predecessor, the alcohol fuel excise tax exemption, 

was estimated to be the largest tax-related benefit in the 1999-2000 EIA subsidy reports. VEETC 

is directed at the production of transportation-related fuels. The alcohol fuels excise tax exemption 

first appeared in Section 221 of the Energy Tax Act of 1978 (Public Law 95-618) in order to 

address gasoline shortages. This exemption was replaced in 2004 with VEETC by Section 301 of 

the American Jobs Creation Act (AJCA) (Public Law 108-357). The AJCA extended the benefit 

through 2010. VEETC provides ethanol blenders/retailers with 51-cents-per-pure-gallon of ethanol 

or $.0051 per percentage point of ethanol blended in motor gasoline. The value of VEETC is 

estimated at $3 billion in 2007. By 2010, the value of this credit is expected to approach $5 billion.

Although the value of this credit may not have changed due to the 2004 legislation, funds are no 

longer be diverted from the Highway Trust Fund but rather come from the Treasury’s General 

Fund. A major effect of this credit has been a sizable boost in U.S. ethanol production and a 

significant redirection of corn production away from traditional uses. 

Revenue Loss/Outlays 

The lost revenue to the U.S. Treasury from the VEETC for Fiscal Year (FY) 2006 through FY 2012 

is shown below. These values include the amount of the alcohol fuel credit and the foregone 

gasoline excise tax receipts (Table A17). 

Table A17. Estimated Revenue Loss and Outlay Equivalent: VEETC, 2006 to 2012 

(million nominal dollars) 

Fiscal Year Revenue Loss 

2006 2,570

2007 2,990 

2008 3,460 

2009 4,280 

2010 4,990 

2011 1,440 

2012 0 

NOTE: All estimates have been rounded to the nearest $10 million.

The value (in millions) for the revenue loss from the alcohol (ethanol) fuel credits for each year 

is: FY06 = $50; FY07=$50; FY08=$60; FY09=$70; FY10=$80; FY11=$30. 

Source: Analytical Perspectives, Budget of the United States Government, Fiscal Year 2008, 

Table 19-1, “Estimates of Total Income Tax Expenditures,” Office of Management and Budget; 

http://www.whitehouse.gov/omb/budget/fy2008/pdf/spec.pdf; accessed August 13, 2007.

Rationale 

To reduce U.S. dependence on imported oil used as a transportation fuel. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Imported petroleum and ethanol-blended gasoline. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 145 

21. Exclusion of Utility-Sponsored Conservation 

Description 

Section 111 of the Energy Policy Act of 1992 (EPACT1992) (Public Law 102-486) amended the 

Section 136 of the Internal Revenue Code (IRC or Code) to allow taxpayers to exclude from their 

gross income utility-paid rebates and subsidies for participating in conservation programs for 

purposes of calculating tax liability. Utilities engaged in demand side management activities often 

pay consumers to purchase more efficient heating or cooling equipment in order to reduce the 

consumption of natural gas and electricity. However, the relatively small size of the subsidy, as 

compared with the billions of dollars spent on household appliances each year, results in only a 

minor impact on U.S. demand for electricity and natural gas. 

Revenue Loss/Outlays 

The value of this tax expenditure is an estimated $110 million for the year 2007. 

Table A18. Estimated Revenue Loss: Utility-Sponsored Conservation, 

1987 to 2012 (million nominal dollars) 

Fiscal Year Revenue Loss-Individuals 

1987 NA

1988 NA

1989 NA

1990 NA

1991 NA

1992 NA

1993 50

1994 100

1995 130

1996 100

1997 70

1998 80

1999 90

2000 90

2001 70

2002 80

2003 80

2004 100

2005 80

2006 110

2007 110

2008 110

2009 110

2010 110

2011 110

2012 110

NOTE: All estimates have been rounded to the nearest $5 million from 1987 through 2001. 

Thereafter, all estimates are rounded to the nearest $10 million. 

Sources: 1987-1993: Office of Management and Budget, Budget of the United States 

Government, Fiscal Year 1993 (Washington, DC, 1992). 1994-2012: Office of Management 

and Budget, Analytical Perspectives, Fiscal Year 2008 (Washington, DC, 2007). 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

146 Energy Information Administration / Appendix A: Fact Sheets 

Rationale 

The rationale for the tax subsidy is to encourage consumers to take advantage of utility funds 

available for the upgrade of heating and cooling equipment or the operation of equipment without 

penalty. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Natural gas transformation, electricity end use. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 147 

22. Exclusion of Interest Income on Energy Facility and Local Bonds 

Description 

The Revenue Expenditure and Control Act of 1968 (Public Law 90-364) exempts interest on 

private activity bonds used to finance certain energy facilities from gross income for Federal tax 

purposes. There are three types of privately-used facilities for which such bonds may be issued: 

facilities for the local furnishings of natural gas and electricity; district heating and cooling facilities; 

and certain environmental facilities at hydroelectric dam sites.225 Electric and natural gas services 

provided from facilities with bonds issued by eligible third parties are limited to providing service in 

no more than two adjacent counties (or one city and an adjacent county). The issuance of private 

activity bonds is subject to annual limits established for each State by the Internal Revenue 

Service (IRS), and State-specific allocation processes. 

The tax exemption encourages investment in debt-financed energy projects. The subsidy lowers 

utility financing costs and results in product prices that are lower and product consumption that is 

greater than would be otherwise without the subsidy. 

Revenue Loss/Outlays 

The value for this expenditure is an estimated $40 million in 2007 (Table A19). 

Rationale 

The tax exemption is intended to encourage the development of specific types of energy facilities. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Natural gas transformation, electricity generation.

 

225 Several other types of private activity bonds are also subject to these caps. The tax-free status of bonds for certain small-scale 

hydroelectric generating facilities, geothermal facilities, and alcohol production facilities was terminated in the 1980s. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

148 Energy Information Administration / Appendix A: Fact Sheets 

Table A19. Estimated Revenue Loss: Interest Exclusion on Energy Facility Bonds, 

1987 to 2012 (million nominal dollars) 

Revenue Loss 

Fiscal Year Individuals Corporations Total 

1987 0 305 305

1988 0 290 290

1989 0 315 315

1990 0 255 255

1991 0 125 125

1992 0 125 125

1993 100 65 165

1994 105 70 175

1995 105 70 175

1996 105 70 175

1997 105 70 175

1998 80 30 110

1999 85 30 115

2000 70 20 90

2001 70 20 90

2002 80 30 110

2003 70 20 90

2004 80 20 100

2005 60 20 30

2006 30 10 40

2007 30 10 40

2008 40 10 50

2009 40 10 50

2010 40 10 50

2011 40 10 50

2012 40 10 50

NOTE: All estimates have been rounded to the nearest $5 million from 1987 through 2001. 

Thereafter, all estimates are rounded to the nearest $10 million. 

Sources: 1987-1993: Office of Management and Budget, Budget of the United States Government, 

Fiscal Year 1993 (Washington, DC, 1992). 1994-2012: Office of Management and Budget, Analytical 

Perspectives, Fiscal Year 2008 (Washington, DC, 2007). Also subsequent and earlier editions.
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 149 

23. Exclusion of Special Benefits for Disabled Coal Miners 

Description 

Department of Labor, Health and Human Services, and Education and Related Agencies 

Appropriation Act of 1986, (Public Law 99-178) allows for non-taxable disability payments out of 

the Black Lung Trust Fund. The Departments of Labor, Health and Human Services, and 

Education, and Related Agencies Appropriation Act of 1993 (Public Law 102-394, Title II) provides 

that: 

“For carrying out title IV of the Federal Mine Safety and Health Act of 1977, and thereafter 

the payment of travel expenses on an actual cost or commuted basis to an individual, for 

travel incident to medical examinations, and when travel of more than 75 miles is 

required, to parties, their representatives, and all reasonably necessary witnesses for 

travel within the United States, Puerto Rico and the Virgin Islands.” 

Title II, also made appropriations to the Department of Health and Human Services for the Social 

Security payments to fund special benefits for disabled coal miners. 

Revenue Loss/Outlays 

The expected revenue loss associated with this tax expenditure is estimated at $40 million for 

2007 (Table A20). 

Table A20. Estimated Revenue Loss: Exclusion of Disabled Coal Miner Benefits, 

2001 to 2011 (million nominal dollars) 

Fiscal Year Revenue Loss-Individuals 

2001 

2002 

2003 

2004 

2005 

2006 

2007 

2008 

2009 

2010 

2011 

70 

70 

60 

60 

50 

50 

40 

40 

40 

40 

 0 

NOTE: All estimates have been rounded to the nearest $10 million. 

Sources: 2006-2012: Office of Management and Budget, Budget of the United States 

Government, Fiscal Year 2008 (Washington, DC, 2007). Also earlier editions. 

Rationale 

To reduce medical costs of coal miners and to allow them to seek treatment at appropriate 

medical care facilities. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Coal. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

150 Energy Information Administration / Appendix A: Fact Sheets 

24. Expensing of Capital Costs with Respect to Complying with EPA 

Sulfur Regulations 

Description 

Sections 338 and 339 of the American Jobs Creation Act of 2004 (AJCA) (Public Law 108-357) 

created a new 5-cent-per-gallon tax credit for small petroleum refiners who must incur capital 

costs complying with the Environmental Protection Agency’s (EPA) rules limiting the sulfur 

content of diesel fuel.226 Eligible refiners may claim the credit until they have recovered 25-percent 

of such costs.227 

For these purposes a small refiner is one that employs not more than 1,500 persons directly in 

refining and has less than 205,000-barrels-per-day (average) of total refining capacity.228 The 

credit is reduced for refiners with a capacity between 155,000-barrels-per-day and 205,000-

barrels-per-day.229 The conferee’s report states that when capacity “differs substantially” from 

average daily output of refined product, capacity should be measured by reference to daily 

average output.230

Cooperatives may also choose to pass some or all of this credit to their patrons. As with the small 

ethanol producer credit, any pass-through is to be apportioned among patrons on the basis of 

patronage, and any credit not passed through to patrons is treated as a general business credit by 

the cooperative.231

Section 1324 of the Energy Policy Act of 2005 (Public Law 109-58) allows small refiners to deduct 

75-percent of qualified capital costs related to complying with EPA sulfur regulations. This 

provision applies to Section 338 of the AJCA. 

Revenue Loss/Outlays 

The estimated value of this credit was $10 million in 2007 (Table A21). 

Table A21. Estimated Revenue Loss: Expensing EPA Sulfur Compliance Capital Costs, 2005 

to 2012 (million nominal dollars) 

Fiscal Year Revenue Loss-Corporations 

2005 

2006 

2007 

2008 

2009 

2010 

2011 

2012 

10 

10 

10 

10 

10 

10 

10 

10 

NOTE: All estimates have been rounded to the nearest $10 million. 

Sources: 2006-2012: Office of Management and Budget, Budget of the United States Government, 

Fiscal Year 2008 (Washington, DC, 2007), Table 19-2, and earlier years; Income Tax Treatment of 

Cooperatives: Patronage Refunds and other Income Issues, Cooperative Information Report 44, Part 2, 

2005 Edition, Donald A. Frederick. http://www.rurdev.usda.gov/RBS/pub/cir442.pdf, p. 120, accessed 

August 27, 2007. 

 

226 American Job Creation Act of 2004, Section 339, Pub. L. No. 108-357, 118 Stat. 1481 (codified at 26 U.S.C. Section 45H). See 

also, H.R. Conf. Rept. No. 755, 108th Cong., 2d Sess. At 538-539. 

227 I.R.C. Section 45H (b)(1). 

228 I.R.C. Section 45H (c)(1). ). 

229 I.R.C. Section 45H (b)(2). 

230 H.R. Conf. Rept. No. 755, 108th Cong., 2d Sess. at 313. 

231 I.R.C. Section 45H (g). 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 151 

Rationale 

The purpose of this provision is to aid small refiners by way of financial assistance for capital 

costs incurred due to EPA rules limiting the sulfur content of diesel. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Diesel fuels. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

152 Energy Information Administration / Appendix A: Fact Sheets 

25. Expensing of Exploration and Development Costs: Oil, Natural 

Gas, and Other Fuels 

Description 

Tax law allows energy producers, principally oil and natural gas producers, to write off, i.e., 

expense, certain exploration and development (E&D) expenditures rather than capitalizing them 

and depreciating them over time. The most important of these expenditures consist of intangible 

drilling costs (IDCs) associated with oil and natural gas investments. Integrated oil companies can 

expense 70 percent of their IDCs for successful domestic wells and 100 percent for unsuccessful 

domestic wells. The remaining 30 percent must be amortized over 5 years. Nonintegrated 

(independent) oil producers can expense 100 percent of their IDCs for all domestic wells. The 70-

percent provision also applies to surface stripping and other selected expenditures for fuel 

minerals other than oil and natural gas (principally coal). The remainder must be amortized over 5 

years. This tax expenditure, estimated at $860 million, was the fourth largest tax expenditure in 

2007. 

The option to expense IDCs (and dry hole costs) of oil and natural gas wells was originally based 

on regulations issued in 1916. A court invalidated the regulations in 1945, but Congress 

subsequently gave its approval to the treatment and it became law in 1954. The option to expense 

mine development expenditures and the option to expense mine exploration expenditures were 

formalized into law in 1951 and 1966, respectively.

Integrated oil companies were constrained to expensing only 85 percent of their IDCs by a 1982 

tax law. The percentage was subsequently reduced to 80 percent by the Tax Reform Act of 1984 

and to its present 70 percent by the Tax Reform Act of 1986.

Revenue Loss/Outlays 

The “Revenue Loss” data are estimated by the Treasury Department (Table A22 ). They are the 

difference between estimated Federal income tax payments in a reference case and estimated 

actual Federal income tax payments. The reference case assumes that relevant IDCs and certain 

other E&D expenditures are cost-depleted. The actual case assumes that they are expensed. 

The data in the table are mostly negative from fiscal year 1987 through 1999. The negative values 

imply a payment to the Federal government of funds that it had loaned (tax deferrals), mostly to oil 

companies, in earlier periods. In a normal growth situation, the values would be positive. However, 

as a result of the sharp drop in oil E&D expenditures resulting from generally lower oil prices 

during that period, repayments of old “loans” outweighed the receipt of new ones. That trend 

reversed itself starting in 2000, as oil prices started increasing in the late 1990s through the 

present. Since 1967, the total revenue losses associated with this expenditure are estimated to be 

roughly $53 billion.232

 

232 Based upon estimates for 1968-2000 appearing in the General Accounting Office, Petroleum and Ethanol Fuels: Tax Incentives 

and Related GAO Work, GAO/RCED-00-301R (Washington, DC, September 2000) and EIA estimates based upon data appearing 

in the Office of Management and Budget’s Analytical Perspectives of the U.S. Budget, Fiscal Year 2008, 2006, 2004, and 2002. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 153 

Table A22. Estimated Revenue Loss: Expensing of Exploration and 

Development Costs, 1987 to 2012 (million nominal dollars) 

Revenue Loss 

Fiscal Year Individuals Corporations Total 

1987 425 (1,065) (640) 

1988 455 (805) (350) 

1989 560 (590) (30) 

1990 (70) (385) (455) 

1991 (95) (185) (280) 

1992 (40) (15) (55) 

1993 (15) 90 80 

1994 0 (70) (70) 

1995 (70) (215) (285) 

1996 (60) (180) (240) 

1997 (35) (115) (150) 

1998 (20) (90) (110) 

1999 (10) (70) (80) 

2000 0 20 20 

2001 10 40 50 

2002 20 130 150 

2003 30 180 210 

2004 30 230 260 

2005 50 340 390 

2006 90 590 680 

2007 110 750 860 

2008 110 730 840 

2009 90 620 710 

2010 80 520 600 

2011 60 390 450 

2012 40 270 310 

NOTE: All estimates have been rounded to the nearest $5 million from 1987 through 2001. 

Thereafter, all estimates are rounded to the nearest $10 million. 

Sources: 1987-1996: Office of Management and Budget, Budget of the United States 

Government, Fiscal Year 1996 (Washington, DC, 1996). Also earlier editions. 1997-2012: 

Office of Management and Budget, Analytical Perspectives, Fiscal Year 2008 (Washington, 

DC, 2007), Table 19-2. Also earlier editions.

Rationale 

Intangible drilling costs were asserted by producers to be conventional operating expenses that 

therefore should be expensed. The provision is intended to encourage additional mineral 

exploration and development. It was explicitly codified to reduce uncertainty concerning its status 

in order to encourage further exploration and development. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Crude oil, natural gas, and coal production. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

154 Energy Information Administration / Appendix A: Fact Sheets 

26. Natural Gas Distribution Pipelines Treated as 15-Year Property 

Description 

Section 1325 of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) provides that 

natural gas distribution pipelines be given a 15-year capital cost recovery period. Prior to this, 

natural gas distribution pipelines were assigned a 20-year recovery period. This 15-year cost 

recovery period applies to the original user of property which is placed in service before January 1, 

2011. It does not apply to property contracted for before April 12, 2005. 

Revenue Loss/Outlays 

The “Revenue Loss” data are estimated by the Treasury Department (Table A23). The difference 

between estimated Federal income tax payments in a reference case and actual Federal income 

tax payments is presented. The reference case assumes that natural gas distribution pipelines 

have a 20-year capital cost recovery period. The actual case assumes that natural gas distribution 

pipelines have a 15-year capital cost recovery period. 

Table A23. Estimated Revenue Loss: 15-Year Life for Natural Gas 

Pipelines, 2006 to 2012 (million nominal dollars) 

Fiscal Year Revenue Loss-Corporations 

2006 

2007 

2008 

2009 

2010 

2011 

2012 

20 

50 

90 

120 

150 

150 

120 

NOTE: All estimates have been rounded to the nearest $10 million. 

Source: Office of Management and Budget, Analytical Perspectives, Fiscal Year 2008

Washington, DC, 2007), Table 19-2 

Rationale 

To increase natural gas distribution pipeline capacity. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Natural gas distribution pipelines. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 155 

27. New Technology Credit 

Description 

The New Technology Credit , also known as the Renewable Electricity Production Tax Credit 

(REPC),233,234 as well as the Production Tax Credit (PTC), was first introduced as part of the 

Energy Policy Act of 1992 (EPACT1992) (Public Law 102-486). The corresponding Internal 

Revenue Service Code Section 45 credit was defined as a 1.5-cents-per-kilowatthour (kWh) 

payment (adjusted annually for inflation), payable for 10 years, to private investors as well as to 

investor-owned electric utilities for electricity from wind power and closed-loop (dedicated crops) 

biomass facilities placed in service after December 31, 1993, and before July 1, 1999. 

The Tax Relief Extension Act of 1999 (Public Law 106-170) extended and modified the PTC. It 

expanded the tax credit to include poultry litter facilities and poultry waste facilities, landfill gas, 

and certain other biomass. These and wind power and closed-loop biomass facilities qualified for 

the PTC if placed in service before January 1, 2001. The poultry waste and poultry litter facilities 

must have been in service after December 31, 1999, and before January 1, 2001. The PTC 

expired at the end of 2001. The credit for electricity produced from poultry litter is available to the 

lessor/operator of a qualified facility that is owned by a government entity. 

The PTC was extended in March 2002 through December 31, 2003, by the Job Creation and 

Worker Assistance Act of 2002 (Public Law 107-147). The PTC expired at the end of 2003 and 

lapsed until October 2004, when it was renewed as part of the Working Families Tax Relief Act of 

2004 (Public Law 108-311), which extended it through December 31, 2005. 

The American Jobs Creation Act of 2004 (AJCA) (Public Law 108-357) expanded the PTC to 

include open-loop biomass, geothermal energy, solar energy, small irrigation power, and 

municipal solid waste (landfill gas and trash combustion facilities). 

The Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) expanded the credit to include 

certain hydropower facilities and Indian (Native American) coal and extended it through December 

31, 2007. EPACT2005 also made solar facilities placed into service after December 31, 2005, 

ineligible for the PTC. Also, geothermal facilities that claim the 2005 Federal Business Energy Tax 

Credit (10 percent on equipment installed from January 1, 2006, through December 31, 2008) 

may not also claim the PTC. (The Business Energy Tax Credit is commonly known as the 

Investment Tax Credit.) 

In December 2006, the credit was extended through the end of 2008 by the Tax Relief and Health 

Care Act of 2006 (Public Law 109-432). 

The following resources are now eligible for the REPC: 

• wind energy, 

• closed-loop biomass, 

• open-loop biomass (including agricultural livestock waste nutrients),

• geothermal energy, 

• small irrigation power (150 kilowatts - 5 megawatts),

• municipal solid waste (trash combustion),

• landfill gas, 

 

233 New Technology Credit is the term used by the U.S. Department of Treasury to describe the production tax credit and an 

investment tax credit in Office of Management and Budget, Analytical Perspectives, Budget of the United States Government, 

Fiscal Year 2008, http://www.whitehouse.gov/omb/budget/fy2008/pdf/spec.pdf, accessed December 11, 2007. Production tax 

credit (PTC) is the more commonly-used term. 

234 For a summary of the history of the renewable electricity production tax credit, see, Database of State Incentives for Renewable 

Energy, http://www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=US13F&State=Federal¤tpageid=1, accessed 

December 11, 2007. Details regarding the PTC as promulgated in EPACT2005 are contained in “Renewable Electricity Production 

Tax Credit,” Northeast Regional Biomass Program, http://www.nrbp.org/pdfs/energy_policy_act_2005.pdf, accessed December 11, 

2007.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

156 Energy Information Administration / Appendix A: Fact Sheets 

• refined coal,

• Indian coal, 

• solar energy, and 

• hydropower. 

Revenue Loss 

The lost revenue to the Treasury related to this tax expenditure is estimated at $690 million in 

2007 (Table A24). By 2008, the New Technology Credit is expected to be the second largest tax 

expenditure. 

Table A24. Estimated Revenue Loss: New Technology Credit, 2006 to 2012 

(million nominal dollars) 

Revenue Loss 

Fiscal Year 

Individuals Corporations Total 

2006 40 470 510 

2007 50 640 690 

2008 60 900 960 

2009 60 1,060 1,120 

2010 60 1,090 1,150 

2011 60 1,090 1,150 

2012 60 1,090 1,150 

NOTE: All estimates have been rounded to the nearest $10 million. 

Source: Office of Management and Budget, Budget of the United States. Government, Fiscal 

Year 2008, Office of Management and Budget, Analytical Perspectives, Fiscal Year 2008, 

Table 19-2, “Estimates of Total Income Tax Expenditures, 

”http://www.whitehouse.gov/omb/budget/fy2008/pdf/spec.pdf. Accessed August 9, 2007. 

Rationale 

This credit aims to improve the economics to developers of affected renewable generating 

technologies, such that they are cost-competitive in the electricity generating market. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Renewable generating technologies. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 157 

28. Nuclear Production Tax Credit 

Description 

Section 1306 of Title XIII of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) 

provides for a credit for the production of electricity from advanced nuclear power facilities by 

amending the Internal Revenue Code with the addition of Section 45J. This tax expenditure allows 

the Secretary of Treasury, in consultation with the Secretary of Energy, to permit a production tax 

credit (PTC) of 1.8 cents (not adjusted for inflation) per kilowatthour to qualified advanced nuclear 

power facilities for an 8-year period after the facility is placed in service after enactment of the Act 

and before January 1, 2021. The legislation limits the national megawatt capacity for PTCs to 

6,000 megawatts-electric (MWe). The credit limitation is based on the Secretary of Treasury's 

allocated capacity per facility with an annual limitation of $125 million per 1,000 MWe per taxable 

year with a total nationwide limit of 6,000 megawatts which would be allocated by the Secretary of 

Energy. The allowable credit is also reduced by reason of grants, tax exempt bond, subsidized 

energy financing, and other credits but such reduction cannot exceed 50 percent of the allowable 

credit. 

The Energy Information Administration’s Annual Energy Outlook 2008 (AEO2008) “assumes that 

up to 9 gigawatts of new capacity will receive the Title XIII PTC. AEO2008 also assumes that 

participating utilities will be able to take all the tax credits in each of the first 8 years of their

qualifying units’ operation.” 

Revenue Loss/Outlay 

The Treasury Department did not estimate the value of this tax expenditure as no nuclear power 

plants are expected to go into operation within the Treasury’s forecasting horizon which goes out 

to the year 2012. 

Rationale 

Section 1306 of EPACT2005 is intended to remove investment barriers to the funding of the 

construction of new nuclear power plants. The intent is to reduce the chance that investors will be 

exposed to construction-delay-related risks 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Nuclear power. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

158 Energy Information Administration / Appendix A: Fact Sheets 

29. Modification to Special Rules for Nuclear Decommissioning Costs 

Description 

Section 1310 of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) modifies the 

rules governing the funding of qualified Internal Revenue Code (IRC or Code) Section 468A 

decommissioning trust funds, which prior to the modification required utilities to make payments 

into a qualified fund over the life of the fund subject to a level funding (payment) requirement. The 

change in law permits utilities to transfer funds from non-qualified trust funds, i.e., Grantor Trusts, 

notwithstanding the level of funding requirement. Furthermore, it permits an additional exception 

for utilities to fully fund the present value of a Section 468A trust fund with a lump sum payment. 

Section 1310 of EPACT2005 also eliminated the requirement that a nuclear utility’s rates be set 

on a cost-of-service basis in order to qualify for a tax deduction in the current period for amounts 

contributed to a qualified decommissioning trust fund. 

Revenue Loss/Outlay 

The Treasury Department did not estimate the value of this tax expenditure. The Joint Committee 

on Taxation estimated it to be $199 million in 2007, with a cumulative cost of $1.3 billion through 

2015.235

Rationale 

The amendments to IRC Section 468A allow utilities to transfer non-qualified funds to a qualified 

trust and make a one-time payment to fully fund the trust. These actions are taken by a nuclear 

power plant owner prior to the sale of the plant, in order to facilitate the sale of the plant. It 

facilitates the buyer assuming the decommissioning liability, with the Section 468A trust fully 

funded consistent with the Nuclear Regulatory Commission decommissioning assurance 

regulations. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Section 1310 is limited to the disposition of nuclear power plants. It mitigates tax liabilities that 

could have accrued under pre-existing law. As a result, it facilitates the sale of nuclear assets in 

instances where nuclear utilities are required to divest generation under State deregulation 

initiatives or when utilities make a business decision to sell nuclear assets. 

 

235 Joint Committee on Taxation, “Estimated Effects of the Conference Agreement for Title XIII of H.R. 6, The Energy Tax 

Incentives Act of 2005, “ JCX 05-95, July 27, 2005.
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 159 

30. Partial Expensing for Advanced Mine Safety Equipment 

Description 

Section 404 of the Tax Relief and Welfare Act of 2006 (Public Law 109-432) amended the Internal 

Revenue Code by addition Section 179E, which allows for 50-percent expensing of qualified new 

advance mine safety equipment property used in underground mines. This underground mine 

equipment must exceed the effectiveness of current safety equipment requirements. The 

equipment can include: communications technology, enabling continuous contact between miners 

and above ground personnel, electronic tracking devices, emergency breathing apparatuses, and 

monitoring equipment to detect levels of carbon monoxide, methane, and oxygen. The equipment 

must be placed in service after December 20, 2006, and before January 1, 2009. Section 405 also 

provides a business tax credit for mine rescue teams training costs. 

Revenue Loss/Outlay 

Estimated revenue losses associated with this tax expenditure equal $10 million in 

2007 (Table A25). 

Table A25. Estimated Revenue Loss: Partial Expensing of Mine 

Safety Equipment, 2006 to 2012 (million nominal dollars) 

Fiscal Year Revenue Loss-Corporations 

2006 0 

2007 10 

2008 20 

2009 0 

2010 0 

2011 0 

2012 0 

NOTE: All estimates have been rounded to the nearest $10 million. 

Sources: Office of Management and Budget, Analytical Perspectives, 

Fiscal Year 2008 (Washington, DC, 2007). 

Rationale 

Improve the safety of mine operations. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Coal production. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

160 Energy Information Administration / Appendix A: Fact Sheets 

31. Temporary 50-Percent Expensing for Equipment Used in the 

Refining of Liquid Fuels 

Description 

Section 1323 of the Energy Policy Act of 2005 (Public Law 109-58) allows refineries to expense 

50 percent of the cost of equipment used in the refining of liquid fuels. The deduction becomes 

available in the taxable year in which the refinery is placed in service. The remaining 50 percent of 

the cost remains eligible for regular depreciation treatment. This provision applies to the original 

user of the refinery property, for which construction must begin after June 14, 2005, and before 

January 1, 2008. The property must be placed in service before January 1, 2012. 

Revenue Loss/Outlays 

The “Revenue Loss” data were estimated by the Treasury Department (Table A26). The 

difference between estimated Federal income tax payments in a reference case and actual 

Federal income tax payments is presented. The reference case assumes that the temporary 

50-percent expensing provision is in place. The actual case assumes that conventional capital 

cost recovery applies. 

Table A26. Estimated Revenue Loss: Temporary 50-Percent Expensing 

of Refining Equipment, 2006 to 2012 (million nominal dollars) 

Fiscal Year Revenue Loss-Corporations 

2006 

2007 

2008 

2009 

2010 

2011 

2012 

10 

30 

120 

240 

260 

180 

(50) 

NOTE: All estimates have been rounded to the nearest $10 million. 

Source: Office of Management and Budget, Budget of the United States 

Government, Analytical Perspectives, Fiscal Year 2008 (Washington, DC, 2007).

Rationale 

To increased liquid fuels refinery capacity. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Liquid fuels. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 161 

32. Transmission Property Treated as 15-Year Property 

Description 

Section 1308 of the Energy Policy Act of 2005 (Public Law 109-58) amended subparagraph E of 

Section 168(e)(3) of the Internal Revenue Code by adding transmission property rated 

69 kilovolts and above to property qualifying as 15-year property under the Modified Accelerated 

Cost Recovery System (MACRS). The tax law prior to passage of Section 1308 assigned a 30-

year class life and 20-year amortization period for transmission facilities. This amendment to the 

Code is one of the tax-related transmission infrastructure incentives included in EPACT2005. 

Shortening the amortization period reduces taxable income in the current tax year and increases 

deferred taxes associated with the timing difference between book and tax depreciation. This 

increases internally generated funds that may be available for reinvestment in transmission 

facilities. The 15-year property rate is applicable to eligible facilities placed in service after April 

11, 2005. 

The North American Electric Reliability Corporation (NERC) projects an 8.8-percent (14,500 circuit 

miles) increase in transmission investment in the United States over the next 10 years. According 

to NERC, the current 10-year projection of transmission capacity additions amounts to more than 

a 30-percent increase from the prior year’s assessment. NERC further states the pace of 

additions over the next 5 years “appears to be accelerating” relative to original schedules.236 Some 

of the projected transmission additions will be made by tax-exempt transmission-owners (i.e., 

publicly-owned utilities and cooperatives). Thus, not all of the anticipated additions will be eligible 

for this tax benefit. Nor are there any data available to indicate that the acceleration of 

construction of already planned additions or the increase in planned additions that is for treatment 

as 15-year property is entirely a function of the change in the property classification from 20 years 

to 15 years. 

Revenue Loss/Outlays 

According to the Treasury Department, the estimated of the value of this tax expenditure is 

included in the total estimate of the cost of accelerated depreciation for machinery and equipment. 

The Treasury Department referred EIA to the estimate prepared by the Joint Committee on 

Taxation (JCT) of the cost of this provision.237 JCT estimated that reclassifying transmission 

facilities from 20-year property to 15-year property cost $18 million in 2007, with a total cost of 

$1.2 billion between 2005 and 2015.238,239

Rationale 

The rationale for the provision is to provide investor-owned utilities with a tax incentive to increase 

investment in critical transmission infrastructure facilities. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

This tax expenditure is targeted at increasing transmission capacity and improving system 

reliability. It is related to deliverability of electricity without consideration or preference to a 

particular fuel used in electricity production. 

 

236 North American Electric Reliability Corporation, “2007 Long-term Reliability Assessment 2007-2016,” (Princeton, New Jersey), 

October 25, 2007, p. 18. 

237 Email correspondence with Curtis Carlson, Office of Tax Analysis, Department of the Treasury, November 2, 2007. 

238 Joint Committee on Taxation, Estimated Budget Effects of the Conference Agreement for Title XIII of H.R. 6, JCX-59-05, July, 

27, 2005. 

239 This revenue loss is actually a tax deferral. Over time, there is no change in depreciation (except in present value 

terms). Depreciation taken earlier can no longer be taken later in the asset's life. If the rate of transmission investment is constant 

over time, the tax expenditure would fall to zero as the timing difference between book and tax depreciation reverses, such that the 

deferred tax is recovered. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

162 Energy Information Administration / Appendix A: Fact Sheets 

33. Treatment of Income of Certain Cooperatives 

Description 

Section 319 of the American Jobs Creation Act of 2004 (Public Law 108-357) amended Section 

501(c)(12) of the Internal Revenue Code to provide for the exclusion of certain non-member 

income from the calculation of the “85-percent test.”240 Section 319(a) allows cooperatives to 

exclude income from nuclear decommissioning trust fund transactions, income received for 

services provided to non-members under a Federal Energy Regulatory Commission (FERC) 

approved open access tariff241 and income received from a FERC-approved independent 

transmission provider.242 Nuclear decommissioning trust fund transactions are defined to include 

income realized from the transfer of the trust in connection with the sale of a cooperative’s interest

in a nuclear plant,243 and trust fund distributions to pay for decommissioning expenses and 

earnings on trust fund investments. Section 319(a) also permits cooperatives to exclude from the 

85-percent test any gain that would normally receive deferred recognition as income arising from 

a like kind exchange or involuntary conversion of generation, transmission, distribution and natural 

gas distribution property. Section 319(b) permits cooperative to treat wholesale and retail sales to 

non-member as member sales to the extent such sale mitigate member load lost as a result of 

competition. This provision applies to non-members that supplant member load lost as a result of 

the cooperative providing mandatory, non-discriminatory open access. Qualify sales are accorded 

this treatment for a 7-year period. 

A sunset provision limited the benefit of Section 319 through December 31, 2006. The sunset 

provision was eliminated in Section 1304 of EPACT2005. 

Eleven generation and transmission cooperatives own undivided interests in nuclear plants and 

may benefit from the exclusion of decommissioning trust income from the 85-percent test were 

decommissioning trust income to otherwise pose a challenge. Exclusion of trust fund income from 

the 85-percent test may lift a potential barrier for cooperatives to participate in new nuclear plants. 

With regard to the transmission-related provisions, some cooperatives voluntarily joined 

RTOs/ISOs prior to Congress amending Section 501(c)(12). There has not been a wave of 

transmission-owning cooperatives joining subsequent to the amendment. One could interpret the 

lack of activity to mean that while the elimination of potential tax liability associated with providing 

open access transmission reduces a cost, the costs providing open access transmission under a 

FERC-approved tariff, or joining an RTO/ISO, exceed the benefits. 

 

240 The 85-percent test is designed to ensure that organizations exempt under IRC 501(c)(12) provide services at cost to their 

members. Accordingly, each year a cooperative's income, with certain modifications, is determined and the total amount received 

from members for the sole purpose of meeting losses and expenses must be at least 85 percent of the income. The 85-percent test 

is applied on the basis of an annual accounting period. Failure to meet the requirement in a particular year precludes exemption for 

that year, but has no effect upon exemption for years in which the 85-percent test is satisfied. Rev. Rul. 65-99, 1965-1 C.B. 242. 

Source: Internal Revenue Service: http://www.irs.gov/pub/irs-tege/eotopicd94.pdf. 

241 In Order No. 888, the FERC required non-public utilities that own, operate or control transmission facilities, as a condition of 

receiving open access transmission service from a public utility under its Open Access Transmission Tariff (OATT), to provide 

reciprocal transmission service under comparable terms. FERC adopted a voluntary “safe harbor” process as one method of 

satisfying this reciprocity requirement. Non-public utilities (e.g., electric cooperatives participating in the Rural Utilities Service loan 

program) can file an OATT with the Commission under the voluntary “safe harbor” provision. Under this provision, the Commission 

issues a declaratory order finding the OATT appropriate for “safe harbor” status if its provisions “substantially conform or are 

superior to” the pro forma OATT. See, Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission 

Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & 

Regs. ¶ 31,036 (1996) at 31,760-61 (Order No. 888), order on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 (1997), order 

on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1997), aff’d in relevant 

part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. 

FERC, 535 U.S. 1 (2002). 

242 For purposes of ensuring the applicability of the transmission-related provisions to electric cooperatives with in the Electric 

Reliability Council of Texas (ERCOT), the statute defines FERC to include the Public Utilities Commission of Texas with respect to 

cooperatives operating in ERCOT. 

243 The transfer of a nuclear decommissioning trust fund by a cooperative in conjunction with the sale of its interest in a nuclear 

plant can create a tax liability arising from the realized gain on trust fund assets and the discharge of the decommissioning liability 

assumed by the buyer. See Internal Revenue Service, PLR 2000334002, Release Date August 8, 2000. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 163 

Revenue Loss/Outlay 

The Treasury Department did not estimate the value of this tax expenditure. The Joint Committee 

on Taxation estimated the value at $14 million for 2007. The cumulative value through 2010 is 

estimated at $93 million. The Joint Committee report does not provide a breakdown as to how the 

estimated tax expenditure is divided between the certain treatment provide to nuclear-related 

transactions, income received under FERC-approved open-access tariffs, revenue received from 

independent transmission providers, or loss of load mitigation.244

Rationale 

Under Internal Revenue Code Section 501(c)(12) cooperatives’ tax-exempt status is in part 

preserved by maintaining compliance with the 85-percent test, which requires that they conduct 

the bulk of their business with members. This places the promotion of competition through open 

access in direct conflict with providing open access transmission service to non-members. 

Similarly, mandatory retail access, which has been imposed on cooperatives in some States, 

could result in cooperatives facing either stranded costs or the loss of exempt status if they make 

sales to non-members to mitigate loss of member load induced by open access. Excluding 

income from these transactions from the calculation of the 85-percent test eliminates an income 

tax-related barrier in to cooperatives providing open access and participating in competitive 

markets. 

The nuclear-related provision precludes the loss of tax-exempt status that may otherwise occur in 

the course of a cooperative meeting its decommissioning funding obligations. The provision also 

mitigates a tax-related barrier to the potential sale of nuclear assets. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

The portion of the provision pertaining to the treatment of nuclear decommissioning trust for 

purposes of computing the 85-percent test impacts that indirect cost associated with cooperatives’ 

ownership of nuclear generation. It eliminates potential income tax liability to the extent it 

precludes non-member nuclear decommissioning trust income from causing cooperatives to lose 

their tax-exempt status based on the 85-percent test. Excluding decommissioning trust income 

from non-member decommission trust income for purposes of computing the test could factor into 

cooperatives’ decisions to acquire an ownership interest in new nuclear plants. 

The portion of the provision that provides for the exclusion of Regional Transmission 

Organization/Independent System Operator (RTO/ISO)-related income from the calculation of the 

test is intended to eliminate a barrier to transmission-owning cooperatives’ participation in such 

organizations. The provision is neutral with regard to the fuels used in electric generation in the 

sense that cooperative participation in RTOs/ISOs increases the scope of transmission facilities 

over which all forms of generation would have non-discriminatory access to transmission services. 

 

244 Joint Committee on Taxation, “Estimated Effects of the Conference Agreement for Title XIII of H.R. 6, The Energy Tax 

Incentives Act of 2005, ” JCX 05-95, July 27, 2005.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

164 Energy Information Administration / Appendix A: Fact Sheets 

34. United States Department of Agriculture Energy Programs 

Description 

In Fiscal Year (FY) 2000, the United States Department of Agriculture (USDA) initiated the 

Commodity Credit Corporation (CCC) Bioenergy Program to alleviate crop surpluses and 

stimulate production of biofuels. The Agricultural Risk Protection Act of 2000 (Public Law 106-

224) included the Biomass Research and Development Act, which directed the USDA and the 

Department of Energy (DOE) to cooperate and coordinate polices to promote research and 

development leading to the production of bioproducts. 

The Farm Security and Rural Investment Act of 2002 (Public Law 107-171), the 2002 Farm Bill, 

contained the first energy title (Title IX) in farm bill history. The 2002 Farm Bill authorized a range 

of programs through 2007 to promote bioenergy and bioproduct production and consumption. Key 

provisions included the Federal Biobased Products Preferred Procurement Program (FB4P), 

which requires Federal agencies to procure bio-based products. Another program, the Biodiesel 

Fuel Education Program, awards competitive grants to educate government and private entities 

with vehicle fleets about the benefits of biodiesel fuel use. 

The 2002 Farm Bill extended the CCC Bioenergy Program through FY 2006, expanded the 

Conservation Reserve Program (CRP) pilot biomass authority to a nationwide general authority, 

and authorized placement of wind turbines on land enrolled in CRP. The program was funded at 

$50 million annually. 

The Biomass Research and Development Program is operated jointly by USDA and DOE. This 

program supports research and development of biomass-based products, bioenergy, biofuels, 

and related processes. Eligible entities are institutions of higher learning, national laboratories, 

Federal or State research agencies, private sector entities, and nonprofit organizations. Fiscal 

year 2006 funding for the Biomass Research and Development Program was $12 million. 

USDA’s Agricultural Research Service (ARS) is USDA's primary research agency. Specific 

energy-related work being conducted by ARS follows:

• The process of cellulose degradation is not well understood. This research 

provides new information on the regulation of cellulose degradation by an 

organism that shows particular promise for converting cellulosic biomass.

• Inhibitors formed during pretreatment of lignocellulosic material reduce the 

performance of ethanol-producing fermentation organisms. ARS scientists are 

using a method called directed adaptation, developing strains of organisms that 

have enhanced ability to convert toxic compounds into less toxic compounds. 

Development of these more tolerant organisms is a significant step toward 

achieving the technology necessary for commercial production of ethanol from 

cellulosic plant material.

• There is a need to identify genes that regulate cell wall composition of alfalfa so 

that new varieties can be developed that have greater potential as biofuel 

feedstocks. ARS scientists identified and characterized a gene, UDP-sugar 

pyrophosphorylase (USP), which plays an important role in cell wall biosynthesis in 

plants. The isolation of the USP gene and new knowledge learned about the 

protein it produces will allow cell walls of alfalfa plants to be modified to improve 

the value of this crop as a bioenergy feedstock.

USDA’s Cooperative State Research, Education, Extension and Service (CSREES) provides 

funding for about 60 projects that include an energy-related objective. 

USDA’s Forest Service (FS) is working to increase production of all energy sources in an 

environmentally-sound manner, capitalizing on the potential of woody biomass as a renewable 

energy resource, and contributing to the improvement of infrastructure for transmitting energy 

across the country. Increasing domestic energy supply includes providing energy facility corridors, 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 165 

ensuring that lands are available for energy mineral development and production, developing 

renewable energy resources such as woody biomass, wind, solar power, and geothermal energy, 

and re-licensing hydropower facilities. 

The FS actively participates in a government-wide initiative aimed at promoting development and 

use of bio-based products and bioenergy. Programs include research on enhancing opportunities 

to use forest biomass to produce energy and other value-added products; developing economical, 

environmentally-acceptable woody cropping systems to produce energy and other value-added 

products; exploring new processes to convert wood into ethanol; and, identifying ways to increase 

energy conservation through changes in manufacturing technologies, harvesting technologies, 

building construction practices, and designed landscapes. 

The focus of the FS biomass and bioenergy efforts is woody materials that are not part of the 

commercial forest product material flows. Woody biomass includes forest vegetation treatment 

residuals (tree limbs, tops, needles, leaves, and other woody parts) that are by-products of forest 

management and ecosystem restoration. 

EPACT2005 authorized up to $50 million for grants to improve the commercial value of forest 

biomass for electric energy, useful heat, transportation fuels, and other commercial purposes. In 

FY 2006, 88 applications were received, totaling almost $18 million in requests. Eighteen 

proposals were funded at a Federal cost of $4.2 million. These projects leveraged approximately 

$9 million in non-Federal funds. 

Between FY 2001 and FY 2005, USDA funds expended on bio-based products, bioenergy, and 

other energy-related programs totaled $1.4 billion. USDA outlays in FY 2006 on bio-based 

products, bioenergy, and other energy-related programs is estimated at $272 million. In addition, 

Federal and State income tax credits and other tax incentives that promote the use of ethanol and 

biodiesel reduce tax collections by over $2 billion annually. 

The CCC Bioenergy Program began on December 1, 2000, and ended on June 30, 2006. Under 

the program, cash payments were made to bioenergy producers who increased their annual 

bioenergy production from eligible agricultural commodities. Eligible commodities included barley, 

corn, grain sorghum, oats, rice, wheat, soybeans, other oilseeds, cellulosic crops, and animal fats 

and oils. From December 2000 through March 2006, the program reimbursed bioenergy 

producers $537 million for 2.5 billion gallons of increased ethanol production, 146.4 million gallons 

of increased biodiesel production, and 26.7 million gallons of base biodiesel production. 

 Revenue Loss/Outlays 

Expenditures for the various biomass and biofuels programs managed by USDA agencies totaled 

$41.8 million in FY 2007. Regarding the Rural Business Service (RBS) program, not all of the 

RBS programs focus exclusively on providing financial assistance for the development of energy 

infrastructure and promotion of energy efficiency or conservation. Therefore, it is difficult to 

precisely identify the budget subsidy for energy-related activities within particular loan programs. 

As a result, the budget subsidies, and authorized lending, grant, and guarantee levels discussed 

in this section do not reflect the totality of RBS loan and grant programs. 

Rationale 

Alleviate crop surpluses and to promote the development of biofuels. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Wind, solar, geothermal, bioenergy, biofuels for electric generation, transportation fuels, biomass 

co-products, and energy efficiency. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

166 Energy Information Administration / Appendix A: Fact Sheets 

Direct Expenditures 

35. Building Technology Assistance Program 

Description 

The U.S. Department of Energy (DOE) provides conservation assistance in a number of areas, 

primarily through the Building Technology Assistance Program, which complements DOE’s 

research and development efforts and accelerates the deployment of new technologies and the 

adoption of advanced building practices through technical and financial assistance, outreach, and 

selective demonstration projects. According to the Office of Energy Efficiency and Renewable 

Energy, “The Building Technology Assistance Program works to improve the energy efficiency of 

the Nation’s buildings—through innovative new technologies and better building practices.” The 

Building Technology Assistance Program supports two grant programs: the Weatherization 

Assistance Program, which provides support for the weatherization of low-income homes, and the 

State Energy Program, which provides grants to promote innovative State energy efficiency and 

renewable energy activities. The Energy Conservation and Production Act (Public Law 94-385) 

and the Department of Energy Organization Act of 1977 (Public Law 95-91) provided the 

legislative framework for the weatherization program. The Energy Policy Act of 2005 

(EPACT2005) (Public Law 109-58) authorized $500 million for fiscal year (FY) 2006, $600 million 

for 2007, and $700 million for FY 2008 for the weatherization program. EPACT2005 authorized 

funding of $100 million, successively, for FY 2006 and FY2007 and $125 million for FY 2008 for 

the State Energy Program 

Revenue Loss/Outlays 

Federal appropriations outlays for the Building Technology Assistance Program amounted to $278 

million (nominal dollars) in FY 2006 versus $155 million in FY 1998. $242 million of this total was 

directed to the weatherization program while $36 million was directed to the State Energy 

Program.245

Rationale 

To increase the efficiency of homes occupied by low-income citizens who least can afford rising 

energy bills. 

The Building Technology Assistance Program subsidizes energy conservation and is designed to 

reduce energy consumption. Although the technologies supported often are cost-effective on their 

own, cost sharing with nonprofit and government agencies make the first-cost barrier less 

prohibitive.246

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Renewable fuels, oil, natural gas, and electricity end use. 

 

245 Department of Energy budget 2007. 

246 See http://www.eere.energy.gov/buildings/about/mypp.html.
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 167 

36. Low Income Home Energy Assistance Program 

Description 

LIHEAP is a block grant program under which the Federal government gives States, the District of 

Columbia, U.S. territories, and Indian tribal organizations annual grants to provide home energy 

assistance for needy households. LIHEAP assistance does not reduce eligibility or benefits under 

other aid programs. LIHEAP grantees are, however, allowed some flexibility as the program 

allows “maximum policy discretion to grantees.” Federal law permits income eligibility to be 

established at either 60 percent of the State's median income or 150 percent of the HHS poverty 

income guidelines, whichever is greater. Sixty percent of a State's median income is usually 

higher than 150 percent of the HHS poverty level. For a four-person family in Fiscal Year 2007, 

60 percent of the median was estimated at $66,111.247 248 LIHEAP provides two sources of funds: 

regular funds, which are allocated to the states as prescribed by LIHEAP legislation; and, 

contingency funds, which are released and allocated at the discretion of the president and the 

Secretary of Health and Human Services.249

The year 2003 was the latest year for which disaggregated program data were available. In that 

year fifty States were provided heating assistance for that year in the amount of $1.1 billion while 

cooling assistance was provided to 15 States in the amount of $73 million.250 Approximately, 4.4 

million households received heating assistance and 494,000 households cooling assistance. In 

2003, for residential units, space heating and cooling accounted for about 43 percent of lowincome, energy expenditures. Households receiving heating assistance fell at 102 percent of the 

poverty line while those receiving cooling assistance, fell at 124 percent of the poverty line. Annual

cooling assistance averaged $65 dollars while heating assistance amounted to $258.251

Although LIHEAP funds are available for both cooling and heating, a preponderance of 

expenditures goes to relatively cold-weather States. In 2007, the largest recipient states of 

LIHEAP funds were New York, Pennsylvania, Illinois, Michigan, and Ohio.252 LIHEAP funds are 

only used by a fraction of eligible participants. In 2005, 34.8 million households were eligible for 

LIHEAP, while 5.3 million households received LIHEAP benefits, amounting to 15 percent of all 

eligible households.253 By comparison, in 1983, 6.8 million households received LIHEAP benefits, 

which amounted to 31 percent of eligible households. The aging of the population and increased 

independence of handicapped persons means that these groups will account for a growing share 

of LIHEAP payments. For 2002, according to HHS: 

 “of the 4.1 million households receiving heating assistance, approximately 1.4 million 

households had at least one household member 60 years or older; approximately 1 

million of these households had at least one child 5 years or under. Some of these 

households contained both an elderly person and a young child. Although available, State 

data on households with disabled members are not comparable as each State can use its 

own definition of ‘disabled.’”254

 

247 U.S. Department of Health and Human Services, Low Income Home Energy Assistance Program, State Median Income 

Estimates for Optimal Use in Federal Fiscal Year 2006 LIHEAP Programs and Mandatory Use in Federal Fiscal Year 2007 LIHEAP 

Programs, (Washington, DC, March 6, 2006): http://www.acf.hhs.gov/programs/liheap/guidance/information_memoranda/im06-

05.html; accessed October 16, 2007. 

248 Ibid. Accessed October 16, 2007. 

249 Congressional Research Service, The Low-Income Home Energy Assistance Program (LIHEAP): Program and Funding, Order 

Code RL 31865 (Washington, DC, October 2007), p. 1.

250 U.S. Department of Health and Human Services, Low Income Home Energy Assistance Program, 

http://www.acf.hhs.gov/programs/liheap/, accessed October 16, 2007. 

251 U.S. Department of Health and Human Services, LIHEAP, Executive Summary—Low Income Home Energy Assistance Report 

to Congress for Fiscal Year 2003, http://www.acf.hhs.gov/programs/liheap/data/execsum.html, accessed October 16, 2007. 

252 Department of Health and Human Services, LIHEAP, 

http://www.acf.hhs.gov/programs/liheap/guidance/information_memoranda/07-allotments.xls. 

253 Department of Health and Human Services. http://www.acf.hhs.gov/programs/liheap/data/notebook/figure_11.html. 

254 Department of Health and Human Services, 

http://www.acf.hhs.gov/programs/opre/acf_perfplan/ann_per/apr2005/apr_sg3_73.html. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

168 Energy Information Administration / Appendix A: Fact Sheets 

Federal rules also require LIHEAP outreach activities, coordination with the U.S. Department of 

Energy’s Weatherization Assistance Program, and annual audits. Grantees decide the mix and 

dollar range of benefits, choose how benefits are provided, and decide what agencies will 

administer the program components. In addition to funds used for heating and/or cooling 

assistance, however, a reasonable amount of the funds must be set aside by grantees for energy 

crisis intervention. Up to 15 percent of grantees’ allotments (up to 25 percent with a waiver) may 

be used for low-cost residential weatherization or other energy-related home repair. 

Payments may be made directly to eligible households or to home energy suppliers. Assistance 

may be provided in the form of cash, vouchers, or payments to third parties, such as utility 

companies or fuel dealers. In practice, the majority of the funds are paid directly to energy 

providers. 

Revenue Loss/Outlay 

In the early years of the LIHEAP program, funding ranged at around $3.5 billion. Since 1988, 

funding for the program, has generally ranged from $1 billion to $2.4 billion, with the exception of 

the year 2006 when funding exceeded $3 billion. Section 121 of the Energy Policy Act of 2005 

(EPACT2005) (Public Law 109-58) authorized LIHEAP funding at $5.1 billion for the fiscal years 

2005 through 2007. EPACT2005 also allowed LIHEAP funds to be use to purchase renewables 

fuel and requested that HHS conduct a study on how LIHEAP could reduce deaths related to 

extreme temperatures. In FY 2006, Congress appropriated an additional $1 billion in emergency 

LIHEAP expenditures due to high energy costs. A portion of the funding was also directed at Gulf 

Coast states most affected by Hurricane Katrina. 

Rationale 

To help lower income families, including the elderly and the handicapped, maintain their standard 

of living in the face of high energy costs. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

No. 2 fuel oil, natural gas, coal, and electricity end use. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 169 

37. Renewable Energy Production Incentive (REPI) 

Description 

The Renewable Energy Production Incentive (REPI) originated in the Energy Policy Act of 1992 

(EPACT1992) (Public Law 102-486) with the purpose of promoting increases in the generation 

and utilization of electricity from renewable energy sources, and to advance renewable energy 

technologies. This program, authorized under Section 1212, provides financial incentive payments 

to electricity produced and sold by new qualifying renewable energy generation facilities. 

EPACT1992 designated eligible electricity production facilities that commenced operation 

between October 1, 1993, and September 30, 2003. Eligible electric production facilities that may 

be considered to receive REPI payments include not-for-profit electrical cooperatives; public 

utilities; State governments; Commonwealths; territories of the United States; the District of 

Columbia; Indian tribal governments, or a political subdivision thereof; or Native Corporations that 

sell the facility's electricity. The Code of Federal Regulations, Part 451.4 provides more 

information on qualifying facilities and who may apply. 

As non-profits, REPI beneficiaries do not pay Federal income taxes. Therefore, they are ineligible 

for the investment energy tax credit available to investor-owned utilities. Initially, qualifying facilities 

were eligible for annual incentive payments of 1.5 cents per kilowatthour (1993 dollars and 

indexed for inflation) for the first 10-year period of their operation, subject to the availability of

annual appropriations in each Federal fiscal year of operation. Criteria for qualifying facilities and

application procedures were contained in the final rule for this program. Initially, qualifying facilities 

included solar, wind, geothermal (with certain restrictions as contained in the final rule), or closedloop biomass (except for municipal solid waste combustion) generation technologies. The U.S. 

Department of Energy is responsible for managing REPI. 

REPI expired in 2003 even though several projects continued to receive funding subsequently. 

REPI appropriations were reauthorized with Section 202 of the Energy Policy Act of 2005 

(EPACT2005) (Public Law 109-58) for fiscal years 2006 through 2007. Section 202 also expanded 

the list of eligible technologies and facility owners and the procedure for which funds were 

distributed so that funding would sufficiently pay for all approved applications but with an allocation 

of 60 percent for Tier 1 customers and 40 percent for Tier 2 customers (see paragraphs below). 

Section 202 also extended the kilowatt subsidy to ocean and wave energy. REPI was extended 

through December 31, 2008 by Section 207 of the Tax Relief and Health Care Act of 2006 (Public 

Law 109-432). Section 202 included Indian tribal governments and subdivisions thereof among 

the owners of qualified renewable energy facilities. 

REPI payments consist of Federal outlays of funds. Procedures for annual payments to qualifying 

facilities for the REPI program are contained in the final rule. Payments are dependent upon the 

availability of annual appropriations. If there are insufficient appropriations to make full payments 

for electricity production from all qualifying facilities, Tier 1 applicants receive incentive payments 

first. Tier 1 qualifying facilities include use solar, wind, geothermal, or closed-loop (dedicated 

energy crops) biomass technologies to generate electricity. Tier 1 receives either full payments or 

pro rata payments if funds are insufficient to cover all requests. If funds are available after making

full payments to these facilities, payments from the remaining funds are then made to Tier 2 

qualifying facilities. These facilities use open-loop biomass technologies, such as landfill methane 

gas, biomass digester gas, and plant waste material that is co-fired in a generation facility to 

generate electricity. If there are insufficient funds to make full payments to all Tier 2 qualifying 

facilities, payments are made to those facilities on a pro rata basis. Pro rata payments result in a 

portion of the electricity production being fully paid and the remainder not receiving payment. 

Electricity for which payment is not made may be added to the next fiscal year’s electricity 

production and submitted by the qualifying facility for payment consideration, providing the annual 

application is made in a timely manner within the 10-fiscal-year eligibility window. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

170 Energy Information Administration / Appendix A: Fact Sheets 

Revenue Loss/Outlay 

In the first year of the REPI program 1994 (payment year 1995), there were sufficient 

appropriations to make full production incentive payments of $693,120 (nominal dollars) to the 

owners of all qualifying facilities. In the second year of the REPI program, there were sufficient 

appropriations to make full production incentive payments of $2,398,472 (nominal dollars) to the 

owners of all qualifying facilities (Table A27). For the third year of the REPI program, the available

funds of $2,490,893 (nominal dollars) were insufficient to make full production incentive payments 

to the owners of all qualifying facilities. Therefore, full payments were made for electricity 

produced by Tier 1 facilities, and partial payments on a pro rata basis were made for Tier 2 

facilities. For the fourth year of the REPI program, the available funds of $2,853,997 (nominal 

dollars) were insufficient to make full production incentive payments to the owners of all qualifying 

facilities. Therefore, full payments were made for electricity produced by Tier 1 facilities and partial 

payments were made for Tier 2 facilities on a pro rata basis. The fifth year of the REPI program 

received $4,000,000 from Congress. This appropriation did not cover requests for reimbursement. 

Tier 1 was fully funded; Tier 2 funding was prorated on the basis of production. Underfunding of 

Tier 2 programs has continued since. Only in the first 2 years of the program were Tier 2 

customers fully funded. Tier 2 funding fell to 87 percent in 1996 and to a low of 0 percent for 2003 

and 2004. Funding for Tier 2 programs rose to 40 percent for 2005. Meanwhile, the years 2003 

through 2005 saw funding for the Tier 1 group fall below 100 percent. In 2005 (payment year 

2006), funding for Tier 1 customers was $6.3 million and just under $2.0 million for Tier 2 

customers.255

Rationale 

To promote increased generation from renewable energy and to improve the performance of 

renewable energy technologies. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Solar, wind, ocean wave energy, geothermal (with certain restrictions as contained in the 

rulemaking), or biomass (except for municipal solid waste combustion) generation technologies 

used to produce electricity by new generating facilities (which started operation between October 

1, 1993, and September 30, 2003) owned by publicly-owned utilities. 

 

255 Net electricity production by qualified REPI facilities averaged 894,483 million kilowatthours between 2001 and 2005. 
Federal Financial Interventions and Subsid

Energy Information Administration / Appendix A: Fact Sheets 

Table A27. REPI Appropriations (Dollars) 

Year of Production (FY) Year of Payment (FY) Appropriated Funds Tier 1 Paid Tier 1 Unpaid Percent Tier 1 Paid Tier 2 Paid 

EPACT1992 

1994 1995 $693,120 $100,725 - 100% $592,395 1995 1996 $2,398,472 $218,604 - 100% $2,178,217 1996 1997 $2,490,893 $195,902 - 100% $2,294,991 1997 1998 $2,853,997 $154,504 - 100% $2,699,493 1998 1999 $4,000,000 $122,167 - 100% $3,877,833 1999 2000 $1,500,000 $603,182 - 100% $896,818 2000 2001 $3,991,000 $1,339,377 - 100% $2,651,625 2001 2002 $3,787,000 $1,365,846 - 100% $2,421,154 2002 2003 $4,815,033 $1,810,911 - 100% $3,004,122 2003 2004 $3,714,911 $3,714,911 $1,091,206 77% - 2004 2005 $4,960,000 $4,960,000 $2,205,009 69% - 

EPACT2005 

2005 2006 $4,925,375 $2,955,225 $6,323,364 60% $1,970,150 2006 2007 $4,900,000 $2,940 2007 $4,690,000 2008 $4,690,000 2009 $4,690,000 2010 $4,690,000 

Sources: Department of Energy, Office of Energy Efficiency and Renew

Energy,http://www.eere.energy.gov/repi/projects.cfm, accessed October Forecast: Department of Energy, Office of Energy Efficiency and Renewa

“Appendix J, “Weatherization and Intergovernmental Assistance Program 

FY 2008 Benefit Estimates. NREL/TP-620-39684.

2011 $4,690,000 2012 $4,690,000 2013 $4,690,000 2014 $4,690,000 2015 $4,690,000 2016 $4,690,000 2017 $4,690,000 2018 $4,690,000 2019 $4,690,000 2020 $4,690,000 2021 $4,690,000 2022 $4,690,000 2023 $4,690,000 2024 $4,690,000 2025 $4,690,000 2026 $4,690,000 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

172 Energy Information Administration / Appendix A: Fact Sheets 

Research and Development 

38. Advanced Turbine Systems 

Description 

There is a growing national need for increased electricity and reduced emissions from electric 

power generating plants. The objective of the Advanced Turbine Systems (ATS) program, which 

is currently being phased out, was to develop ultra-high-efficiency natural gas turbine systems for 

utilities, independent power producers, and industrial markets. The ATS program was striving for 

revolutionary, yet achievable advances that include: industrial turbine systems for distributed 

power generation that show a 15-percent improvement over today’s best natural gas turbine 

systems; and large central power plants for utility systems that break the 60-percent barrier in net 

thermal efficiency. 

Revenue Loss/Outlays 

There was no funding for advanced turbine systems in 2007. 

Rationale 

The intent behind this program was to improve the fuel efficiency of electric turbine systems while 

reducing emissions. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Natural gas. Although the ATS program will demonstrate performance with natural gas fuel, 

advanced turbine design systems will make use of fuels other than natural gas, such as coal and 

renewable biomass. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 173

 

Basic Research 

39. Basic Energy Research 

Description 

The Basic Energy Sciences (BES) program supports research and operates facilities to provide the 

foundation for new and improved energy technologies and for understanding and mitigating the 

environmental impacts of energy use. There are two BES subprograms. Materials Sciences and 

Engineering supports basic research to explore the scientific foundations for the development of materials 

that improve their efficiency, economy, environmental acceptability, and safety for energy generation,

conservation, transmission, and use. Applications include lighter, stronger materials to increase fuel

economy in automobiles, alloys and ceramics that improve the efficiency of combustion engines, and 

more efficient photovoltaic materials for solar energy conversion. The Department of Energy (DOE) 

Chemical Sciences, Geosciences and Energy Biosciences program, supports research crucial for 

improving combustion systems, solar photo-conversion processes, and for applications to renewable fuel

resources, environmental remediation, and photosynthesis. The $1.4 billion (total project cost) Spallation 

Neutron Source at Oak Ridge National Laboratory, the world’s most powerful neutron scattering facility, 

will be in its first full year of operations in fiscal year (FY) 2007. Four of the five Nanoscale Science 

Research Centers, part of the National Nanotechnology initiative, will be fully operational in FY 2007. 

Construction is also underway on the next -generation $379 million (total project cost) Linac Coherent

Light Source at the Stanford Linear Accelerator Center (SLAC). 

Revenue Loss/Outlays 

The operating plan for basic energy sciences excluding fusion is about $1.3 billion in fiscal FY 

2007. About $1.1 billion is funding for Basic Energy Sciences. Construction is funded at $125 

million and science laboratories infrastructure is funded at $42 million. 

Rationale 

To undertake basic research where commercial payoffs are uncertain, long-term, or unavailable 

to the public. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

All forms of energy. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

174 Energy Information Administration / Appendix A: Fact Sheets 

40. Building Technology, State and Community Programs Research 

and Development 

Description 

Section 109 of the Energy Policy Act of 2005 authorized the Department of Energy (DOE) to 

develop, test, and demonstrate advanced Federal and private building efficiency standards. The 

mission of the DOE building technology (BTS) research and development (R&D) program, within 

the Office of Energy Efficiency and Renewable Energy, is to make buildings more efficient and 

affordable and communities more livable. The goal of the Building Research and Standards 

program is to accelerate the introduction of highly efficient building technologies and practices 

through R&D and increase the minimum energy efficiency of buildings and equipment through 

appliance standards, building codes, and guidelines. The building technology R&D (non-grant) 

programs complement other DOE grant programs that help demonstrate and increase consumer 

awareness of the benefits and costs of energy-efficient technologies. The program develops 

technologies, techniques and tools for making residential and commercial buildings more energy 

efficient, productive, and affordable. The portfolio of activities includes efforts to improve the 

energy efficiency of building components and equipment, including the advancement of solid state 

lighting technologies for general illumination, and their effective integration using whole -buildingsystem-design techniques; the development of energy efficient building codes and equipment 

standards; and integration of clean renewable energy systems into building design and operation. 

Revenue Loss/Outlays 

Appropriations for the BTS program appropriations were $68 million per year for fiscal year (FY) 

2007 and $77 million in FY 2008. 

Rationale 

To increase energy efficiency and reduce the carbon footprint of residential and commercial 

buildings. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Oil, natural gas, and electricity end use. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 175

 

41. Clean Coal Power Initiative 

Description 

The Clean Coal Power Initiative (CCPI), an industry/government cost-shared partnership, 

responds to the government’s commitment to increase investment in Clean Coal Technology 

(CCT). CCPI provides the means to demonstrate those technologies proven through research and 

development to have commercial potential. Demonstrations are at a commercial scale in actual 

operating environments, which is essential to moving them to the threshold of commercialization. 

The CCPI provides government co-financing for new coal technologies that can help utilities meet 

the President's Clear Skies Initiative to cut sulfur dioxide (SO2), nitrogen oxides (NO2) and 

mercury pollutants from power plants by nearly 70 percent by the year 2018. Also, some of the 

early projects are showing ways to reduce greenhouse emissions by boosting the efficiency at 

which coal plants convert coal to electricity or other energy forms. 

Eight projects were selected under the first-round CCPI solicitation, of which two were withdrawn. 

Of the remaining six projects supported by the first round of the CCPI, three projects are currently 

in the operational phase, two are in the construction phase, and one is still in the pre-award 

phase. 

Four projects were recently selected from the second-round CCPI solicitation and are in various 

stages of development. Of the four projects recently chosen, two will demonstrate advanced 

integrated gasification combined cycle (IGCC) technology; one will demonstrate an innovative 

multi-pollutant control process for NOx, SOx, and mercury; and one will demonstrate a neuralnetwork control process for advanced multi-pollutant controls by means of plant optimization. 

Revenue Loss/Outlays 

The fiscal year (FY) 2007 operating plan for coal research and development appropriations is 

$60.5 million. 

Rationale 

The objective of the program is to sharply reduce the air emissions and other pollutants from coalburning power plants. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Coal. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

176 Energy Information Administration / Appendix A: Fact Sheets 

42. Fusion Energy Sciences 

Description 

The Fusion Energy Sciences (FES) program is the national research effort to advance plasma 

science, fusion science, and the fusion technology knowledge-base required for an economicallyand environmentally-attractive fusion energy source. Facilities include the DIII-D at General 

Atomics in San Diego, the Alcator C-Mod at the Massachusetts Institute of Technology, and the 

National Spherical Tokamak Experiment at the Princeton Plasma Physics Laboratory (PPPL). 

Assembly of the National Compact Stellarator Experiment (NCSX) is ongoing at PPPL. The 

Department of Energy is also participating in the President’s initiative on ITER (Latin, for “the 

way”) , an international burning plasma fusion experiment. 

The goal of the FES program is to “acquire the knowledge base for an economically and 

environmentally attractive fusion energy source.” Although there is not a schedule for developing 

and deploying fusion energy systems, the availability of fusion as an option for large central station

power plants could eventually provide valuable insurance against possible environmental 

concerns related to fossil and nuclear energy. In addition, there may be nearer-term applications 

of fusion in transmutation of wastes and isotope production. 

Revenue Loss/Outlays 

The fiscal year 2007 operating plan for this appropriation was $319 million. 

Rationale 

To further the understanding of fusion energy. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Nuclear energy. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 177

 

43. FutureGen 

Description 

FutureGen was initiated on February 27, 2003, in response to the National Energy Policy Report 

of May 2001, prepared under the National Energy Policy Developmental Group. The objective of 

FutureGen was to create a 275-MW coal-fired power plant that would be the world’s first to 

produce electricity and hydrogen while sequestering carbon dioxide emissions. This prototype 

plant was to serve as a laboratory for clean-coal and hydrogen technology development. The 

latter being in connection with the development of technology to facilitate the transition to a 

hydrogen-based economy, including emission-free vehicles. The program was to be partially 

funded by the FutureGen Alliance, a consortium of major coal companies and electric companies. 

Other countries were urged to participate in the project. Four potential plant sites were 

considered by the FutureGen Alliance, which led to the December 2007 announcement of the 

selection of Matoon, Illinois as the site of the prototype plant. 

The project will employ coal gasification technology integrated with combined-cycle electricity 

generation and the sequestration of carbon dioxide emissions. The project will be supported by 

the ongoing coal research program, which will also be the principal source of technology for the 

prototype. The project is expected to require 10 years to complete and will be led by the 

FutureGen Industrial Alliance Inc., a non-profit industrial consortium representing the coal and 

power industries, with the project results being shared among all participants and industry as a 

whole.256

Revenue Loss/Outlays 

The funding for this program was $54 million in fiscal year 2007. 

Rationale 

To prove the technical feasibility and economic viability of the near-zero atmospheric emissions of 

sulfur dioxide, nitrogen oxides, mercury, particulates, and carbon dioxide. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Coal. 

 

256 The prospects for FutureGen grew uncertain when, in January 2008, the U.S. Department of Energy announced that it intended 

to restructure FutureGen. The DOE’s new FutureGen vision called for “Federal-funding to demonstrate cutting edge CCS (Carbon 

Capture and Storage) at multiple commercial-scale integrated gasification combined-cycle (IGCC) demonstration plants...Under 

this new approach multiple plants would produce at least 3000 megawatts of electricity and jointly these projects will capture and 

safely sequester at least double the amount of carbon dioxide annually compared to the concept announced in 2003.” Source: 

DOE, Fact Sheet, “DOE to Demonstrate Cutting-Edge Carbon Capture and Sequestration Technology at Multiple FutureGen Clean 

Coal Projects.” The DOE cited higher than expected costs for the restructuring. The DOE also stated that the program would be 

revamped so that DOE would only fund the carbon sequestration element of the program. The restructuring cast strong doubts 

over whether the prototype plant, selected in December, 2007 for Mattoon, Illinois, would continue. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

178 Energy Information Administration / Appendix A: Fact Sheets 

44. Fuel and Power Systems 

Description 

The Fuel and Power systems program provides research for FutureGen intended to reduce 

dramatically coal power plant emissions (especially mercury) and significantly improve efficiency 

to reduce carbon emissions, leading to a viable near-zero atmospheric emissions coal energy 

system. 

The Innovations for Existing Plants (IEP) program has a near-to mid-term focus to improve overall 

power plant efficiency and develop advanced cost-effective environmental control technologies, 

with a focus on mercury, for retrofitting existing power plants and other coal technologies including 

those developed in support of the FutureGen project. 

The Integrated Gasification Combined Cycle (IGCC) program is intended to develop technologies 

for gas stream purification to meet quality requirements for use with fuel cells and conversion 

processes. 

The Advanced Turbines program is focused on creating the technology base for turbines that will 

permit the design of near-zero atmospheric emission IGCC plants and a class of FutureGen 

plants with carbon capture and sequestration 

The Carbon Sequestration program’s purpose is to develop a portfolio of technologies that would 

reduce greenhouse gas emissions. The program’s goal is to research and develop a portfolio of 

safe and cost-effective greenhouse gas capture, storage, and mitigation technologies by 2012, 

leading to substantial market penetration beyond 2012. 

The mission of the Fuels program is to conduct the research necessary to promote the transition 

to a hydrogen economy. Research is intent on targeting cost reduction and increased efficiency of 

hydrogen production from coal feedstocks. 

Advanced Research projects seek a greater understanding of the physical, chemical, biological, 

and thermodynamic barriers that limit the use of coal and other fossil fuels. The program funds 

two categories of activity. The first includes applied research programs to develop the technology 

base needed for the development of super-clean, very high efficiency coal-based power and coalbased fuel systems. The second is a set of crosscutting studies and assessment activities in 

environmental, technical and economic analyses, coal technology export, and integrated program 

support. 

The objectives of the Fuel Cells activity are to provide the technology-based development of lowcost, scalable, and fuel flexible fuel cell systems that can operate in central coal based power 

systems as well as having applications in other electric utility (both central and distributed), 

industrial, and commercial/residential markets. 

Revenue Loss/Outlays 

The fiscal year 2007 operating plan for coal research and development (R&D) appropriations, 

excluding the unallocated component, is $311.3 million.

Rationale 

To provide an adequate scientific and engineering knowledge base to foster technological 

advances in the private sector. Also, coal-burning power plants are at the center of the 

controversies involving global warming. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Coal mining, combustion, liquefaction, and gasification. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 179

 

45. Industrial Sector Research and Development 

Description 

The mission of the U.S. Department of Energy (DOE) industrial sector research and development 

(R&D) program, within the Office of Energy Efficiency and Renewable Energy (EERE), is to 

improve the energy efficiency, environmental performance, and productivity of energy-intensive 

industries by rapidly developing and delivering advanced science and technology options that will 

lower raw material and energy use per unit of output; improve labor and capital productivity; and 

reduce generation of wastes and pollutants. The energy-intensive industries include forest 

products, steel, glass, aluminum, chemicals, metal casting, agriculture, petroleum, and mining. 

The fiscal year (FY) 2007 goal of this program is to reduce primary nonrenewable energy by 0.03 

quadrillion Btu per year in 2010. Carbon dioxide emissions would be reduced by 0.7 million metric 

tons carbon equivalent per year in 2010. 

Revenue Loss/Outlays 

The industrial sector program appropriations were $56.6 million in FY 2007. 

Rationale 

To improve energy efficiency in the industrial sector. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

All fuels, end use. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

180 Energy Information Administration / Appendix A: Fact Sheets 

46. Nuclear Energy Research Initiative and Energy Policy Act of 2005 

Related Research and Development 

Description 

The Department of Energy (DOE) created the Nuclear Energy Research Initiative (NERI) with the 

intent to address and help overcome technical and scientific obstacles to the future use of nuclear 

energy in the United States. There are several programs that have been implemented as part of 

NERI. They include the Generation IV Nuclear Energy Systems Initiative (Gen IV), Nuclear 

Hydrogen Initiative (NHI), Advanced Fuel Cycle Initiative (AFCI), and Nuclear Power 2010.257,258

The goal of Gen IV is to address fundamental research and development issues necessary to 

establish the viability of next-generation nuclear energy system concepts. The 2007 operating 

plan provides $45.6 million for the Gen IV initiative to expand research and development that 

could help achieve the desired goals of sustainability, economics, and proliferation resistance. 

The NHI, with funding of $19.3 million, is intended to conduct research and development on 

enabling technologies, demonstrate nuclear-based hydrogen production technologies, and 

develop technologies that will apply heat from Gen IV nuclear energy systems to produce 

hydrogen. 

The Advanced Fuel Cycle Initiative, which is an element of the Gen IV effort, is intended to 

develop a better, more efficient, and proliferation-resistant nuclear fuel cycle. This research and 

development program focuses on methods to reduce the volume and long-term toxicity of high-level 

waste from spent nuclear fuel, to reduce the long-term proliferation threat posed by civilian 

inventories of plutonium in spent fuel, and to provide for proliferation-resistant technologies to 

recover the energy content in spent nuclear fuel. The focus of this initiative is to be the Global 

Nuclear Energy Partnership (GNEP). It is funded at $167.5 million in the 2007 operating plan. 

GNEP is intended to accelerate work being done under the AFCI program. Advanced recycling 

technologies are expected to be able to extract highly radioactive elements of commercial spent 

nuclear fuel and use that material as fuel in fast spectrum reactors to generate additional 

electricity. The extracted material, which includes all transuranic elements (e.g., plutonium, 

neptunium, americium, and curium), would be consumed by fast reactors to significantly reduce 

the quantity of material requiring disposal in a repository with the further benefit of producing 

power. The plutonium would remain bound with other highly radioactive isotopes, thereby 

preserving its proliferation resistance and reducing security concerns. With the transuranic 

materials separated and used for fuel, the volume of waste that would require disposal in a 

repository would be reduced by 80 percent. 

The Nuclear Power 2010 program is funded at $80.3 million in FY 2007 to complete the issuance 

of three Early Site Permits by the U.S. Nuclear Regulatory Commission (NRC). In addition, the 

program will complete the industry cost-shared project initiated in FY 2003 to develop generic 

guidance for the Construction and Operating License (COL) application preparation, to resolve 

generic COL regulatory issues and to continue the implementation phase of the two New Nuclear 

Plant Licensing Demonstration Projects awarded in FY 2005. 

The Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) contained several provisions 

intent on promoting current and future nuclear programs. 

Subtitle C of Title 5 of EPACT 2005 funds a prototype Next Generation Nuclear Plant Project to 

produce both electricity and hydrogen. The prototype nuclear reactor and associated hydrogen 

plant is to be sited at the Idaho National Laboratory (INL) in Idaho. A consortium of industrial 

 

257 The following objectives have been established for the NERI program: develop advanced reactor and fuel cycle concepts and 

scientific breakthroughs in nuclear technology to overcome scientific and technical obstacles to expanded future use of nuclear 

energy in the United States, including issues involving nuclear proliferation, unfavorable economics, and nuclear waste disposition; 

advance the state of U.S. nuclear technology to maintain a competitive position in overseas and domestic markets; and promote 

and maintain nuclear science and engineering infrastructure to meet future technical challenges and improve the performance, 

efficiency, reliability, economics, and other attributes to enhance nuclear energy applications. 

258 Source: U.S. Department of Energy, Nuclear Energy, www.ne.doe.gov/neri/neNERIresearch.html. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 181

 

partners is to carry out the cost-shared research, development, design, construction and 

operations of the integrated plant.259

Section 951 of Title IX cites eight objectives of nuclear energy research and development. They 

are: enhancing nuclear power's viability; reducing the likelihood of proliferation; maintaining a 

cadre of nuclear scientists and engineers; maintaining national laboratory and university 

programs, supporting individual and multidisciplinary researchers; developing, planning, 

constructing, acquiring, and operating special research equipment/facilities; supporting technology 

transfer; and, reducing the environment impact of nuclear energy-related activities. 

Section 952 of Title IX (Research and Development) lists the Office of Nuclear Energy's core 

programs as the Nuclear Energy Research Initiative, Nuclear Energy Systems Support Program, 

Nuclear Power 2010 Program, Generation IV Nuclear Energy Systems Initiative, and the Reactor 

Production of Hydrogen. The Nuclear Power 2010 program shall include the use of expertise and 

capabilities of industry, higher education, and the national laboratories. The Generation IV 

initiative must examine advanced proliferation-resistant and passively-safe reactor designs that 

are economically competitive, high in efficiency, low in cost, and improved safety and 

instrumentation. 

Section 953 provides for an Advanced Fuel Cycle Initiative under Title IX (Research and 

Development, Subtitle E - Nuclear Energy). This section authorizes the Secretary of Energy to 

conduct an advanced fuel recycling technology, research, development, and demonstration 

program to evaluate proliferation-resistant fuel recycling and transmutation technologies that 

minimize environmental and public health and safety impacts. 

Section 954 - University Nuclear Science and Engineering Support under Title IX - Research and 

Development, Subtitle E - Nuclear Energy authorizes the Secretary of Energy to conduct a 

program to invest in human resources and infrastructure in the nuclear sciences and related 

fields. This section references the requirements in the program to conduct an 

undergraduate/graduate fellowship program to attract new talent; conduct a junior faculty research 

initiation grant program; support fundamental nuclear sciences, engineering, and health physics 

research; encourage collaborative nuclear research; and, support communication and outreach 

related to these areas. This section also requires the Secretary of Energy to conduct a fellowship 

program for university professors and to set up a visiting scientist program at the national 

laboratories. 

Revenue Loss/Outlays 

The operating plan for these programs is $319.2 million in FY 2007: $302.6 million for NERI and 

$16.5 million for university research. 

Rationale 

To improve the commercial prospects of nuclear power. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Nuclear energy. 

 

259 Source: U.S. Department of Energy, Nuclear Energy. http://www.ne.doe.gov/energyPolicyAct2005/neEPACT2a.html, accessed 

October 16, 2007. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

182 Energy Information Administration / Appendix A: Fact Sheets 

47. Oil Technology Research and Development 

Description 

This program is being phased out. The overall approach of oil technology research and 

development (R&D) was, first, to identify those types of oil deposits that have both the greatest 

potential for improved oil recovery and the greatest risk of abandonment within the next 5 to 10 

years and, second, to apply available technologies. The technologies to be further investigated 

are called secondary and enhanced oil recovery. The first generally involves drilling and improved 

production methods based on sophisticated geological and geophysical interpretation. Enhanced 

oil recovery includes the injection of chemicals, gases, or heat to overcome physical barriers in 

the reservoir. 

Revenue Loss/Outlays 

Oil R&D appropriations were $2.7 million in fiscal year 2007 for the management of the closeout 

of this program. 

Rationale 

The enhanced oil recovery research was aimed at capturing a significant portion of the estimated 

300 billion barrels left in the ground from past recovery rates and methods. The goal is to 

preserve access to identified deposits while developing and testing technologies designed to 

overcome the specific problems that prevent increased oil recovery. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Crude oil production. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 183

 

48. Renewable Energy Technology Research and Development 

Description 

The Department of Energy’s (DOE) Office of Energy Efficiency and Renewable Energy (EERE) 

energy supply and conservation activities promote the development and use of clean, reliable, 

efficient, and cost-effective power technologies to meet growing national energy needs, to reduce 

dependence on foreign energy sources, and to enhance energy security. 

The Hydrogen Technology Program, aligned with the Energy Policy Act of 2005 (EPACT2005), 

focuses on hydrogen production, delivery, storage, and fuel cell technologies. This program 

supports a $1.2 billion Hydrogen Fuel Initiative to accelerate the development of hydrogen fuel cell 

vehicle and infrastructure technologies. The program is intended to enable a commercialization 

decision by industry on fuel cell vehicles and hydrogen infrastructure by 2015. A positive 

commercialization decision in 2015 could lead to market introduction of hydrogen fuel cell vehicles 

by 2020. The overall request in fiscal year (FY) 2007 is $289.5 million. Other organizations also 

contribute to this Presidential Initiative, including: 

• Basic hydrogen research in the Office of Science; 

• Coal-based hydrogen production research in the Office of Fossil Energy; 

• Nuclear-based hydrogen production research in the Office of Nuclear Energy, Science 

and Technology; and, 

• Hydrogen safety-related activities at the U.S. Department of Transportation. 

The Biomass and Biorefinery Systems Research and Development (R&D) program intends to 

accelerate critical research, development and deployment resulting in industrial-scale validation of 

biorefinery pathways. The program focuses on three areas: (1) platforms R&D, to reduce the cost 

of outputs and byproducts from biochemical and thermochemical processes; (2) utilization of 

platform outputs, to develop technologies and processes that co-produce liquid and gaseous 

fuels, chemicals and materials, and/or heat and power, and integrate those technologies and 

processes into biorefinery configurations; and (3) feedstock infrastructure, to develop costeffective biomass harvesting, storage and delivery systems, and to develop energy supply crops 

suitable for diverse regions and climates. 

The Solar Energy Program focuses on R&D to enable cost effective development of solar power 

that will reduce U.S. demand for natural gas and promote a cleaner environment. Through the 

Department’s new Solar America Initiative (SAI), the Solar Energy Program intends to accelerate 

the market competitiveness of solar electricity from photovoltaic (PV) systems 

The Wind Energy Program intends to develop and promote the use of advanced technologies to 

harness wind resources. The program focus is on developing low-wind-speed utility scale 

technology, through leveraged partnerships with industry, to substantially increase the 

economically viable wind resource base across the country. 

Since 1974, the Geothermal Technology Program has worked in partnership with U.S. industry to 

establish geothermal energy as an economically competitive contributor to the U.S. energy supply. 

The Department planned to conclude the Geothermal Technology program in FY 2007 and 

transfer results of its research and development work related to geothermal technology to industry 

and state and local governments. However, the program was resuscitated with appropriations in 

2008 and an appropriation request in 2009.260

The Vehicle Technologies Program supports the Freedom CAR and Fuel Partnership and the 

21st Century Truck Partnership, to enable light-and heavy-duty highway transportation to become 

more efficient. Technology research includes advanced lightweight materials, advanced batteries, 

improved power electronics, electric motors, and advanced combustion engines and fuels. 

 

260 A Massachusetts Institute of Technology report prepared under a Idaho National Laboratories Subcontract sponsored by the 

Department of Energy’s Assistant Secretary for Energy Efficiency and Renewable Energy, Office of Geothermal Technologies, 

concluded that Enhanced Geothermal Systems could provide 100,000 Megawatts of base-load electric-generating capacity by 

2050. Source: “The Future of Geothermal Energy, Impact of Enhanced Geothermal Systems (EGS) in the United States in the 21st

Century,” Massachusetts Institute of Technology, ISBN: 0-615-13438-6, 2006. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

184 Energy Information Administration / Appendix A: Fact Sheets 

Building Technologies (BT) Program develops technologies, techniques and tools for making 

residential and commercial buildings more energy efficient, productive, and affordable. The 

portfolio of activities includes efforts to improve the energy efficiency of building components and 

equipment , including the advancement of solid state lighting technologies for general illumination, 

and their effective integration using whole -building-system-design techniques; the development of 

energy efficient building codes and equipment standards; and integration of clean renewable 

energy systems into building design and operation. 

Industrial Technologies Program (ITP) works to reduce the energy intensity of the U.S. industrial 

sector through a coordinated program of research and development, validation, and dissemination 

of energy -efficiency technologies and operating practices. 

The Federal Energy Management Program (FEMP) advances energy efficiency and water 

conservation and promotes the use of renewable energy in federal agencies, including the 

Department of Energy. FEMP also evaluates and reports the progress in these areas to the 

President and Congress. 

The Facilities and Infrastructure activity supports capital investments to support research and 

development program at the National Renewable Energy Lab (NREL). The Weatherization and 

Intergovernmental Activities program deploys energy efficient and renewable energy products into 

the marketplace, and funds Weatherization Assistance and State Energy Program grants. 

The Program Support account provides for program measurement and strategic direction, as well 

as for technology advancement and outreach. Technical Advancement and Outreach activities 

provide the public with accurate information on energy efficiency and renewable energy 

technologies to help the public make better energy choices. 

Revenue Loss/Outlays 

The fiscal year 2007 operating plan for Renewable Energy Technology R&D is $962.6 million. 

Rationale 

EERE conducts research, development, and deployment activities in partnership with industry to 

advance a diverse supply of reliable and affordable energy efficiency and clean power 

technologies and practices. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

The program includes wind, solar, hydrogen technology, biofuels and biomass, geothermal, 

hydroelectric, and electricity delivery and energy reliability. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 185

 

49. Environmental Management 

Description 

After the Department of Energy (DOE) ceased most nuclear weapons production operations in the 

late 1980s, it established a program to manage the legacy of contamination resulting from the 

operation of the largest government-owned industry. DOE manages thousands of contaminated 

areas and buildings, huge waste volumes, and nuclear materials left over from the nuclear 

weapons production and process and nuclear-related research efforts. This program supports 

activities that manage and address the environmental legacy resulting from civilian nuclear energy 

research. The nuclear energy research and development of DOE and its predecessor agencies 

generated waste and contamination that pose unique problems, including large quantities of 

contaminated soil and groundwater and a number of contaminated structures. Upon completion of 

cleanup activities, these sites or portions of a site will be turned over to other DOE program 

landlords or to the Office of Legacy Management for long-term surveillance and maintenance. 

Non-Defense Environmental Cleanup provides funding in several accounts: Fast Flux Test 

Reactor Decontamination and Decommissioning (D&D), Gaseous Diffusion Plants, Small Sites, 

and the West Valley Demonstration Project. Funding for the Small Sites account includes projects 

at Argonne National Laboratory, Brookhaven National Laboratory, the Energy Technology 

Engineering Center (ETEC), Idaho National Laboratory, the Inhalation Toxicology Laboratory, Los 

Alamos National Laboratory, Moab, and the Stanford Linear Accelerator Center. 

Revenue Loss/Outlays 

The Non-Defense Environmental Management fiscal year 2007 budget in the operating plan is 

$349.7 million. 

Rationale 

To clean up and close contaminated nuclear weapons sites. After cleanup there will be no further 

DOE presence, with the exception of long-term surveillance and maintenance. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Nuclear contamination. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

186 Energy Information Administration / Appendix A: Fact Sheets 

50. Clean Cities Program 

Description 

The Clean Cities program, sponsored by the Department of Energy’s Office of Energy Efficiency 

and Renewable Energy’s FreedomCAR and Vehicle Technologies Program (FCVT), was 

established in 1993 to advance the economic, energy, and environmental security of the United 

States by partnering with local jurisdictions to reduce petroleum consumption in the transportation 

sector. Clean Cities works through a network of 80 volunteer, community-based coalitions, which 

develop public/private partnerships to promote the use of alternative fuels and vehicles, expand 

the use of fuel blends, encourage the use of fuel economy practices, increase the acquisition of 

hybrid vehicles by fleets and consumers, and advance the use of idle-reduction technologies in 

heavy-duty vehicles. 

The Clean Cities program provides its coordinators support in the following areas: market and 

technology analysis; tools and information; technical assistance; funding; partnerships and 

alliances; and training; and events. Clean Cities has a sister program “Clean Cities International.” 

Clean Cities coalitions have increased the number of alternative-fuel vehicles (AFVs) on the road 

every year since 1993, with gains averaging 15-percent in recent years. In 2005, the program 

reached the milestone of displacing one billion gallons of petroleum. 

Rationale 

Reduce petroleum consumption in urban transportation. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Petroleum end use. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 187

 

51. Army Corps of Engineers/Bureau of Reclamation Hydropower 

Projects 

Description 

The Department of the Interior’s Bureau of Reclamation and the Army Corps of Engineers are 

both engaged directly and indirectly in hydroelectric power. Both agencies are charged with the 

construction, operation, and maintenance of Federal hydroelectric facilities. The Corps of 

Engineers operates nationwide, whereas the Bureau of Reclamation conducts its activities only in 

17 western States. 

The direct costs of maintenance and operation in producing hydroelectricity are paid by the Power 

Marketing Administrations (PMAs), which purchase and resell the power; however, the indirect 

costs of the projects are not allocated to electricity production. Typically, construction of dams has

been primarily for the benefits of irrigation, municipal water supply, and flood control, and only 

secondarily for the production of power. Construction costs incurred for flood control, recreation, 

and fish and wildlife purposes are nonreimbursable and are borne by users of irrigation, municipal 

water supply, and power generation. Thus, the costs of construction for power generation need to 

be pro-rated accordingly. Moreover, when the Corps of Engineers dredges a waterway to facilitate 

navigation, and that waterway flows to a hydroelectric facility, silting at the dam is reduced, 

increasing the life of the dam and reducing maintenance costs. The costs are registered not for 

hydroelectric power generation but for navigation. 

Essentially, most of the fixed costs of developing the hydroelectric sites have been paid by the 

Federal government for other reasons. It may well be that, were it not for the other reasons, 

electric power would not have been available until later in the affected areas. The value of the 

economic development, although difficult to estimate, can be seen as resulting from the 

availability of relatively inexpensive hydropower. 

Revenue Loss/Outlays 

The direct costs of power are reimbursed by the PMAs. The imputation of indirect costs borne by 

the Corps of Engineers or the Bureau of Reclamation for electricity production is difficult to 

estimate, in part because Federal reclamation law allows cross-subsidization among projects. 

Thus, users of the electricity reimburse not only the construction costs allocated to power 

generation but also some portion of the construction costs incurred for irrigation. 

Rationale 

The original rationale for Federal involvement with hydroelectric plants was that the cost of adding 

hydroelectric capability to dams was small in comparison with the perceived benefits of economic 

development. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Hydropower, electricity generation.
Federal Financial Interventions and Subsidies in Energy Markets 2007 

188 Energy Information Administration / Appendix A: Fact Sheets 

52. ENERGY STAR Program 

Description 

According to the Department of Energy: “ENERGY STAR is a voluntary labeling program 

sponsored by the U.S. Department of Energy (DOE) and the U.S. Environmental Protection 

Agency (EPA). The ENERGY STAR label helps businesses and consumers easily identify highly 

efficient products, homes, and buildings that save energy and money, while protecting the 

environment.” 

DOE works with manufacturers and standards organizations to develop technical requirements 

and qualifications defining ENERGY STAR status. A number of manufacturers have redesigned 

their products to achieve maximum energy and even water savings. ENERGY STAR-labeled 

clothes washers, for example, use 35 percent to 50 percent less water and 50 percent less energy 

per load than conventional washers. 

More than 100 lighting manufacturers produce ENERGY STAR-qualified compact fluorescent 

bulbs (CFLs). With advanced technology, CFLs use 75 percent less energy than a standard 

incandescent bulb and last up to 10-times longer. Likewise, over 350 manufacturers produce 

ENERGY STAR-qualified windows and window components. ENERGY STAR-qualified windows 

can save 15-percent on a household's total energy bill. All together, the ENERGY STAR label 

appears on over 30 categories of products. 

ENERGY STAR retail partners promote recognition and purchase of ENERGY STAR-labeled 

products. In 2001, they sold more than 1.7 million ENERGY STAR-labeled appliances sold. Many 

retail partners also support a wide range of ENERGY STAR promotional activities such as radio 

ads, in-store displays, and appliance rebates to educate consumers about the benefits of 

ENERGY STAR. 

The typical U.S. household spends about $1,300 on home energy bills. ENERGY STAR states 

that its approved products can save consumers up to 30 percent on those energy bills, without 

sacrificing features, style, or comfort. 

Rationale 

Promotes energy efficiency, lower energy costs to consumers and environmental quality. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Electricity and residential natural gas. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 189

 

53. Federal Energy Management Program 

Description 

The Federal Energy Management Program (FEMP) was established in 1974 to provide direction, 

guidance, and assistance to Federal agencies in planning and implementing energy management 

programs. The mission of FEMP is to reduce the cost of the Federal government by advancing 

energy and water efficiency, promoting renewables, and managing utility costs. Section 543 of the 

National Energy Conservation Policy Act, as amended by the Energy Policy Act of 1992 

(EPACT1992), requires each agency to achieve: a 10-percent reduction in energy consumption in 

its Federal buildings by fiscal year (FY) 1995, when measured against a FY 1985 baseline on a 

Btu-per-gross-square-foot basis; and a 20-percent reduction in Btu per gross square foot by FY 

2000. Furthermore, agencies were required to achieve a 30-percent reduction by fiscal year FY 

2005 per Executive Order 12902, issued in 1994.Executive Order 13123, issued in June of 1999, 

“Greening the Government Through Efficient Energy Management” supersedes Executive Order 

12902. Executive Order 13123 encourages effective energy management in the Federal 

government and builds on work begun under EPACT1992 and previous Executive Orders. The 

goals of the order include: 

• Through life-cycle cost-effective energy measures, each agency shall reduce its 

greenhouse gas emissions attributed to facility energy use by 30 percent by 2010, 

compared to such emissions levels in 1990. 

• Through life-cycle cost-effective energy measures, each agency shall reduce energy 

consumption per gross square foot of its facilities, excluding facilities covered in other 

sections of this order, by 30 percent by 2005 and 35 percent by 2010 relative to 1985. 

• Through life-cycle cost-effective energy measures, each agency shall reduce energy 

consumption per square foot, per unit of production, or per other unit as applicable by 20 

percent by 2005 and 25 percent by 2010 relative to 1990. 

• Each agency shall try to expand the use of renewable energy within its facilities and in its 

activities by implementing renewable energy projects and by purchasing electricity from 

renewable energy sources. In support of the Million Solar Roofs initiative, the Federal 

government shall strive to install 2,000 solar energy systems at Federal facilities by the 

end of 2000 and 20,000 solar energy systems at Federal facilities by 2010. 

• Through life-cycle cost-effective energy measures, each agency shall reduce the use of 

petroleum within its facilities. 

• The Federal government shall strive to reduce total energy use and associated 

greenhouse gas and other air emissions, as measured at the source. 

• Through life-cycle cost-effective measures, agencies shall reduce water consumption and 

associated energy use in their facilities to reach the goals set in the Order. 

Section 104 The Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) provides further 

direction to Federal agencies implementation of FEMP. Specifically, it directs Federal agencies 

to purchase ENERGY STAR and FEMP-designated products, except when it is not cost-effective 

or does not meet functional requirements. 

Revenue Loss/Outlays 

Funding for FEMP, $23.8 million in FY 1999 and zero in FY 2007, is not included in the tables of 

this report, although it appears in the End Use R&D category of the Department of Energy budget, 

because the impact of the program is primarily internal to the Federal government. Funds are 

used for education, training, and encouragement of third-party investments. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

190 Energy Information Administration / Appendix A: Fact Sheets 

Rationale 

The purpose of FEMP is to reduce the Federal government’s total cost of utility services, i.e. 

energy and water through adoption of energy efficiency measures evaluated on a life-cycle cost 

basis. The program also promotes the expanded use of renewable technologies. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Energy and water efficiency, renewable energy technologies, end-use. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 191

 

54. Loan Guarantees for Innovative Technologies 

Description 

Title XVII of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) provides loan 

guarantee incentives for Innovative Technologies. This title allows the Secretary of Energy to 

provide loan guarantees for up to 80 percent of eligible project costs after consultation with the 

Secretary of the Treasury. The guarantee is applicable for projects that avoid, reduce, or 

sequester air pollutants or anthropogenic emissions of greenhouse gases and employ new or 

significantly improved technologies as compared to commercial technologies in service in the 

United States today. No guarantee shall be made unless an appropriation for the cost has been 

made or the Secretary of Energy has received from the borrower a payment in full for the cost of 

the obligation and deposited the payment into the Treasury. The incentive covers a broad range of 

technologies and also includes advanced nuclear energy facilities. Other projects eligible for loans 

include wind, photovoltaic, biomass, hydropower facilities, and advanced fossil energy 

technologies, such as integrated gasification combined cycle, industrial gasification, petroleum 

coke gasification. Efficiency improvements to end-use technologies also qualify for loans. These 

may include: hydrogen fuel technology for residential, industrial, or transportation applications, 

carbon capture and sequestration technologies, and agriculture and forestry technologies that 

reduce carbon dioxide emissions. 

On February 15, 2007, Section 20320(a) of the Revised Continuing Appropriations Resolution 

(Public Law 110-5) authorized the Department of Energy (DOE) to issue loan guarantees under 

Title XVII of EPACT2005 for loans in the total principal amount of $4 billion. EPACT2005 also 

required that not later than 120 days after the date of enactment of this division, and annually 

thereafter, the Secretary of Energy shall transmit to the Committees on Appropriations of the 

House of Representatives and the Senate a report containing a summary of all activities under 

Title XVII of the Energy Policy Act of 2005. On May 16, 2007, DOE issued a Notice of Proposed 

Rulemaking (NOPR, 72 FR 27471) to establish regulations for the loan guarantee program. On 

October 4, 2007, DOE invited 16 project sponsors, who submitted pre-applications in late 2006, to 

submit full applications for loan guarantees. The projects submitted included advanced 

technologies including biomass, fossil energy, industrial energy efficiency, electricity deliverability, 

and energy reliability, hydrogen, and alternative-fuel vehicles. On October 23, 2007, DOE issued 

final rules (10 C.F.R.609) establishing policies, procedures, and requirements for the loan 

guarantee program in the Federal Register. The final regulation specified DOE decision to 

guarantee up to 100 percent of a qualifying loan, as long as the loan does not exceed 80 percent 

of the cost of a project. The guaranteed portion of a partially guaranteed loan may be separated 

from or “stripped” from the non-guaranteed portion, except in cases where the guarantee exceeds 

90 percent of the loan amount. 

The final regulation also required that eligible projects must deploy new or significantly improved 

technologies that avoid, reduce, or sequester air pollutants or anthropogenic emissions of 

greenhouse gases as compared to commercial technologies in service in the United States at the 

time the loan guarantee agreement is executed. DOE also stipulated that a project’s receipt of 

other government assistance does not disqualify a project from receiving a Title XVII loan 

guarantee; however, when evaluating a projects application for a loan guarantee, DOE will 

consider the extent to which the project will receive other government assistance, e.g., grants, tax 

credits, other loans. 

In a report released in April of 2007, the Government Accountability Office (GAO) noted that the 

DOE will “have to estimate the subsidy costs to determine the fees to charge borrowers." GAO 

also noted that “estimated subsidy costs could be difficult because the program targets innovative 

technologies whose future success is uncertain, and loan performance could depend heavily on 

future economic conditions, including energy prices, which are hard to predict accurately.”261

 

261 Government Accountability Office, Department of Energy Observations on Actions to Implement the New Loan Guarantee for 

Innovative Technologies, GAO-07-798T (Washington, DC, April 2007). 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

192 Energy Information Administration / Appendix A: Fact Sheets 

Revenue Loss/Outlay 

No loans were guaranteed in fiscal year (FY) 2007. Therefore, there were no costs associated 

with default risk and the only expenses were administrative. FY 2006 administrative budget 

amounted to roughly $503,000. In the full-year Continuing Resolution that was enacted into law on 

February 15, 2007, Congress provided DOE with $7 million to fund the operation of its Loan 

Guarantee Office, and authority to issue guarantees for up to $4 billion in loans. The President 

has requested $8.4 million for operation of the DOE Loan Guarantee Office in FY 2008. 

Rationale 

To promote innovative technologies in energy production and energy usage. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Projects eligible for loans include advanced nuclear, wind, photovoltaics, biomass, hydropower 

facilities, solar and advanced fossil energy technologies, such as integrated gasification 

combined cycle, industrial gasification, and petroleum coke gasification. Efficiency improvements 

to end-use technologies also qualify for loans. These may include: hydrogen fuel technology for 

residential, industrial, or transportation applications, carbon capture and sequestration 

technologies, and agriculture and forestry technologies that reduce carbon dioxide emissions. 

Also included are alternative-fuel vehicles, electricity reliability investments, industry energy 

efficiency projects, and pollution control equipment. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 193

 

55. Nuclear Power Plant Construction Delay Support 

Description 

Section 638 under Title VI of the Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) 

provided standby support for certain nuclear power plant delays. This section allows the Secretary 

of Energy to enter into contracts for standby support for delays for up to a total of six reactors of 

no more than three different reactor designs. Covered delays include the failure of the Nuclear 

Regulatory Commission (NRC) to comply with schedules for review and approval of inspections or 

the conduct of hearings, in addition to litigation that delays full-power operation. The Secretary of 

Energy would pay 100 percent of the covered costs for the first two reactors that have received a 

combined license and for which construction has begun. However, the Department of Energy 

would not cover any costs that result in a failure of the project sponsor to take any action required 

by law or regulation or any events within the sponsor's control. Covered costs would include 

principle or interest on debt coverage, and the difference on the fair market price of purchase 

power and contractual price of power from the plant, up to a total of $500 million. For the next four 

reactors, the Secretary would pay 50 percent of the covered costs (principal and interest and 

purchase power difference) of a delay, up to $250 million. Covered costs are subject to the 

Secretary of Energy receiving appropriations or payments from project sponsors sufficient to pay 

such covered cost. 

Revenue Loss/Outlays 

NA. 

Rationale 

To remove barriers to new nuclear power investment related to uncertainty regarding construction 

time horizons. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Nuclear power. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

194 Energy Information Administration / Appendix A: Fact Sheets 

56. Nuclear Waste Fund262

Description 

The Nuclear Waste Policy Act of 1982 (NWPA)(Public Law 97-425) established the Federal 

government's responsibility and statutory framework to provide for permanent disposal of 

commercially-generated spent nuclear fuel and the high-level radioactive waste generated by the 

Nation's nuclear defense activities. The Department of Energy (DOE), as directed by the Act, 

initially undertook a national screening exercise to evaluate candidate repository sites. In 1986, at 

the conclusion of this scientific screening activity, DOE recommended three sites to the President 

for further study as potential repositories. Congress, however, in the Nuclear Waste Policy 

Amendments Act of 1987, directed DOE to investigate only one site at Yucca Mountain, Nevada, 

for possible development as a geologic repository. 

The Conference Report to the fiscal year 1997 Energy and Water Appropriations Act directed 

DOE to complete a Viability Assessment for the Yucca Mountain site. This report was completed 

and sent to Congress in December 1998. In 2002, Congress approved and the President signed 

into law the Yucca Mountain Development Act (House Joint Resolution 87, Public Law 107-200) 

which completed the site selection process mandated by the Nuclear Waste Policy Act and 

approved the development of a repository at Yucca Mountain. In 2006, DOE announced that it 

had plans to submit to the Nuclear Regulatory Commission a license application for a Yucca 

Mountain repository by June 2008. Currently, under the DOE’s "best-achievable" schedule, the 

repository will open in 2017. The Yucca Mountain Project is the primary activity of the Office of 

Civilian Radioactive Waste Management. DOE studied Yucca Mountain for 20 years to determine 

its potential as a repository. 

In March 2007, the Secretary of Energy announced that he would send to Congress a legislative 

proposal to improve the Nation’s ability to manage and dispose of defense-related and 

commercially-produced nuclear waste. 

Revenue Loss/Outlays 

The fund is paid for by the users of the disposal service. The NWPA provides for two types of fees 

to be paid by utilities for management and disposal of commercial spent nuclear fuel: an ongoing 

fee of 1 mill (one tenth of a cent) per kilowatthour (kWh) of electricity generated and sold on or 

after April 7, 1983, and a one-time fee for electricity generated and sold prior to April 7, 1983. The

NWPA directed that the utility fees be paid into the Nuclear Waste Fund, a separate account 

established in the U.S. Treasury. The funding for the program's activities consist of 

appropriations principally from two sources: the Nuclear Waste Disposal Appropriation and the 

Defense Nuclear Waste Disposal Appropriation. The budget requests a total of $651 million in 

budget resources for the Civilian Radioactive Waste Management Program in fiscal year (FY) 

2006. Appropriations totaled $495 million. The FY 2007 request was $545 million with 

appropriations of $445 million. (All figures are expressed in nominal dollars.) In early 2007, 

payments and interest credited to the fund were approximately $28 billion. 

Rationale 

To develop a permanent repository site that will enable the Nation to advance its plans for the 

disposition of nuclear waste. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Nuclear power waste storage. 

 

262 In addition to the direct expenditures, tax expenditures, R&D expenditures, and government support for Federal electricity 

discussed in the body of this report, the Federal government intervenes in energy markets through its sponsorship of trust funds, 

which are related to energy production. These funds are intended to be self supporting. However, the Federal government faces 

potential risks in the event that these funds should face revenue shortfalls. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 195

 

57. Power Marketing Administrations 

Description 

In the past, the Federal government has sought to advance development in rural areas through its 

Power Marketing Administrations (PMAs): Bonneville (BPA), Southeastern (SEPA), Southwestern 

(SWPA), and Western Area (WAPA). The Alaska Power Administration was sold in 1998, more 

than 10 years after privatization of all the PMAs was first proposed by the Executive Branch. The 

sale of the Alaska Power Administration was achievable largely because of its small size (by far 

the smallest of the PMAs) and because it operated strictly as an electricity generator, with no 

transmission operations or non-energy activities, such as flood control, irrigation, or recreation. 

Much of the activity of the PMAs consists of marketing power produced by the U.S. Army Corps of 

Engineers and Bureau of Reclamation hydropower projects. The four PMAs sell electricity 

primarily generated by hydropower projects located at Federal dams. Preference in the sale of 

power is given to public entities and electric cooperatives. Support to the PMAs include: (1) lowinterest loans; (2) preferential repayment schedules; (3) debt forgiveness; and (4) no primary 

taxation, such as property or income tax. 

Bonneville Power Administration 

BPA, by far the largest PMA, can be used as an example to describe Federal support. As part of 

the New Deal, BPA was created by Congress to sell the power generated from Federal dams in 

the Columbia Basin. Publicly-owned utilities were given preferential customer status to the power. 

The law called for the PMAs to be self-supporting by offsetting their cost from the fees charged for 

power; however, even if BPA always repaid its debt on time and covered all its other accounting 

(historical) costs, the rates charged for electric power still would not cover the true cost of 

providing the power. 

BPA serves 3 million customers and supplies about half of all power in the Northwest. Its 15,000 

mile transmission network accounts for 75 percent of the bulk transmission system in the 

Northwest. BPA markets power from 31 dams and 1 nuclear power plant. 263 Its service territory 

includes Oregon, Washington, Idaho, Western Montana, and small parts of California, Eastern 

Montana, Nevada, Utah, and Wyoming. BPA provides about 35 percent of the power consumed in 

the Pacific Northwest. BPA’s service territory covers 300,000 miles and 12 million people. BPA 

serves 57 electric cooperatives, 41 municipalities, 29 public utility districts, 7 Federal agencies, 6

investor-owned utilities (IOU), 5 direct-service industries, 1 port district and 2 Indian tribes.264 

Forty-seven percent of BPA’s power sales goes to public utilities, 18 percent is sold outside the 

Northwest, and 13 percent is sold to IOUs. 

Southeastern Power Administration 

SEPA markets electricity in 11 States: Alabama, Florida, Georgia, Illinois, Kentucky, Mississippi, 

North Carolina, South Carolina, Tennessee, Virginia, and West Virginia. In 2005, the utility had 22 

hydroelectric projects with 3,392 megawatts of generating capacity and sold 8.7 billion 

kilowatthours of electricity to 494 wholesale customers for $220 million. It sold power to 293 public 

bodies, 199 electric cooperatives, and 2 IOUs.265 Unlike the other PMAs, SEPA does not own a 

transmission system. 

Southwestern Power Administration 

SWPA markets power from 24 hydroelectric power plants operated by the Army Corps of 

Engineers to customers in Arkansas, Kansas, Louisiana, Missouri, Oklahoma, and Texas. SWPA 

has 2,174 megawatts of generation capacity and operates 1,380 miles of transmission lines. In 

2006 it marketed and delivered 2.3 billion kilowatthours of electricity, 57 percent of which went to 

electric cooperatives, 25 percent to municipalities and 2 percent to government agencies.266

 

263 All of these dams were completed prior to 1977, the first to be completed in 1909. 

264 BPA fast facts, http://www.bpa.gov/corporate/about_BPA/Facts/FactDocs/BPA_Facts_2006.pdf, accessed October 11, 2007. 

265 Southeastern Power Administration, Southeastern Power Administration 2005 Annual Report, p 2. 

266 Southwestern Power Administration 2004-2006 Annual Report, pp. 4 and 15. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

196 Energy Information Administration / Appendix A: Fact Sheets 

Western Area Power Administration 

WAPA was established by the Congress in the 1977 under Section 302 of the Department of 

Energy Organization Act (Public Law 95-91) to manage power marketing and transmission 

operations that previously were under the responsibility of the U.S. Department of Interior’s 

Bureau of Reclamation. WAPA markets power in Arizona, California, Colorado, Iowa, Kansas, 

Montana, Minnesota, Nebraska, Nevada, New Mexico, North Dakota, South Dakota, Texas, 

Wyoming, and Utah. It operates 17,000 miles of transmission lines and sells power from 56 

hydroelectric generation facilities owned and operated by the Army Corps of Engineers, the 

Bureau of Reclamation, and the International Boundary and Water Commission.267 In 2005, 

WAPA sold 36 billion kilowatthours of electricity, 25 percent to municipalities, 23 percent to State 

agencies, 20 percent to cooperatives, and the remaining 32 percent to various other users. The 

utility receives annual appropriations from the Congress to cover all expenses associated with its 

power and other activities. Its power rates are set to recover those costs, along with all costs 

associated with debt servicing.268

Similar to the Tennessee Valley Authority (TVA), WAPA also engages in some non-Federal 

capital acquisition. In some cases, WAPA has relied on customers as a source of funds for 

expanding its electric power capacity through customer advance payments on power under cosponsoring arrangements with entities for construction, operation and maintenance.269 WAPA has 

also received loans from State governments. 

Revenue Loss/Outlays 

In 2006, the Treasury’s estimated net financing costs for the PMAs ranged from $89 million (2007 

dollars) to $393 million. 

Rationale 

PMA were intended to promote economic development in areas where it was felt that private 

enterprise would not offer electric power and in part because of the nature of the regional 

economy. The flexible repayment approach was adopted in view of the significant variability in 

revenues associated with hydroelectric power, a major source of power for some PMAs. The 

PMAs calculate and repay interest expenses, and all other expenses, in accordance with their 

statutes and applicable DOE orders. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Electricity generation, transmission, distribution, and end use. 

 

267 The one thermal plant that WAPA markets power from is the Navajo Generating Station. This unit is, however, not owned by 

WAPA, and is therefore not added into the subsidy calculation. Source: Western Area Power Administration, Western Area Power 

Administration 2006 Annual Report, p. 35. 

268 Western Area Power Administration 2005 Western Profile, p. 5. 

269 Western Area Power Administration 2006 Annual Report, p. 39. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 197

 

58. Price-Anderson Fund270

Description 

A Federal regulation that continues to have a cost-reducing effect on the nuclear power industry is 

the Price-Anderson Act of 1959, which placed a limit of $560 million on the liability of individual 

nuclear power plants for damage resulting from any one accident This limit provides a subsidy to 

the nuclear industry to the extent that insurance premiums paid by the operators of individual 

plants are reduced. 

The Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) introduced significant 

modifications to Price-Anderson. Section 602 of EPACT2005 extends the indemnification 

authority of the Atomic Energy Act. The indemnification of certain Nuclear Regulatory Commission 

licensees is extended from December 31, 2003, to December 31, 2025. The indemnification of 

department contractors is extended from December 31, 2006, to December 31, 2025, and the 

indemnification of nonprofit educational institutions is extended from August 1, 2002, to 

December 31, 2025. This is the fifth time that the Price Anderson Act has been extended since it 

inception in 1957. 

For commercial nuclear power plants, the Price-Anderson Act provides for a two-layer 

compensation system to pay public liability claims. The first layer consists of a set amount of 

insurance for each reactor site currently available from the private insurance market. Licensed 

reactors in the United States. are also required to carry private insurance which is now valued at 

$300 million.271 The second is provided by funds made available through an assessment on each 

licensed reactor of a pro-rated share not to exceed a specified amount. EPACT2005 raised the 

maximum total charge per reactor per accident to $95.8 million from $63 million and added an 

inflation adjustment factor. Section 603 of EPACT2005 also raised the annual secondary level 

payout from $10 million to $15 million, which will be adjusted for inflation. 

This is not the first time that the insurance premiums have been raised. In order to make a larger 

pool of money available to pay public liability claims, the 1988 amendments to the Act increased 

maximum secondary insurance assessments from the $5 million (nominal dollars) established in 

1975 to $63 million per reactor per incident, which was to be adjusted for inflation at 5-year 

increments effective in August. The 1988 amendments also increased potential liability limits to 

$7.34 billion ($200 million primary insurance and $7.14 billion secondary insurance coverage) per 

accident. The 1988 amendments extended the Price-Anderson Act for 15 years, to August 1, 

2002. 

The Department of Energy (DOE) is required by the Price-Anderson Amendments Act, a Federal 

law, to protect its contractors from legal claims that may arise as the result of a nuclear accident 

that occurs at a DOE facility. Price-Anderson also allows the DOE to establish nuclear safety rules 

that its contractors must follow, and gives DOE authority to fine contractors for violating those 

rules. 

Section 604 of EPACT2005 limits the indemnity provided by the DOE for its contractors to $10 

billion, subject to adjustment for inflation, for each nuclear incident, including legal costs. 

Section 608 of the EPACT2005 clarifies the treatment of modular reactors as a single facility or 

multiple facilities. Two or more facilities located at a single site, each having a rated capacity of 

100,000 electrical kilowatts or more but not more than 300,000 electrical kilowatts, will be 

considered a single facility, with a combined rated capacity of not more than 1,300,000 electrical 

kilowatts. 

In a 1983 study, the Nuclear Regulatory Commission concluded that the liability limits established 

by the Price-Anderson Act constitute a subsidy; however, the subsidy was not quantified. At issue 

are the probability distributions for various kinds of accidents on a plant-by-plant basis. From 

 

270 In addition to the direct expenditures, tax expenditures, R&D expenditures, and government support for Federal electricity 

discussed in the body of this report, the Federal government intervenes in energy markets through its sponsorship of trust funds, 

which are related to energy production. These funds are intended to be self supporting. However, the Federal government faces 

potential risks in the event that these funds should face revenue shortfalls. 

271 Congressional Research Service, Energy Policy Act of 2005: Summary and Analysis of Enacted Provisions (Order Code 

RL33302) (Washington, DC, March 2005), p.39. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

198 Energy Information Administration / Appendix A: Fact Sheets 

those distributions, the amount of the subsidy can be estimated by calculating the effect of the 

liability limit on the operators’ insurance premiums. 

There is an implied subsidy in the form of reduced insurance premiums per operating unit which 

reduces the operating costs of commercial nuclear power plants. The Federal government acts as 

an insurer for DOE contractors against any finding of liability arising from nuclear activities of the

contractor within the scope of the contract. Price-Anderson coverage could become more critical 

with the significant increase in potential radioactive waste shipments which can be anticipated in 

both the near- and long–term horizon. An increase in shipments is likely to stem from a variety of 

sources, including the decommissioning and decontamination of nuclear reactors, DOE and 

Department of Defense environmental restoration activities, and shipments of spent nuclear fuel 

and high-level radioactive waste under the Nuclear Waste Disposal Act. 

Revenue Loss/Outlays 

There are no associated revenue losses or budgetary outlays at this time. However, Federal 

outlays could rise if the Federal government is forced to clean up a nuclear incident in excess of 

individual liability limits. As the Act limits liability, it reduces the cost of insurance to the owners of 

nuclear power plants and nuclear activities at DOE sites and, hence, reduces the cost of nuclear 

power and other nuclear activities. 

Rationale 

To meet two basic objectives: remove the deterrent to private-sector participation in atomic 

energy presented by the threat of potentially enormous liability claims in the event of a 

catastrophic nuclear accident, and ensure that adequate funds are available to the public to 

satisfy liability claims if such an accident were to occur. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Nuclear power production and other nuclear activities. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 199

 

TVA Electricity Shares by State

(Percent of Total kWh)

Tennessee, 

Other, 3% 64%

Mississippi, 

9%

Kentucky, 

10%

Alabama, 

14%

TVA Operating Revenue Shares by Type of 

Customer (Percent of Operating Revenue)

Direct Serve 

Industrials, 

12%

Municipals 

and 

Cooperatives, 

87%

Federal 

Agencies, 1%

59. Tennessee Valley Authority 

Description 

The Tennessee Valley Authority (TVA) was established in 1933 under the Tennessee Valley Act 

(Public Law 73-17, 48 Stat. 58). Its original purpose was to promote economic development in the 

Tennessee Valley, to improve navigation, and to aid in flood control. TVA is far and away the 

largest of the Federal utilities, having an asset base greater than that of the four PMAs combined. 

TVA is operated as an independent government-owned corporation for the unified development of 

the Tennessee River Basin, which comprises parts of 7 States . The company’s retail customers 

include 62 large industrial concerns and Federal agencies. In 2006, it operated 17,000 miles of 

transmission lines and 29 hydropower dams, 11 fossil fuel plants, 5 nuclear units, 6 combustion 

turbine plants, and 8 diesel units. With the restart of Browns Ferry I in 2007, TVA now operates 6 

nuclear units at 3 plants with a total nuclear generation capacity of 7,000 megawatts (MW). In 

total, TVA has 34,951 MW of winter generating capacity272 and is one of the Nation’s largest 

wholesalers of electricity, with sales of 156 billion kilowatthours in 2006. TVA’s operating revenues 

totaled $9.2 billion in 2006. 

TVA’s service territory covers 8.7 million people located in nearly all of Tennessee and parts of 

Alabama, Kentucky, North Carolina, Mississippi, Georgia, and Virginia. Tennessee accounted for 

64 percent of TVA’s electricity sales. Its wholesale customers include 108 utilities and 20 electric 

cooperatives. TVA received 87 percent of its revenue from cooperatives. In 2006, generation from 

fossil fuels accounted for 64 percent of TVA’s total generation in 2006, while nuclear generation 

accounted for 29 percent, and hydroelectric generation accounted for 6 percent of the total.273

Figure A1. TVA Electricity Shares by State & Operating Revenue Shares by Customer 

The Stewardship Program includes maintaining a system of dams, reservoirs, and navigational 

facilities and, among other things, maintaining and managing 230,000 acres of public land and 

11,000 miles of shoreline. TVA operates and maintains the navigation channel from Paducah, 

Kentucky, to Knoxville, Tennessee; operates a system of multipurpose reservoirs to retain 

excessive seasonal runoff and regulate discharges at flow rates that can be accommodated by 

downstream channels and reservoirs (resulting in the reduction of flood crests); performs dam 

safety modifications and maintenance activities; operates dewatering areas associated with TVA’s 

 

272 Tennessee Valley Authority, Tennessee Valley Authority 10-K, 2006, p. 14. 

273 Tennessee Valley Authority, Tennessee Valley Authority 10-K, 2006, pp. 6, 14, 11, 18. 

Source: TVA, SEC 10K, 2006. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

200 Energy Information Administration / Appendix A: Fact Sheets 

reservoir system; and performs environmental research services at its Muscle Shoals 

Reservation. 

The Water and Land Program is intended to aid conservation. TVA operates an air-quality 

monitoring network, monitors water quality, promotes the wise use of forest resources in the 

region, and prepares maps for its own needs and to help the U.S. Geological Survey. 

The Power Program provides power to an area of 80,000 square miles in the seven Tennessee 

Valley States. TVA owns and operates a substantial mix of hydroelectric, coal, natural gas turbine, 

and nuclear power plants. 

Revenue Loss/Outlays 

The TVA has a complicated financial structure, historically funded through a combination of power 

and nonpower revenues, borrowing, and direct Federal appropriations. In comparison with the 

interest rates paid by investor-owned utilities (IOUs), TVA is estimated to have benefited from 

Federal government support of $65 million to $189 million (2007 dollars) in 2006 because of the 

utility’s artificially low borrowing costs. 

Although TVA is unregulated and was committed early on to hydropower, the cost of debt 

associated with its nuclear program caused its rates to rise to a level close to the average of 

neighboring IOUs. According to the 2000 Federal budget, “Prior to 2000, appropriations provided 

for public services to maintain and operate public resources—navigable channels, flood control, 

recreation and non-regulatory, community-based programs that protect the water quality of the 

Tennessee river system... .The Budget proposes that beginning in 2000, these services be funded 

entirely by TVA’s power revenues, user fees, and sources other than appropriations, except for 

Land Between the Lakes National Recreation Area.” 

How the TVA Sets Rates 

Section 15 d. (f) of the TVA Act requires it to “charge rates for power which will produce gross 

revenues sufficient to provide funds for operation, maintenance, and administration of its power 

system; payments to States and Counties in lieu of taxes; debt service on outstanding bonds... 

the Corporation’s power business having due regard for the primary objectives of the Act, 

including the objective that power shall be sold at rates as low as feasible.” In order to derive its 

revenue requirements, the TVA employs a debt-service coverage (DSC) methodology.274 The 

DSC method gauges an organization’s ability to cover its operating costs and to satisfy its 

obligations to pay principal and interest on debt. The TVA states that is revenue requirements (or 

projected costs) are typically calculated under the DSC method as the sum of the following 

components: fuel and purchased power costs, operating and maintenance costs, taxes, and debt 

service coverage. The TVA then compares its revenue requirements to the projected revenues for 

the test year at existing rates to determine whether the result will be a shortfall or surplus. Rates 

are than adjusted so as to remove the short fall or surplus. 

Rationale 

According to President Franklin Roosevelt’s promotion of the TVA, “[The] potential usefulness of 

the Tennessee River... transcends mere power development; it enters the wide fields of flood 

control, soil erosion, afforestation, elimination from production use of marginal agricultural lands, 

and distribution and diversification of industry.” 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Hydropower, coal, natural gas, and nuclear electricity generation, transmission, distribution and 

end use. 

 

274Tennessee Valley Authority, Tennessee Valley Authority 10-K, 2006, p. 10. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix A: Fact Sheets 201

 

60. Uranium Facilities Maintenance and Remediation Fund275

Description 

Two programs are contained within the Uranium Facilities Maintenance and Remediation fund: 

The Uranium Enrichment Decontamination and Decommissioning and Other Uranium Activities. 

The Uranium Enrichment Decontamination and Decommissioning Fund was established by the 

Energy Policy Act of 1992 (EPACT1992), (Public Law 102-486) to carry out environmental 

management responsibilities at the Nation's three gaseous diffusion plants, located in the East 

Tennessee Technology Park in Tennessee, at the Portsmouth site in Ohio, and at the Paducah 

site in Kentucky. EPA1992 also directs that this fund be used to reimburse licensees operating 

uranium or thorium processing sites for the costs of environmental cleanup at those sites, subject 

to a site-specific reimbursement limit. The Oak Ridge Operations Office is charged with carrying 

out the fund’s mandates. EPACT1992 required that annual contributions to the fund would be 

made for 15 years, terminating at the earlier of 2007 or the collection of $2.25 billion (adjusted for

inflation), from annual assessments to domestic utilities. (The costs are recorded as a fuel cost by 

the licensees and are recovered through electricity customer rates.) The annual assessment is 

not to exceed $150 million, adjusted for inflation, with Federal appropriations making up the 

difference when expenditures exceed the assessed values. 

The Department of Energy’s (DOE) Office of Environmental Management was charged with the 

responsibility for managing the fund and operational control over the three clean-up facilities 

through 2003. In October 2003, the DOE transferred these responsibilities to a new office in 

Lexington, Kentucky, although the Oak Ridge Operations Office was left with responsibility for 

cleanup activities at the Oak Ridge plant. 

The other uranium activities program involves the management of highly-enriched uranium at the 

Paducah and Portsmouth sites. It also involves the management of the DOE’s inventory of 

depleted uranium hexafluoride and other uranium inventories. This responsibility was transferred 

to the Office of Environmental Management in 2001 from the Office of Nuclear Energy’s Science 

and Technology program. Operations at the Portsmouth site ceased in 2001, although the cleanup effort is expected to take several years. 

The Uranium Enrichment Decontamination and Decommissioning Fund is an integral component 

of legislation to privatize uranium enrichment activities in the United States. The fund addresses 

the cleanup liabilities at the three gaseous diffusion plants that are attributable to past DOE 

operations for weapons and commercial fuel. The future operations of the enrichment facilities are 

managed by the commercial United States Enrichment Corporation (USEC). The 

Decontamination and Decommissioning Fund includes contributions from annual budget 

appropriations and contributions from commercial utilities based upon historical enrichment 

services, measured in “separative work units.” 

In a 2004 study, the General Accounting Office found that funding will be: “insufficient to cover the 

cleanup activities at the three plants. Specifically, our Baseline model demonstrated that by 2044, 

the most likely time frame for completing cleanup of the plants, costs will have exceeded 

revenues by $3.5 billion to $5.7 billion.”276

Revenue Loss/Outlays 

Cash income is estimated at $556 million for fiscal year 2007 and $574 million for 2008. 

 

275 In addition to the direct expenditures, tax expenditures, R&D expenditures, and government support for Federal electricity 

discussed in the body of this report, the Federal government intervenes in energy markets through its sponsorship of trust funds, 

which are related to energy production. These funds are intended to be self supporting. However, the Federal government faces 

potential risks in the event that these funds should face revenue shortfalls. 

276 Government Accounting Office, Uranium Enrichment, Decontamination and Decommissioning Fund is Insufficient to Cover 

Cleanup Costs, GAO-04-692 (Washington, DC, July 2004), Summary. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

202 Energy Information Administration / Appendix A: Fact Sheets 

Rationale 

The goal of the Uranium Enrichment Decontamination and Decommissioning Fund is to clean-up 

the surplus enrichment plants as soon as possible and reimburse licensees for their remediation 

activities at uranium and thorium sites. The enrichment plants include valuable facilities and 

equipment, and the clean-up costs will be offset to the extent that DOE is able to recover the 

value from these surplus assets. 

Major Form(s) of Energy/Fuel Cycle Stage(s) Affected 

Nuclear power waste storage. 
 

Appendix B 

Alternative 

Methods of 

Estimating Federal 

Electricity 

Subsidies and 

Interventions 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

204 Energy Information Administration / Appendix B: Alternative Methods of Estimating 

Federal Electricity Subsidies and Interventions 

Alternative Methods of Estimating Federal Electricity Financial Support 

In Chapter 4 a measure of capital investment support (based on interest obligations) was used to measure 

Federal government support to Federally-owned utilities. This appendix presents two alternative measures 

of support: market price support and return on asset support. Due to data limitations, these measures of 

support were not deemed to be as accurate as the interest support described in Chapter 4. As such, the 

methodologies described below are of perhaps greater value than the specific estimates of support, which 

should be viewed as rough. 

Market Price Support 

The market price estimate of support involves the price differential for Federal power sold in wholesale 

electricity markets and investor-owned utility (IOU) power sold in wholesale electricity markets. It should 

be kept in mind that wholesale prices embody more than pure power costs. Often included in wholesale 

prices are such transaction specific items as: capacity fees, delivery fees, and fees for the use of facilities. 

This qualification, however, should not obscure the fact that electricity generation is the largest component 

of wholesale electricity prices277 and that some Federal power is priced significantly below that of 

neighboring utilities. 

There are a number of different measures of wholesale electricity prices. The one used in this analysis, 

“sales for resale,” was the only available measure that could be readily derived from published EIA data. It 

was also used because Federal utilities sell almost all of their electricity in wholesale markets. In a 

competitive market, the prices charged by different companies for the same commodity would be similar,

with some variation resulting from such factors as transportation costs, as competitive forces would not 

allow significant price differences to persist over time. Where well-functioning markets exist, market prices 

can be observed directly. If Federal utilities sell power at below-market prices, the value of their 

preferential rates is the difference between the revenues that would be earned by selling electricity at the 

market price and the actual revenues of the utility. In essence, this price differential amounts to the 

opportunity cost of Federal power. For several reasons, however, caution should be exercised in 

estimating competitive market prices for electricity. First, although U.S. electricity markets have become 

more competitive, they are still significantly regulated. Because the prices charged by IOUs for wholesale 

transactions are often based on their embedded costs, a true competitive price cannot be derived. 

Furthermore, Federal utilities are currently required to sell electricity at rates that cover both power and 

some non-power costs. These latter costs, including environmental protection and aid to irrigation, have 

been found to be relatively higher for Federal utilities than for most IOUs.278

Wholesale electricity flowing over the grid is fungible; however, it is not necessarily a liquid commodity in 

all regions of the country. Thus, the underlying terms and conditions of bilateral transactions, and power 

purchased and sold in centralized markets, must be relied upon to determine whether two or more 

transactions are similar for price comparison purposes. For example, the price of hourly opportunity sales, 

which reflects current market conditions, is not comparable to long-term requirements where the supplier 

assumes a contractual obligation to serve the customer’s current and future needs, including the provision 

of reserve capacity. Essentially, these two transactions involve different goods, and the prices for them are 

not directly comparable. The market price approach implicitly assumes that wholesale power sales by 

Federal utilities are directly comparable to private-utility power sales within the same regions; however, 

this may not always be the case. 

Still, Federal power is in general low-price power particularly when measured against electricity prices in 

regions without access to Federal electricity. In part, this is due to the historic role the Federal government 

has played in the development of the Nation’s hydroelectric resources, particularly in the areas of the 

Columbia and Tennessee River valley basins. Much Federal power comes from relatively cheap 

hydroelectricity, some of which was built long ago when construction costs and interest rates were 

relatively low. Moreover, to a large measure, these original asset investments have been depreciated. In a 

purely rate-regulated environment, conventional ratemaking policy allows low-cost producers to pass on

 

277 Energy Information Administration, Electric Power Annual, 2006, DOE/EIA-348(2006) (Washington, DC, Nov 2007), Table 8.3. 

278 TVA has substantial nonpower costs related to its substantial support of a water transportation network and its stewardship role 

as conservator of public lands. General Accountability Office, Bonneville Power Administration, Better Management of BPA’s 

Obligation to Provide Power is Needed to Control Future Costs, GAO-04-694, (Washington, DC, July 2004), p. 18. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

Energy Information Administration / Appendix B: Alternative Methods of Estimating 205 

Federal Electricity Subsidies and Interventions 

the benefits of cheap power to their customer base. In a regulated environment, selling relatively cheap 

power at below-market prices does not involve a form of government support, as long as the power is sold 

without preference. However, by law certain classes of customers, such as municipalities, cooperatives, 

etc., have preferential access to Federal electricity. Thus, one could argue that it is the policy of 

preference, not price, which is the conveyance of Federal government support. However, this conveyance

has a value in any economic environment, whether rate-regulated or free market, but it can more readily 

be estimated in a market where prices are freely set by supply and demand. 

As wholesale electricity markets have been making a transition to more complete competition (a transition 

that has been in effect for a number of years), market forces have played a greater role in determining 

price.279 In contrast to the rate-regulated environment, in a pure market-based environment, low-cost 

power producers become profit maximizers. Whatever cost advantage these producers possess relative 

to their competitors could be captured in the form of rents. Low-cost producers would have little incentive 

to price their power at anything other than market clearing rates, which in a competitive environment would 

be equal to the industry’s marginal cost of power. Moreover, in a pure market environment, producers 

would be free to sell their electricity to the 

highest bidders without the constraints of a 

preferential customer class. In a purely 

competitive environment, the extent to which 

Federal power prices fell below the prices 

charged for similar power by competing utilities 

would constitute Federal support to the buyers of 

Federal power. 

A comparison is made in this appendix between 

wholesale power prices charged by the four 

power marketing administrations (PMAs), along 

with the Tennessee Valley Authority (TVA), and 

wholesale prices charged by nearby IOUs. The 

intent of the comparison is to ascertain whether 

Federal utilities provide power at rates below 

those charged by neighboring IOUs, thus 

providing their customers with an advantage 

unavailable to other consumers. Accordingly, the 

value of the price differential between rates 

charged by Federal utilities and those charged 

by neighboring IOUs should be seen as a rough 

estimate of any price advantage enjoyed by the 

customers of Federal utilities. 

Federal utilities as a group have mainly wholesale customers, none of their end-use customers are 

classified as residential or commercial.280 In general, their end-use customers are bulk purchasers, such 

as the U.S. Department of Energy’s National laboratories and aluminum smelters in the Pacific Northwest. 

Although most Federal utilities’ power prices are often set in advance (and in the case of the PMAs, with 

oversight by the U.S. Department of Energy and the Federal Energy Regulatory Commission), prices can 

fluctuate due to a number of circumstances. For instance, low water levels can force Federal utilities to 

purchase relatively high-cost power to meet their load needs. As a result, even though Federal utilities 

price their power in advance to meet their operational and borrowing needs, in some years Federal utilities 

post modest profits or losses. The PMAs also have some flexibility in terms of rate adjustments and in

some years mid-year rate adjustments are needed to avoid losses. In making a rate adjustment, the 

PMAs are required to notify their customers through a Federal Register Notice, followed by public 

 

279 There have been some notable reversals in the trend toward State deregulation, such as in the cases of Arizona and Virginia. 

280The customers of Federal utilities in turn sell Federal power to municipals, cooperatives, and IOUs do in turn sell that power to 

residential and commercial end users. For instance, the Memphis Light Gas and Water Division accounted for 9.1 percent of TVA’s 

sales in 2006. Source: Tennessee Valley Authority, Tennessee Valley Authority 2006 Annual Report, p. 9. 

Electricity Markets 

The electricity market has two distinct segments, 

wholesale and retail power markets. Wholesale markets 

comprise the resale and purchase of electricity among 

utilities and nonutility power producers for sale to 

ultimate consumers. Wholesale trade transactions are 

categorized by the service provided: full or partial 

requirements, firm or non-firm, etc. Generally, different 

services have different associated costs of service and, 

under cost-of-service regulation, have different prices. 

Prices of wholesale electricity sales (including the 

PMAs) are subject to approval by the Federal Energy

Regulatory Commission, with the exception of the TVA.a

Retail electric sales are sales covering electrical energy 

supplied for residential, commercial, and industrial enduse purposes. 

a

 The TVA and its regulatory exception are discussed

later in this chapter. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

206 Energy Information Administration / Appendix B: Alternative Methods of Estimating 

Federal Electricity Subsidies and Interventions 

Source: TVA, SEC 10-K, 2006. 

hearings.281 The Secretary of Energy and the Federal Energy Regulatory Commission must approve any 

rate adjustments.282

TVA’s Prices Relative to Neighboring IOUs 

In 2006, TVA’s average wholesale revenues were somewhat higher than the rates in the territories of 

neighboring utilities as measured by the Southeastern Electric Reliability Council (SERC) region’s average 

wholesale power costs. In 2006, TVA’s average wholesale revenues were 5.8 (2007 dollars) cents per 

kilowatthour, compared with an average of 5.5 cents per kilowatthour for utilities operating in the SERC 

region as a whole. As a result, EIA estimates an implicit negative subsidy value of $421 million is being 

paid for by recipients of TVA power. TVA’s prices relative to SERC prices vary from year to year and in 

some years TVA’s wholesale prices are greater than SERC prices and sometimes lower. Since 1998, 

TVA’s prices have exceeded the SERC average wholesale prices in 5 years. In those years where TVA’s 

prices fell below those of surrounding utilities, the price-based subsidy estimate would be positive. 

 TVA’s current electricity prices in large measure reflect past investment decisions. TVA maintains an

asset base which combines relatively low-cost hydroelectric and coal plants with relatively high- cost

nuclear plants. Although the TVA faces very favorable variable costs largely due to its hydroelectric and 

coal plants, due to its inoperable nuclear power plants, its financing costs relative to revenues are 

significantly higher than neighboring utilities, thus raising TVA’s fixed costs. Even though the TVA has not 

brought deferred assets and terminated nuclear assets of $5.4 billion (2007 dollars) into its rate base,283

interest payments on the underlying borrowings are passed on to ratepayers and thus serve to elevate 

TVA’s electricity prices.284 

Figure B1. TVA Net Generation by Energy Source (percent) 

Nuclear power accounted for 64 

percent of TVA’s investment in 

generating assets in 2006, while 

providing 29 percent of its gross 

generation (Figure B1). In 

contrast, fossil fuels and 

hydropower, which accounted for 

33 percent of the utility’s 

generation assets, provided 70 

percent of its generation.285 Due to 

its dependence upon coal and 

nuclear, and to a lesser extent 

hydro, TVA’s variable costs tend 

to be low relative to surrounding 

utilities. However, this cost 

advantage is eroded to a great 

extent by TVA’s high debt 

payments relative to surrounding utilities—a result of its past high-cost, nuclear-related investments. 

BPA’s Prices Relative to Neighboring Investor-Owned Utilities 

More than 90 percent of the electricity sold by BPA is produced from Federal hydroelectric facilities; the 

remainder comes from one nuclear power plant. The average revenues derived from BPA’s wholesale 

electricity sales are, in general, lower than those of competing utilities in BPA’s operating region and much 

 

281 In a General Accountability Office report entitled Power Marketing Administrations Repayment of Power Needs Closer 

Monitoring, the GAO found Department of Energy and Federal Energy Regulatory Commission oversight on PMA rate adjustments 

to be perfunctory. Power Marketing Administrations Repayment of Power Needs Closer Monitoring GAO/AIMD-98-164 

(Washington, DC, June 1998), pp. 7 and 8. 

282 Federal Energy Regulatory Commission (FERC) review is required under Department of Energy Delegation Order 0204-108. 

Department of Energy review is required under the Department of Energy Organization Act of 1977 (Public Law 95-91). Bonneville 

is an exception as it is required to only obtain FERC approval. 

283At $3.3 billion (2007 dollars) in 2006, TVA’s deferred assets and terminated nuclear assets were down substantially from the 

$7.8 billion in terminated nuclear assets in 1998 

284Over the course of a year utilities’ prices can fluctuate apart from any preset rates. In a low rainfall year, utilities are sometimes 

forced to purchase higher priced power to meet their load requirements. 

285 Tennessee Valley Authority SEC 10-K, 2006, pp. 11, 90 and 93. 

Coal Nuclear Natural Gas & Diesel Hydro
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

Energy Information Administration / Appendix B: Alternative Methods of Estimating 207 

Federal Electricity Subsidies and Interventions 

lower than those of IOUs operating outside the Pacific Northwest. Clearly, BPA’s lower average revenue is 

due to its heavy dependence on relatively inexpensive hydroelectric power. BPA hydroelectric capacity 

accounts for more than 90 percent of its total capacity. By comparison, 67 percent of the total capacity in 

the Pacific Northwest is hydroelectric. Only one major utility in the Pacific Northwest region sold more 

hydroelectricity than BPA, although, in general, other utilities in the region also tend to be heavily

dependent on hydropower. The ample hydroelectric resources in the Pacific Northwest also allow 

neighboring utilities to charge rates substantially lower than those in the rest of the Nation. 

Traditionally, electric power in the Northwestern United States has been much cheaper than in most of the 

rest of the country. In 2006, electricity prices averaged 9.04 cents (2007 cents) per kilowatthour for the 

United States as a whole, 5.01 cents per kilowatthour in Idaho, 6.28 cents per kilowatthour in Washington, 

and 6.68 cents per kilowatthour in Oregon (Table B1).

Table B1. Average Price per Kilowatthour for the United States, Selected States by EndUse Sectors, 2006 (2007 Cents per kWh) 

State All Sectors Residential Commercial Industrial

Washington 6.28 6.96 6.69 6.47

Oregon 6.68 7.64 7.14 6.65

Idaho 5.01 6.25 5.23 5.54

Nationwide 9.04 10.63 9.57 6.22

Source: Energy Information Administration Electric Power Monthly, March 2007, DOE/EIA-0226 (2007/03) Table 5.6.B, 

http://tonto.eia.doe.gov/ftproot/electricity/epm/02260703.pdf. Accessed October 15, 2007. 

Residential users in the Pacific Northwest are also among the beneficiaries of BPA’s low-cost hydropower 

production. Residential electricity prices in Idaho averaged 6.25 cents per kilowatthour in 2006 

(2007cents), the lowest in the United States. In contrast, the average price per kilowatthour for residential 

users in the United States as a whole was 10.63 cents. Similar price benefits were realized by commercial 

and industrial electricity consumers in the Pacific Northwest. 

To measure the value of BPA’s relative price advantage, a comparison was made between BPA’s average 

wholesale revenue per kilowatthour and those of nearby utilities. In 2006, BPA’s average revenue per 

wholesale kilowatthour was 3.0 cents (2007 cents), as compared with 4.8 cents for surrounding utilities 

(Table B2).286

Table B2. Implied Support for BPA Based on Market Rates,1998 and 2006 (million 2007 dollars)

Average Prices of Wholesale 

Electricity Sales 

(2007 Cents per Kilowatthour) Year

Wholesale 

Revenues 

(Million 2007 

Dollars) 

Revenues at 

Implied Market 

Prices 

 (Million 2007 

Dollars) 

Implied 

Revenue 

Foregone 

(Million 2007 

Dollars) WECC Regional 

Average BPA Average

Revenue Foregone per 

Unit of Electricity Sold 

(2007 Cents per 

Kilowatthour) 

1998 1,333,447 2,195,299 861,853 3.2 1.9 1.2 

2006 2,716,306 4,333,116 1,616,809 4.8 3.0 1.8 

Sources: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report," 

1998 and 2006. 

 

286 Energy Information Administration, Form EIA-861, “Annual Electric Power Industry Report, ” 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

208 Energy Information Administration / Appendix B: Alternative Methods of Estimating 

Federal Electricity Subsidies and Interventions 

The difference in revenue provides a measure of the price support provided to the recipients of BPA’s lowcost Federal power. If BPA were able to sell its electricity at the same prices as surrounding utilities, its 

revenues would increase by $1.6 billion (2007 cents). This amounts to the difference in revenues that 

would be realized by BPA if BPA raised its electricity rates to the levels of competing utilities, minus the 

revenue actually realized by BPA. In 1998, the implied revenue foregone associated with BPA’s relatively 

lower prices was $862 million (2007 cents). Even though BPA saw an increase in its wholesale prices 

between 1998 and 2006, the percent increase in wholesale prices for surrounding utilities was even 

greater. 

BPA’s price advantage is in large measure due to its low-cost hydroelectric power plants, which were built 

with relatively cheap Federal government financing. Although its prices are among the lowest in the 

region, the utility has a high concentration of nonperforming assets and debt, which causes its prices to be 

higher than they would be otherwise. For the most part, BPA’s nonproductive assets and debt, like those 

of TVA, were accumulated as a result of a large-scale nuclear power program occurring in the 1970s. BPA 

guaranteed much of the debt of the Washington Public Power Supply System (WPPSS), which was 

owned by a group of municipal utilities in Washington State. WPPSS began construction of five nuclear 

power plants in the mid-1970s, but the projects were beset by cost overruns, schedule delays, and 

mudslides. BPA is currently financing debt on three of the five nuclear power plants (Projects 1, 2, and 

3).287 In 2006, BPA carried $3.9 billion in partially completed nuclear power plants on its balance sheet. 

BPA’s wholesale electricity prices have risen considerably since 1998 but so too have those of competing 

utilities. In the future, BPA will have slightly more leeway in raising prices; effective Oct. 1, 2006, BPA has 

the ability to formulaically adjust rates up to $300 million annually to make up for any revenue shortfalls. In 

the fiscal year 2007 budget, the Office of Management and Budget proposed a revenue enhancer for 

BPA, stipulating that whatever profits BPA realizes as a result of a high precipitation year were to be used 

to pay down debt rather than to reduce rates. 

PMA Prices Relative to Neighboring Investor-Owned Utilities 

The prices charged by the three smaller PMAs are among the lowest available in the United States. Since 

their establishment, Congress has mandated that the three smaller PMAs sell their power at the “lowest

possible rates consistent with sound business principles.” Like BPA and TVA, the three smaller PMAs are 

required to provide certain classes of customers with preference power. 

Average wholesale prices charged by the three smaller PMAs are considerably below those charged by 

nearby IOUs; however, they have increased significantly since 1998. The average price realized by SEPA

in 2006 was 4.0 cents (2007 cents) per kilowatthour. Although considerably higher than the average price 

in 1998 (2.3 cents per kilowatthour), it was still cheaper than the surrounding North American Electric 

Reliability Corporation (NERC) region, (i.e., the Southeastern Electric Reliability Council or SERC). The 

SERC price was 5.5 cents per kilowatt hour in 2006 (Table B3). 

For SWPA, the average wholesale price was 4.5 cents per kilowatthour (versus 1.7 cents in 1998), 

compared with 4.8 cents for neighboring IOUs in 2006. For WAPA, average wholesale prices equaled 2.4 

cents (versus 1.9 cents in 1998) cents per kilowatthour, compared with 4.8 cents for neighboring IOUs in 

2006. If the three smaller PMAs charged the same prices as those of competing IOUs, their combined 

average wholesale prices would climb by $873 million (2007 dollars). These differences in revenue and 

price can be viewed as a form of Federal support to the customers of the three smaller PMAs.

 

287 Projects 4 and 5 defaulted on the dept in the 1980s, an event known at the time as the “Whoops Default.” This default, at $2.25 

billion, was the largest municipal default in U.S. history. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

Energy Information Administration / Appendix B: Alternative Methods of Estimating 209 

Federal Electricity Subsidies and Interventions 

Table B3. Computation of Implied Support for Small PMAs on a Market Price Basis, 

1998 and 2006 (millions 2007 dollars) 

Average Prices from 

Wholesale Electricity Sales 

(2007 Cents per Kilowatthour) PMA 

Wholesale 

Revenues 

(Million 2007 

Dollars) 

Revenues at 

Implied 

Market Prices 

(Million 2007 

Dollars) 

Implied 

Revenue 

Foregone 

(Million 2007 

Dollars) Nearby NERC 

Regional Average 

Federal 

PMA 

Average

Revenue Foregone per 

Unit of Electricity Sold 

(2007 Cents per 

Kilowatthour) 

Power Marketing Administration (1998) 

SEPA 208 455 247 5.1 2.3 2.8

SWPA 113 249 136 3.2 1.7 1.5

WAPA 770 1,263 493 3.2 1.9 1.3

Power Marketing Administration (2006) 

SEPA 209 290 82 5.5 4.0 1.5 

SWPA 106 117 11 4.8 4.5 0.3 

WAPA 816 1,596 780 4.8 2.4 2.4 

Sources: Energy Information Administration, Form EIA-861, "Annual Utility Report," 1998 and 2006, 

Southeastern 2005 Annual Report, Southwestern 2004-2006 Annual Report, and Western Area Power 

Administration 2006 Annual Report and corresponding 1998 reports. 

Return on Asset Support 

Another measure is used to estimate the value of Federal revenues forgone when returns on Federal 

electricity assets fall short of the returns on similar assets held by IOUs. This measure is comparable to 

the standard method used by electricity regulatory bodies to determine the appropriate rate base in 

reviews of IOU rate filings. Historically, the structure of the electric utility industry has been predicated on 

the concept that the industry was a natural monopoly. The result was traditional rate base regulation for 

IOUs, designed to protect consumers by ensuring reliability and a fair revenue requirement to electric

utility shareholders. The revenue requirement was based on operating costs and a reasonable return on 

the rate base (invested capital) of the utility. Rate schedules were based on the cost of service for different 

customer classes and projected sales for each customer class to capture the necessary revenue 

requirement. This section compares Federal utility rates of return against those of IOUs to estimate the 

value of Federal support to consumers of Federal power. 

Over the long term, IOUs must earn a sufficient return on invested capital to satisfy their shareholders. 

Historically, U.S. regulators have taken this into account when setting the price of electricity for private 

utilities. If sales of services provided by government-owned assets provide a below-market return on the 

assets, a preferential benefit is being conferred on customers. This approach measures the value of 

forgone Federal utility revenue required for the Federal utilities to realize a market rate of return on their 

assets, i.e., the “opportunity cost” of the return on those assets. A simplified textbook definition of cost for 

a private-sector electric utility equates with operating cost less depreciation of capital assets plus some 

allowance for cost of capital. The extent to which actual Federal utility earnings from electricity sales fall 

below what they would have earned by charging market rates consistent with IOU rates of return 

constitutes a support to the purchasers of Federal power, with the amount of the support equal to the 

difference between revenues sufficient to provide a market return on capital and revenues at the actual 

selling price. 

Like the estimates of market price and interest rate support, estimates of return on asset support are not 

perfect measures of the support provided to the preferred customers of Federal utilities. As stated above, 

U.S. electricity markets are heavily regulated, and the assets utilities have in place today were not fully 

developed under competitive market conditions. There are also two notable distinctions between the IOUs 

and the Federal utilities. One, is Federal utilities are not subject to paying Federal taxes; the other is that 

Federal utilities do not have to raise equity, as they are entirely debt-financed. The return on asset
Federal Financial Interventions and Subsidies in Energy Markets 2007 

210 Energy Information Administration / Appendix B: Alternative Methods of Estimating 

Federal Electricity Subsidies and Interventions 

calculation addresses these issues in part by comparing a Federal utility rates of return (net operating 

income over plant and equipment) with an IOU rate of return prior to taxation and payments of dividends 

(again net operating income over plant and equipment). 

Although most Federal utility power prices are often set in advance (and in the case of the PMAs, 

approved by the U.S. Department of Energy and the Federal Energy Regulatory Commission), prices can 

fluctuate due to a number of circumstances. Low water levels can force Federal utilities to purchase power 

to meet their load needs. As a result, even though Federal utilities price their power to meet their 

operational and borrowing needs, in some years Federal utilities post modest profits or loses. 

TVA’s Return on Capital 

The TVA sets electricity prices, unlike IOUs, not based upon a just and reasonable rate of return but 

instead based upon its cash requirements which include servicing its debt. The TVA needs neither Federal 

Energy Regulatory Commission nor State utility commission approval to set its rates. This report uses two 

measures of comparative financial performance to measure TVA’s return on capital against the return on

capital realized by IOUs. The first measure is net income before interest divided by net utility assets, 

without consideration of deferred assets such as TVA’s inoperable nuclear plants. The second measure 

incorporates these assets of into the denominator. 

IOUs as a group earned a 9.61-percent operating rate of return on investment in 2006 (Table B4). In 

contrast, TVA, excluding its deferred assets, realized a 7.16-percent rate of return and a 

5.43-percent rate of return including its deferred assets in 2006.288 Without its deferred assets, TVA’s 

generating revenues sufficient to earn an 9.61-percent operating return for TVA would require that TVA

increase its prices so that revenue rose by $509 million. To generate a rate of return equal to the IOUs 

when including TVA’s deferred nuclear assets would imply a revenue increase of $1.1 billion. 

Table B4. Tennessee Valley Authority's Return On Assets Estimates, 1998 and 2006 

IOU 

Comparison

 Net Plant 

and 

Equipment 

 Actual 

Revenue 

 Operating 

Income 

Average 

Return 

(Percent) 

Implied IOU 

Rate of 

Return 

(Percent) 

 Implied 

Federal 

Government 

Support 

 Operating 

Income with 

IOU Rate of 

Return 

1998 (million 2007 dollars) 

No Deferred 

Assets 25,277 8,272 2,666 10.55 12 49 490 3,156 

Deferred Assets 34,420 8,272 2,666 7.75 12.49 1,632 4,298 

2006 (million 2007 dollars) 

No Deferred 

Assets 20,769 9,185 1,486 7.16 9.61 509 1,995 

Deferred Assets 27,355 9,185 1,486 5.43 9.61 1,141 2,628 

Sources: Tennessee Valley Authority, SEC 10-K, 2006 and 1998 Annual Report, FERC Form 1 data via Global Energy 

Decisions Inc. 

The operating return on assets measures were chosen, rather than the more familiar net income or return 

on equity, in order to abstract from the differing roles of debt for public-sector versus private-sector 

utilities. Public-sector utilities sometimes have debt that equals or exceeds their assets, and they set 

prices so that there is little or no net income remaining after interest payments. 

BPA’s Return on Capital 

As with the TVA, an assumption is made here that if BPA were to realize the same rate of return on assets 

as IOUs, then an appropriate adjustment to its prices, revenues, and operating income would be needed.

Like the other Federal utilities, BPA is not expected, on average, to realize a positive rate of return. 

Rather, its rates are expected to cover costs and nothing more. A positive rate of return is possible,

however, given unforeseen changes in the operating environment. For instance, BPA is heavily reliant on 

 

288 Because TVA does not pay Federal taxes, the after-tax and pre-tax net income values are the same. The TVA does make 

payments to States in lieu of taxes. These payments equaled $376 million in 2006, or about 4 percent of revenues (Source: 

Tennessee Valley Authority, Tennessee Valley Authority 10K 2006, p. 22. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

Energy Information Administration / Appendix B: Alternative Methods of Estimating 211 

Federal Electricity Subsidies and Interventions 

hydropower. With rates set in advance, income can vary considerably based on annual precipitation in the 

Pacific Northwest. 

The first measure of operating rate of return uses operating income over net utility assets excluding 

deferred nuclear assets. The IOUs realized a 9.61-percent rate of return in 2006, as compared with a 

7.76-percent rate for BPA (Table B5). The second measure includes deferred regulatory assets as plant 

and equipment. In the case of BPA, its $4 billion in deferred assets are primarily related to its nonoperational nuclear power plants. Excluding BPA’s deferred assets, realizing a 9.61-percent rate of return 

would provide BPA with additional revenues of $294 million. Including BPA’s deferred nuclear power 

plants in calculating a return on assets yields a 6.16-percent rate of return. Using this measure, BPA

would have had to raise revenue by $693 million in order to achieve the IOU rate of return Although the 

interest costs associated with BPA’s deferred nuclear power plants are recovered in BPA’s prices, these 

facilities provide limited, if not negative value, to the utility’s asset base. 

Table B5. Return On Assets Estimates for Bonneville Power Administration, 1998 and 2006 

IOU 

Comparison

Net Plant and 

Equipment Actual Revenue

Operating 

Income 

Average 

Return 

(Percent) 

Implied IOU 

Rate of Return 

(Percent) 

Implied 

Federal 

Government 

Support 

Operating 

Income with 

IOU Rate of 

Return 

1998 (million 2007 dollars) 

No Deferred 

Assets 18,445 2,844 1,073 5.82 12.49 1,230 2,303 

Deferred 

Assets 23,680 2,844 1,073 4.53 12.49 1,883 2,957 

2006 (millions 2007 dollars) 

No Deferred 

Assets 15,939 3,692 1,237 7.76 9.61 294 1,531 

Deferred 

Assets 20,095 3,692 1,237 6.16 9.61 693 1,930 

Sources: Bonneville Power Administration 1998 and 2006 Annual Reports and FERC Form 1 via Global Energy Decisions Inc. 

PMA Returns on Capital 

The method used to measure the difference between the returns on assets for the three smaller PMAs 

and those for the IOU comparison group is exactly the same as used for BPA and TVA. As a group the 3 

PMAs realized revenue in excess of expenses in 2006 so their rate of return on investment was nearly 

zero.289 The first measure of operating rate of return uses net income before interest and taxes divided by 

net utility assets. For the comparative IOUs this rate equaled 9.61 percent versus 0.77-percent for the 3 

smaller PMAs. The two other measures incorporate the deferred assets of the IOUs—largely involving 

unfinished nuclear power plants—into a before-tax and after-tax basis. 

Generating revenues sufficient to earn a 9.61-percent operating return for three smaller PMAs would 

require that they increase their prices sufficient to achieve a revenue gain of $512 million (Table B6) 

versus $735 million to realize the IOU 12.49-percent rate of return seen in 1998. The 3 smaller PMAs 

carry no significant inoperable plant and equipment. 

 

289 Note: For SWPA, balance sheet data for the Army Corp of Engineers assets were not available for the years 2004 through 

2006. For WAPA and SEPA, 2006 data were not available. As a consequence, subsidy data were extrapolated based upon the 

latest reported data year using the gross domestic product (GDP) implicit price deflator. Also note that the Western Area Power 

Administration reported a loss in 2006, as it did in the prior 6 years. These losses have been attributable to an unusually low 

precipitation in the western United States. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

212 Energy Information Administration / Appendix B: Alternative Methods of Estimating 

Federal Electricity Subsidies and Interventions 

 

Table B6. Three Smaller PMAs Returns on Net Power Plant and Equipment (million 2007 dollars) 

IOU Comparison 

Net Plant and 

Equipment 

Actual 

Revenue 

Operating 

Income 

Average 

Return 

(Percent) 

Implied IOU 

Rate of Return 

(Percent) 

Implied 

Federal 

Government 

Support) 

Operating 

Income with 

IOU Rate of 

Return 

1998 (millions 2007 dollars) 

No Deferred Assets 7,343 1,070 182 2.48 12.49 735 917 

Deferred Assets 7,343 1,070 182 2.48 12.49 735 917

2006 (millions 2007 dollars) 

No Deferred Assets 5,795 1,131 44 0.77 9.61 512 557

Deferred Assets 5,795 1,131 44 0.77 9.61 512 557 

Sources: Western Area Power Administration 2006 Annual Report, Southwestern Power Administration 2004-2006 Annual 

Report, Southeastern Power Administration 2005 Annual Report. FERC Form 1 data via Global Energy Decisions Inc. 
Appendix C 

Historic 

Perspectives on 

Energy Tax 

Expenditures 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

214 Energy Information Administration / Appendix C: Historic Perspectives 

on Energy Tax Expenditures 

Historic Perspectives on Energy Tax Expenditures 

This appendix provides a historic perspective on energy-related tax expenditures in the United States. The 

Treasury Department began to report tax expenditures in 1967 (Table C1). The reporting of tax 

expenditures as a part of the budget process was mandated by the Congressional Budget Act of 1974 

(Public Law 93-344). The budget of the U.S. Government defines tax expenditures as “revenue losses 

due to preferential provisions of the Federal tax laws, such as special exclusions, exemptions, deductions, 

credits, deferrals, or tax rates.” Although the concept of what constitutes a tax expenditure is clear, the 

determination of what exactly is a preferential provision is subject to interpretation. In preparing this 

section on energy-related tax expenditures, the EIA relied entirely on the definitions of tax expenditures 

presented in Office of Management and Budget (OMB) documents and the staff of the Joint Committee on 

Taxation. 

Energy policy has been shaped by the prevailing condition of the overall economy, political concerns, and 

the condition of energy markets. The introduction of new tax expenditures are generally associated with 

major milestones in energy policy. As a result, the focus of energy-related tax expenditures has changed 

considerably over time. The earliest energy-related tax expenditures go back to World War I and were 

directed at encouraging more domestic oil and natural gas production. The expensing of exploration and

production and percentage depletion were the primary agents used to achieve this goal.290,291 Prior to the 

second oil embargo of 1979, oil and natural gas remained the focus of most tax expenditures. 

In 1967, overall energy tax expenditures were estimated at $8.0 billion (2007 dollars). There were only 

three energy-related tax expenditures reported that year. Excess over cost depletion, at $6.4 billion (2007 

dollars) was far and away the largest tax expenditure for that year, amounting to 81 percent of all revenue 

foregone as a result of energy-related tax expenditures. Between 1967 and 2007, the estimated loss was

equal to $108 billion.292 The next largest item, expensing of exploration and development costs, was 

estimated at $1.5 billion (2007 dollars). Since 1967, the revenue losses associated with this expenditure 

are estimated to be roughly $54 billion.293 Capital gains treatment from royalties on coal came in third in 

1967, at $25 million (2007 dollars). 

 

290 Expensing of exploration and development costs was based on regulations issued in 1916 while the excess of percentage over 

cost depletion appeared in 1926. The percentage over cost depletion stems from the Revenue Act of 1916 which first recognized 

that the depletion of oil and natural gas as a tax deduction. Source: Congressional Budget Office, Tax Expenditures Budget Control 

Options and Five-Year Budget Projections for Fiscal Years 1983-1987 (Washington, DC, November 1992), Table C1. 

291 A court invalidated the expensing of exploration and development costs in 1945, but Congress subsequently gave its approval to 

the treatment, and it became law in 1954. 

292 Based upon estimates appearing in the United States General Accounting Office publication, Petroleum and Ethanol Fuels: Tax 

Incentives and Related GAO Work, GAO/RCED-00-301R (Washington, DC, September 2000) and data appearing in the Office of 

Management and Budget’s Analytical Perspectives of the U.S. Budget 2008, 2006, 2004, and 2002. 

293 Based upon estimates appearing in the United States General Accounting Office publication, Petroleum and Ethanol Fuels: Tax 

Incentives and Related GAO Work, GAO/RCED-00-301R (Washington, DC, September 2000) and EIA estimates based upon data 

appearing in the Office of Management and Budget’s Analytical Perspectives of the U.S. Budget 2008, 2006, 2004, and 2002. 
 Federal Financial Interventions and Subsid

Energy Information Administration / Appendix C: Historic Perspectives on Energy Tax Expenditures 

Table C1. Current and Historic Tax Expenditures, Selected Years, 1967 to 2007 (million 2007 dollars) 

 1967 1974 1976 1981 1984 1992 1996 2004 

Expensing of Exploration and Development Costs 1,489 2,835 2,375 5,537 2,226 -76 -265 282 Expensing of Tertiary Outlays - - - - - 27 - - Exception from Passive Loss Limitation for Working Interests in Oil and Gas Properties - - - - - 110 63 22 Excess of Percentage over Cost Depletion 6,453 7,240 4,662 5,366 3,629 1,023 1,422 672 Capital Gains Treatment of Royalties on Coal 25 17 177 181 324 14 19 76 

Alternative Fuel Production Credit - - - 50 35 618 720 1,127 2

Alcohol Fuel Credit - - - - 9 110 13 33 Exclusion of Interest on state and local Industrial Development Bonds used for Energy Production Facilities 

- - - - 53 172 398 - 

Exclusion of Interest on Energy Facility Bonds - - - - - - - 108 Enhanced Oil Recovery - - - - - - 101 358 Residential Energy Credits - - - 231 - - - - New Technology Credit - - - - - 62 38 358 Alternative Conservation and New Technology Credits Supply Incentives - - - 451 368 - - - 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

216 Energy Information Administration / Appendix C: Historic Perspectives on Energy Tax Expenditures Table C1. Current and Historic Tax Expenditures, Selected Years, 1967 to 2007 (million 2007 dollars) 

 1967 1974 1976 1981 1984 1992 1996 2004 

Residential Energy Credits Conservation Incentives - - - 853 - - - - Tax Credit and Deduction for Clean-Burning Vehicles and Properties - - - - - - 82 - Tax Credit and Deduction for Clean-Burning Vehicles - - - - - - - 76 Alternative Conservation and New Technology Credits Conservation Incentives - - - 592 61 - - - Alcohol Fuel Exemption - - - 177 377 747 847 1,571 1Exclusion from Income of Conservation Subsidies Provided by Public Utilities - - - - - - 190 108 Credit for Holding Clean Renewable Energy Bonds - - - - - - - - Deferral of Gain From Dispositions of Transmission Property to Implement FERC Restructuring Policy 

- - - - - - - - 

Credit for Production from Advanced Nuclear Power Facilities - - - - - - - - Credit for Investment in Clean Coal Facilities - - - - - - - - 

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

- - - - - - - - 

Pass Through from Sulfur Diesel Expensing to Cooperative Owners - - - - - - - - 
 Federal Financial Interventions and Subsid

Energy Information Administration / Appendix C: Historic Perspectives on Energy Tax Expenditures 

Table C1. Current and Historic Tax Expenditures, Selected Years, 1967 to 2007 (million 2007 dollars) 

 1967 1974 1976 1981 1984 1992 1996 2004 

Natural Gas Distribution Pipelines being Treated as 15-Year Property - - - - - - - - Amortized all Geological and Geophysical Expenditures over 2 Years - - - - - - - - Allowance for the Deduction of Certain Energy Efficient Commercial Building Property 

- - - - - - - - 

Credit for Construction of New Energy Efficient Homes - - - - - - - - Credit for Energy Efficiency Improvements to Existing Homes - - - - - - - - Credit for Energy Efficient Appliances - - - - - - - - 30 % Credit for Residential Purchase/Installation of Solar and Fuel Cells - - - - - - - - 

Credit for Business Installation of Qualified 

Fuel Cells and Stationary Microturbine Power Plants 

- - - - - - - - 

Alternative Fuel and Fuel Mixture Tax Credit - - - - - - - - Partial Expensing for Advanced Mine Safety Equipment - - - - - - - - Expensing of Capital Goods with Respect to Complying with EPA Sulfur Regulations - - - - - - - - Biodiesel and Small Agri-Biodiesel Producer Tax Credits - - - - - - - - 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

218 Energy Information Administration / Appendix C: Historic Perspectives on Energy Tax Expenditures Table C1. Current and Historic Tax Expenditures, Selected Years, 1967 to 2007 (million 2007 dollars) 

 1967 1974 1976 1981 1984 1992 1996 2004 

Exclusion of Special Benefits for Disabled Coal Miners - - - - - - - - Transmission Property Treated as FifteenYear Property - - - - - - - - Five-Year Net Operating Loss Carryover for Electric Transmission Equipment - - - - - - - - Treatment of Income of Certain Electric Cooperatives - - - - - - - - 84-Month Amortization of Certain Pollution Control Facilities - - - - - - - - Nuclear Decommissioning - - - - - - - - Total 7,967 10,092 7,214 13,260 7,082 2,779 3,627 4,790 

NOTE: Values for the Alcohol Fuel Credit were unobtainable for the years prior to 1996. 

Sources: Office of Management and Budget, Analytical Perspectives, 2006-2008, Table 19-1. Congressional Budget Office, The President’s Fi

Expenditure Proposals, (Washington, DC, April 1978); Congressional Budget Office, The Effects of Tax Reform on Tax Expenditures, (Washin

A-1, and Energy Information Administration, Federal Energy Subsidies, Federal Interventions in Energy Markets, (SR/EMEU/92-02)(Washingto
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

Energy Information Administration / Appendix C: Historic Perspectives on 219 

Energy Tax Expenditures 

 

The late 1970s saw a second world oil supply shock and heightened environmental concerns brought on 

by a nuclear accident at the Three Mile Island nuclear plant and the Love Canal disaster. During this 

period, energy policy attempted to address energy security and environmental protection. In order to 

address prevailing gasoline shortages, the National Energy Act of 1978 (NEA 1978, Public Law 95-618) 

came into law. NEA 1978 included an alcohol fuels excise exemption, which eventually became one of 

the largest energy-related tax credits by the mid-1990s, and the largest tax expenditure in the year 2007. 

An important component of NEA 1978 was the Energy Tax Act. ETA 1978 established a 10-percent 

business investment tax credit for solar photovoltaic projects. The Act also established a 15-percent 

energy tax credit added to an existing 10-percent investment tax credit for solar thermal and wind 

generation facilities. For residences, ETA 1978 established a credit of 30 percent for the first $2,000 

invested and 20 percent for the next $8,000 for investment in solar and wind energy equipment. This 

credit, along with its production tax credit counterpart, eventually fell under the category of new technology 

credit as defined by the Treasury. ETA also implemented a percentage depletion rate of 22 percent for 

geothermal deposits for 1978 to 1980, and 15 percent after 1983. 

In anticipation that the NEA’s removal of domestically-produced crude oil price controls would quickly lead 

to higher prices, the Crude Oil Windfall Profit Tax of 1980 (Public Law 96-223) was signed into law. Prior 

to passage of the act, the price of most domestically-produced crude oil was regulated. A phase-out of

price controls was determined to be necessary to increase domestic supply. The Crude Oil Windfall Profit 

Tax also introduced an alternative fuels credit. This credit was directed at promoting the use of 

unconventional fuels. The tax credit, initially set at $3.00 per barrel of oil equivalent, was directed at the 

following fuels: (1) oil produced from shale and tar sands; (2) natural gas produced from geopressurized 

brine, Devonian shale, coal seams, tight formations, or biomass; (3) liquid, gaseous, or solid synthetic fuel 

produced from coal liquefaction and pressurization; (4) fuel from qualified processed wood; and (5) steam 

from solid agricultural byproducts. The alternative fuel production credit is often referred to as the Section 

29 credit based upon its former Internal Revenue Service code.294 In 2007, the alternative fuel credit was 

the second largest tax expenditure. 

The second oil price shock also gave rise to several tax expenditures focusing on conservation and 

producing alternative sources of energy. By 1981, energy-related tax expenditures had climbed to $13.3

billion. This was probably a historic highpoint for energy-related tax expenditures even though the U.S. 

economy was less than half its current size and the population was about 25 percent smaller than today.

295

Although traditional tax expenditures continued to grow, new expenditures focused on alternative fuels, 

technologies, and conservation. The expensing of exploration and development now exceeded excess of 

percentage over cost depletion and amounted to a revenue reduction at $5.5 billion (2007 dollars). The

value of excess over cost depletion fell considerably from 1967, and in 1981 equaled $5.4 billion (2007 

dollars). Due to such legislation as the Energy Tax Act of 1978 and the Windfall Profit Tax of 1980, the 

number of energy-related tax expenditures climbed to 12, although two expenditures had de minimis 

values. In 1981, new tax expenditures included: residential energy credits conservation incentives ($853 

million), new technology conservation incentives ($592 million), alternative conservation and new 

technology credit supply incentives ($451 million), residential energy credits supply incentives ($231

million), and the alternative fuel production credit ($50 million). The alcohol fuel credit was in effect for the 

first time that year but with a de minimis value, as was the case of the exclusion of interest on State and 

local government industrial development bonds for energy production facilities. 

After peaking in 1981, energy prices moderated. For most of the low-energy price 1980s, there was little in 

the way of new tax expenditure initiatives and the 1980s witnessed a diminishment of the role of the 

Federal government in providing tax incentives to promote energy supply. During the 1980s, the Energy 

Tax Act of 1978 business energy tax credits was allowed to expire. The Tax Reform Act of 1986 (Public 

Law 99-514) eliminated the 10-percent investment tax credit and extended the energy tax credit until 

1988, but it reduced that credit from 15 percent to 10 percent and eliminated wind as a candidate for any 

credits. By 1984, energy-related tax expenditures had fallen sharply, and overall revenue reductions 

 

294 The Treasury refers to the credit as the alternative fuel production credit. The IRS calls the credit the nonconventional fuel 

source credit. The corresponding IRS code is Section 29. See: http://www.irs.gov/irb/2006-18_IRB/ar06.html . Also, see Budget of 

the United States Government Analytical Perspectives, Fiscal Year 2008 (Washington, 2007), p. 301. 

295 Tax expenditures are revised every year but not for all historic data. Revisions only go back a couple of years so it is difficult to 

discern which exact year saw a peak in these revenue loses. In constant dollars it appears that they peaked in the early 1980s. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

220 Energy Information Administration / Appendix C: Historic Perspectives on 

Energy Tax Expenditures 

related to energy amounted to $6.7 billion (2007 dollars) as the value of some programs were reduced or 

allowed to expire altogether. The value of tax expenditures related to the capital gains treatment of 

royalties on coal, the exclusion of interest on State and local industrial development bonds for certain 

energy facilities, the alternative conservation and technology credits, the alternative fuel production credit, 

and the alcohol fuel credit all declined. In addition to the eight electricity-related tax expenditures listed in 

the budget for that year, there was one tax exemption (alcohol fuels tax exemption). 

During the early 1990s, once again, concerns over energy security and the environment led to passage of 

an omnibus energy bill, the Energy Policy Act of 1992 (EPACT 1992) (Public Law 102-486). EPACT 1992 

was the most significant piece of energy legislation since 1980. The tax provisions of EPACT1992 focused 

on providing incentives that encouraged energy efficiency, renewable energy, and alternative fuels. Some 

of these incentives were directed at geothermal, electric vehicles, and solar power. The business tax 

credit (EPACT1992, Section 1916), which had been extended on a year-to-year basis up until 1992, was 

established as a permanent 10- percent business energy tax credit for investments in solar and 

geothermal equipment. Section 1914 of EPACT1992 established a 10-year, 1.5 cents per kilowatthour 

(kWh) production tax credit (PTC) for wind projects (privately-owned and investor-owned) and biomass 

plants using dedicated crops (closed-loop) placed in service between 1994 and 1993, respectively, and 

June 30, 1999.296 

In 1992, the value of all tax expenditures (including the excise tax exemption) was estimated at $2.0 billion 

(2007 dollars). By 1995, the value of tax expenditures (again, including the excise tax exemption) had

risen to $3.9 billion (2007 dollars). Still this was far less than the estimated 1981 value of $13.3 billion 

(2007 dollars) even though the number of energy subsidies had grown from seven to ten. The percentage 

over cost depletion tax expenditure retained its major role in the order of tax expenditures. However, the 

value of the alternative fuel production credit began to gain prominence. In 1995, at an estimated at $1.2 

billion, this credit accounted for almost one-third of total tax expenditures. 

The 1990s began with the first Persian Gulf War and a brief surge in petroleum prices. However, for the 

remainder of the decade, energy prices remained stable and concerns over energy security were 

diminished. For over a decade, no omnibus energy legislation was passed after EPACT1992. During most 

of the 1990s, the number of energy-related tax expenditures remained the same. However, in dollar 

terms, the Section 29 credit grew considerably, rising from $18 million (2007 dollars) in 1983 to $2.4 billion 

by 2005 (2007 dollars). The value of the Section 29 credit is expected to fall by more than half by 2008 

and then disappear after that as the credit is phased out.297 Largely due to rapidly growing usage of wind to 

supply electricity, the production tax credit, reported by the Treasury under the category “new technology 

credit,” has been the fastest growing major tax expenditure over the last few years. The value of the new 

technology credit is expected to remain strong throughout the remainder of the decade. In 2008, the new 

technology credit is expected to be the second largest tax expenditure and the second largest tax 

expenditure directed toward renewables. 

The Energy Policy Act of 2005 and Other Recently Enacted Energy Tax 

Expenditures 

The Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) and accompanying legislation moved 

the orientation of energy tax expenditures further towards energy efficiency and electricity. EPACT2005 

represented the first major piece of Federal government energy legislation to emerge since the Energy 

Policy Act of 1992 (EPACT1992). The purpose of EPACT2005 was to address several energy issues such 

as America’s growing dependence on imported oil, rising environmental concerns, electricity industry 

restructuring, and the reliability of the Nation’s transmission system. 

EPACT2005 embodied several new energy initiatives as well as expanding on several tax expenditures already 

on the books. Mainly as a result of EPACT2005 and accompanying legislation, there were 38 tax expenditure 

programs listed in the U.S. budget in 2007 versus 11 in the 1999 budget. Those tax expenditures aimed at 

 

296Closed-looped biomass consist of crops grown, in a sustainable manner, for the sole purpose of bioenergy and bioproduct uses, 

which might include annual crops, such as corn and wheat, perennial crops, such as trees and shrubs, and grasses, such as 

switchgrass. Open-looped biomass is biomass that can be used to produce energy even though it was not grown specifically for 

this purpose. Examples of open-loop biomass include agricultural livestock waste and residues from forest harvesting operations 

and crop harvesting. 

297 The current primary recipient of the fuel, synthetic coal, loses its eligibility after January 1, 2008. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

Energy Information Administration / Appendix C: Historic Perspectives on 221 

Energy Tax Expenditures 

 

energy production totaled $10.4 billion (2007 dollars) in fiscal year (FY) 2007, a substantial rise from $4.8 billion 

(2007 dollars) in 2004, the year prior to passage of EPACT2005. EPACT2005 was intended to double the use 

of biofuels. EPACT2005 also added a number of measures that encouraged households and businesses to 

engage in greater conservation efforts. 

EPACT2005 contained several provisions for alternative fuels and advanced technologies. The 

expenditures focused on achieving greater end-use energy efficiency are, however, short-lived or of 

relatively small monetary value. Due to EPACT2005, nuclear power for the first time became a beneficiary 

of future Federal tax expenditures. The production tax credits (PTC) allocated towards nuclear as a result 

of EPACT2005 are substantial. The PTCs target the construction of “new technology” nuclear plants. The

owners of eligible plants will receive a 1.8-cents-per-kilowatthour credit. The credit is in effect for the first 8 

years of plant operation. The Treasury Department has not projected the value of this expenditure 

because it anticipates no new eligible plants in commercial operation within its current forecast horizon, 

which runs through 2012. EIA’s Annual Energy Outlook 2008 forecasts that 16,600 megawatts of new 

capacity will be added by 2030. Section 638 of EPACT2005 provided an insurance program, “standby 

support,” which provides up to $500 million to defer costs resulting from construction delays for the first 

two reactors and $250 million for the next four reactors. 

By one estimate, EPACT2005 provided for about $14.5 billion in tax expenditures over an 11-year 

period.298 Of this amount, $4.5 billion was allocated to renewables, $3 billion to coal, $3 billion to electricity, 

and $2.6 billion to oil and natural gas.299 EPACT2005 places a considerable emphasis on renewable 

energy.300

Other legislation enacted contemporaneously with EPACT2005 also had a noteworthy impact upon 

energy-related tax expenditures. The Job Creation and Worker Assistance Act of 2002 (Public Law 107-

147) extended the PTC through 2003 in March 2002. The PTC expired at the end of 2003 and lapsed until 

October 2004. It was extended through the end of 2005 by Section 313 of the Working Families Tax 

Relief Act of 2004 (Public Law 108-311). Section 710 of the American Jobs Creation Act of 2004 (Public

Law 108-357) expanded the PTC to include open-loop biomass, geothermal energy, solar energy, small 

irrigation power, and municipal solid waste (landfill gas and trash combustion facilities). 

Section 909 American Jobs Creation Act of 2004 also included provisions, which for the first time, 

addressed investment incentives for expanding Nation’s transmission grid. Although not an omnibus 

piece of energy-related tax legislation, the AJCA had a significant number of energy measures, the value 

of which is estimated at $5 billion.301 The law amended the Internal Revenue Code to permit taxpayers to 

realize a gain from investments in qualifying electric transmission transactions ratably over an 8-year 

period if the gain from the sale is reinvested in certain exempt utility property. The law defined "qualifying 

electric transmission transaction" as the sale or other disposition before January 1, 2007, to an 

independent transmission company of: (1) property used in the trade or business of providing electric 

transmission services, or (2) any stock or partnership interest in such a trade. Section 1305 of EPACT

2005, extended the special tax treatment of capital through December 30, 2007. 

In 2007, Congress also scaled back some of tax expenditures benefiting the oil and natural gas industry 

and to use the funds to promote renewable energy and energy efficiency. Title I of the Clean Energy Act of 

2007 would have reduced oil and natural gas tax expenditures by $7.6 billion between 2007 and 2017.302 

These provisions were not included in the Energy Independence and Security Act of 2007 (Public Law 

110-140). 

 

298 Congressional Research Service, Energy Policy Act of 2005: Summary and Analysis of Enacted Provisions, (Order Code 

RL33302) (Washington, DC, March 8, 2006), p. 3. 

299 Congressional Research Service, Energy Policy Act of 2005: Summary and Analysis of Enacted Provisions, (Order Code 

RL33302) (Washington, DC, March 8, 2006), p. 3. 

300 Ibid. 

301 Congressional Research Service, CRS Report for Congress, Energy Tax Policy: History and Current Issues, (Order Code: 

RL33578) (Washington, DC, November 7, 2007), p. 11.

302 Congressional Budget Office, H.R. 6, Clean Energy Act of 2007, Letter to Congressman Rahall, Chairman of the Committee on 

Natural Resources, January, 2007. Estimates were provided by the Joint Committee on Taxation. 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

222 Energy Information Administration / Appendix C: Historic Perspectives on 

Energy Tax Expenditures 

Synthetic Fuels Corporation 

Oil shale has long been used as a fuel source for naval vessels. In the early 20th century, three oil major 

oil shale reserve deposits were dedicated for naval use. The United States has the largest know oil shale 

deposits. Most oil shale deposits lie in Colorado, Utah, and Wyoming. The United States is estimated to 

have as much as 1.8 trillion barrels of oil shale, although not all of that is currently treated as an

economically-recoverable fuel.303 One midpoint range of recoverable reserves estimates indicates that the 

United States has more than triple the proven reserves of Saudi Arabia.304 Although a relic of the past, the 

long defunct Synthetic Fuels Corporation (SFC) bears mentioning in this report because at one time it was 

intended to be the largest direct expenditure program in the Nation’s history outside of wartime. Direct 

Federal spending on energy-related projects totaled $2 billion in 2007. Relative to spending during the last 

oil price spike during the late 1970s and early 1980s, this value looks quite moderate. The SFC was 

established as a government agency in the midst of the second oil price shock by the Energy Security Act 

of 1980 (Public Law 96-294). In 1981, crude oil prices reached roughly $37 per barrel (or $73 per barrel in 

2007 dollars)305 with widespread expectations that they were destined to go much higher. The SFC was 

abolished under the Consolidated Omnibus Budget Reconciliation Act (Public Law 99-272) in 1986, when 

oil prices declined to near-record lows. At one point, Congress and the President were negotiating 

spending a possible $88 billion on the program. In 1979, the Interior Department and Appropriation Act

(Public Law 96-126) and the Supplemental Appropriations Act (Public Law 96-304) budgeted $18 billion 

($42 billion in 2007 dollars) in financial incentives. By the time the program was terminated, total spending 

was estimated at $8 billion. The Windfall Profit Tax of 1980 provided funding for the SFC which was 

directed to develop synthetic gas, liquids from tar sands, coal, and shale. 

The intention was for the SFC to team with private sector entities to eventually develop 0.5 million barrels 

of oil equivalent a day by 1987 and 2 million barrels by 1992. In essence, the SFC was to be an 

independent Federal entity, which was to function as an investment bank. Before being legislated out of 

existence, SFC funded four projects with long-term price guarantees. A Congressional Research Service 

report released in 1983 described the endeavor: “the Federal government and U.S. industry are 

embarking on the largest and most intensive effort ever undertaken to increase the production of 

synfuels...”306

Oil shale is currently eligible for a couple of tax credits in the form of the percentage depletion and the 

Section 29 credit discussed above. The Section 29 credit grew out of the Windfall Profit Tax of 1980 which 

occurred around the time of the genesis of the SFC. EPACT2005 showed renewed interest in oil shale 

declaring that “the development of oil shale, tar sands, and other strategic unconventional fuels are 

strategically important domestic resources that should be developed to reduce the growing dependence of 

the United States on politically and economically unstable sources of foreign oil imports.” 307To that end, 

EPACT2005 called for the development of a leasing of Federally-owned lands. The Secretary of the 

Interior is directed to make land in the states of Colorado, Utah, and Wyoming available for research and 

development activities to develop technologies capable of recovering liquid fuels from oil shale. For the 

 

303 Congressional Research Service, Oil Shale: History, Incentives, and Policy, (Order Code RL33359) (Washington, DC, April, 

2006), Summary. 

304 Bartis, James, T, et al, “Oil Shale in the United States, Prospects and Policy Issues,” Rand Corporation, ISBN 0-8330-3848-6, 

Prepared for the Department of Energy’s National Energy Technology Laboratory, 2005. This study estimated that the price of lowsulfur, light crude oil, such as Texas intermediate, would need to be at least $75 to $95 per barrel for a first-of-a-kind oil shale 

operation to be profitable. 

305 Prices are the average U.S. wellhead price. Source: Energy Information Administration, Annual Energy Review 2006 (DOE/EIA0384 (2006) (Washington, DC, June 2007), Table 5.18

306 Congressional Research Service, Synthetic Fuels Corporation and National Synfuels Policy (Issue Brief Number IB81139) 

(Washington, DC, February, 1983), p. 1. 

307 Section 369, Energy Policy Act 2005, Public Law 109-58. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

Energy Information Administration / Appendix C: Historic Perspectives on 223 

Energy Tax Expenditures 

 

first 10 years, the royalty rate will be set at 1 to 3 percent of the value of gross production with States 

receiving half the value. The Mineral Leasing Act of 1920 (MLA) authorized the leasing of land for 

developing deposits of coal, phosphates, petroleum, natural gas and other minerals. MLA limited the size 

of a lease tract to 5,120 acres with the further restriction of preventing any corporation or individual from 

obtaining any more than one lease. Section 369 of EPACT 2005 increased the size of a lease tract to 

5,760 acres, and allowed an individual to obtain up to 50,000 acres of oil shale leases in any one State. 
 
Appendix D 

Description of 

Bond Ratings 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

226 Energy Information Administration / Appendix D: Description of Bond Ratings 

This appendix consists of a description of the various bond ratings used by bond-rating firm of 

Moody’s Investor Services. The information was obtained from the State Treasury Office of the 

State of California. 

Moody's - Definitions of Bond Ratings 

Long-Term Issue Credit Ratings 

Aaa Bonds that are rated Aaa are judged to be of the best quality. They carry the smallest degree of 

investment risk and are generally referred to as "gilt edge." Interest payments are protected by a 

large or by an exceptionally stable margin and principal is secure. While the various protective 

elements are likely to change, such changes as can be visualized are most unlikely to impair the 

fundamentally strong position of such issues. 

Aa Bonds rated Aa are judged to be of high quality by all standards. Together with the Aaa group 

they comprise what are generally known as high grade bonds. They are rated lower than best 

bonds because margins of protection may not be as large as for Aaa securities, fluctuation of 

protective elements may be of greater amplitude, or there may be other elements present that 

make the long-term risks appear somewhat larger than in Aaa securities. 

A Bonds that are rated A possess many favorable investment attributes and are to be considered as 

upper medium grade obligations. Factors giving security to principal and interest are considered 

adequate, but elements may be present that suggest a susceptibility to impairment some time in 

the future. 

Baa Bonds that are rated Baa are considered as medium grade obligations, i.e., they are neither 

highly protected nor poorly secured. Interest payments and principal security appear adequate for 

the present but certain protective elements may be lacking or may be characteristically unreliable 

over any great length of time. Such bonds lack outstanding investment characteristics and in fact 

have speculative characteristics as well. 

Ba Bonds that are rated Ba are judged to have speculative elements; their future cannot be 

considered as well assured. Often the protection of interest and principal payments may be very 

moderate, and thereby not well safeguarded during both good and bad times over the future. 

Uncertainty of position characterizes bonds in this class. 

B Bonds that are rated B generally lack characteristics of the desirable investment. Assurance of 

interest and principal payments or maintenance of other terms of the contract over any long 

period of time may be small. 

Caa Bonds that are rated Caa are of poor standing. Such issues may be in default or there may be 

present elements of danger with respect to principal or interest. 

Ca Bonds that are rated Ca represent obligations that are speculative in a high degree. Such issues 

are often in default or have other marked shortcomings. 

C Bonds that are rated C are the lowest rated class of bonds, and issues so rated can be regarded 

as having extremely poor prospects of ever attaining any real investment standing. 

NOTE: Since October 1996, Moody's has applied numerical modifiers 1, 2, and 3 in each generic rating classification 

from Aa to B. (see Moody's Expanded Public Finance Rating Symbols chart below). The modifier 1 indicates that the 

issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking, and the 

modifier 3 indicates that the issue ranks in the lower end of its generic category. 

Source: State of California, State Treasurers Office: http://www.treasurer.ca.gov/ratings/moodys.asp, accessed 

October 11, 2007. 
Appendix E 

Types of Loans 

Available 

Through the 

Rural Utilities 

Service 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

228 Energy Information Administration / Appendix E: Types of Loans 

 Available Through the Rural Utilities Service 

Hardship Loans 

Eligible Facilities: Distribution, subtransmission, and headquarters (service & warehouse) 

facilities 

Eligible Borrowers: Retail providers that meet rate disparity thresholds and whose consumers 

fall below average per capita and household income thresholds or that have suffered a severe, 

unavoidable hardship, such as a natural disaster, as determined by the RUS Administrator 

Interest Rate: 5 percent 

Supplemental Financing Required: No 

Loan Term: Term of loan not to exceed useful life of the facilities being financed, with a 

maximum term of 35 years. 

Municipal Rate Loans 

Eligible Facilities: Distribution, subtransmission, and headquarters (service & warehouse) 

facilities 

Eligible Borrowers: Retail providers for all facilities; power supply providers for subtransmission 

and headquarters facilities 

Interest Rate: Interest rates will be established quarterly by RUS based on interest rates available 

in the municipal bond market for similar maturities and is determined at the time of the advance 

Supplemental Financing Required: Yes, generally 30 percent, except in the case of financial 

hardship as determined by the RUS Administrator and the first loan following a merger or 

consolidation 

Loan Term: Term of loan not to exceed useful life of the facilities being financed, with a 

maximum term of 35 years. Power supply borrowers' loan term is also based on the term of its 

wholesale power contracts. 

Treasury Rate Loans 

Eligible Facilities: Distribution, subtransmission, headquarters (service & warehouse), and 

renewable generation facilities 

Eligible Borrowers: Retail providers for all facilities; power supply providers for renewable 

generation facilities 

Interest Rate: Interest rates will be established daily by the United States Treasury and is 

determined at the time of each advance 

Supplemental Financing Required: No 

Loan Term: Term of loan not to exceed useful life of the facilities being financed, with a 

maximum term of 35 years. Power supply borrowers' loan term is also based on the term of its 

wholesale power contracts. 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration/ Appendix E: Type of Loans 229 

Available Through the Rural Utilities Service 

FFB Guaranteed Loans 

Eligible Facilities: Distribution, transmission (bulk and subtransmission), generation, and 

headquarters (office, service and warehouse) facilities 

Eligible Borrowers: Retail and power supply providers 

Interest Rate: Interest rates will be established daily by the United States Treasury. Added to that 

rate is one-eight of 1 percent. The interest rate is determined at the time of each advance 

Supplemental Financing Required: No 

Loan Term: Term of loan not to exceed useful life of the facilities being financed, with a 

maximum term of 35 years. Power supply borrowers' loan term is also based on the term of its 

wholesale power contracts. 

Eligible Borrowers 

Eligible borrowers are corporations, States, territories, and subdivisions and agencies thereof, 

municipalities, people's utility districts, and cooperative, non-profit, limited-dividend, or mutual 

associations that provide retail or power supply service needs in rural areas 

Rates 

Current interest rates for these loan programs may be found on the RUS “Rates” web site 

(http://www.usda.gov/rus/electric/rates.shtml#ffb).

Specific language on loan eligibility and terms can be found in RUS Rules and Regulations 7CFR 

Part 1714 (http://www.usda.gov/rus/electric/fr2002/fr09ap02-01.pdf). Loan policies and application 

procedures can be found in 7CFR Part 1710.” 

Source: Rural Utilities Service: http://www.usda.gov/rus/electric/loans.htm, accessed October 11, 

2007. 

 

Appendix F 

Table of 

Authorizations 

and 

Regulations 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

232 Energy Information Administration / Appendix F: Table of Authorizations and Regulations 

Table of Authorizations and Regulations 

The laws and regulations below provided the legal basis for the programs discussed in this report. 

Public Laws: 

Public Law 72-154 Revenue Act of 1932 

Public Law 73-17 Tennessee Valley Act of 1933 

Public Law 75-329 Bonneville Projects Act 1937 

Public Law 78-534 Flood Control Act of 1944 

Public Law 82-183 Revenue Act of 1951 

Public Law 90-364 Revenue Expenditure Control Act of 1968 

Public Law 91-173 Tax Reform Act of 1969 

Public Law 91-177 Federal Mine Safety and Health Act of 1977 

Public Law 93-344 Congressional Budget Act of 1974 

Public law 93-454 Columbia River Transmission Act of 1974 

Public Law 94-12 Tax Reduction Act of 1975 

Public Law 95-91 Department of Energy Organization Act of 1977 

Public Law 95-227 Black Lung Benefits Revenue Act of 1977 

Public Law 95-618 Energy Tax Act of 1978 

Public Law 96-126 Interior and Related Agencies Appropriation Act of 1980 

Public Law 96-223 Crude Oil Windfall Profits Tax of 1980 

Public Law 96-294 Energy Security Act of 1980 

Public Law 96-304 Supplemental Appropriations Rescission Act of 1980 

Public Law 96-493 Gasohol Competition Act of 1980 

Public Law 96-499 Omnibus Reconciliation Act of 1980 

Public Law 97-35 Low Income Home Energy Act 1981 

Public Law 97-424 Surface Transportation Assistance Act of 1982 

Public Law 97-425 Nuclear Waste Policy Act of 1982 

Public Law 98-369 Deficit Reduction Act of 1984 

Public Law 99-178 Department of Labor, Health and Human Services and Education and Related 

Agencies Appropriation Act of 1986 

Public Law 99-272 Consolidated Omnibus Budget Reconciliation Act of 1986 

Public Law 99-499 Superfund Amendments and Reauthorization Act of 1986 

Public Law 99-510 Tax Reform Act of 1986 

Public Law 99-519 Tax Reform Act of 1986 

Public Law 99-514 Tax Reform Act of 1986 

Public Law 100-494 Alternative Motor Fuels Act of 1988 

Public Law 100-647 Technical Miscellaneous Revenue Act of 1988 

Public Law 101-508 Omnibus Budget Reconciliation Act of 1990 

Public Law 101-549 Clean Air Act Amendments of 1990

Public Law 102-486 Energy Policy Act of 1992 

Public Law 103-66 Omnibus Budget Reconciliation Act of 1993 

Public Law 103-129 Rural Electric Loan Restructuring Act of 1993 

Public Law 103-252 Human Service Amendments Act of 1994 

Public Law 105-34 Taxpayer Relief Act of 1997 

Public Law 105-178 Transportation Equity Act for the 21st Century of 1998 

Public Law 106-51 Emergency Steel Loan Guarantee and Emergency Oil and Gas Guaranteed 

Loan 

Public Law 106-170 Tax Relief Extension Act of 1999

Public Law 106-224 Agricultural Risk Protection Act of 2000 

Public Law 107-171 Farm Security and Rural Investment Act of 2002 

Public Law 107-147 Job Creation and Worker Assistance Act of 2002 
 Federal Financial Interventions and Subsidies in Energy Markets 2007 

 Energy Information Administration / Appendix F: Table of Authorizations and Regulations 233 

Public Law 107-200 Yucca Mountain Development Act of 2002 

Public Law 107-204 Sarbanes-Oxley Act of 2002 

Public Law 108-311 Working Families Tax Relief Act of 2004 

Public Law 108-357 American Jobs Creation Act of 2004 

Public Law 108-447 Consolidated Appropriations Act of 2005 

Public Law 109-58 Energy Policy Act of 2005 

Public Law 109-97 Agricultural, Rural Development, Food and Drug Administration, and Related 

Agencies and Appropriations Act 2006 

Public Law 109-222 Tax Increase Prevention and Reconciliation Act of 2005 

Public Law 109-432 Tax Relief and Health Care Act of 2006 

Public Law 110-5 Revised Continuing Appropriations Act of 2007 

Public Law 110-140 Energy Independence and Security Act of 2007 

United States Codes of Federal Regulations 

7 U.S.C. 901, et seq. 

7 U.S.C. 903 

7 U.S.C. 913 

7 U.S.C. 940c-1 

7 CFR 1714.8 

29 U.S.C. 45(e)(11) 

30 U.S.C. 241 

15 U.S.C. 825s 

16 U.S.C. 8381 

26 U.S.C. 40A 

26 U.S.C. 45H 

2 U.S.C. 661a 

U.S. Internal Revenue Service, Notice 2007-38: 2007-18 I.R.B. 1103, Nonconventional Source 

Fuel Credit, Section 45K Inflation Adjustment Factor and Section 45K Reference Price 

(Washington, DC, April 30, 2007) 

Internal Revenue Service, “Highlights of the Energy Policy Act of 2005 for Individuals,” 

http://www.irs.gov/newsroom/article/0,,id=153397,00.html, accessed October 16, 2007 

Internal Revenue Service, Bulletin 2006-18, http://www.irs.gov/irb/2006-18_IRB/ar06.html, 

accessed October 11, 2007 

Internal Revenue Service Notice 2006-88, issued on September 26, 2006 

IRS Form 8835, “Renewable Electricity, Refined Coal and Indian Coal Production Credit” 

http://www.irs.gov/pub/irs-pdf/f8835.pdf, accessed August 30, 2007 

Appendix G 

Bibliography 
Federal Financial Interventions and Subsidies in Energy Markets 2007 

236 Energy Information Administration / Appendix G: Bibliography 

American Job Creation Act of 2004, Section 339, Pub. L. No. 108-357, 118 Stat. 1481 (codified at 26 U.S.C. 

Section 45H). See also, H.R. Conf. Rept. No. 755, 108th Cong., 2d Sess. at 538-539. 

Ball, J., “TVA Plan Seen by Critics as Unfair Grab for Power,” Wall Street Journal (March 5, 1997). 

Bartis, James, T, et al, “Oil Shale in the United States, Prospects and Policy Issues,” Rand Corporation, 

ISBN 0-8330-3848-6, Prepared for the Department of Energy’s National Energy Technology Laboratory, 

2005. 

Bird, B.M., Platau, S.M. and Warren, A., “Excluding Utility Rebates from Gross Income,” The CPA Journal 

(March 1993), p. 56. 

Bonneville Power Administration, Administrative Billing Procedures: 

http://www.bpa.gov/Power/PSR/pbl_billing_procedures.pdf, accessed October 11, 2007. 

Bonneville Power Administration, BPA fast facts, 

http://www.bpa.gov/corporate/about_BPA/Facts/FactDocs/BPA_Facts_2006.pdf, accessed October 11, 

2007. 

Bonneville Power Administration, BPA Fact Sheet, History of BPA’s Residential Exchange Program, June 

2007: http://www.bpa.gov/corporate/pubs/fact_sheets/07fs/fs061507.pdf, accessed October 11, 2007. 

Bonneville Power Administration, BPA Journal, February 1997, p.3: 

http://www.bpa.gov/corporate/pubs/journal/97jl/jl0297x.pdf, accessed October 11, 2007. 

Bonneville Power Administration, 1998 Annual Report. 

Bonneville Power Administration, 2006 Annual Report. 

Code of Federal Regulations, 7 U.S.C. 903, “Administer the Rural Electrification Act of 1938,” 

http://a257.g.akamaitech.net/7/257/2422/14mar20010800/edocket.access.gpo.gov/cfr_2003/7cfr2.47.htm. 

Code of Federal Regulations, 7 CFR 1714.8, “Hardship rate loans,” http://law.justia.com/us/cfr/title07/07-

11.1.2.1.5.1.2.8.html. 

Bureau of Reclamation, The History of Hydropower Development in the United States, 

http://www.usbr.gov/power/history.html, accessed March 12, 2008. 

California Energy Commission, Ethanol Fuel Incentives Applied in the U.S., P600-04-001, January 2004). 

Congressional Budget Office, Tax Expenditures: Current Issues and Five-Year Budget Projections for Fiscal 

Years 1982-1986, (Washington DC, September 1981). 

Congressional Budget Office, Government-Sponsored Enterprises and Their Implicit Government Subsidy: 

The Case of Sallie Mae, (Washington, DC, December 1985). 

Congressional Budget Office, The Effects of Tax Reform on Tax Expenditures, (Washington, DC, March 

1988). 

Congressional Budget Office, Tax Expenditures: Current Issues and Five-Year Budget Projections for 

Fiscal Years 1982-1986. 

Congressional Budget Office, The President’s Fiscal Year 1979 Tax Expenditure Proposals, (Washington, 

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Appendix H 

Letter from 

Senator Lamar Alexander
Federal Financial Interventions and Subsidies in Energy Markets 2007 

254 Energy Information Administration / Appendix H: Letter from Senator Lamar Alexander