SR/OIAF/2007-05

Energy and Economic Impacts

of Implementing Both a 25-Percent

Renewable Portfolio Standard and a 25-

Percent Renewable Fuel Standard by 2025

August 2007

Energy Information Administration

Office of Integrated Analysis and Forecasting

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 any other organization. Service

Reports are prepared by the Energy Information Administration upon special request and are

based on assumptions specified by the requester.

 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 iii

Preface

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.

The projections in this report are not statements of what will happen but of what might

happen, given the assumptions and methodologies used. The reference case projections are

business-as-usual trend forecasts, given known technology, technological and demographic

trends, and current laws and regulations. Thus, they provide a policy-neutral starting point

that can be used to analyze policy initiatives. EIA does not propose, advocate, or speculate

on future legislative and regulatory changes. All laws are assumed to remain as currently

enacted; however, the impacts of scheduled regulatory changes, when defined, are reflected.
iv Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Contacts

The Office of Integrated Analysis and Forecasting prepared this report. General questions

concerning the report can be directed to John J. Conti (john.conti@eia.doe.gov, 202/586-

2222), Director of the Office of Integrated Analysis and Forecasting, and Andy S. Kydes

(akydes@eia.doe.gov, 202/586-0883), Senior Technical Advisor to the Office. Specific

questions about the report can be directed to the following analysts:

Renewable Portfolio Standard ...... Chris Namovicz (cnamovicz@eia.doe.gov, 202/586-2025)

Macroeconomic Analysis ............. Kay Smith (kay.smith@eia.doe.gov, 202/586-1132)

Residential and Commercial......... Erin Boedecker (erin.boedecker@eia.doe.gov, 202/586-4791)

Industrial...................................... T. Crawford Honeycutt (choneycu@eia.doe.gov, 202/586-1420)

Transportation.............................. John D. Maples (john.maples@eia.doe.gov, 202/586-1757)

Electricity .................................... Jeffrey Jones (jeffrey.jones@eia.doe.gov, 202/586-2038)

Biomass Resources ...................... Robert Smith (rsmith@eia.doe.gov, 202/586-9413)

Renewable Fuels Resources ......... Anthony Radich (aradich@eia.doe.gov, 202/586-0504)

Renewable Fuel Standard............. William Brown (wbrown@eia.doe.gov, 202/596-8181)

Refinery Operations ..................... William Brown (wbrown@eia.doe.gov, 202/586-8181)

Oil and Natural Gas Supply.......... Philip M. Budzik (pbudzik@eia.doe.gov, 202/586-2847)

Coal ............................................. Michael Mellish (michael.mellish@eia.doe.gov, 202/586-2136)

Additional staff who contributed significantly to the analysis include: Alan Beamon, Paul

Holtberg, Paul Kondis, Michael Schaal, and Peter Whitman.

For ordering information and questions on other energy statistics available from EIA, please

contact EIA’s National Energy Information Center at:

National Energy Information Center, EI 30

Energy Information Administration

Forrestal Building

Washington, DC 20585

Telephone: 202/586-8800

TTY: 202/586-1181

FAX: 202/586-0727

E-mail: infoctr@eia.doe.gov

World Wide Web Site: http://www.eia.doe.gov/

FTP Site: ftp://ftp.eia.doe.gov/
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 v

Contents

Executive Summary .........................................................................................................ix

1. Background and Scope of the Analysis.........................................................................1

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

Proposal Summary ..........................................................................................................1

General Methodology......................................................................................................2

Sensitivity Cases .............................................................................................................2

2. Analytical Issues ............................................................................................................5

Infrastructure, Market, and Technology Concerns............................................................5

Other Concerns and Uncertainties....................................................................................9

Uncertainties in the Reference Case...............................................................................10

3. Energy Market Impacts of the Renewable Policy Proposal.......................................11

Electricity Sector Impacts..............................................................................................11

End-Use Energy Consumption.......................................................................................17

End-Use Carbon Dioxide Emissions..............................................................................24

Primary Energy Impacts ................................................................................................25

Fuel Supply Impacts......................................................................................................26

Economic Impacts .........................................................................................................36

4. Alternative Cases.........................................................................................................41

Measuring and Interpreting the Relative Impacts of the Policy.......................................42

Electricity Sector Impacts..............................................................................................43

Transportation Sector Impacts .......................................................................................47

Primary Energy Consumption........................................................................................49

Fuel Supplies.................................................................................................................49

Economic Impacts .........................................................................................................54

Appendix A. Request Letters..........................................................................................61

Appendix B. Key Updates and Changes to the AEO2007 Reference Case

 Assumptions ...............................................................................................67
vi Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Tables

 1. Analysis Cases ..............................................................................................................3

 2. Selected Electric Power Results, 2025 and 2030 ..........................................................12

 3. Transportation Sector Key Indicators and Delivered Energy Consumption ..................23

 4. Carbon Dioxide Emissions by End-Use Sector ............................................................24

 5. Liquid Fuels Supply Impacts of the Reference and Policy Cases..................................29

 6. Renewable Fuels Summary for the Reference and Policy Cases...................................30

 7. Natural Gas Consumption by Sector, 2030 ..................................................................35

 8. Natural Gas Supply by Source, 2030 ...........................................................................35

 9. Economic Impacts, Policy Case...................................................................................37

10. Summary of Electricity Sector Impacts of Alternative Policy Cases, 2025 ...................44

11. Transportation Sector Key Indicators and Delivered Energy Consumption, 2025.........47

12. Liquid Fuels Supply Impacts in Alternative Policy Cases, 2025...................................48

13. Renewable Fuels Summary for the Reference and Policy Cases, 2025 .........................50

14. Summary of Economic Impacts of Alternative Policy Cases in 2025 ...........................55

15. Summary of Energy Impacts of Alternative Policy Cases in 2025................................57
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 vii

Figures

 1. Renewable Portfolio Standard Credit Price, Policy Case..............................................13

 2. Comparison of RFS and RPS Credit Prices in Common Units, Policy Case .................13

 3. Renewable Generation Capacity, Reference and Policy Cases .....................................15

 4. Renewable Generation, Reference and Policy Cases....................................................15

 5. Electricity Prices, Reference and Policy Cases.............................................................17

 6. Delivered Residential Energy Consumption, Reference and Policy Cases....................18

 7. Delivered Commercial Energy Consumption, Reference and Policy Cases ..................18

 8. Industrial Energy Consumption, Reference and Policy Cases.......................................20

 9. Transportation Energy Consumption, Reference and Policy Cases...............................21

10. Minimum Requirements for New Dual-Fuel Light-Duty Vehicle Manufacturing

and E85 Fuel Availability, Policy Case......................................................................22

11. Carbon Dioxide Emissions by End-Use Sector, Reference and Policy Cases................25

12. Primary Fuel Consumption, Reference and Policy Cases .............................................26

13. Composition of the U.S. Gasoline Pool, Reference and Policy Cases...........................27

14. Sources of Renewable Liquid Fuel Supply, Reference and Policy Cases......................29

15. Imports as Percent of Liquid Fuel Products Supplied, Reference and Policy Cases ......31

16. Coal Production by Region, Reference and Policy Cases .............................................36

17. Consumer and Producer Prices, Policy Case ................................................................37

18. Real GDP and Consumption Impacts, Policy Case.......................................................38

19. Industrial Impacts, Policy Case....................................................................................39

20. RPS Credit Prices in Alternative Policy Cases .............................................................45

21. Electricity Prices in Alternative Policy Cases, 2025 and 2030......................................46

22. Renewable Generation in 2025 in Alternative Cases....................................................46

23. Change in Primary Energy Consumption Across the Cases, 2025 and 2030 .................49

24. Sources of Renewable Fuel Supply in Alternative Cases, 2025 ....................................52

25. Consumer Price Impacts in the Policy Cases................................................................58

26. Wholesale Price Impacts in the Policy Cases ...............................................................58

27. GDP Impacts in the Policy Cases.................................................................................59

28. Consumption Impacts in the Policy Cases....................................................................59

B1. AEO2007 Reference Case and High Yield Biomass Supply Curves, 2030...................69

 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 ix

Executive Summary

Background

This report responds to a request by Senator James Inhofe for analysis of a

“25-by-25” proposal that combines a requirement that a 25-percent share of electricity sales

be produced from renewable sources by 2025 with a requirement that a 25-percent share of

liquid motor transportation fuel sales also be derived from renewable sources by 2025. The

electricity requirement is implemented as a renewable portfolio standard (RPS), while the

motor fuel standard is implemented as a renewable fuel standard (RFS).

The RPS establishes a market for renewable energy credits, which will be created by the

generation of electricity from qualified renewable generators (e.g., wind, geothermal,

biomass, and solar). Electricity retailers must hold RPS credits in proportion to the amount

of electricity they sell. Electricity providers can generate their own renewable electricity or

trade renewable electricity credits to assure compliance. Similarly, the RFS establishes a

market for renewable fuel credits, based on the amount of ethanol or other biofuels sold for

motor transportation. Transportation fuel providers must hold RFS credits in proportion to

the amount of motor transportation fuels they sell.

This study compares a Policy Case incorporating the 25-by-25 proposal to an updated

version of the Reference Case from the Energy Information Administration’s (EIA’s)

Annual Energy Outlook 2007 (AEO2007).1 Revisions to the Reference Case for this analysis

included: expiration of existing ethanol tax credits and tariffs as currently scheduled by law;

updates to supply curves for domestic biomass and corn resources; inclusion of offshore

wind technology; and updates of the potential for ethanol imports from Brazil.

Analysis Issues

All long-term projections contain considerable uncertainty. This analysis suggests that, to

comply with the twin 25-by-25 mandates, it will be necessary for electricity and motor fuel

producers to dramatically increase their use of technologies that play a relatively small role

in today’s energy markets. For example, the amount of qualifying renewable generation

needed to comply with the RPS would require almost a 13-fold increase in nonhydropower

renewable generation from 2005 levels by 2025. Similarly, the amount of ethanol and

biodiesel needed to comply with the RFS would require more than a 12-fold increase from

2005 levels.

Big changes in the energy system, especially when implemented quickly, come with

numerous uncertainties, the impacts of which may not be fully captured in this study. For

example, compliance with the twin 25-by-25 mandates would require successful

development and rapid deployment of new technologies, such as biomass gasification

power plants and cellulosic ethanol plants, that currently are not commercially available.

Policy case results are very sensitive to assumptions made regarding the cost and

1Energy Information Administration, Annual Energy Outlook 2007, DOE/EIA-0838(2007) (Washington, DC,

February 2002), web site http://www.eia.doe.gov/oiaf/aeo/index.html.
x Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

availability of key technologies. Even current technologies, such as wind power, engender

significant uncertainties. Once the most economical wind resources are utilized, less

attractive resources would have to be developed, with costs that are not well understood.

While a strong push for renewable energy technologies could lead to significant reductions

in their costs through breakthroughs or learning, it is also possible that costly hurdles—such

as resistance to the siting of new plants, higher than expected transmission interconnection

costs, and fuel supply limits—could arise, limiting the development and deployment of

renewable energy technologies, and making the proposed mandates much more disruptive

and possibly unattainable.

The large increases in bioenergy resources, including corn and other energy crops, that

would be needed to comply with the 25-percent RPS and RFS requirements could have

significant impacts on agricultural markets and put upward pressure on food and feed prices

worldwide. While very rapid improvements in crop yields could limit such pressures, there

is considerable uncertainty about the potential for and timing of such improvements. The

RFS would also require rapid market penetration of Flex Fuel Vehicles (FFVs) and

development of the infrastructure needed to deliver E85 and biodiesel to consumers. As

requested, this study assumes that the Senate Bill 23 (S.23) provisions requiring the sale of

FFVs and installation of E85 pumps would be put in place.

In addition to technological uncertainties, the Policy Case implies structural changes in the

U.S. economy that are not readily apparent from the aggregate impacts on gross domestic

product (GDP) or energy prices. Implementation of the proposed RFS policy is likely to

involve a major realignment of current capital investment plans and strategies for refiners,

automotive manufacturers, and others. For example, substantial capital investment would be

needed to put the E85 infrastructure in place to meet the requirements under the RFS policy.

The results of this analysis also suggest that the 25-percent requirement for renewable

motor fuel use would significantly increase the use of corn in ethanol production, leading to

sharply higher corn prices, substantial changes in domestic feed practices, and large cuts in

or elimination of corn exports. The uncertainties inherent in implementing this policy

suggest that, while not impossible, it would be very challenging and carry substantial risk.

Key Results

Electricity Sector Impacts

The RPS causes a dramatic shift away from coal and natural gas to renewable fuels,

particularly biomass and wind.

• Coal-fired electricity generation in the Policy Case is 938 billion kilowatthours (28

percent) lower in 2030 than in the Reference Case. Natural-gas-fired generation is 99

billion kilowatthours (11 percent) lower in 2030. Generation from nuclear power is 80

billion kilowatthours (9 percent) lower in 2030.

• In the Policy Case, biomass generation is 495 billion kilowatthours (363 percent)

higher in 2030 than in the Reference Case, while wind generation is 424 billion
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 xi

kilowatthours (824 percent) higher. To reach the generation levels in the Policy Case,

biomass and wind capacity grow to more than 10 times their current levels.

• To comply with a 25-percent RPS, almost 70 percent of the generating capacity added

from 2005 to 2025 would have to be renewable technologies—amounting to more than

a 10-fold increase in nonhydroelectric renewable capacity over this period.

The RPS credit price and the growing dependence on higher-cost renewables lead to higher

electricity prices and higher consumer electricity bills, particularly in 2025 and beyond.

• Average retail electricity prices are 6.2 percent (0.5 cents per kilowatthour in 2005

dollars2) higher in the Policy Case than in the Reference Case in 2030. The RPS credit

price generally increases through 2025, when the maximum required share for

renewable generation is initially imposed. From 2025 to 2030, the RPS credit price is

projected to vary between 3.8 and 4.8 cents per kilowatthour.

• In the Policy Case, annual consumer expenditures on electricity are very close to those

in the Reference Case through 2022, as the reduction in fuel prices caused by lower

fossil fuel use for electric power generation outweighs the increased capital costs of

new renewable generation capacity. After 2023, the net capital investment costs of

meeting the RPS and the higher renewable fuel costs outweigh the changes in fossil

fuel prices, and electricity expenditures are higher than in the Reference Case.

Consumer expenditures for electricity in the Policy Case are $16 billion (3.9 percent)

higher in 2030; however, the higher electricity bills are partially offset by lower

natural gas bills.

• Cumulative (undiscounted) expenditures for electricity for the period 2009-2030 are

about $65 billion (about 0.8 percent) higher than in the Reference Case, while

cumulative discounted expenditures are $15 billion (0.4 percent) higher.

Liquid Fuels and Transportation Sector Impacts

The RFS mandate results in dramatic increases in biofuels consumption and reduced

consumption of petroleum-based fuels.

• To meet the RFS requirements in the Policy Case, ethanol production increases more

than 4-fold over production in the Reference Case in 2025. In the Policy Case, about

30 billion gallons of ethanol is sold in 2020, 61 billion gallons in 2025, and 66 billion

gallons in 2030. In the Reference Case, only 11 billion gallons of ethanol is sold in

2020, 13 billion gallons in 2025, and 16 billion gallons in 2030.

• In 2025, the E85 share of the gasoline pool is over 30 percent in the Policy case,

compared to less than 1 percent in the Reference Case.3 Such a shift would require

2

 All energy price and expenditure values in this report are in 2005 dollars.

3E85 contains approximately 75 percent ethanol and 25 percent gasoline. E85 consumption in 2025 is 4.3

million barrels per day, and the total gasoline pool is 12.87 million barrels per day.
xii Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

massive investment to ensure that vehicles and delivery and refueling infrastructure are

in place to meet the needs of the market.

• Corn-based ethanol production in the Policy Case increases to about 25.5 billion

gallons in 2025 and 2030, almost triple the 9.0 billion gallons produced from corn in

the Reference Case in 2025. In the Reference Case, corn-based ethanol production

increases to nearly 12 billion gallons in 2030.

• Cellulosic ethanol technology is assumed to become commercially available in 2010,

but the relatively high capital costs of cellulosic ethanol plants is initially a significant

barrier to its adoption. After 2015, with RFS credit prices and corn prices rising in the

Policy Case, cellulosic ethanol becomes more economical, and production grows to

about 8 billion gallons in 2020, 28 billion gallons in 2025, and more than 31 billion

gallons in 2030.

• Increased ethanol imports meet part of the high biofuel requirement of the proposed

RFS policy. In the Policy Case, ethanol imports grow to 8 billion gallons (137 percent

more than in the Reference Case) in 2025 and 9 billion gallons (158 percent more than

in the Reference Case) in 2030.

• Consumption of petroleum products4 is significantly reduced. Relative to the

Reference Case, nonrenewable liquid fuel use is about 2.3 quadrillion Btu (5 percent)

lower in 2020, 5.3 quadrillion Btu (11 percent) lower in 2025, and 6.0 quadrillion Btu

(12 percent) lower in 2030. The RFS mandate increases transportation energy prices

and consumer expenditures for transportation fuels.

• The projected retail price of gasoline in the Policy Case increases by about 10 cents per

gallon (5 percent) in 2020, 28 cents (13 percent) in 2025, and 24 cents (11 percent) in

2030 relative to Reference Case prices. Diesel fuel price increases are somewhat

greater than those for gasoline, because production of biodiesel is not large enough to

affect the price of diesel imports.

• Consumer expenditures on liquid transportation fuels increase by $28 billion (about 5.4

percent) in 2020 and about $50 billion (8 percent) in 2030 in the Policy Case relative

to the Reference Case.

• Cumulative undiscounted transportation energy expenditures by consumers from 2009

to 2030 are about $562 billion higher in the Policy Case than in the Reference Case.

Cumulative discounted expenditures over the same period are $193 billion higher in

the Policy Case than in the Reference Case.

• The RFS credit price, which reflects the payment above market value that is required

to bring the marginal gallon of renewable fuel to market in the Policy Case, is $2.18

per gallon in 2025 and falls to $2.02 per gallon in 2030.

4

 Excludes consumption of ethanol and biodiesel.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 xiii

Higher prices contribute to a reduction in transportation demand for liquid motor fuels on

an energy basis.

• Total demand for light-duty vehicle travel is 1.6 percent (62 billion vehicle miles)

lower in 2025 and 2.2 percent (93 billion vehicle miles) lower in 2030 in the Policy

Case than in the Reference Case.

• In the last decade of the projection period, higher fuel prices in the Policy Case cause a

shift in consumer preference from light trucks to cars. By 2030, the shift more than

makes up for the drop in fuel economy resulting from lower sales of hybrid and diesel

vehicles.

• On an energy basis, transportation liquids consumption in 2030 decreases by 2.5

percent, from 38.2 quadrillion Btu in the Reference Case to 37.2 quadrillion Btu in the

Policy Case.

Other Energy Impacts

• Increasing the use of renewable motor fuels leads to higher overall consumption of

primary energy, in part because of the significant use of energy in the conversion from

biomass to ethanol.

• Projected primary energy use from coal, oil, natural gas, and nuclear fuel is reduced

substantially. Compared to the Reference Case, total nonrenewable primary energy use

is nearly 4.8 percent lower in 2020, 7.7 percent lower in 2025, and 8.6 percent lower in

2030 in the Policy Case.

o The reduction in coal, nuclear fuel, and natural gas energy use is primarily driven

by the RPS. In the Policy Case, coal use is 3.1 quadrillion Btu (11 percent) lower

in 2020, 6.1 quadrillion Btu (20 percent) lower in 2025, and 7.8 quadrillion Btu

(23 percent) lower in 2030 than in the Reference Case. Between 2020 and 2030,

the corresponding decrease in natural gas consumption ranges from 1.8 percent to

5.2 percent. The reductions in nuclear power are smaller than 10 percent in all

years.

o The reduction in petroleum consumption and the increase in biofuels consumption

of ethanol and biodiesel are driven by the RFS. Relative to the Reference Case,

petroleum consumption in the Policy Case is 11.4-percent (2.8 million barrels per

day) lower in 2025 and 12.1-percent (3.1 million barrels per day) lower in 2030.

• The demand for net imports of crude oil and petroleum products, is reduced by

approximately 0.8 million barrels per day in 2020, 2.1 million barrels per day in 2025,

and 2.4 million barrels per day in 2030. Domestic crude oil production is minimally

affected in the Policy Case, but refinery gain is reduced due to reduced refining

activity and natural gas liquids production falls with the reduction in natural gas

production resulting primarily from the RPS.

• On the basis of energy content, the RFS credit price in the Policy Case is significantly

higher ($25.80 per million Btu in 2025 and $23.90 per million Btu in 2030) than the
xiv Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

RPS credit price for the electricity sector ($11.20 per million Btu in 2025 and $14.10

per million Btu in 2030). In other words, the difference in cost between renewable

transportation fuels (in this case, ethanol) and fuels that are used for motor fuel

transportation in the Reference Case is larger than the corresponding cost difference in

electricity generation costs.

Greenhouse Gas Emissions Impacts

• Total U.S. energy-related carbon dioxide emissions in the Policy Case are 1,138

million metric tons (14 percent) lower in 2030 than in the Reference Case; however,

they remain 831 million metric tons (14 percent) above 2005 levels. Carbon dioxide

emissions from the U.S. transportation sector are reduced by 370 million metric tons

(14 percent) in 2030, while electricity sector emissions are reduced by 724 million

metric tons (22 percent).

Biomass and Corn Market Impacts

• Biomass consumption for energy uses in the Policy Case rises from less than 30

million tons in 2005 to 571 million tons in 2030, as the power sector and the

transportation sector compete for biomass to meet their respective requirements. This

level of consumption nearly exhausts the biomass supply represented in the Reference

Case, placing upward pressure on biomass prices and raising uncertainty about the

ability of the agricultural sector to provide the amounts of biomass that would be

required in the Policy Case.

• In the Policy Case, the price of biomass rises from approximately $1.70 per million

Btu (roughly $30 per ton) in 2005 to about $5.10 per million Btu (over $88 per ton) in

2030.

• Approximately 9.2 billion bushels of the total 2025 corn production is used to make

ethanol in the Policy Case, up from 3.4 billion bushels in the Reference Case. As a

result, less corn is available for food and feed.

• Corn prices in the Policy Case increase to about $6.50 per bushel in 2025 (compared

with $3.00 per bushel in the Reference Case), then fall to about $6.20 in 2030.

Demand for corn-based ethanol remains flat from 2025 to 2030, because of increased

cellulosic ethanol production.

Economic Impacts

Achieving the 25-percent renewable fuel target in both the electricity generation and

transportation fuel markets leads to higher energy prices, as producers substitute more

expensive renewable fuels for less expensive fossil fuels. Higher energy prices reduce

economic activity.

• Total GDP losses (discounted at a rate of 4 percent) in the Policy Case relative to the

Reference Case over the 2009-2030 period are $296 billion (0.12 percent).
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 xv

• Cumulative discounted losses in consumer expenditures in the Policy Case relative to

the Reference Case over the 2009-2030 period are $149 billion (0.10 percent).

 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 1

1. Background and Scope of the Analysis

Background

This Service Report was prepared by the Energy Information Administration (EIA) in

response to a January 30, 2007, request from Senator James Inhofe.5 Senator Inhofe

requested an analysis of a proposal (referred to as the 25 x 25 Policy Scenario in his letter

request) to achieve a 25-percent renewable portfolio standard (RPS) and a 25-percent

renewable fuel standard (RFS) by 2025. The combined RPS and RFS policy proposal is

referred to as “the Policy” hereafter in the report. Copies of the request letter and a followup letter of clarification are provided in Appendix A.

Proposal Summary

The proposal analyzed in this study has two components: (1) an RPS, which requires that

the percentage of electricity sales produced from renewable sources, excluding existing

hydroelectric generation, must reach 25 percent by 2025; and (2) an RFS, which requires

that the volumetric percentage of the transportation gasoline and diesel fuel market supplied

from renewable resources, in the form of ethanol and biodiesel, must reach 25 percent by

2025 and then grow proportionately with growth in demand for transportation gasoline and

diesel fuel. Each sector (electricity sales and gasoline plus diesel transport fuels) is required

to meet its own target by 2025. Twenty-five percent of electricity sales would be from

renewable generators and 25 percent of gasoline plus diesel fuel sales would be from either

ethanol or biodiesel on a volumetric basis.

A key assumption in both the electricity and transportation sectors is that all tax or other

policy incentives for domestic renewable fuels and ethanol import tariffs in current laws and

regulations are allowed to sunset without extension.

The RPS target in the electricity sector is implemented using a credit trading system, where

the qualifying renewables include:

• Biomass used in dedicated plants or co-fired with other fuels

• Geothermal

• Municipal solid waste (including landfill gas)

• Solar thermal

• Photovoltaic (PV)

• Wind (both onshore and offshore)

• Incremental new hydroelectricity above that existing in 2006.

Further, existing qualifying generators, except existing hydroelectricity, receive credits

under the proposed Policy. The renewable share is expressed as a share of electricity sales

in kilowatthours. The required share is set equal to the share of qualifying renewable

generation sales in 2006 and increases to 25 percent in 2025. Thereafter, it is held at 25

5

In followup communications on February 6, 2007, Senate staff also requested that the import tariff on ethanol

imports be allowed to sunset, as provided under current law.
2 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

percent. All retail electricity sellers are included. RPS credit trading is allowed only within

the electricity sector, and there is no cap on the credit price.

The RFS target for the motor transportation sector is also implemented using tradable

credits, where the qualifying renewable fuels include:

• Corn-based ethanol

• Cellulose-based ethanol

• Biodiesel production from all sources, including animal fats and oil-based beans/seeds.

As with the RPS, existing qualifying sources receive credits. The renewable share is

expressed as a share of all liquids sold in the motor transportation sector that displace either

gasoline or diesel. The required share is set equal to the share of qualifying renewables sold

in 2006 and increases to 25 percent in 2025. Thereafter, it is held at 25 percent. RFS credit

trading is allowed only within the transportation sector, and there is no cap on the credit

price. The existing import tariff on Brazilian ethanol imports (51 cents per gallon) is

allowed to sunset in 2010. Finally, measures that facilitate compliance with the RFS, such

as mandates to produce Flex Fuel Vehicles (FFVs) and the availability of E85 pumps at

gasoline dispensing stations, are assumed as stipulated in Senate Bill 23 (S.23).

General Methodology

In this study, analyses of the energy sector impacts and energy-related economic impacts of

the Policy proposal are based on the Annual Energy Outlook 2007 (AEO2007)

6

 reference

and high price cases, as amended to allow for the additional assumptions and modeling

enhancements necessary to evaluate the proposal. As in the preparation of the Annual

Energy Outlook and most EIA service reports, the National Energy Modeling System

(NEMS) was used to evaluate the impacts of the Policy Case and alternative assumptions.

A number of changes were made in NEMS to address the Policy and to include

enhancements relevant to the analysis. They included changes to the macroeconomic

module to improve the representation of the impact on the entire economy of price increases

for agricultural products, motor fuel, and electricity; changes in the Petroleum Market

Module to ensure convergence of NEMS; and changes to the Renewable Fuels and

Transportation Modules to incorporate the proposal’s mandates. The changes made to the

AEO2007 NEMS are summarized in Appendix B.

Sensitivity Cases

In addition to the four cases requested by Senator Inhofe (Reference, High Price, Policy,

and High Price Policy), four additional cases are provided to illustrate the impacts of higher

availability of ethanol imports and more optimistic assumptions for the cellulosic ethanol

technology: Low-Cost Ethanol Imports, Low-Cost Ethanol Imports Policy, High Renewable

Technology, and High Renewable Technology Policy. The cases analyzed for this request

6Energy Information Administration, Annual Energy Outlook 2007, DOE/EIA-0838(2007) (Washington, DC,

February 2002), web site http://www.eia.doe.gov/oiaf/aeo/index.html.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 3

are shown in Table 1. High Renewable Technology and High Technology are used

interchangeably throughout this text.

Table 1. Analysis Cases

Case Name Description

Reference Case Based on the AEO2007 reference case and updated as described above.

High Price Case Based on the AEO2007 high price case, but includes revisions adopted in

the Reference Case for this study.

Policy Case Based on the Reference Case for this study, but includes revisions to

NEMS modules needed to represent the RPS and RFS policies and

incentives.

High Price Policy

Case

Based on the AEO2007 high price case, but includes revisions adopted in

the Reference Case and Policy Case for this study.

Low-Cost Ethanol

Imports Case

Assumes that prices for U.S. ethanol imports are significantly lower, and

that their availability is greater, than in the Reference Case.

Low-Cost Ethanol

Imports Policy Case

Combines the assumptions from the Low-Cost Ethanol Imports Case with

the Policy Case assumptions.

High Renewable

Technology (High

Technology) Case

Uses the assumptions of the AEO2007 rapid renewable generation

technology assumptions and the rapid cellulosic ethanol technology

progress assumptions with the changes made in the Reference Case for

this study. Cellulosic technology capital costs are assumed to decline to

$186 million per 50-million-gallon-per-year plant in 2015 and remain

constant thereafter. Finally, the “high yield” biomass supply curve was also

assumed for the High Technology Case.

High Renewable

Technology Policy

(High Technology

Policy) Case

Combines the assumptions from the High Renewable Technology Case

with the Policy Case assumptions.

 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 5

2. Analytical Issues

All long-term projections contain considerable uncertainty. It is difficult to foresee how

existing technologies might evolve or what new technologies might emerge as market

conditions change, particularly when those changes are expected to be fairly dramatic. Also,

it is difficult to estimate the extent to which consumers will adopt new technologies. Given

such uncertainties, meeting the Policy mandates—a 25-percent RPS in the electric power

sector and a 25-percent RFS in the motor fuels market by 2025—could be very challenging.

Specifically, the magnitude and pace of infrastructure investments needed, together with

uncertainty about the feasibility, cost, and initial date of commercial availability of

advanced technologies that do not exist today or currently play a very small role, raise

significant concerns. Further, success of the proposed Policy will depend critically on the

passage of future enabling legislation compatible with the S.237 provisions on FFVs and on

the installation of pumps for E85 and biodiesel to make the fuels available to consumers.

Infrastructure, Market, and Technology Concerns

In the electricity sector, the amount of qualifying renewable generation needed to comply

with the RPS of the proposed Policy would require about a13-fold increase over the next 18

years from the current U.S. level of nonhydropower renewable generation. In the

transportation sector, the amounts of ethanol and biodiesel production needed to comply

with the RFS would require more than a 12-fold increase from current levels. While not

impossible, such rapid development would be very challenging, and it would carry

substantial risk.

Infrastructure Concerns

Meeting the 25-percent RPS target could require more than 100 gigawatts of new wind

capacity. Because some of the best wind resources are located in unpopulated areas, distant

from demand load centers, significant investments in transmission infrastructure may be

needed to develop them. In other cases, offshore wind resources could be an attractive

option; and again, new transmission infrastructure would be needed to connect offshore

plants to the grid. Developing the necessary transmission infrastructure to take advantage of

the best wind resources is certainly technically possible; however, costs and public

acceptance are uncertain. For example, recent plans to expand the transmission system

through relatively undeveloped areas have met considerable resistance.

Currently, most biofuel production facilities are located close to corn and soybean acreage

in the Midwest in order to minimize the transportation costs for bulky, unrefined materials.

The facilities are therefore situated far from major consumption centers on the East and

7EIA was asked to adopt two enabling provisions of S.23 as part of the analysis of the Policy proposal. The

first provision requires that light-duty vehicle manufacturers must build and certify vehicles that can use high

ethanol blends (up to 85 percent ethanol) or diesel and biodiesel blends. The second provision requires that 50

percent of all major-owned or branded gasoline stations must provide dispensing facilities for E85 and

biodiesel blends.
6 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

West coasts. Additionally, biofuel production generates large supplemental streams of bulky

co-products with limited marketability.

Further complicating matters is the fact that biodiesel and ethanol cannot be blended at

petroleum refineries and batched through existing pipelines. Ethanol is easily contaminated

by water, and biodiesel dissolves entrained pipeline residues. Consequently, railroad cars

and tanker trucks made from biofuel-compatible materials must be used to transport large

volumes of biofuels to market. Many biofuel producers locate their facilities near dedicated

feedstock supplies or large demand centers in order to minimize transportation costs and

susceptibility to bottlenecks. Still, limited rail and truck capacity has complicated the

delivery of ethanol and contributed to regional ethanol supply shortages and price spikes, as

occurred between April and June 2006.

The potential transportation bottlenecks and costs for the biofuels industry are likely to

become much more problematic with the proposed Policy than they are today. At the 25-

percent RFS level mandated by the Policy, biofuels would significantly penetrate motor

fuels markets across the entire United States. The necessary infrastructure for collecting,

processing, and distributing large volumes of biofuels would have to be expanded or, in

many cases, created. Without substantial infrastructure investment, it would be difficult or

impossible for producers to avoid bottlenecks in the transportation and delivery of biofuels

to market.

There are also other factors that could hamper the distribution of biofuels to end-use

markets. Although E10 (“gasohol”) is readily dispensed throughout the United States, there

are limited numbers of fueling stations for biodiesel and E85—currently, less than 1 percent

of the total number of U.S. vehicle fueling stations. S.23, if passed, would require

approximately 50 percent of “majors and branded” motor fuel dispensing stations (roughly

25 percent of all U.S. fueling stations) to install “high biofuel blend” pumps for E85 and/or

B20.

Recent EIA estimates for replacing one gasoline dispenser and retrofitting existing

equipment to carry E85 at an existing fueling station range from $22,000 to $80,000 (2005

dollars), depending on the scale of the retrofit. By these estimates, the total investment cost

for installation of biofuel pumps would range from about $0.8 billion to about $3 billion. To

recoup the investment costs over a 15-year period, assuming that an E85 pump would

dispense one-half the volume of an average unleaded gasoline pump (about 160,000 gallons

per year), the retail price of E85 would have to be raised by 2 to 7 cents per gallon.

The total infrastructure investment costs that would be required to support the 25-percent

RFS have not been estimated. Further, some of the majors and branded dispensing stations

may choose to sell their less profitable station holdings (they would become unbranded and

non-major owned) to avoid the expense, and that could reduce the availability of E85

dispensing stations to consumers, making market acceptance of E85 slower.

Market Concerns

Market concerns arise both from the uncertainty inherent in petroleum and agricultural

markets and from the linkage of food and fuel markets that would result from
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 7

implementation of the RFS policy. With respect to petroleum, the current volatility of crude

oil markets casts doubt on the potential for biofuels to remain competitive in the future

without government mandates, such as the S.23 and this RFS policy proposal. With an RFS,

fuel price risks are shifted to consumers through the price of credits; however, consumer

acceptance, awareness, and willingness to use biofuels, as well as manufacturers’

willingness to produce FFVs, are unknown (and unlikely without a government mandate).

The costs associated with vehicle manufacturing also are shifted to consumers under an

RFS mandate, but again there is no guarantee that consumers will choose to purchase E85

or biodiesel fuels in the quantities needed to fulfill the mandate.

The RFS, which requires biofuels production to reach approximately 65 billion gallons by

2025, could require more than 25 billion gallons of corn-based ethanol and 25 billion

gallons of cellulosic ethanol, a technology that is not commercially available at present. It

could also require a roughly 8-fold increase in ethanol imports as well as about 5 billion

gallons of domestic biodiesel production. As a result, domestic corn and soybean prices

could increase dramatically from current levels, significantly increasing domestic prices for

food and feed and reducing exports.

In agricultural markets, production of corn and biomass is subject to agricultural risks, such

as crop failure caused by disease or drought. Moreover, the competition for arable land that

would result from increased corn production at the levels needed to satisfy the 25-percent

RFS could significantly raise all food and feed prices in the United States. The current

generation of corn and soy biofuels crops are grown almost exclusively on prime

agricultural land in the Midwest. It is not clear that sufficient land resources would be

available for large-scale expansion of corn and soybean cultivation, given the intense

competition with conventional agricultural products for arable land.

The markets for biofuels, biofuel co-products, and crop commodities are linked, and they

are susceptible to changes in the prices and availability of the crops. Surging demand for

biofuel feedstocks under the RFS policy would exert upward price pressure on corn and

soybean commodities and influence the markets for food, feed, industrial feedstocks, and

exports. Additionally, the generation of co-products increases directly with biofuel

production. At high levels of biofuel production, co-products may be oversupplied, resulting

in depressed prices and lower revenues to offset fuel production costs.

In 2005, co-products from the 3.9 billion gallons of ethanol produced were significant,

including 10 million tons of dried distillers’ grains and solubles (DDGS), 473,000 tons of

corn gluten meal, 2.6 million tons of corn gluten feed, and 283,000 tons of corn oil.8 As

biofuel production grows to the 7.5 billion gallons mandated in the Energy Policy Act of

2005 (EPACT2005), DDGS production is expected to grow to more than 15 million tons.

With the RFS policy, more than 25 billion gallons of corn-based ethanol would be required

in 2025, and DDGS production would exceed 50 million tons—probably causing a dramatic

drop in its market-clearing price. At that point, the value of DDGS could be as low as the

value of biomass or fertilizer.

8Renewable Fuels Association, 2005 Annual Industry Outlook, web site http://www.ethanolrfa.org/industry/

outlook/.
8 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Biodiesel production also results in some valuable co-products. Current biodiesel

production uses surplus soybean oil generated as a co-product in the soybean meal industry,

with little effect on other soybean commodity markets. Annual production levels

approaching 300 to 600 million gallons of soybean oil would, however, begin to compete

with food and feed markets for soybeans.9 Ten pounds of crude glycerol is generated as a

co-product for every 100 pounds of biodiesel, and the glycerol generated from 300 to 600

million gallons of biodiesel production per year would be equal to nearly one-half of the

current glycerol market in North America, causing a substantial oversupply and depressing

prices.

Technology Concerns

Meeting the 25-percent RFS and RPS mandates in the Policy proposal would require

successful and early development of currently unproven and noncommercial technologies,

including those that convert cellulose to sugars and, ultimately, to cellulosic ethanol. The

success of the Policy would also depend on the cost, performance, and first date of

commercial availability of advanced biomass electricity generation technology and the

development of the energy crop industry needed to support it.

While it is expected that both technologies—advanced biomass generation and cellulosic

ethanol production—will be feasible, their actual costs, performance, and first dates of

commercial availabilities are uncertain, because no such commercial plants exist at present.

If the technologies became commercially available in the first few years of the next decade

and their costs were lower than expected, then the costs of meeting the RPS and RFS could

be lower than projected here. On the other hand, if the costs of early commercial plants

were much higher than projected10 and/or the first dates of commercial availability were

delayed into the second half of the next decade or beyond, then the actual costs of the policy

could be much higher than estimated in this analysis. In that event, meeting the RFS by

2025 could require potentially implausible levels of corn-based ethanol production or

unprecedented levels of ethanol imports from Brazil. With the success of the Policy

dependent on noncommercial technologies with significant uncertainty in cost,

performance, and date of commercial availability, significant economic risks would be

imposed on the market.

In the case of electricity generation from biomass, the technology consists of a biomass

handling preprocessor that reduces the biomass to a treatable consistency; a gasifier and

scrubber to remove noxious or corrosive gases in the mix; and a combined-cycle generating

plant. In concept, the technology is much like an integrated gasification combined-cycle

(IGCC) plant with coal as the feedstock; however, no full-scale commercial IGCC plants

have been built. The major engineering issue with biomass remains the “front end handling

and processing” component, which tends to jam or clog. Small-scale pilot plants have not

9

Promar International, “Evaluation and Analysis of Vegetable Oil Market: The Implication of Increased

Demand for Industrial Uses on Markets & USB Strategy” (November 2005), pp. 25-35, web site

http://www.nbb.org/resources/reportsdatabase/reports/gen/20051101_gen-368.pdf.

10Precommercial engineering estimates of capital and operating costs of new technologies tend to understate

the costs of the first few commercially available plants; there is generally no evidence to suggest that the

cellulosic ethanol technology will prove otherwise.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 9

attained utilization rates exceeding 60 percent. Because the front end is an expensive

component, either the engineering problem must be solved or the unit will have to be built

with a “spare front end handler” to maintain high overall utilization, significantly increasing

its capital and nonfuel operating and maintenance costs.

In the case of cellulosic ethanol, current estimates of capital costs for a 50 million gallon per

year cellulosic ethanol plant are expected to be high: about $365 million (2005 dollars), as

compared with $65 million for a corn-based plant of similar size. With no commercial

cellulosic ethanol plants currently in operation, investment risk is high for a first-of-its-kind,

large-scale cellulosic ethanol production facility. EPACT2005 provides financial incentives

that are expected to bring the first 250 million gallons per year of cellulosic ethanol

production capacity on line between 2010 and 2015; however, it is not certain what the

initial plant and operating costs will be or how quickly the costs and investment risk will

fall as a result of manufacturing experience and further research.

Other Concerns and Uncertainties

In addition to the concerns discussed above, there are several other areas of uncertainty that

could affect the feasibility and costs of meeting the RPS and RPS policy goals.

• The supply and cost of biomass energy crops to generate electricity and produce

cellulose-based ethanol will be critical in determining credit prices and the prices of

delivered energy under the main Policy. The critical uncertainty involves the

availability and cost of biomass for use in electric power generation and ethanol

production, as well as the cost, performance, and first dates of commercial availability

of the technologies. To the extent that this analysis overstates the cost and understates

the availability of biomass technology, the impact on the U.S. energy market and

economy could be smaller than indicated here; however, if biomass supply is

overstated and prices are understated here, the impact could be larger.

• The projected level of about 25 billion gallons of corn ethanol production in 2025

under the Policy would significantly increase U.S. corn demand and likely require

much higher prices to clear the market, with a significant impact on food and feed

markets and a large cut in, or elimination of, U.S. corn exports. Also, several recent

studies that are less optimistic about yield growth and expansion of corn acreage

suggest a maximum level of U.S. corn ethanol production that is below 20 billion

gallons, which would make the feasibility of meeting the RFS much more uncertain.

• The impacts of rising corn prices on the prices of other domestic and international

agricultural food and feed products—and ultimately on U.S. economic growth—is

highly uncertain but potentially larger than the direct energy price impacts alone.

Analysis of those impacts would require the application of an integrated model that

examines agricultural competition across the economy and energy sectors both

domestically and internationally. For this study, EIA used an integrated domestic

model to derive biomass and corn prices; however, the model is not integrated with the

rest of the domestic or international economy.

• The availability and pricing of ethanol exports from Brazil will be critical in

determining domestic RFS credit prices. Further, the availability of ethanol exports

will depend on the extent to which additional land resources are used for ethanol
10 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

production, which is highly uncertain. Although Brazil may be willing to make such

investments, it is unclear at what market price the investments would be made or how

they would be funded.

• As indicated in the request for analysis, this study assumes the enactment, in some

form, of legislation (like portions of S.23) that will facilitate the development of

biofuels transportation and distribution infrastructure and the production of only dualfuel capable light-duty vehicles after 2016. The enactment of such legislation is highly

uncertain. Its details could determine what the costs are, who bears the costs of

building the infrastructure, and the likelihood that the intended goals will be achieved.

Uncertainties in the Reference Case

NEMS, like all models, is a simplified representation of reality. Projections are dependent

on the data, methodologies, model structure, and assumptions used to develop them.

Because many of the events that shape energy markets (including severe weather,

technological breakthroughs, and geopolitical developments) are random and cannot be

anticipated, energy markets are subject to uncertainty. Moreover, future developments in

technologies, demographics, and resources cannot be foreseen with certainty. Nevertheless,

well-formulated models are useful for analyzing complex policies. They can provide

valuable insight, because they ensure consistency in accounting and represent (albeit

imperfectly) key interrelationships.

EIA’s projections are not statements of what will happen, but what might happen, given

technological and demographic trends and current policies and regulations. The Reference

Case used for this analysis, based on the AEO2007 reference case, incorporates current laws

and regulations as of September 1, 2006. Thus, it provides a policy-neutral starting point

that can be used to analyze energy policy initiatives. In its reference cases, EIA does not

propose, advocate, or speculate on future legislative or regulatory changes. Laws and

regulations generally are assumed to remain as currently enacted or in force (including

sunset or expiration provisions); however, the impacts of scheduled regulatory changes,

when clearly defined, are reflected.

This report, like other EIA analyses of energy and environmental policy proposals, focuses

on the impacts of those proposals on energy choices made by consumers in all sectors and

the implications of those decisions for the economy. This focus is consistent with EIA’s

statutory mission and expertise. The study does not account for any possible health or

environmental benefits that might be associated with enactment of a combined RPS and

RFS.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 11

3. Energy Market Impacts of the Renewable Policy Proposal

Electricity Sector Impacts

Implementing a 25-percent RPS by 2025 has significant impacts on power sector generation

by fuel, generating technology selection, and electricity prices. The power sector shifts

away from its long-term reliance on coal-fired generation, toward increased reliance on

nonhydropower renewable generation and incremental hydroelectric generating sources.

This trend has little impact on emissions of sulfur dioxide, nitrogen oxides, and mercury.

Because these three pollutants are subject to emissions caps, their levels are essentially

unchanged (although the costs of compliance are lower). However, the change in fuel mix

leads to somewhat lower carbon dioxide (CO2) emissions, which currently are not regulated.

The higher cost of renewable generating technologies results in lower delivered prices for

fossil fuels but higher electricity prices overall. Table 2 summarizes key electricity sector

impacts.

RPS Credit Prices

The RPS credit price, shown in Table 2 for 2025 and 2030, generally increases through

2025, when the maximum required share for renewable generation is initially imposed.

Between 2025 and 2030, the credit price is projected to vary between 3.8 and 4.8 cents per

kilowatthour. The credit price represents the incremental cost of meeting the specified

renewable target. Essentially, it describes the difference between the cost of the cheapest

available renewable option that satisfies the requirement and the alternative technology that

would have supplied the electricity if the RPS had not been in place. Naturally, the credit

price is affected by the costs and performance of the available renewable options and the

alternative nonrenewable technologies. Figure 1 illustrates the RPS credit prices in the

Policy Case.

Inter-sector Compliance Options

The proposed Policy analyzed in this report calls for compliance with separate renewable

sales targets in the electricity and transportation sectors. The marginal cost of compliance,

as reflected by the credit price for each sector, would not be expected to be the same for

each sector, as each has different compliance options. Both sectors can and do use

significant amounts of cellulosic biomass as part of the compliance strategy, and at times

this may represent the marginal unit of supply to one or both sectors. Even so, costs may

differ between the two sectors, as each has different conversion efficiencies and capital and

non-feedstock operating costs.
12 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Table 2. Selected Electric Power Results, 2025 and 2030

2025 2030

2005 Reference Policy Reference Policy

RPS Credit Price (2005 cents/kWh) NA NA 4.8 NA 4.5

Capacity (gigawatts)

Coal Steam 314.8 406.1 323.4 468.0 342.5

Other Fossil Steam 121.4 88.3 80.9 87.0 80.9

Combined Cycle 176.6 210.4 196.0 211.6 196.6

Combustion Turbine/Diesel 133.2 135.1 146.5 154.2 178.9

Nuclear Power 100.0 111.7 102.7 109.1 98.9

Pumped Storage 20.8 20.8 20.8 20.8 20.8

Other 0.0 5.6 8.1 11.4 13.2

Conventional Hydropower 80.6 80.8 85.9 80.8 85.9

Geothermal 2.3 3.0 8.6 3.2 9.6

Municipal Solid Waste/Landfill Gas 3.6 4.1 5.8 4.2 5.9

Wood and Other Biomass 6.5 9.8 75.1 11.7 84.5

Solar10.6 2.1 2.0 3.6 3.8

Wind 9.6 17.8 130.6 17.9 144.4

Other Industrial Capacity217.7 31.1 33.4 35.1 39.6

Total 987.7 1,126.7 1,220.0 1,218.4 1,305.6

Generation (billion kilowatthours)

Coal 2,014.6 2,852.6 2,161.7 3,320.0 2,382.2

Petroleum 121.9 105.0 101.4 107.0 102.9

Natural Gas 751.7 1001.0 768.3 938.0 838.8

Nuclear Power 780.5 886.0 815.2 869.5 789.4

Pumped Storage/Other 13.0 8.0 8.1 8.5 8.6

Conventional Hydropower 265.1 307.5 328.3 307.7 328.4

Geothermal 15.1 21.6 66.1 23.1 73.8

Municipal Solid Waste/Landfill Gas 23.3 27.2 40.4 27.7 40.8

Dedicated Biomass 30.5 57.0 535.9 69.5 605.3

Biomass Co-Firing 7.4 67.2 83.7 66.8 26.4

Solar10.9 4.4 4.2 7.2 7.6

Wind 14.6 51.3 425.1 51.5 475.2

Total 4,038.4 5,388.9 5,338.2 5,796.6 5,679.4

Electricity Prices and Sales

Electricity Sales (billion kiowatthours) 3,660.0 4,825.9 4,778.3 5,168.4 5,056.6

Retail Electricity Prices (2005 cents/kWh) 8.1 8.0 8.3 8.0 8.5

Electric Sector Emissions

Sulfur Dioxide (million short tons) 10.2 3.7 3.6 3.7 3.6

Nitrogen Oxides (million short tons) 3.6 2.3 1.9 2.3 2.0

Mercury (tons) 51.2 16.9 16.9 16.5 15.7

Carbon Dioxide (million metric tons) 2,375 3,046 2,425 3,321 2,597

Fuel Prices

Natural Gas Wellhead Price (2005 dollars per mcf) 3 7.51 5.54 5.47 5.90 5.86

Coal Minemouth Price (2005 dollars per ton) 23.34 21.83 21.34 23.17 21.73

1

Includes solar thermal power, utility-owned photovoltaics, and distributed photovoltaics.

2

Includes capacity in the industrial sector fueled by petroleum, natural gas, or other gaseous fuels.

3mcf = thousand cubic feet. kWh = kilowatthour.

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 13

Figure 1. Renewable Portfolio Standard Credit Price, Policy Case

(2005 cents per kilowatthour)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

If the proposed Policy were applied as an aggregate target for the two sectors, with credit

trading allowed between the sectors (that is, 25 percent of the combined electricity and

motor transportation fuels markets), the credit prices in the two sectors would converge to a

common value. Currently, the electricity sector target is specified in cents per kilowatthour

and the transportation sector target in dollars per gallon of ethanol. A joint target would

require a common unit of comparison, as shown in Figure 2 for the Policy Case.

Figure 2. Comparison of RFS and RPS Credit Prices in Common Units, Policy Case

(2005 dollars per million Btu)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.
14 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

The higher credit price in the transportation sector indicates that an aggregate target would

encourage more compliance in the electricity sector and reduced compliance in the

transportation sector. More than 25 percent of the electricity generated in the electricity

sector would be from renewable fuels, and less than 25 percent of the motor transportation

fuels would be biofuels. The shift in the compliance burden between sectors would tend to

reduce the overall cost of compliance; however, EIA is not able to determine the impact of

such a scheme without specification of a mechanism for inter-sector credit trading.

Generation by Fuel

In the Reference Case, coal-fired plants continue as the primary source of electricity,

increasing from about 50 percent of total supply in 2005 to 53 percent in 2025 (Table 2).

Both nuclear and natural gas plants provided 19 percent of total generation in 2005. Nuclear

generation is projected to increase over the subsequent 20 years but at a slower rate than

total generation, and so the share of generation from nuclear plants in 2025 falls to 16

percent. Natural gas generation is projected to rise initially but then decline as natural gas

prices increase. In 2025, the share of total generation from natural gas plants is projected to

be about 19 percent—about the same share as in 2005. In 2030, nuclear power generation

falls slightly from 2025 levels due to some age-related retirements, and its share of

electricity generation falls to 15 percent. Natural gas power generation falls by about 6

percent from 2025 levels as increasing natural gas prices erode its competitiveness, and its

total market share falls to about 16 percent in 2030 (Table 2).

Hydroelectric plants are the largest source of renewable generation, but production from

existing facilities is not credited toward the RPS requirement. The share of hydroelectric

generation declines in the Policy Case from about 6.5 percent of total supply in 2005 to 6

percent in 2025. Nonhydropower renewables remain a small source of electricity in the

Reference Case, but the corresponding share of total generation doubles from 2 percent in

2005 to 4 percent in 2025. Biomass and wind plants represent the primary sources of

nonhydropower renewable generation. Production from both these technologies more than

triples between 2005 and 2025, although their share of total generation remains small

throughout the projection.

In general, biomass and wind electricity supplies are projected to represent the primary

options for complying with the RPS. Although total wind capacity exceeds biomass

capacity (Figure 3), biomass generation is considerably higher than the output from wind

capacity (Figure 4) because of a higher biomass capacity factor. Dedicated biomass plants

have higher utilization rates than wind plants, which are dependent on an intermittent

resource. Also, biomass can be co-fired with coal in existing fossil steam units.

In the Policy Case, biomass generation in 2025 and 2030 provides about one-half of the

renewable generation required by the RPS (Table 2). Considerable increases in biomass

electricity generation occur in virtually every region of the United States. Wind plants

account for more than 35 percent of the RPS requirement in 2025 and 2030. Most of the

wind capacity additions are expected to be built in the West and Midwest. More moderate

increases are projected for geothermal, municipal solid waste, and hydroelectric

technologies, which together supply about 10 percent of the needed renewable generation.

Little change in solar generation is expected as a result of the RPS (Table 2).
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 15

Figure 3. Renewable Generation Capacity, Reference and Policy Cases

(gigawatts)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Figure 4. Renewable Generation, Reference and Policy Cases

(billion kilowatthours)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

The requirement for renewable generation specified in the RPS is expected to reduce

electricity production from other fuel types. Compared to the Reference Case, coal-fired

generation is about 24 percent lower in 2025 and 28 percent lower in 2030 in the Policy

Case. Natural-gas-fired generation is 23 percent lower in 2025 and 11 percent lower in 2030

in the Policy Case than in the Reference Case (Table 2). Similarly, nuclear generation is

about 8 percent less in 2025 and 9 percent less in 2030.

With biomass expected to be the leading renewable option for satisfying the RPS, the

availability of biomass fuel supplies has a considerable impact on the ability of the electric

power sector to comply with the RPS. Some biomass feedstocks can be used for both

electricity production (dedicated biomass plants and co-firing in coal-fired plants) and

cellulosic-based ethanol, and the respective sectors compete for those common resources in
16 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

order to comply with the RPS and RFS. If more economical supplies of imported ethanol

were available, then less biomass fuel would be needed to produce cellulose-based ethanol,

and more would be available for electricity generation.

Carbon Dioxide Emissions

In the Reference Case, CO2 emissions resulting from electricity generation grow from 2,375

million metric tons in 2005 to 3,046 million metric tons in 2025, an increase of almost 30

percent (Table 2). The increase in emissions results from higher fossil fuel consumption,

particularly coal.

In the Policy Case, the increased penetration of renewable generating plants displaces some

generation from fossil plants and slows the growth in CO2 emissions (Table 2). CO2

emissions in 2025 total about 2,425 million metric tons, which represents a reduction of

about 20 percent from the Reference Case and only a slight increase from 2005 levels.

Electricity Prices

In the Reference Case, electricity prices are expected to decline from 2005 to 2015 and then

increase gradually, so that the prices in 2025 and 2030 are similar to the price in 2005

(Table 2 and Figure 5). The initial decline in prices results from a corresponding decrease in

fuel prices and comparatively few capacity additions (because some areas currently have a

surplus of generating capacity). Between 2015 and 2025, fuel prices to electricity generators

start to rise, and more new plants are required to meet projected increases in demand.

Compared to the Reference Case, the cost of complying with the RPS in the Policy Case is

projected to increase the price of electricity by about 3.3 percent and 6.2 percent in 2025

and 2030, respectively (Table 2 and Figure 5). Although the increased renewable generation

resulting from the RPS displaces fossil generation and results in lower fuel prices, that

decrease is more than offset by the higher cost of building and operating renewable capacity

per unit of output.

The RPS could, however, result in lower electricity prices in some areas of the United

States. The Western Regions have considerable renewable resources that could enable

suppliers to provide renewable generation in excess of their own requirements and sell

surplus credits to producers in other areas with less economical renewable options. The

resulting revenue could more than offset the costs of building renewable plants in the West.

Consumers’ expenditures for electricity in the Policy Case are $9 billion higher than in the

Reference Case in 2025 and $16 billion higher in 2030. The higher electricity bills are

partially offset by lower consumer natural gas bills. Through 2022, however, electricity

prices in the Policy Case are generally lower than in the Reference Case, because the cost of

generation declines more than the cost of capital increases.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 17

Figure 5. Electricity Prices, Reference and Policy Cases

(2005 cents per kilowatthour)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Relative to the Reference Case, end-use sector expenditures for purchased electricity rise

while end-use sector expenditures for natural gas fall in the Policy Case. From 2009 through

2030, cumulative expenditures for electricity (discounted at 7 percent) are $15 billion (0.4

percent) higher and natural gas expenditures are $17 billion (1.0 percent) lower in the

Policy Case than in the Reference Case.

End-Use Energy Consumption

Consumers and businesses in all sectors of the economy are projected to reduce their

electricity consumption and increase their direct use of fossil fuels in response to the higher

delivered electricity prices in the Policy Case. These changes reduce overall energy

consumption but raise consumers’ energy bills.

Residential and Commercial Sectors

There is little change in residential and commercial energy consumption in 2025 in the

Policy Case relative to the Reference Case. Lower electricity consumption is offset by

increased natural gas consumption. In both sectors, total delivered energy use11 in 2025 is

0.1 percent lower in the Policy Case than in the Reference Case (Figures 6 and 7).

Residential electricity demand is 0.5 percent lower and commercial electricity demand is

0.3 percent lower in 2025 in the Policy Case than in the Reference Case, because electricity

prices rise as suppliers pass along the costs of holding renewable credit permits and because

of increased renewable fuel use. In 2030, electricity demand in the Policy Case is 1.0

percent lower in the residential sector and 1.1 percent lower in the commercial sector than

projected in the Reference Case.

11Delivered energy does not include losses associated with the conversion and distribution of electricity.
18 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Figure 6. Delivered Residential Energy Consumption, Reference and Policy Cases

(quadrillion Btu)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Figure 7. Delivered Commercial Energy Consumption, Reference and Policy Cases

(quadrillion Btu)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Increased use of renewable fuels leads to lower natural gas consumption in the electric

power sector and, in turn, to lower natural gas prices in the Policy Case relative to the

Reference Case. As a result, residential natural gas use is 0.2 percent higher and commercial

natural gas use is 0.4 percent higher in 2025 in the Policy Case than in the Reference Case.

In the commercial sector, petroleum liquids consumption is 1.2 percent lower in 2025 in the

Policy Case than in the Reference Case as a result of higher commercial distillate fuel

prices. Although the price of heating oil in the Policy Case is similar to that in the Reference

Case, the price of diesel fuel for commercial engines is higher than in the Reference Case,

leading to lower commercial demand for petroleum.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 19

Annual residential and commercial energy expenditures are higher with implementation of

the Policy proposal. Residential energy expenditures increase by 1.5 percent ($30 per

household) in 2025 in the Policy Case relative to the Reference Case due to higher

electricity prices. The change in commercial energy expenditures with enactment of the

Policy proposals is similar to that in the residential sector. Commercial energy expenditures

are 2.3 percent higher in 2025 in the Policy Case than in the Reference Case.

Higher electricity prices relative to natural gas prices in the Policy Case lead to 2.3 percent

more commercial natural-gas-fired combined heat and power (CHP) capacity in 2025

relative to the Reference Case. In 2030, the higher relative electricity prices result in 19

percent more natural-gas-fired CHP capacity in the Policy Case compared to the Reference

Case. Higher electricity prices in the Policy Case also lead to more use of PV systems in the

buildings sectors. Residential and commercial PV capacity in 2030 is 9.6 percent higher in

the Policy Case than in the Reference Case.

Industrial Sector

Industrial energy consumption is higher in the Policy Case due to large increases in the use

of biofuels and heat co-products for ethanol production. Total delivered industrial energy

consumption is 33.9 quadrillion Btu in 2030 in the Policy Case, compared with 30.3

quadrillion Btu in the Reference Case. The increase in industrial sector consumption of

biofuels and natural gas in the Policy Case more than offsets a decline in coal use. In 2030,

industrial consumption of biofuels and heat co-products increases from 0.8 quadrillion Btu

in the Reference Case to 5.2 quadrillion Btu in the Policy Case, as a result of the increase in

production of biomass-derived transportation fuels. Cellulosic ethanol production increases

from 0.2 billion gallons to 31 billion gallons; the amount of corn used to produce ethanol

increases by 107 percent; and biodiesel production increases from 1.6 billion gallons to 4.8

billion gallons.

Increased ethanol production also results in a sharp increase in natural gas use for heat and

power production at ethanol plants, which in 2030 increases from 0.3 quadrillion Btu in the

Reference Case to 0.8 quadrillion Btu in the Policy Case. Natural-gas-fired CHP plants are

also responsible for increased natural gas consumption, particularly in response to higher

electricity prices after 2020. An additional 4.3 gigawatts (18 percent) of natural-gas-fired

CHP capacity is added in the Policy Case. Overall, industrial natural gas consumption

averages 5 to 8 percent (400 to 600 trillion Btu) higher in the Policy Case than in the

Reference Case (Figure 8).

The increases in consumption of biofuels, heat co-products, and natural gas are partially

offset by a drop in the use of coal to produce liquids and electricity in coal-to-liquids (CTL)

plants. CTL liquids production in 2030 falls from 445 thousand barrels per day in the

Reference Case to 202 thousand barrels per day in 2030 in the Policy Case. As a result, total

coal use at CTL plants is reduced by 55 percent, from 112 million tons in the Reference

Case to 51 million tons in the Policy Case.

The net economic impact of the Policy Case is a reduction in industrial value of shipments,

by 3.3 percent in 2030 compared with the Reference Case. All industries are adversely

affected to some degree. Among manufacturing industries, petroleum refining has the
20 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

largest percentage decline in output (12 percent in 2030), followed by the aluminum

industry (8 percent) and the steel industry (6 percent).

Figure 8. Industrial Energy Consumption, Reference and Policy Cases

(quadrillion Btu)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Transportation Sector

In the transportation sector, total energy consumption in 2025 and 2030 in the Policy Case

is slightly lower than in the Reference Case (Figure 9). Total transportation energy

consumption increases from 28.1 quadrillion Btu in 2005 to 36.5 quadrillion Btu in 2025

and 39.1 quadrillion Btu in 2030 in the Reference Case. Total transportation energy

consumption in the Policy Case is 0.6 quadrillion Btu (1.5 percent) lower in 2025 and 1.0

quadrillion Btu (2.6 percent) lower in 2030, as a result of reductions in freight travel (due to

reduced industrial output) and in fuel use for light-duty vehicle travel (associated with

higher driving costs).

Ethanol and biodiesel consumption in the Policy Case represents a much larger share of

highway liquid fuel use than in the Reference Case. On an energy basis, renewable fuels

account for 5.0 percent and 5.6 percent of highway liquid fuel use in the Reference Case in

2025 and 2030, respectively. In the Policy Case, renewable fuels account for about 20

percent of highway liquid fuels consumption on an energy basis in 2025 and in 2030.

To facilitate compliance with the renewable fuel supply and consumption mandate, policies

consistent with those outlined in S.23, the Biofuels Security Act of 2007, were adopted in

this analysis. S.23 stipulates minimum requirements for the manufacture of dual-fuel

capable light-duty vehicles and the installation of E85 fuel pumps by major oil companies at

owned and branded stations. It requires that 100 percent of light-duty vehicles manufactured

after 2016 must be dual-fuel capable and that 50 percent of owned and branded stations

must install one or more pumps that dispense E85 fuel. However, two aspects of S.23 were

not considered in this analysis: the requirement for specific minimum E85 sales volumes
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 21

and the provisions for Corporate Average Fuel Economy credits from the manufacture and

sale of dual-fuel vehicles.

Figure 9. Transportation Energy Consumption, Reference and Policy Cases

(quadrillion Btu)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

EIA data indicate that approximately 50 percent of all retail fuel sales occur through owned

and branded retail outlets, which equates to a consumer fuel availability value of 25

percent.12 Expected penetration rates of new dual-fuel vehicle sales and E85 fuel

availability are illustrated in Figure 10.

Although the Policy Case requires the installation of E85 fueling infrastructure to begin by

2008 and reach the maximum share by 2017, the projections indicate that E85 will not

become a cost-competitive alternative to gasoline until 2015. As a result, the projections

indicate that the E85 infrastructure requirements considered in the analysis could be delayed

by as much as 7 years.

The cost of installing E85 retailing infrastructure and the associated impact on fuel cost and

fuel retailer profitability were not considered in this study. An EIA analysis of the

incremental cost associated with retrofitting an existing gasoline station to dispense E85

indicates that the costs could vary widely, depending on the scale of the retrofit and the

annual volume of E85 dispensed.13 At 40 thousand gallons per year, the estimated

incremental charge required to recover the cost over 15 years ranges from 8 cents per gallon

12It was determined that retail sales volumes were a better indicator of the potential fuel availability to

consumers than the number of retail outlets offering an alternative fuel. The intent of this assumption is to

capture consumer access/through rates at regulated stations versus those not required to provide the alternative

fuel. The retail sales volumes were determined by assuming that fuel marketers required to report on Form

EIA-28 fit the owned and branded requirement defined in S.23 (see http://www.eia.doe.gov/emeu/perfpro/

btab30.html).

13Energy Information Administration, Incremental Costs of Installing E-85 Dispensers at Gasoline Stations

(Washington, DC, July 21, 2005).
22 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

for a minimal retrofit (tank cleaning and nozzle, hose, and filter replacement) to 29 cents

per gallon for the replacement of the existing underground tank and dispenser with E85-

compatible equipment. As annual E85 pump volumes approach 50 percent of equivalent

unleaded gasoline pump volumes (about 160,000 gallons per year), the incremental costs

decrease significantly and could vary from 2 cents per gallon to 7 cents per gallon

depending on the scale of the retrofit. The incremental costs per gallon are 2 to 3 times

higher if the cost recovery period is reduced to 5 years. These estimates do not account for

any gains or losses in revenues that may result from replacing an unleaded gasoline

dispenser with an E85 dispenser. In the initial years of operation, fuel-related revenues are

likely to be lower if an existing gasoline tank and dispenser are replaced with E85

equipment.

Figure 10. Minimum Requirements for New Dual-Fuel Light-Duty Vehicle

Manufacturing and E85 Fuel Availability, Policy Case

 (percent of total)

Source: National Energy Modeling System, run IRES2525.D060607A.

The incremental cost of adding an E85 dispenser at a new retail fuel facility is negligible in

comparison with the cost of adding a new gasoline dispenser. If the conversion to E85 from

an existing gasoline dispenser is made during the regularly scheduled cycle for gasoline

tank and equipment maintenance and cleaning, the incremental cost of conversion to the

E85 fuel dispensing capability ranges between a few percent and 50 percent of the cost for a

conversion done outside the normal maintenance cycle.

Also not addressed in this study are the costs and implications associated with developing

an ethanol distribution network capable of moving in excess of 60 billion gallons of ethanol

annually. The distribution costs represented here reflect an infrastructure designed to

accommodate volumes expected under typical business-as-usual projections, which are

significantly lower than the volumes addressed in this study. Distribution of ethanol in all

cases is accomplished via truck, rail, and barge shipments, with costs varying by mode of

travel and intra- or interregional considerations.

Depending on the mode of travel and distance shipped, ethanol distribution costs vary from

3.5 cents per gallon to 14.0 cents per gallon, excluding any additional costs that may be
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 23

incurred due to additional infrastructure development requirements, congestion, new

distribution patterns, or legal issues related to an expanded ethanol distribution network.

Also not considered are any distribution cost savings that could result from the installation

of dedicated ethanol pipelines.

Fuel Prices and Expenditures

The 25-percent RFS policy raises consumer prices for gasoline and diesel in 2025 by about

13 percent and 22 percent, respectively (Table 3). After 2025, the RFS percent ceases to

change, reducing the upward pressure on gasoline and diesel prices. In 2030, gasoline and

diesel prices in the Policy Case are about 11 percent and 17 percent higher, respectively,

than in the Reference Case.

Table 3. Transportation Sector Key Indicators and Delivered Energy Consumption

2025 2030

2005 Reference Policy Reference Policy

Light-Duty Vehicles

Billion Miles Traveled 2,721 3,930 3,869 4,323 4,230

Efficiency – Miles Per Gallon

Average For New Light-Duty Vehicles 25.2 29.1 29.1 29.4 29.7

New Cars 30.0 33.5 33.8 33.9 34.5

New Light Trucks 21.8 26.1 25.7 26.6 26.5

Average, All Light-Duty Stock 19.7 21.9 21.7 22.3 22.4

New Car Sales (thousands) 8,109 8,687 9,095 8,926 9,406

New Light Truck Sales (thousands) 8,125 10,442 9,560 11,256 10,628

Highway Energy Use (quadrillion Btu)

Total Light-Duty Vehicles 16.9 21.6 21.5 23.3 22.9

Automobiles 8.4 8.7 9.0 9.0 9.2

Light Trucks 8.5 12.9 12.4 14.2 13.7

Energy Use by Fuel (quadrillion Btu) 16.9 21.6 21.5 23.3 22.9

Motor Gasoline 16.6 20.8 15.1 22.3 16.1

Distillate Fuel Oil (Diesel) 0.3 0.7 0.1 0.9 0.1

E85 0.0 0.01 6.24 0.02 6.69

Total Transportation Consumption (quadrillion Btu) 28.1 36.5 36.0 39.1 38.1

Key Transportation Fuel Prices (dollars per gallon)

Average Gasoline Price 2.32 2.16 2.44 2.21 2.45

Average Diesel Price 2.41 2.21 2.70 2.31 2.70

Average E85 Price 2.19 2.22 1.89 2.23 1.91

Transportation Energy Expenditures 2009–2025 2009-2030

Cumulative Undiscounted Billion Dollars NA 8,493 8,759 11,552 12,113

Discounted at 7 Percent NA 5,121 5,232 5,968 6,162

Note: All prices are in 2005 dollars.

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.
24 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Unlike gasoline and diesel fuel prices, E85 prices in the Policy Case fall, because revenues

from RFS credits reduce the price of ethanol production. E85 prices in the Policy Case are

about 15 percent lower than those in the Reference Case in 2025 and 2030, despite the

increased cost of ethanol production in the Policy Case.

Transportation energy expenditures in the Policy Case are about $68 billion (12 percent)

higher in 2025 and $50 billion (7.7 percent) higher in 2030 than in the Reference Case.

Cumulative undiscounted consumer expenditures for transportation energy between 2009

and 2025 are about $266 billion higher in the Policy Case than in the Reference Case.

End-Use Carbon Dioxide Emissions

In the Reference Case, total end-use CO2 emissions increase from 5,945 million metric tons

CO2 equivalent in 2005 to 7,381 million metric tons in 2025 and 7,914 million metric tons

in 2030 (Table 4). In the Policy Case, CO2 emissions from the end-use sectors are

significantly lower, because the average carbon intensity of the fuels used is lower. In 2025,

total end-use CO2 emissions are 13 percent (972 million metric tons) lower in the Policy

Case than in the Reference Case, and in 2030 they are 14 percent (1,138 million metric

tons) lower.

Table 4. Carbon Dioxide Emissions by End-Use Sector

(million metric tons carbon dioxide)

2025 2030

Sector 2005 Reference Policy Reference Policy

Residential 1,254 1,531 1,304 1,614 1,360

Commercial 1,051 1,461 1,228 1,623 1,345

Industrial 1,682 1,893 1,710 2,013 1,777

Transportation 1,958 2,497 2,168 2,664 2,294

Total 5,945 7,381 6,409 7,914 6,776

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

In the Reference Case, the transportation sector accounts for 33.8 percent of total CO2

emissions in 2025, followed by the industrial sector (25.6 percent), residential sector (20.7

percent), and commercial sector (19.8 percent). CO2 emissions from the electric power

sector are assigned to each sector according to its share of electricity sales. Compared with

the Reference Case, the reductions in CO2 emissions in 2025 in the Policy Case are

proportional to the change in energy consumption in the transportation sector. The

transportation sector reductions account for 34 percent (329 million metric tons) of the total

CO2 reduction of 972 million metric tons in 2025 (Figure 11).
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 25

Figure 11. Carbon Dioxide Emissions by End-Use Sector, Reference and Policy Cases

 (million metric tons)

Notes: Emissions associated with electricity consumption in the end-use sectors is reported under electric power.

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Primary Energy Impacts

Increasing the use of renewable fuels in the electricity and motor fuels sectors would lead to

higher overall primary fuel use, because additional energy would be needed to produce

ethanol and because of the accounting conventions used to estimate the primary resources

consumed in renewable electricity generation. For example, for wind, geothermal, and solar

electricity generation, primary energy use is calculated by multiplying the renewable

electricity generated by an assumed standard heat rate of 10,200 Btu per kilowatthour to

derive a fossil-fuel equivalent. In these cases the measure can be somewhat misleading,

because increased use of primary energy is often considered a negative attribute of policy.

A more meaningful measure is total consumption of nonrenewable primary energy from

coal, oil, and nuclear fuels.

In the Policy Case for this analysis, total primary energy consumption from nonrenewable

sources is 5.3 percent lower in 2020, 7.7 percent lower in 2025, and 8.6 percent lower in

2030 than in the Reference Case (Figure 12).

The 25-percent RPS policy leads to lower coal and, to a lesser extent, natural gas and

nuclear fuel use in 2025 as generation from nonrenewable fuels is displaced by generation

from renewable fuels. In the Policy Case, coal use is 3.1 quadrillion Btu (11 percent) lower

in 2020, 6.1 quadrillion Btu (20 percent) lower in 2025, and 7.8 quadrillion Btu (23 percent)

lower in 2030 than in the Reference Case. The change in natural gas and nuclear use is

smaller than 10 percent in all years.
26 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Figure 12. Primary Fuel Consumption, Reference and Policy Cases

 (quadrillion Btu)

Note: “Other Liquid Fuels” includes all liquid fuels other than E85.

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

The percentage of nonrenewable fuel use declines in the Policy Case with the increasing

RPS and RFS percentages but not as quickly as the RPS and RFS requirements rise. In the

electricity generation sector, new renewable capacity displaces more efficient coal and

natural gas capacity that would have been built in the Reference Case. Because the newer

capacity would have been more efficient and would have been run at higher utilization rates

than the older coal and natural gas units, the RPS actually increases the amounts of coal and

natural gas consumed per kilowatthour of electricity generated.

Nonrenewable liquid fuel use is also significantly lower in the Policy Case, because it is

displaced by increased ethanol use in gasoline blending and E85 and increased biodiesel use

in diesel fuel, including ethanol and biodiesel blends. Overall, nonrenewable liquid fuel use

is 2.3 quadrillion Btu (5 percent) lower in 2020, 5.3 quadrillion Btu (11 percent) lower in

2025, and 6.0 quadrillion Btu (12 percent) lower in 2030 in the Policy Case than in the

Reference Case.

In contrast, because of the increased production and use of E85 and biodiesel in the Policy

Case, the amounts of biofuels used to produce heat and co-products and other renewable

fuels are all significantly higher than in the Reference Case. In combination, the use of these

fuels in the Policy Case is more than double that in the Reference Case in 2020 and

approaches 3.5 times the Reference Case level in 2025 and 2030.

Fuel Supply Impacts

Petroleum and Renewable Fuels Impacts

The provisions of the proposed RFS require that gasoline and diesel producers must either

blend and sell an increasing percentage of renewable fuels or purchase enough credits to

cover their sales of gasoline and diesel fuels. For the Reference Case, this implies a need for

approximately of 34 billion gallons of renewable fuel in 2020, increasing to 66 billion
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 27

gallons in 2025.14 For 2026 and each year thereafter, the renewable fuels requirement would

be proportional to 25 percent of total gasoline and diesel sales, including ethanol and

biodiesel blends, in that year. In 2030, the Policy Case would require approximately 70

billion gallons of biofuels to be consumed in the motor transport market.

Under the RFS proposal, suppliers of gasoline, diesel, E85, and diesel blends would be

obligated to hold one biofuel credit for every 4 gallons of motor fuel sold (e.g., gasoline,

E10, E85, biodiesel blends, and diesel). For this study, ethanol and biodiesel are considered

to be the only renewable fuels qualified to fulfill the RFS requirement. In contrast to the

existing RFS, no additional credit is assigned to either fuel, depending on its feedstock or

technology.

Given the magnitude of the RFS requirement, gasoline blends containing up to 10 percent

ethanol (E10) would not be sufficient to ensure compliance. Most gasoline-powered

vehicles currently manufactured are warranted to operate on gasoline blends with ethanol

content up to 10 percent. The use of FFVs, which can operate on much higher

concentrations of ethanol—currently, up to 85 percent (E85)—would be required.15 In 2025,

the market share of E85 in the gasoline pool is projected to increase from less than 1 percent

in the Reference Case to almost 30 percent in the Policy Case (Figure 13).

Figure 13. Composition of the U.S. Gasoline Pool, Reference and Policy Cases

 (billion gallons)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

14The quantity of motor gasoline consumed in 2025, including sales of E85, is 197 billion gallons. The amount

of diesel fuel consumed in 2025, as represented by sales of ultra-low-sulfur diesel (ULSD) and biodiesel

blends, is 65 billion gallons.

15To address cold starting issues, the percentage of ethanol actually varies seasonally. The annual average

ethanol content of 74 percent is used for the projections.
28 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Many new light-duty vehicles powered by diesel fuel are warranted for up to 5 percent

biodiesel. The reluctance of engine manufacturers to warranty higher blends stems from

concerns about the wide range of product quality currently on the market. A campaign to

improve the quality of the product significantly is assumed to mitigate such concerns to the

point where the number of manufacturers willing to warrant certified B20 blends (a mixture

of petroleum diesel and 20 percent biodiesel) will be sufficient to absorb the volumes of

biodiesel available.16

Tables 5 and 6 and Figure 14 summarize the major impacts of the proposed RFS on the

downstream market for liquid motor fuels. Relative to the Reference Case, the RFS

requirement is projected to increase the consumption of renewable fuels by 21 billion

gallons in 2020 and 50 billion gallons in 2025 in the Policy Case. The increase in biofuel

consumption increases the cost of gasoline in the Policy Case by 10 cents per gallon in 2020

and by 28 cents per gallon in 2025 (2005 dollars). For diesel fuel, the cost increases are 15

cents per gallon in 2020 and 49 cents per gallon in 2025. The comparatively higher impact

on diesel prices results in part from the lower average renewable content of diesel fuel.17

Each gallon of renewable fuel blended into a product lowers the number of credits needed

and the price. As a result, diesel bears more of the cost of RFS compliance than motor

gasoline on a per-gallon basis.

Higher relative prices in the Policy Case contribute to a reduction in transportation fuel use.

In the Policy Case, liquid motor fuels consumption is approximately 480 trillion Btu (about

1.5 percent) lower than in the Reference Case in 2025 and about 940 trillion Btu (about 2.5

percent) lower in 2030.18 The combination of displacing petroleum volumes with renewable

fuels and lowering consumer demand for petroleum products reduces the consumption of

imported crude oil and petroleum products by approximately 0.8 million barrels per day in

2020, 2.1 million barrels per day in 2025, and 2.4 million barrels per day in 2030. Domestic

crude oil production is minimally affected in the Policy Case, but refinery gain is reduced

due to reduced refining activity and natural gas liquids production falls with the reduction in

natural gas production resulting primarily from the RPS. The import share of liquid fuel

consumption, including ethanol imports, declines from about 60 percent in the Reference

Case to about 51 percent in the Policy Case in 2025.

Despite the drop in fuel use, consumer expenditures on liquid transportation fuels increase

in the Policy Case by $28 billion in 2020, $69 billion in 2025, and $51 billion (2005 dollars)

in 2030 compared with the Reference Case.

The RFS credit price is $2.18 in 2025 and $2.02 per gallon in 2030 in the Policy Case.

16Cummins (a manufacturer of on-highway truck engines with significant market share) has approved B20

from BQ-9000 certified companies. BQ-9000 is the biodiesel industry’s quality control program for biodiesel

producers consistently meeting American Society of Testing Materials specification D-6751.

17The opportunities for large-scale biodiesel production—at the scale envisioned for either corn-based or

cellulosic ethanol for this policy proposal—are limited, in part because ethanol receives the same credit price

per gallon as biodiesel even though biodiesel contains considerably more energy per gallon, and because

ethanol is expected to be cheaper to produce at quantities exceeding 5 billion gallons per year.

18Because E85 has roughly 75 percent of the energy content of gasoline, energy units (rather than volume) are

used in comparing fuel demand across cases.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 29

Table 5. Liquid Fuels Supply Impacts of the Reference and Policy Cases

2025 2030

Supply and Disposition 2005 Reference Policy Reference Policy

Supply (million barrels per day)

 Net Crude Oil Imports 10.1 12.0 11.3 12.8 11.7

 Net Product Imports 2.5 2.9 1.8 3.5 2.5

 Ethanol Imports 0.01 0.2 0.5 0.2 0.6

 Domestic Ethanol Supply 0.3 0.6 3.5 0.8 3.7

 Net Import Share of Liquid Product (percent) 60.5 59.6 51.1 61.0 52.8

Ethanol (billion gallons)

 Corn Based 3.9 9.0 25.5 12.0 25.3

 Cellulose Based 0.0 0.3 28.1 0.3 31.3

 Imports 0.1 3.3 7.7 3.5 9.0

 Ethanol Total 4.0 12.5 61.3 15.7 65.6

Consumption (quadrillion Btu)

 E85 0.0 0.01 6.2 0.02 6.7

 Motor Gasoline 17.0 21.3 15.5 22.7 16.6

 Motor Diesel 6.0 8.6 7.7 9.6 8.2

 Transportation Liquid Fuels Subtotal 27.4 35.6 35.1 38.2 37.2

 All Liquid Fuels 39.5 48.1 47.3 51.0 49.6

Delivered Petroleum Product Prices (2005 dollars per gallon)

 E85 2.19 2.23 1.89 2.23 1.91

 Ethanol Wholesale Price 1.80 1.64 2.76 1.67 2.69

 Motor Gasoline 2.32 2.16 2.44 2.21 2.45

 Motor Diesel 2.41 2.21 2.70 2.31 2.70

Credit Price NA NA 2.18 NA 2.02

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Figure 14. Sources of Renewable Liquid Fuel Supply, Reference and Policy Cases

 (billion gallons)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.
30 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Table 6. Renewable Fuels Summary for the Reference and Policy Cases

2025 2030

2005 Reference Policy Reference Policy

RFS Results

RFS Constraint (billion gallons) 3.5 9.0 66.0 9.8 70.4

Credit Price1 (dollars per gallon) NA NA 2.18 NA 2.02

Ethanol (billion gallons)

Corn Based Production 3.9 9.0 25.5 12.0 25.3

Cellulose Based Production 0.00 0.25 28.0 0.25 31.3

Imports 0.1 3.3 7.7 3.5 9.0

Total 4.0 12.5 61.3 15.7 65.6

Ethanol in E85 (billion gallons) 0.01 0.05 48.1 0.08 51.6

Ethanol in Gasoline Blending 4.0 12.5 13.2 15.6 14.1

Percent of Motor Gasoline Pool 2.9 7.0 31.2 8.2 31.2

Blend Percent of Motor Gasoline 2.9 6.9 9.4 8.1 9.4

Prices (2005 dollars)

Corn Price (dollars per bushel) 2.29 3.00 6.50 3.17 6.21

CD 4 Biomass Price (dollars per million Btu) 0.94 1.51 5.02 1.51 5.12

Agricultural Impacts

Total Corn Crop (million bushels) 11,807 14,138 14,473 14,899 15,170

Corn for Ethanol (million bushels) 1,323 3,363 9,228 4,433 9,174

Fraction of Corn Going to Ethanol 11% 24% 64% 30% 60%

Net Corn Exports (million bushels) 1,814 2,657 -1,871 2,099 -1,561

Corn Acres (million acres) 74 77 79 77 78

Corn Yield (bushels per acre) 160 183 183 194 194

Biomass Supplied (million tons) <30 41 535 43 579

1

All prices are in 2005 dollars.

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Ethanol Imports

The United States recently passed Brazil to become the world’s largest producer of fuel

ethanol. In the past, Brazil has emphasized ethanol production from sugar cane for domestic

use. More recently, representatives of the Brazilian government have expressed interest in

exporting more ethanol, with the United States considered as an important potential

market.19

Brazil currently cultivates sugar cane on about 6 million hectares of land (1 hectare = 2.47

acres). About half of the cane is used to produce ethanol, and the other half is used to

produce sugar for food use. Brazil’s ethanol production in 2004 was 4.1 billion gallons, and

its total exports were 635 million gallons, including 112 million gallons exported to the

United States.

Brazil has vast potential to increase ethanol production and exports. One recent study

indicated that as much as 90 million more hectares of underutilized agricultural land is

19“Gov. [Jeb] Bush Throws Support Behind Ethanol Initiative,” The Miami Herald (December 19, 2006).

See http://www.mre.gov.br/portugues/noticiario/internacional/selecao_detalhe.asp?ID_RESENHA=293740&

Imprime=on.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 31

available.20 However, the investments needed to increase production capacity to 54 billion

gallons in 25 years may be substantial.21

Very high levels of biofuel consumption would be needed to meet the requirement of the

proposed RFS policy (Figure 15), and it is possible that higher levels of ethanol imports

could be a cost-effective way to meet part of the requirement. Currently, ethanol imported

directly from Brazil is subject to a tariff of 54 cents (nominal) per gallon. The tariff on

ethanol imports is scheduled to expire in 2010, and imports are projected to rise to 3.3

billion gallons of ethanol in the Reference Case in 2025 from approximately 0.11 billion

gallons in 2005. In the Policy Case, ethanol imports total 7.7 billion gallons in 2025, or 4.5

billion gallons more than in the Reference Case (Table 6).

Figure 15. Imports as Percent of Liquid Fuel Products Supplied, Reference and Policy Cases

 (percent of total supply)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Cellulosic Ethanol

No commercial plant using cellulosic feedstock to produce ethanol is in existence today.

IOGEN, a Canadian biotechnology firm, estimates that the cost of such a plant would be

approximately $6 per gallon of capacity annually (2005 dollars) for a plant producing 50

million gallons per year.22 EIA estimates for its AEO2007 reference case, and those used in

this study, are based on the IOGEN estimate.

As in AEO2007, the capital costs in this analysis are adjusted for technological optimism

(early estimates of construction costs for first-of-a-kind plants tend to be optimistic) and

learning-by-doing (construction costs decline with manufacturing experience) in a manner

20Cambridge Energy Research Associates, Ethanol-Powered Brazil: The Land of Green Gold?, p. 13.

21University of Campinas, Sao Paulo, Brazil, Study of the Possibilities and Impacts of the Production of Large

Quantities of Ethanol with the Aim to Partially Replace Gasoline in the World.

22Quoted as “installed” capital cost for the facility. See “Not Your Father’s Ethanol,” Business Week (February

21, 2005).
32 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

consistent with the treatment of other emerging technologies within NEMS.23 Once the first

few plants are built, with Federal incentives in this case, learning-by-doing reduces costs as

experience increases.24

Learning-by-doing assumes that production costs fall as manufacturing experience with the

technology increases. The rate of learning, however, depends on the newness and maturity

of the component parts that make up the technology—the more mature the component parts,

the slower the learning rate.

For cellulosic ethanol, this study assumes that two-thirds of the capital costs would be

represented by mature technologies or materials, such as the power plant; only elements

such as the pre-treatment and hydrolization/fermentation units are subject to very rapid

learning. After the addition of 200 units (equivalent to 10 billion gallons per year capacity),

the capital cost in the EIA approach is approximately 83 percent of the base cost in 2012,

and 66 percent of the estimated first-of-a-kind cost. The cumulative effect of applying

EIA’s methodology results in an nth-of-a-kind plant cost for cellulosic ethanol of $5.14 per

gallon per year.

A widely quoted National Energy Renewable Laboratory (NREL) study by Aden et al.25

details an engineering study that estimates a capital cost of $3.39 per gallon per year.26

There are several important differences between the NREL and EIA estimates. First, the

NREL study is an engineering analysis of an nth-of-a-kind plant, which assumes that

several technological and engineering hurdles will be overcome, whereas EIA’s estimate is

for a first-of-a-kind commercial plant. Second, the NREL study assumes a slightly larger

plant (69.3 million gallons per year versus 50 million gallons per year). The economies of

scale make the NREL study plant slightly less expensive. Finally, the total project

economics in the NREL study were chosen to match the Department of Energy’s target

selling price of $1.07 per gallon (2000 dollars) to be achieved by 2010. Basing the future

price on a research and development target raises the issue of uncertainty: investments in

research and development cannot, statistically speaking, assure a successful outcome within

a specific time frame.

EIA’s nth-of-a-kind plant cost estimate for cellulosic ethanol of $5.14 per gallon per year is

51 percent higher than the NREL estimate for a similar but not necessarily identical plant.

The EIA and NREL estimates of nth-of-a-kind capital costs illustrate the range of costs that

may be realized, while the application of learning to the plant components illustrates the

extent to which costs could decline if the technology merely evolved without further

technological breakthroughs. Such breakthroughs could reduce the “footprint” of the plant

23For example, http://www.eia.doe.gov/oiaf/aeo/overview/electricity.html, “technological optimism factor

reflects the inherent tendency to underestimate costs for new technologies. The degree of technological

optimism depends on the complexity of the engineering design and the stage of development,” and EPRI,

Technical Assessment Guide, Volume 1: Electricity Supply-1986, pp. B-18 to B-20.

24See Energy Information Administration, Electricity Market Module Documentation, DOE/EIA-M068(2006),

pp. 69-73, web site http://tonto.eia.doe.gov/FTPROOT/modeldoc/m068(2006).pdf.

25A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. Neeves, J. Sheehan, and B. Wallace, Lignocellulosic Biomass to

Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and Enzymatic

Hydrolysis for Corn Stover, NREL/TP-510-32438 (June 2002).

26Escalated by Chemical Engineering Plant Cost Index, from 2000 to 2005 constant dollars.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 33

and lead to much greater cost reductions than currently projected by EIA. Such

breakthroughs are not predictable, however, and assuming that they will occur would

indicate a higher degree of technological progress than has been observed for other

technologies.27

Agriculture Market Impacts

Dramatic increases in domestic production of corn ethanol would be needed to meet the

renewable fuels requirement in the Policy Case. Corn ethanol production reaches 25 billion

gallons in 2025 in the Policy Case, and U.S. corn production is projected to be insufficient

to meet the total demand for corn at such high levels of ethanol production.

Historically, the United States has been a large exporter of corn, and in the absence of new

policy it is projected to continue exporting corn. But assuming that corn and cellulose

would be the only sources of ethanol, the United States would be required to import corn or

corn products to meet demand in the Policy Case. For example, U.S. corn exports total 2.7

billion bushels in 2025 in the Reference Case, whereas corn imports total 1.9 billion bushels

in 2025 in the Policy Case (Table 6).

It is likely, however, that U.S. agriculture and biofuels markets would adjust to higher corn

prices in ways that would eliminate the need for corn imports. For instance, feedstocks

previously regarded as uneconomical might be used to produce ethanol or biodiesel (in the

United States or elsewhere) to meet the requirement. Furthermore, the projections assume

that corn yields would continue to increase at historical rates, from 151 bushels per acre in

2006 to 183 bushels per acre in 2025. Genetic improvements to corn plants, however, may

allow quicker yield growth or higher sugar/starch content. Any of these developments,

which may be triggered by the relatively higher price of corn, would lessen the need for

corn imports in the Policy Case. Alternatively, any corn imports could be in the form of a

wide range of finished and intermediate products that contain corn.

EIA models domestic ethanol production from corn and cellulosic biomass and Brazilian

ethanol production from sugar cane. It is possible that very high corn prices could cause

U.S. ethanol producers to turn to other starchy or sugary crops that EIA has not modeled,

such as sugar cane, higher-starch corn, sorghum, wheat, barley, sugar beets, potatoes, or

cassava. Ethanol producers might also choose corn wet-mill technology over corn dry-mill

technology to produce ethanol. Wet mills produce corn oil, corn gluten meal, and corn

gluten feed as co-products. The output of these products per bushel of corn is more valuable

than DDGS from a dry mill, but wet mills require higher capital expenditures.

New corn ethanol plants are assumed to be the dry-mill type, producing DDGS as a coproduct. DDGS can be used as an animal feed supplement, but there are limits on its use,

depending on the type of animal. At current levels of corn ethanol production, DDGS is

assumed to sell for the price of corn on a weight basis. This analysis assumes that the

DDGS value starts to fall in relation to corn at a production level of 18 billion gallons. If the

value of DDGS falls sufficiently, it is assumed that the DDGS would be burned for process

27A. McDonal and L. Scharattenhozer, “Learning Rates for Energy Technologies,” Energy Policy, Vol. 29,

No. 4 (2001), pp. 255-261.
34 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

energy at the ethanol plant. In 2025, 78 million tons of DDGS is projected to be produced in

the Policy Case, with 15 million tons used for process energy.

There are many uncertainties about the agriculture market impacts of high levels of biofuels

demand. The corn price in 2025 is projected to rise from $3.00 per bushel (2005 dollars) in

the Reference Case to $6.50 per bushel in the Policy Case (Table 6). The higher corn prices

would cause prices for other commodities to rise, and the increases would be reflected in

food prices. In the short term, higher food prices would impose hardships on developing

nations. In the longer term, however, farmers in the developing world could benefit from

the increased demand for agricultural products, which would lead to more investment and

more farm employment. Some investments could enable current subsistence farmers to

market their surplus output.

EIA models domestic biodiesel production from soybean, cottonseed, canola (edible

rapeseed), sunflower oils, yellow grease, and animal fats. European biodiesel producers

prefer industrial rapeseed oil for raw material, because it yields biodiesel with better cetane

and cold flow properties than soybean oil biodiesel. Industrial rapeseed is not edible,

however, which limits it potential market and marketability by farmers. U.S. farmers want

as many markets for their crop as possible to enhance profits at minimum risk, and they

tend to resist cultivation of crops specialized to one use. Farmers like the fact that

conventional corn and soybeans can be sold for food or industrial use.

The proposed RFS policy probably would result in added incentives for farmers to grow

specialized biofuels crops beyond those incorporated in current modeling structures. It is

possible that U.S. agriculture in the future will be better optimized for biofuels production.

Finally, EIA also does not model biodiesel production from algae or jatrohpa, both of which

promise higher yields of oil per acre of land than soybeans.

Meeting the requirements of the proposed Policy could be more costly than indicated in this

analysis if other nations also increased their requirements for renewable motor fuels. Japan,

for example, recently mandated ethanol-blended gasoline, and the European Union has set a

target of 5.75 percent biofuels in fuels for light-duty vehicles. The proposed Policy would

also be affected by the choices of other nations that produce and export biofuels. Brazil, the

largest exporter of ethanol, and Indonesia and Malaysia, major exporters of palm oil that

can be used to make biodiesel, might choose to use more of their production domestically to

displace fossil fuels.

Natural Gas Supply

In the Policy Case, natural gas consumption declines in the electric power sector as natural

gas generation is displaced by renewable energy sources (Table 7). In the industrial sector,

natural gas consumption increases in the Policy Case, as more natural gas is used in the

production of corn-based ethanol. Natural gas consumed in petroleum refining is included

in the industrial natural gas consumption figures shown in Table 7.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 35

Table 7. Natural Gas Consumption by Sector, 2030

(trillion cubic feet)

Consumption Category Reference Case Policy Case

Residential and Commercial 9.6 9.6

Electric Power 5.9 5.0

Industrial 8.6 9.1

 Petroleum Refining 1.2 1.7

Other Consumption 2.0 1.9

Total U.S. Consumption 26.1 25.6

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

The increase in natural gas consumption for corn-based ethanol production in the Policy

Case partially offsets the decline in natural gas consumption for electric power generation.

As a result, total natural gas consumption and supply are projected to be only slightly (0.5

trillion cubic feet) lower in the Policy Case than in the Reference Case (Tables 7 and 8).

Table 8. Natural Gas Supply by Source, 2030

(trillion cubic feet)

Supply Category Reference Case Policy Case

U.S. Natural Gas Production 20.4 20.0

Net Pipeline Imports 0.9 0.9

Net LNG Imports 4.6 4.5

Supplemental Supply 0.1 0.1

Total Natural Gas Supply 26.0 25.5

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Coal Supply

Total coal production in the Policy Case is projected to be 23 percent (340 million tons)

lower in 2025 and 25 percent (426 million tons) lower in 2030 than in the Reference Case

(Figure 16). The impacts fall more heavily on coal production west of the Mississippi River,

which meets most of the incremental demand for coal in the Reference Case. While the RFS

also affects coal markets to some extent, the RPS for the electricity sector is the dominant

influence that drives the shift away from coal in the Policy Case.

The displacement of coal-fired electricity generation by renewable generation accounts for

most of the reduction in coal consumption in the Policy Case relative to the Reference Case,

and much of the remaining decline is attributable to decreased production of coal-based

synthetic liquids. In 2025, coal-fired generation is 691 billion kilowatthours lower in the

Policy Case than in the Reference Case, equal to 73 percent of the increase in renewable

generation in 2025. In 2030, the decline in coal-fired generation in the Policy Case is even

larger, amounting to 938 billion kilowatthours—equal to 93 percent of the increase in

renewable generation in 2030 (see Table 2).
36 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Figure 16. Coal Production by Region, Reference and Policy Cases

 (million short tons)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Reduced output of coal-based synthetic liquids in the Policy Case results from lower

demand for diesel and other petroleum products and a lower selling price for the excess

electricity generated at CTL plants. Relative to the Reference Case, coal consumption at

CTL plants in the Policy Case is 50 million tons lower in 2025 and 61 million tons lower in

2030.

Economic Impacts

In the Policy Case, higher energy and food prices are projected to reduce economic activity

(Table 9). Achieving 25-percent penetration of renewable fuels in both electricity

generation and motor transportation leads to higher energy prices as consumers substitute

more expensive renewable fuels for less expensive fossil fuels. Higher renewable fuel

demand, in turn, increases the cost of key inputs and results in higher electricity and

transportation prices.

Impacts on Energy and Aggregate Prices

Consumer energy prices in the Policy Case rise steadily for the first 10 years of the

projection, to 13.0 percent above prices in the Reference Case—roughly one-quarter of the

increase in overall consumer prices. The peak consumer price inflation occurs in 2025,

when the renewable standards are met, then starts to subside. The inflation rate (year-toyear change in consumer prices) reaches 12.7 percent for consumer energy prices and 3.0

percent for overall consumer prices in 2025. As energy prices begin to recede, overall

consumer prices stabilize to approximately 3.0 percent above Reference Case levels.

Wholesale prices show similar patterns: peaking in 2025, then starting to stabilize at higher

levels after 2025 (Figure 17).
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 37

Table 9. Economic Impacts, Policy Case

2020 2025 2030

2006 Reference Policy Reference Policy Reference Policy

Components of GDP

(billion 2000 dollars)

GDP 11,415 17,082 17,060 19,670 19,595 22,496 22,427

 Consumption 8,083 12,010 11,989 13,732 13,693 15,590 15,584

 Investment 1,966 3,034 3,029 3,772 3,762 4,737 4,797

 Government 1,997 2,396 2,399 2,542 2,549 2,710 2,723

 Exports 1,299 3,588 3,571 4,902 4,836 6,586 6,439

 Imports 1,928 3,768 3,755 4,966 4,960 6,654 6,715

Aggregate Prices in the Economy

 WPI – Fuel & Power (1982 = 1.0) 1.72 1.83 1.84 2.12 2.25 2.42 2.57

 CPI – Energy (1982/84 = 1.0) 2.03 2.17 2.25 2.51 2.79 2.85 3.15

 CPI – All Urban (1982/84 = 1.0) 2.02 2.60 2.63 2.90 2.98 3.23 3.34

 WPI – All commodities (1982 = 1.0) 1.66 1.81 1.85 1.94 2.06 2.06 2.19

Inflation Rate, Unemployment Rate

and Federal Funds Rate

 Inflation 3.56 1.83 2.09 2.26 3.02 2.27 2.24

 Unemployment Rate 4.72 4.46 4.56 4.54 4.70 4.71 4.90

 Federal Funds Rate 5.01 5.04 5.22 5.10 5.52 5.19 5.25

Industrial Sector

(billion 2000 dollars)

 Total Industrial 5,899 7,792 7,703 8,590 8,344 9,502 9,188

 Non-Manufacturing 1,557 1,847 1,802 1,937 1,859 2,022 1,955

 Manufacturing 4,342 5,945 5,901 6,654 6,485 7,480 7,233

 Energy-Intensive 1,186 1,431 1,416 4,528 1,470 1,635 1,565

 Non-Energy-Intensive 3,156 4,514 4,484 5,126 5,015 5,845 5,669

Disposable Income 8,279 13,007 12,989 15,171 15,137 17,530 17,529

Disposable Income Per Capita 27,632 38,582 38,529 43,248 43,153 48,036 48,032

Note: WPI = Wholesale Price Index; CPI = Consumer Price Index.

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Figure 17. Consumer and Producer Prices, Policy Case

 (percent change from Reference Case)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.
38 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

GDP and Consumption Impacts

In general, higher delivered energy prices relative to a baseline reduce real output for the

economy, energy consumption, and, indirectly, real consumer spending for other goods and

services due to lower purchasing power. In the Policy Case, higher energy prices result in

lower aggregate demand for goods and services and lower real GDP relative to the

Reference Case (Figure 18). In the Policy Case, total discounted GDP losses28 over the 2009

to 2030 time period are $296 billion (-0.12 percent) relative to the Reference Case. After

energy prices peak in 2025, both real GDP and consumption begin to return to baseline

levels.

Real GDP is a measure of what the economy produces; however, consumers ultimately are

interested in their purchases of goods and services, or “consumption.” GDP and

consumption impacts of a proposed policy can differ if the policy leads to changes in the

level and shares of the GDP: consumption, investment, government expenditures, and net

exports. In the Policy Case, cumulative discounted consumption losses relative to the

Reference Case are $149 billion (-0.09 percent). Consumption impacts, like GDP impacts,

generally grow over time; however, as energy price increases subside, consumption begins

to return to the respective reference cases. On an undiscounted basis, GDP and consumption

losses are much larger29 (Figure 18).

Figure 18. Real GDP and Consumption Impacts, Policy Case

 (cumulative change from Reference Case, billion 2000 dollars)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

Industry and Employment Impacts

As energy prices increase, the energy-intensive sectors, including food, paper, bulk

chemicals, petroleum refining, glass, cement, steel, and aluminum, show greater losses than

28The discount rate used to compute macroeconomic losses in GDP and consumption losses is 4 percent.

29Using the economic principle of discounting and the time value of money tends to weigh losses at the

beginning of a period more than equal losses at the end of a period. For example, a dollar loss in 2030 is

valued at about $0.45 in 2010 when discounted at 4 percent.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 39

the rest of the industrial sectors, reaching 4.3 percent below the Reference Case in 2030 in

the main Policy Case. Figure 19 shows output losses for the industrial sector as a whole and

for the energy-intensive industries in the Policy Case. The industrial value of shipments in

the energy-intensive industries is down by 4.3 percent relative to the baseline in 2030, as

higher inflation and lower demand impact industrial activity. Total non-farm employment is

down by 0.1 percent in 2030, as a result of lower industrial activity.

Figure 19. Industrial Impacts, Policy Case

(percent change from Reference Case)

Source: National Energy Modeling System, runs IBASE.D060607A and IRES2525.D060607A.

 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 41

4. Alternative Cases

Chapter 2 described some of the analytic issues and uncertainties associated with an

analysis of the proposed Policy—national implementation of a 25-percent RPS and a 25-

percent RFS by 2025. Chapter 3 summarized EIA’s analysis of the expected consequences

of the Policy, using a Reference Case based on assumptions close to those of the AEO2007

reference case. This chapter describes analyses estimating the likely impacts of the same

Policy in alternative cases, based on different assumptions about key uncertainties in the

Reference Case.

Assessment of the consequences of any potential policy or proposed legislation requires the

selection of a reference case against which impacts are to be measured; however, the

reference case chosen will inevitably include a variety of uncertainties, including most

importantly the future path of national economic growth, energy prices, and the

development and adoption of new technologies. Any change in reference case assumptions

about the specific resolution of such uncertainties in a projection represents, in effect, a

potential alternative reference case or “view of the world.” For example, the high and low

economic growth cases and the high and low price cases in AEO2007 represent such

potential alternative reference cases or outlooks.

For this analysis, EIA chose three groups of key uncertainties to be examined, first by

changing assumptions from those in the Reference Case—creating three “alternative

reference cases”—and then by adding the policy assumptions to each of the alternative

cases.30 The resulting six cases, which were summarized briefly in Chapter 1 (see Table 1),

are as follows:31

• High Price Case: The High Price Case, modified from the AEO2007 high price case

to incorporate the same changes in assumptions that were made in the Reference Case

for this study, uses more pessimistic assumptions for worldwide crude oil and natural

gas resources. In this alternative reference case, world light, sweet crude oil prices in

2030 are about 70 percent higher than projected in the Reference Case.

• High Price Policy Case: Combines the High Price Case with model changes required

to meet the Policy assumptions.

• Low-Cost Ethanol Imports Case: This alternative reference case incorporates the

same changes in assumptions that were made in the Reference Case for this study but

30Typically, EIA tries to select pairs of alternative cases for its analyses that represent both more pessimistic

and more optimistic assumptions about how key uncertainties will be resolved. In this analysis that was not

possible, primarily because assumptions opposite to those used for the alternative cases described in this

chapter—low price path for liquid fuels and natural gas, reduced availability and higher prices for ethanol

imports, and slower rates for the development and adoption of renewable energy technologies (including

reduced availability of biomass supplies)—would raise the cost of the policy substantially and, in all

probability, make it outright impossible to achieve in some cases.

31The High Price Case was specifically requested by Senator Inhofe. The Low-Cost Ethanol Imports Case and

High Renewable Technology Case were added by EIA to demonstrate the impacts of two other key groups of

parameters.
42 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

replaces the Reference Case ethanol import supply curves with more optimistic supply

curves.32

• Low-Cost Ethanol Imports Policy Case: Combines the Low-Cost Ethanol Imports

Case with the Policy assumptions.

• High Renewable Technology Case: This alternative reference case, which is also

referred to as the High Technology Case, incorporates the same changes in

assumptions that were made in the Reference Case for this study and in addition uses

assumptions for advanced renewable generation technologies and cellulosic ethanol

production from the AEO2007 high renewables case, and a much larger biomass

supply (see Appendix B, Figure B1).

• High Technology Policy Case: Combines the High Technology Case with the Policy

assumptions.

Measuring and Interpreting the Relative Impacts of the Policy

In this chapter, each of the three alternative reference cases has an associated policy case.

Each alternative reference case (without the Policy assumptions) represents an alternative

outlook for the U.S. energy economy, which in turn ultimately determines the magnitude of

the energy and economic costs when the proposed Policy is added to it. In comparing the

impacts of the Policy on the alternative reference cases, the appropriate comparison is

between the paired reference and associated policy cases because they represent the same

basic outlook for everything except the Policy. Comparisons between one reference case

and the policy case for a different reference case with the Policy imposed are generally

inappropriate. For example, comparison of gasoline prices in the Reference Case described

in Chapter 3 with gasoline prices in the High Price Policy Case would be inappropriate

because it would overstate the costs of the Policy. Similarly, comparison of gasoline prices

in the Reference Case with gasoline prices in the High Technology Policy Case would also

understate the costs of the Policy, unless there is a strong basis for claiming that the more

favorable technology menu in the High Technology Policy Case is available only as a direct

result of the Policy.

Absent a direct link between the scenario assumptions and the Policy examined in this

report, the appropriate measure of the effects of the Policy under different sets of underlying

assumptions is the change in a given projection (such as gasoline prices) in an alternative

policy case from the same projection in the corresponding alternative reference case. The

impact estimates provided in this chapter reflect this approach.

32While the Low-Cost Ethanol Import Case shows slightly greater ethanol imports (3.4 billion gallons in 2025)

than the Reference Case (3.3 billion gallons in 2025), little else changes relative to the Reference Case.

Consequently, results from the Low-Cost Ethanol Imports Case generally are omitted from the tables and

figures in this chapter.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 43

Electricity Sector Impacts

In the three alternative reference cases presented in this chapter, renewable energy is more

competitive than in the main Reference Case, because the assumptions in the alternative

cases either lower the cost of renewable energy or raise the cost of fossil energy. Low-cost

ethanol imports or more rapid progress in the development and adoption of renewable

technologies would lower the cost of renewable energy; higher oil and natural gas prices

would raise the prices of the fossil fuels that compete with renewables. In each of the

corresponding policy cases, the projections for RPS credit prices and the impacts on

electricity prices are lower than those in the main Policy Case (Table 10).

In the Low-Cost Ethanol Imports Policy Case, the availability of low-cost ethanol imports

reduces the use of domestic biomass by U.S. ethanol producers and makes more biomass

available to power producers. In the High Price Policy Case, higher oil and natural gas

prices reduce the incremental costs of increasing renewable fuel use in power generation,

thus reducing the cost of complying with the 25-percent RPS. Similarly, in the High

Technology Policy Case, more rapid improvement in the cost and performance of new

renewable technologies makes those technologies more economically attractive and lowers

RPS compliance costs.

RPS Credit Prices

In the main Policy Case, the RPS credit price rises sharply between 2020 and 2025 as the

required renewable generation share grows to the 25-percent target (Figure 20). The RPS

credit price in the Policy Case peaks at about 4.8 cents per kilowatthour in 2025 and then

generally hovers between 3.8 and 4.6 cents per kilowatthour thereafter. The same general

pattern is seen in the alternative policy cases, but the RPS credit prices tend to peak at a

lower level in 2025 and then fall after 2025:

• In the Low-Cost Ethanol Imports Policy Case, the RPS credit price peaks at 4.3 cents

per kilowatthour in 2025, then falls to a level of 2.5 to 3.0 cents per kilowatthour from

2025 to 2030. U.S. ethanol producers use less biomass in this case because of the

lower-cost ethanol imports. The resulting increased availability of lower-cost biomass

to power producers reduces their need for more expensive renewables after 2025.

• In the High Price Policy Case, the RPS credit price peaks at 4.6 cents per kilowatthour

in 2025 and then generally hovers between 3.2 and 3.5 cents per kilowatthour between

2025 and 2030. The higher oil and natural gas prices after 2025 in the High Price Case

(compared to the Reference Case) reduce the credit price that is needed to stimulate

renewable technology options for complying with the 25-percent RPS.

• In the High Technology Policy case, RPS credit prices are much lower than in the

Policy Case, peaking at 3.4 cents per kilowatthour in 2025 and falling to 1.3 cents per

kilowatthour in 2030. More rapid improvement in renewable generation technologies,

particularly the biomass generation technology, is the key factor leading to the lower

RPS credit prices in this case. In fact, generation from biomass combustion in

dedicated plants in the High Technology Case, without the 25-percent RPS

requirement, is more than three times the projected level in the Reference Case in

2025, making the additional requirements in the High Technology Policy Case less

difficult to meet.
44 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Table 10. Summary of Electricity Sector Impacts of Alternative Policy Cases, 2025

2005 Reference Policy

Low-Cost

Ethanol

Imports

Policy

High

Price

High

Price

Policy

High

Tech

High Tech

Policy

RPS Credit Price

(2005 cents per kilowatthour) NA NA 4.8 4.3 NA 4.6 NA 3.4

Capacity (gigawatts)

 Coal Steam 315 406 323 323 442 353 393 325

 Other Fossil Steam 121 88 81 82 75 77 89 81

 Combined Cycle 177 210 196 196 194 195 208 197

 Combustion Turbine/Diesel 133 135 146 140 128 140 134 142

Nuclear Power 100 112 103 103 122 103 112 103

 Pumped Storage 21 21 21 21 21 21 21 21

 Other 0 6 8 7 5 6 5 8

 Conventional Hydropower 81 81 86 83 81 84 81 83

 Geothermal 2 3 9 6 3 8 3 6

 Municipal Solid Waste/Landfill Gas 4 4 6 5 4 5 4 5

 Wood and Other Biomass 7 10 75 90 11 80 26 86

 Solar11 2 2 2 2 2 2 2

 Wind 10 18 131 98 18 123 18 107

 Other Industrial Capacity218 31 33 33 27 28 31 32

 Total 988 1,127 1,220 1,190 1,134 1,224 1,127 1,198

Generation (billion kilowatthours)

 Coal 2,015 2,853 2,162 2,163 3,108 2,360 2,764 2,191

 Petroleum 122 105 101 100 91 87 105 101

 Natural Gas 752 1,001 768 770 695 604 974 755

 Nuclear Power 780 886 815 815 967 815 886 815

 Pumped Storage/Other 13 8 8 8 8 8 8 8

 Conventional Hydropower 265 308 328 319 308 322 309 318

 Geothermal 15 22 66 47 24 59 23 44

 Municipal Solid Waste/Landfill Gas 23 27 40 35 27 35 28 34

 Dedicated Biomass 30 57 536 646 62 568 174 622

 Biomass Co-Firing 7 67 84 110 78 88 60 89

 Solar11 4 4 4 5 5 5 4

 Wind 15 51 425 326 52 408 52 378

 Total 4,038 5,389 5,338 5,343 5,424 5,358 5,387 5,360

Electricity Prices and Sales

 Electricity Sales (billion kilowatthours) 3,660 4,826 4,778 4,785 4,813 4,778 4,823 4,802

 Retail Electricity Price (2005 cents per kWh) 8.10 7.99 8.26 8.26 8.25 8.48 7.98 8.08

Electric Sector Emissions

 Sulfur Dioxide (million short tons) 10.21 3.72 3.56 3.51 3.57 3.50 3.73 3.46

 Nitrogen Oxides (million short tons) 3.60 2.25 1.93 2.03 2.19 1.92 2.24 1.99

 Mercury (short tons) 51.25 16.86 16.86 17.35 15.79 15.42 16.83 16.86

 Carbon Dioxide (million metric tons) 2,375 3,046 2,425 2,428 2,964 2,386 2,983 2,450

Fuel Prices (2005 dollars)

 Natural Gas Wellhead Price (dollars per mcf3) 7.51 5.54 5.47 5.45 6.73 6.64 5.59 5.38

 Coal Minemouth Price (dollars per ton) 23.34 21.83 21.34 20.83 24.14 22.37 21.63 20.76

1

Includes solar thermal power, utility-owned photovoltaics, and distributed photovoltaics.

2

Includes capacity in the industry sector fueled by petroleum, natural gas, or other gaseous fuels.

3mcf = thousand cubic feet.

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES252HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 45

Electricity Prices

The projected increases in electricity prices between the three alternative reference cases

and their corresponding policy cases are generally smaller than the increase between the

main Reference Case and the Policy Case (Figure 21). In the Policy Case, electricity prices

reach 8.3 cents per kilowatthour in 2025, 0.3 cents per kilowatthour (3.3 percent) higher

than in the Reference Case; and in 2030, the price difference between the Reference Case

and the Policy Case grows to 0.5 cents per kilowatthour (6.2 percent). In the Low-Cost

Ethanol Imports Policy Case, electricity prices are also 0.3 cents per kilowatthour (3.5

percent) higher in 2025 than in the Low-Cost Ethanol Imports Case, but the difference does

not change by much after 2025. In the High Price Policy Case, electricity prices are 0.2

cents per kilowatthour (2.9 percent) higher than in the High Price Case in 2025 and 0.4

cents per kilowatthour (4.8 percent) higher in 2030.

Figure 20. RPS Credit Prices in Alternative Policy Cases

 (2005 cents per kilowatthour)

Source: National Energy Modeling System, runs IRES2525.D060607A, IRES2525LCB.D060607A, IRES2525HP.D060607A,

and IRES2525HT.D060607A.

The importance of assumptions about technological progress is illustrated by their impact

on electricity prices in the High Technology Policy Case: electricity prices in the High

Technology Policy Case are only 0.1 cent per kilowatthour higher than prices in the High

Technology Case in 2025, and there is virtually no difference in electricity prices between

the two cases in 2030. In the High Technology Policy Case, new renewable technologies,

particularly biomass, are competitive with nonrenewable generating technologies.

Electricity Generation by Fuel

Renewable generation in the alternative policy cases is generally similar to that in the main

Policy Case (Figure 22). In all the alternative policy cases, there are very large increases in

biomass and wind generation and smaller increases in geothermal and conventional

hydroelectric generation, relative to the corresponding reference cases. The competition

between biomass and wind to supply the generation needed to comply with the 25-percent
46 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

RPS does vary slightly among the alternative policy cases. In the Low-Cost Ethanol Imports

Policy Case, where lower cost biomass is available to the power sector, there are larger

increases in biomass electricity generation than are projected in the main Policy Case

relative to the Reference Case.

Figure 21. Electricity Prices in Alternative Policy Cases, 2025 and 2030

 (cents per kilowatthour)

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IRES2525LCB.D060607A,

IHIPRICE.D060607A, and IRES2525HP.D060607A.

Figure 22. Renewable Generation in 2025 in Alternative Cases

 (billion kilowatthours)

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IRES2525LCB.D060607A,

IHIPRICE.D060607A, and IRES2525HP.D060607A.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 47

Transportation Sector Impacts

Demand for transportation services is responsive to changes in fuel prices; however, the

projected impacts on travel and fuel economy in the policy cases relative to their respective

reference cases are minimal, because there are only minor fuel price changes between the

reference cases and the associated policy cases. Transportation fuel prices vary the least

between the High Price Case and High Price Policy Case and between the High Technology

Case and the High Technology Policy Case (Table 11). As a result, travel demand and fuel

economy show only marginal impacts, and the change in total transportation energy

consumption in 2025 varies by only about 0.5 percent, across the paired reference and

policy cases.

Table 11. Transportation Sector Key Indicators and Delivered Energy Consumption, 2025

2005 Reference Policy High Price

High Price

Policy High Tech

High Tech

Policy

Light-Duty Vehicles (LDVs)

 Billion Miles Traveled 2,721 3,930 3,869 3,664 3,641 3,935 3,909

 Efficiency (miles per gallon)

 Average for New LDVs 25.2 29.1 29.1 31.6 31.0 29.0 28.8

 New Cars 30.0 33.5 33.8 35.8 35.7 33.5 33.6

 New Light Trucks 21.8 26.1 25.7 27.9 26.9 26.1 25.6

 Average: All LDV Stock 19.7 21.9 21.7 23.1 22.9 21.7 21.6

New Car Sales (thousands) 8,109 8,687 9,095 10,255 10,127 8,631 8,815

New Light Truck Sales (thousands) 8,789 11,266 10,364 9,626 9,408 11,336 10,880

Highway Energy Use (quadrillion Btu)

 All LDVs 16.9 21.6 21.5 18.9 19.4 21.7 21.7

 Automobiles 8.4 8.7 9.0 9.0 9.0 8.7 9.0

 Light Trucks 8.5 12.9 12.5 9.9 10.3 12.9 12.7

Energy Use by Fuel (quadrillion Btu) 16.9 21.6 21.5 18.9 19.4 21.7 21.7

 Motor Gasoline 16.6 20.8 14.4 17.9 13.4 20.9 15.3

 Distillate Fuel Oil (Diesel) 0.3 0.7 0.1 0.8 0.1 0.7 0.1

 E85 0.0 0.0 6.2 0.0 5.8 0.0 6.3

Total Transportation Energy Demand

(quadrillion Btu) 28.1 36.5 36.0 33.3 33.5 36.6 36.4

Key Transportation Fuel Prices (dollars per gallon)

 Average Gasoline Price 2.32 2.16 2.44 3.06 3.20 2.12 2.26

 Average Diesel Price 2.41 2.21 2.70 2.96 3.27 2.22 2.49

 Average E85 Price 2.19 2.22 1.89 2.51 2.49 2.15 1.74

Transportation Energy Expenditures, 2009-2025

 Cumulative Undiscounted Billion Dollars NA 8,493 8,759 10,773 10,924 8,482 8,616

 Discounted at 7 Percent NA 5,121 5,232 6,396 6,462 5,117 5,175

Note: All prices are shown in 2005 dollars.

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES252HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.

Because renewable fuels are more competitive in the High Price Case and the High

Technology Case than in the Reference Case, the RFS credit price is highest in the Policy

Case (Table 12). Consequently, in the Policy Case, gasoline prices in 2025 are 13 percent
48 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

higher and diesel prices are 22 percent higher than projected in the Reference Case, whereas

in the High Price Policy Case gasoline and diesel prices in 2025 are 5 percent and 10

percent higher, respectively, than in the High Price Case, and in the High Technology Case

gasoline and diesel prices in 2025 are 7 percent and 12 percent higher, respectively, than

projected in the High Technology Case. Unlike gasoline and diesel fuel prices, E85 prices

are lower in the policy cases than in the corresponding reference cases, because revenues

from the credits are assumed to be used to reduce the cost of ethanol production.

Because the Policy Case has the highest RFS credit prices and the largest relative increases

in fuel prices, it also has the largest increase in transportation energy expenditures.

Compared with the Reference Case, transportation energy expenditures in 2025 are $68

billion (about 12 percent) higher in the Policy Case. Compared with the High Price Case,

transportation energy expenditures in 2025 are $43.1 billion (about 6 percent) higher in the

High Price Policy Case. And compared with the High Technology Case, transportation

energy expenditures in 2025 are $35 billion (about 6 percent) higher in the High

Technology Policy Case. From 2009 to 2025, cumulative undiscounted transportation

energy expenditures by consumers are $266 billion higher in the Policy Case than in the

Reference Case, $151 billion higher in the High Price Policy Case than in the High Price

Case, and $132 billion higher in the High Technology Policy Case than in the High

Technology Case—again illustrating that the starting point (reference case) and the pace of

technological progress can have significant impacts in determining the projected effects of

policy changes on energy expenditures.

Table 12. Liquid Fuels Supply Impacts in Alternative Policy Cases, 2025

2005 Reference Policy High Price

High Price

Policy High Tech

High Tech

Policy

Supply Balance (million barrels per day)

 Net Crude Oil Imports 10.0 12.0 11.3 9.8 9.5 12.0 11.4

 Net Product Imports 2.5 2.9 1.8 1.7 1.1 2.8 1.7

 Ethanol Imports 0.01 0.2 0.5 0.3 0.5 0.2 0.4

 Domestic Ethanol Supply 0.3 0.6 3.5 0.8 3.2 0.8 3.7

 Net Import Share of Liquids 60.5 59.6 51.1 49.6 44.2 59.0 50.9

Ethanol (billion gallons)

 Corn-Based 3.9 9.0 25.6 11.9 24.1 8.7 18.9

 Cellulosic 0.00 0.25 28.1 0.2 24.6 4.0 38.0

 Imports 0.1 3.3 7.7 2.9 7.5 3.0 5.3

 Total 4.0 12.5 61.3 15.1 56.2 15.8 62.2

Consumption (quadrillion Btu)

 E85 0.00 0.01 6.2 0.02 5.8 0.01 6.3

 Motor Gasoline 17.0 21.3 15.5 18.3 13.8 21.3 15.7

 Transportation Liquid Fuels 27.4 35.6 35.1 32.4 32.6 35.6 35.5

 All Liquid Fuels 39.5 48.1 47.3 44.3 44.2 48.1 47.8

Delivered Liquid Fuel Product Prices (2005 dollars per gallon)

 E85 2.19 2.22 1.89 2.51 2.49 2.15 1.74

 Ethanol Wholesale Price 1.80 1.64 2.76 1.68 2.73 158 2.02

 Motor Gasoline 2.32 2.16 2.44 3.06 3.20 2.12 2.26

 RFS Credit Price NA NA 2.18 NA 1.46 NA 1.34

Total Energy Expenditures (billion 2005 dollars) 907 1,236 1,317 1,460 1,513 1,231 1,269

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES252HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 49

Primary Energy Consumption

Differences in primary energy consumption between the respective reference and policy

cases are similar across the cases (Figure 23). The largest difference is between the High

Technology Case and the High Technology Policy Case, where industrial sector use of

biofuels heat and co-products in 2030 is 4.8 quadrillion Btu higher in the High Technology

Policy Case than in the High Technology Case because of the lower costs and higher

availability of biomass supplies compared to the other reference and policy cases.

Primary energy consumption in 2025 increases in all the policy cases relative to their

respective reference cases, by between 3.0 and 4.5 quadrillion Btu, because coal- and

natural-gas-fired generating capacity is replaced by renewable capacity to meet the policy

mandates.33 With the large buildup of renewable generation capacity, more efficient

generation technologies using natural gas and coal are not added, and the average efficiency

of all fossil-fired generation is reduced. On the other hand, industrial natural gas

consumption increases as more ethanol production facilities begin operating.

Figure 23. Change in Primary Energy Consumption Across the Cases, 2025 and 2030

 (quadrillion Btu)

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES252HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.

Fuel Supplies

Fuel supply projections from the Reference Case, High Price Case, and High Technology

Case are summarized and compared with projections from the corresponding policy cases in

Table 12 (for liquid fuels) and Table 13 (for renewable fuels). As noted earlier, the starting

point (assumptions) for each case matters greatly. That is, the assumptions for the different

reference cases, without the policy requirements, determine the magnitude of the energy and

economic impacts when the policy requirements are added.

33A portion of the projected increase in primary energy consumption is due to the accounting framework used

to translate wind, geothermal, solar energy used for electricity generation to primary resource equivalents. The

accounting framework equates a kilowatthour of generated electricity to primary energy by multiplying by a

constant but somewhat arbitrary heat rate that is close to the fossil fuel generation system average.
50 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Table 13. Renewable Fuels Summary for the Reference and Policy Cases, 2025

2005 Reference Policy High Price

High Price

Policy High Tech

High Tech

Policy

RFS Results

 RFS Constraint (billion gallons) 3.5 9.0 66.0 8.4 61.0 9.0 66.9

 RFS Credit Price (2005 dollars per gallon) NA NA 2.18 NA 1.46 NA 1.34

Ethanol (billion gallons)

 Corn-Based 3.9 9.0 25.5 11.9 24.1 8.7 18.9

 Cellulosic 0.00 0.25 28.0 0.25 24.6 4.0 38.0

 Imports 0.1 3.3 7.7 2.9 7.5 3.0 5.3

 Total 4.0 12.5 61.3 15.1 56.2 15.8 62.2

 Ethanol Used in E85 0.01 0.05 48.1 0.1 44.4 0.1 48.9

 Ethanol Used in Gasoline Blending 4.0 12.5 13.2 15.0 11.9 15.7 13.3

 Ethanol Percent of Motor Gasoline Pool 2.9 7.0 31.2 9.7 31.7 8.8 31.2

 Blend Percent of Motor Gasoline Pool 2.9 6.9 9.4 9.5 9.6 8.6 9.4

Prices (2005 dollars)

 Corn Price (2005 dollars per bushel) 2.29 3.00 6.50 3.27 6.14 2.99 4.43

 Census Division 4 Biomass Price

 (2005 dollars per million Btu) 0.94 1.51 5.02 1.51 4.95 1.50 3.96

Agricultural Impacts

 Total Corn Crop (million bushels) 11,807 14,138 14,473 14,201 14,449 14,313 14,338

 Corn for Ethanol (million bushels) 1,323 3,363 9,228 4,462 8,805 3,247 6,871

 Percent of Corn Going to Ethanol 11 24 64 31 61 23 48

 Net Corn Exports (million bushels) 1,814 2,657 -1,871 1,809 -1,544 2,747 -52

 Corn Acres Harvested (million acres) 74 77 79 77 79 77 78

 Corn Yield (bushels per acre) 160 183 183 183 183 183 183

 Biomass Supplied (million tons)1<30 41 535 48 529 126 698

1

Biomass Supplied excludes wood and wood waste, which may be used for biomass power generation.

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES252HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.

For example, if the price of fossil fuels rose rapidly to three times the Reference Case

levels, and the potential for building new U.S. nuclear capacity were significantly limited,

the incremental cost of the policy through 2030, all else being equal, would be negligible,

because renewable generating technologies would probably be economical without any

additional incentives. On the other hand, if fossil fuel prices fell to less than $20 per barrel

and wellhead natural gas prices to $2.00 per thousand cubic feet, all else being equal, the

incremental cost of the policy would be considerably higher than projected in the Policy

Case for this analysis.

World oil prices and U.S. natural gas prices, the rate of improvement in renewable

generation and cellulosic ethanol technologies, and the availability and prices of domestic

biomass and imported ethanol are key determinants of the cost of implementing the 25-

percent RPS and RFS policy in this analysis. The High Price Case represents an alternative

view of the future with significantly higher world oil and domestic natural gas prices. The

High Technology Case represents a view that incorporates the Reference Case assumptions

in all areas except renewable technology development, the availability of low-cost biomass

supplies, and the rate of technological progress in developing cellulosic ethanol technology.

The other uncertainty examined for this analysis is the availability of imported ethanol at

low cost. The Low-Cost Ethanol Imports Case, in addition to incorporating all the
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 51

Reference Case assumptions, assumes the availability of large quantities of ethanol imports.

As expected, the impacts of the Policy on this case are dramatic: a projected 20.7 billion

gallons of ethanol is imported in 2025 in the Low-Cost Ethanol Imports Policy Case,

compared with 3.4 billion gallons in the Low-Cost Ethanol Imports Case, 7.7 billion gallons

in the Policy Case, and 3.3 billion gallons in the Reference Case. The dramatic increase of

ethanol imports in the Low-Cost Ethanol Imports Policy Case delays the need for

accelerated development of domestic production facilities for corn-based and cellulosic

ethanol and makes more domestic biomass available for use in electricity generation. As a

result, the projected RPS and RFS credit prices are lower than those in the Policy Case, and

the impacts on electricity and motor fuel prices are smaller.

High Price Policy Case

Price increases in High Price Policy Case (relative to the High Price Case) are smaller than

the price increases between the Reference Case and the Policy Case, because the price of

liquid petroleum products in the High Price Case is higher than those in the Reference Case

and closer to the prices of the renewable fuels that replace them. As such, the shift to

alternative motor transport fuels in the High Price Policy Case results in a smaller price

increase relative to the High Price Case than is seen in the Policy Case relative to the

Reference Case.

By themselves, the assumptions of the High Price Case induce an additional 2.9 billion

gallons per year (32 percent) of corn ethanol production, even as the total demand for liquid

fuels falls from 48.1 to 44.3 quadrillion Btu (-7.9 percent) (Figure 24). However, the

product prices in the High Price Case are not high enough by themselves to induce the

building of cellulosic ethanol production facilities. Consumer energy expenditures in the

High Price Case are $224 billion (18 percent) above those in the Reference Case in 2025,

whereas in the Policy Case consumer expenditures are only 7 percent above those in the

Reference Case. In addition, the increase in consumer energy expenditures in the High Price

Policy Case relative to the High Price Case in 2025, $53 billion, is 35 percent smaller than

the increase in the Policy Case relative to the Reference Case (again, showing that the

starting point matters).

In the High Price Policy case, renewable fuels are more competitive with petroleum fuels

than projected in the Policy Case, and the RFS credit price in 2025 is 33 percent lower:

$1.46 per gallon compared with $2.18 per gallon (2005 dollars). The 4-percent increase in

consumer energy expenditures in 2025 in the High Price Policy Case relative to the High

Price Case, to $1,513 billion, is also smaller than the 6.6-percent increase in the Policy Case

relative to the Reference Case. As the price of domestically produced renewable liquids

moves closer to the price of petroleum liquids, the import share of liquids declines from 60

percent in the Reference Case to 50 percent in the High Price Case and to 44 percent in the

High Price Policy Case.

Because the 25-percent RFS requirement is met at a lower overall level of demand for

motor fuels in the High Price Policy Case than in the Policy Case, both corn ethanol

production and cellulosic ethanol production are lower, while ethanol imports are

essentially the same in the two cases. Corn ethanol production increases by 16.5 billion

gallons and cellulosic ethanol increases by 27.8 billion gallons in 2025 between the
52 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Reference and Policy Case. When the Policy is applied to the High Price Case, corn ethanol

production increases by 12.2 billion gallons, and cellulosic ethanol production increases by

24.4 billion gallons. Comparing the relative changes between the Policy Case and the High

Price Policy Case, the reduction in corn ethanol production is much smaller than the

reduction in cellulosic ethanol production due to the difference in the cost structures of corn

and cellulosic ethanol plants. That is, comparing the Policy Case to the High Price Policy

Case, corn ethanol production is 5.8 percent (1.4 billion gallons) lower in 2025, and

cellulosic ethanol production is 12 percent (3.4 billion gallons) lower. For the new

technology of cellulosic ethanol plants, cumulative learning effects lower the capital costs

as more capacity is built.

Figure 24. Sources of Renewable Fuel Supply in Alternative Cases, 2025

 (billion gallons)

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES2525HI.D060607A, IHITECH.D060607A, IRES2525HT.D060607A, ILCBRAZIL.D060607A, and

IRES2525LCB.D060607A.

Corn prices in the High Price Case, at $3.27 per bushel in 2025, are 9 percent higher than

projected in the Reference Case, and 33 percent (1.1 billion bushels) more corn is used for

ethanol production. In the High Price Policy Case, however, the amount of corn used for

ethanol production is 4.6 percent (0.4 billion bushels) less than in the Policy Case. At the

production levels projected in the analysis cases for this study, increases in the demand for

corn used in ethanol production are met, for the most part, not by the planting and

harvesting of more acres but by changes in net imports and consumer demand. As a result,

the percentage of the total U.S. corn crop consumed for ethanol production is somewhat

lower in the High Price Policy Case (61 percent) than in the Policy Case (64 percent).

The U.S. Department of Agriculture estimates that approximately 92.9 million acres of corn

is planted in the United States,34 of which 85.4 million acres is expected to be harvested,35

34USDA/National Agricultural Statistics Survey (NASS), Acreage, June 2007 (Washington, DC, June 29,

2007).
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 53

bringing 2007-2008 corn production to 12.8 billion bushels.36 The 85.4 million acres

harvested exceeds the level of corn acres harvested across all cases, as shown in Table 13

for 2025. The observations about the acreage planted and harvested point to the large degree

of uncertainty and volatility that arise in the agricultural markets, as discussed in Chapter 2.

High Technology Policy Case

In the High Technology Case, the price of renewable liquid fuels in the transportation sector

is lower than projected in the Reference Cases, because technological advances are assumed

to reduce the cost of building cellulosic ethanol production facilities and the cost of the

biomass supply to those facilities. The net cost of biofuel production in the High

Technology Case is reduced sufficiently to make biofuels (such as cellulosic ethanol)

competitive with conventional motor transport fuels without new policy mandates. As a

result, cellulosic ethanol production in 2025 increases from 250 million gallons per year in

the Reference Case and High Price Case to 4 billion gallons per year in the High

Technology Case. In the High Technology Policy Case, however, the RFS credit price,

which represents a “cross subsidy” for all qualified motor transport fuels, is still needed to

achieve the Policy requirement (Table 13).

In the High Technology Policy Case, the increase in cellulosic ethanol production leads to

lower corn ethanol production, lower corn prices, and lower energy expenditures by

consumers for motor fuels than in the Policy Case. Cellulosic ethanol production is

projected to total 38 billion gallons in 2025 in the High Technology Policy Case. As a

result, corn ethanol production in 2025 is 26 percent lower in the High Technology Policy

Case, at 18.9 billion gallons, than the 25.5 billion gallons projected in the Policy Case; corn

prices are 32 percent lower at $4.43 per bushel (2005 dollars); and corn imports are nearly

eliminated.

On the other hand, the increase in demand for biomass to be used in cellulosic ethanol

plants and electric power plants in the High Technology Policy Case is substantial. From a

level of less than 30 million tons supplied in 2005, the High Technology Policy Case

projects total U.S. demand for biomass in 2025 at 698 million tons, or 30 percent higher

than in the Policy Case. That would represent a substantial percentage of the total biomass

estimated to be available for use, raising concerns about the feasibility of achieving the

levels of supply that would be needed.

Total energy expenditures by consumers in the High Technology Policy Case in 2025 are

projected to total $1,269 billion, 3.6 percent below the Policy Case projection and only 3

percent above the Reference Case projection. Said another way, total energy expenditures

by consumers in the High Technology Policy Case in 2025 are $48 billion (3.6 percent) less

than in the Policy Case and only $33 billion (2.7 percent) more than in the Reference Case.

35USDA/World Agricultural Outlook Board (WAOB), World Agricultural Supply and Demand Estimates,

WASDE-448 (Washington, D.C., July 12, 2007).

36Ibid.
54 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Low-Cost Ethanol Imports Policy Case

In the Low-Cost Ethanol Imports Case, ethanol imports in 2025 are projected at 3.4 billion

gallons—not much more than the 3.3 billion gallons projected in the Reference Case. In the

Low-Cost Ethanol Imports Policy Case, however, imports of ethanol from Brazil total 20.7

billion gallons in 2025, an increase of 170 percent from the 7.7 billion gallons projected in

the Policy Case.

Like the High Price Policy Case, the Low-Cost Ethanol Imports Policy Case predominantly

affects demand for cellulosic ethanol in comparison with the Policy Case. Cellulosic ethanol

production in 2025 falls from 28 billion gallons in the Policy Case to 19.2 billion gallons in

the Low-Cost Ethanol Imports Policy Case (a 32-percent decrease), whereas corn ethanol

production falls from 25.5 billion gallons to 22.4 billion gallons (12 percent), because lower

demand for corn reduces corn prices, making corn-based ethanol more competitive with

cellulosic ethanol.

Given the level of corn ethanol displaced, the Low-Cost Ethanol Imports Policy Case results

in a smaller reduction in corn prices and a smaller reduction in RFS credit prices relative to

the Policy Case than are projected in the other alternative policy cases examined. For

example, the 2025 price of corn in the Low-Cost Ethanol Imports Policy Case, at $5.57 per

bushel in 2005 dollars, is 9 percent lower than projected in the High Price Policy Case and

26 percent higher than projected in the High Technology Policy Case. The RFS credit price

of $1.83 per gallon in 2005 dollars in 2025 in the Low-Cost Ethanol Imports Policy Case is

25 percent above the RFS credit price in the High Price Policy Case and 37 percent above

that in the High Technology Policy Case.

In summary, although the Low-Cost Ethanol Imports Policy Case reduces RFS credit prices

by 16 percent and corn prices by 14 percent relative to the Policy Case projections, the

savings achieved are not as great as those in the other alternative policy cases examined in

this study.

Economic Impacts

Key economic results illustrating the projected effects of implementing the Policy in the

Reference Case and in the High Price and High Technology alternative reference cases are

summarized in Table 14. As noted in Chapter 3, implementation of the proposed Policy in

the electricity generation and transportation markets would lead to higher energy prices as

consumers substitute more expensive renewable fuels for less expensive fossil fuels; and the

higher energy prices would lead to a decline in economic activity.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 55

Table 14. Summary of Economic Impacts of Alternative Policy Cases in 2025

Reference Policy High Tech

High Tech

Policy High Price

High Price

Policy

Components of GDP (billion 2000 dollars)

 GDP 19,670 19,595 19,676 19,645 19,673 19,628

 Consumption 13,732 13,693 13,736 13,724 13,605 13,591

 Investment 3,772 3,762 3,773 3,755 3,762 3,761

 Government 2,542 2,549 2,542 2,545 2,549 2,555

 Exports 4,902 4,836 4,903 4,864 4,846 4,795

 Imports 4,966 4,960 4,966 4,943 4,691 4,695

Aggregate Prices in the Economy

 WPI: Fuel and Power (1982 = 1.0) 2.12 2.25 2.11 2.16 2.59 2.66

 CPI: Energy (1982/84 = 1.0) 2.51 2.79 2.49 2.63 3.05 3.22

 CPI: All Urban (1982/84 = 1.0) 2.90 2.98 2.90 2.94 2.90 2.96

 WPI: All commodities (1982 = 1.0) 1.94 2.06 1.94 1.99 2.03 2.11

Inflation Rate, Unemployment Rate, and Federal Funds Rate

 Inflation 2.26 3.02 2.24 2.87 2.11 2.67

 Unemployment Rate 4.54 4.70 4.53 4.53 4.54 4.64

 Federal Fund Rate 5.10 5.52 5.10 5.50 4.75 5.05

Industrial Sector (billion 2000 dollars)

 Total Industrial 8,590 8,344 8,595 8,436 8,556 8,385

 Nonmanufacturing 1,937 1,859 1,937 1,891 1,971 1,910

 Manufacturing 6,654 6,485 6,658 6,545 6,585 6,475

 Energy-Intensive 4,528 1,470 1,529 1,487 1,494 1,451

 Non-Energy-Intensive 5,126 5,015 5,129 5,058 5,091 5,024

Disposable Income 15,171 15,137 15,176 15,181 14,867 14,856

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHITECH.D060607A,

IRES2525HT.D060607A, IHIPRICE.D060607A, and IRES252HP.D060607A.

In the High Technology Policy Case, accelerated progress in the development and

improvement of renewable generation and cellulosic ethanol technologies and greater

availability of relatively low-cost domestic biomass supplies make the policy easier to

achieve than in the Policy Case. Similarly, in the Low-Cost Ethanol Imports Policy Case,

the policy is easier to achieve because large volumes of ethanol imports are available at

relatively low cost. In both cases, RPS and RFS credit prices are lower than projected in the

Policy Case, ultimately mitigating the cost of the Policy to consumers and its impacts on the

U.S. economy. The cost of the Policy is lower in the alternative policy cases, because

renewable fuels are already more competitive with traditional fossil fuels in the

corresponding alternative reference cases, according to the scenario definitions.

In the High Price Policy Case, the economic impacts of imposing the Policy on the High

Price Case, which assumes higher fossil fuel energy prices than in the Reference Case, are

smaller than the impacts in the High Technology Policy Case and Low-Cost Ethanol

Imports Policy Case, which are based on alternative reference cases with lower energy

prices. With higher prices for liquid fuels and natural gas: (a) the aggregate price of energy

is higher; (b) GDP and consumption are lower; (c) the demand for energy, specifically for

electricity and liquids, is lower; and (d) the proportion of renewable fuels used is higher in

both the electric power and motor transportation sectors.
56 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

When fossil fuel prices are higher, renewable generation and biofuels are more competitive

in a greater number of situations, and so a relatively smaller economic incentive is needed

to achieve the necessary market penetration. Consequently, when the RPS and RFS policy

requirements are added to the High Price Case, the negative impacts on key energy and

economic indicators in the High Price Policy Case are smaller than those in the Policy Case

relative to the Reference Case. The result is a pattern of lower RPS and RFS credit prices,

smaller increases in electricity prices, and smaller increases in motor transportation fuel

prices. Therefore, the projected losses in real GDP, consumption, and industrial output are

smaller.

Key energy sector results illustrating the projected effects of implementing the Policy in the

Reference Case and in the High Price and High Technology alternative reference cases are

summarized in Table 15. In the High Price Policy Case, consumer energy prices rise

steadily through 2025, to almost 6 percent above prices in the High Price Case—roughly

one-half of the percentage increase projected in the Policy Case relative to the Reference

Case (Figures 25 and 26). Overall, the CPI for All Urban consumer prices is as much as 2.5

percent higher in the High Price Policy Case than in the High Price Case (Table 14). The

percentage increases in energy prices projected in the High Technology Policy Case relative

to those in the High Technology Case are even smaller, averaging only 2 percent in 2025.

Smaller price changes mean smaller impacts on real GDP, consumption, and industrial

production as compared with the impacts in the High Price Policy Case relative to the High

Price Case.

Relative to the High Price Case, discounted GDP losses in the High Price Policy Case total

$165 billion (less than 0.1 percent)—equal to slightly more than one-half the impact on

GDP in the Policy Case relative to the Reference Case (Figure 27). In other words, because

price changes from the High Price Case to the High Price Policy Case are smaller than those

from the Reference Case to the Policy Case, the impacts on national consumption and GDP

are smaller. After 2025, when energy prices peak, both real GDP and consumption begin to

return to baseline levels. In the High Technology Policy Case, GDP losses in 2025 relative

to projected GDP in the High Technology Case are comparable to, but smaller than, those in

the High Price Policy Case (relative to the High Price Case), illustrating the beneficial effect

of faster-than-expected technological progress.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 57

Table 15. Summary of Energy Impacts of Alternative Policy Cases in 2025

Reference Policy High Price

High Price

Policy High Tech

High Tech

Policy

RPS Credit Price

(2005 cents per kilowatthour) NA 4.8 NA 4.6 NA 3.4

RFS Credit Price

(2005 dollars per gallon of biofuel) NA 2.18 NA 1.46 NA 1.34

Consumption (quadrillion Btu)

 Liquids 49.1 48.3 45.2 45.1 49.1 48.8

 Natural Gas 26.8 25.6 24.7 24.4 26.6 25.4

 Coal 30.3 24.1 32.7 26.0 29.6 24.5

 Nuclear 9.2 8.5 10.1 8.5 9.2 8.5

 Hydropower 3.1 3.3 3.1 3.2 3.1 3.2

 Biomass 3.9 11.4 4.3 11.3 5.3 13.0

 Other Renewables 1.4 7.0 1.5 6.5 1.5 5.6

 Total 123.8 128.3 121.5 125.2 124.4 128.9

Average Prices: Selected Fuels

 Transportation Fuels

 Motor Gasoline (2005 dollars per gallon)1

2.16 2.44 3.06 3.20 2.12 2.26

 Diesel (2005 dollars per gallon)22.21 2.70 2.96 3.27 2.22 2.49

 E85 (2005 dollars per gallon) 2.22 1.89 2.51 2.49 2.15 1.74

 Biomass (2005 dollars per million Btu)31.51 5.02 1.51 4.95 1.50 3.13

Electricity Fuel Input Prices (2005 dollars per million Btu)

 Steam Coal 1.62 1.59 1.76 1.69 1.61 1.56

 Distillate 10.29 10.19 15.50 15.60 10.23 10.19

 Residual Fuel Oil 6.59 6.57 11.92 11.79 6.58 6.61

 Natural Gas 5.96 5.72 6.98 6.78 5.98 5.62

Average Retail Electricity Prices

(2005 cents per kilowatthour) 8.0 8.3 8.2 8.5 8.0 8.1

Undiscounted Cumulative Expenditures, 2009-2025 (billion 2005 dollars)4

 Electricity Revenues from Retail Sales 5,838 5,833 6,015 6,019 5,828 5,798

 Motor Transport Expenditures 8,493 8,759 10,773 10,924 8,482 8,616

 Subtotal 14,331 14,592 16,788 16,924 14,260 14,414

Total U.S. Energy Expenditures 18,643 18,879 21,748 21,873 18,616 18,675

Discounted Cumulative Expenditures, 2009-2025 (billion 2005 dollars)5

 Electricity Revenues from Retail Sales 3,511 3,507 3,619 3,616 3,506 3,491

 Motor Transport Expenditures 5,121 5,232 6.396 6,462 5,117 5,175

 Subtotal Expenditures 8,632 8,739 10,015 10,098 8,623 8,666

Total U.S. Energy Expenditures 11,271 11,361 13,017 13,063 11,257 11,277

1Motor gasoline contains up to 10 percent ethanol.

2Diesel fuel may contain up to 20 percent biodiesel from renewable sources.

3Census Division 4 price.

4

Simple undiscounted sum (2005 dollars).

5Discounted at 7 percent per year back to 2009.

Source: EIA Office of Integrated Analysis and Forecasting. National Energy Modeling System runs IBASE.D060607A,

IRES2525.D060607A, IHIPRICE.D060607A, IRES252HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.
58 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Figure 25. Consumer Price Impacts in the Policy Cases

 (percent change from corresponding reference cases)

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES2525HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.

Figure 26. Wholesale Price Impacts in the Policy Cases

 (percent change from corresponding reference cases)

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES2525HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.

Cumulative discounted consumer expenditures from 2005 to 2025 in the High Price Policy

Case are only $35 billion (0.02 percent) lower than projected in the High Price Case (Figure

28). As is typically the case for GDP, consumption declines generally grow over time as

energy prices continue to rise in the High Price Policy Case relative to the High Price Case;

however, as the increase in energy prices subsides, the consumption declines also slow, and

eventually they are reversed. On an undiscounted basis, the declines in GDP and

consumption from the High Price Case to the High Price Policy Case are much larger.37

37Using the economic principle of discounting and the time value of money tends to weigh losses at the

beginning of a period more than equal losses at the end of a period. For example, a dollar loss in 2030 is

valued at about $0.45 in 2010 when discounted at 4 percent.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 59

Figure 27. GDP Impacts in the Policy Cases

 (cumulative change from corresponding reference cases, billion 2000 dollars)

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES2525HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.

Figure 28. Consumption Impacts in the Policy Cases

 (cumulative change from corresponding reference cases, billion 2000 dollars)

Source: National Energy Modeling System, runs IBASE.D060607A, IRES2525.D060607A, IHIPRICE.D060607A,

IRES2525HP.D060607A, IHITECH.D060607A, and IRES2525HT.D060607A.

 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 61

Appendix A. Request Letters
62 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 63
64 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 65

 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 67

Appendix B. Key Updates and Changes to the AEO2007

Reference Case Assumptions

The following list identifies the changes that were made to the AEO2007 version of the

NEMS models, input assumptions, and policy assumptions to allow analysis of the proposed

Policy.

Macroeconomic Changes from AEO2007 Reference Case

• The 51-cent-per-gallon subsidy on ethanol was allowed to expire as stated in current

U.S. law.

• Ethanol was included in the transportation fuels as input to the Global Insight

macroeconomic model because of its magnitude.

• For the Policy cases, the producer price index for farm products was increased by 50

percent of the corn price increase derived from the renewables module. Grains,

livestock, poultry, eggs, and dairy constitute 90 percent of the producer price index for

farm products. On a wholesale level, this assumes that 60 percent of the corn price

increase was passed on for the above mentioned categories.

• Ethanol imports were included in non-petroleum industrial supplies and materials

imports in the Global Insight macroeconomic model.

Petroleum Market Module Changes from AEO2007 Reference Case

• The 51-cent-per-gallon blenders’ subsidy on ethanol and the 54-cent import tariff were

allowed to expire simultaneously in 2010, approximating current U.S. law.

• While the blenders’ tax credit is set to expire 1 year after the ethanol import tariff, both

laws were assumed to expire in the same year to preserve the intent of the requested

analysis.

• Added an improved representation of international ethanol import supply as a function

of price.

• Updated the cellulose ethanol representation from a simple input supply curve to a

merchant plant representation that incorporates capital investment and production

decision making as well as technology learning.

• Updated the biodiesel representation to a merchant plant representation and added the

ability to process animal fats.

• Added totally new logic to represent the demand for E85 as function of price and a

number of other key consumer preferences within the Petroleum Market Module to

represent producer and consumer behavior in an RFS policy. The new formulation was

necessary to ensure and accelerate convergence of demand and prices in the RFS case.
68 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

• Incorporated the flexibility to choose between imports of petroleum gasoline and

gasoline blending components.

• Increased the ethanol blending percentage in non-California reformulated and

oxygenated gasoline to 10 percent. The change represents a recent EIA reassessment

of the market. The change, while critical in the Policy cases, has little influence on the

reference or high price cases of AEO2007.

• Added logic to implement EPACT2005 Provision 942 (Cellulosic Biofuel Production

Incentives) in the Policy cases. The extension allows for further support for cellulosic

ethanol if prices are expected to be economic sooner in the time horizon through an

RFS.

• Lowered the DDGS netback price for ethanol production whenever corn-ethanol

production exceeds 18 billion gallons.

• Adjusted maximum build rates for ethanol plants consistent with current market

investment trends.

The AEO2007 analysis assumed that the maximum ethanol import quantity that would be

available at any price through the entire projection horizon would be about 900 million

gallons per year. A review of a recent study for potential Brazilian ethanol production and

exports to the United States through 2012 provided new data points through which simple

exponential supply curves were estimated by year.38 Whether the levels of ethanol supply

from Brazil to the United States will increase as assumed by these curves will depend

critically on the level of investments made in Brazil to expand sugar cane crop production

and ethanol conversion facilities and the competition for the ethanol from the rest of the

world. The removal of the import tariff combined with the new ethanol import supply

curves results in ethanol imports that are three times larger than in the AEO2007 reference

case.

The study cited above claims that there are over 90 million hectares (over 200 million acres)

of cleared but idle, non-environmentally sensitive, land available for development of

ethanol production. If the land were aggressively developed for sugar cane production,

Brazilian ethanol production could grow to over 50 billion gallons per year. Large-scale

investments for plant and infrastructure, estimated to be between $150 billion to $250

billion dollars, would be required to build roads, purchase farming equipment, expand the

ethanol transportation infrastructure, build new conversion plant facilities, and provide for

port and ship expansions. One of the scenarios addressed in this analysis, the Low-Cost

Ethanol Imports Case assumes that such investments are made for Brazilian ethanol

development.

38University of Campinas, Sao Paulo, Brazil, Study of the Possibilities and Impacts of the Production of Large

Quantities of Ethanol with the Aim to Partially Replace Gasoline in the World.
 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025 69

Renewable Market Module Changes from AEO2007 Reference Case

• Added offshore wind technology as a capacity expansion option in selected coastal

regions, with revised cost and performance estimates.

• Updated corn and biomass feedstock costs consistent with University of Tennessee

POLYSYS study.

EIA’s estimates of biomass supply curves were taken from the U.S. Department of

Agriculture’s latest estimates through 2015, which were developed under contract with Dr.

Ugarte at the University of Tennessee using an integrated land and crop competition model.

EIA contracted with Dr. Ugarte to extend these curves through 2030. The corn supply

curves also were developed using POLYSYS and were generally higher-priced than those in

AEO2007 for the same level of demand; however, the maximum availability of corn supply

in the new estimate is much larger than the AEO2007 reference case and allows for corn

imports when corn prices and demand are sufficiently high. In addition to the reference

case, a high yield case was constructed to evaluate the impact of potentially higher biomass

crop yields. Similar to the reference case, the biomass supply curves through 2015 were

obtained from the USDA and extended through 2030 by Dr. Ugarte under contract to the

EIA (Figure B1).

Figure B1. AEO2007 Reference Case and High Yield Biomass Supply Curves, 2030

0

2

4

6

8

10

12

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000

Trillion Btu

$2005/MMbtu

New Reference AEO2007 Reference High Yiield

350 million tons 590 million tons

AEO2007

Reference

New

Reference

Biomass High Yield

Biomass

Source: Dr. Daniel de la Torre Ugarte, University of Tennessee. Using the agricultural model POLYSIS.
70 Energy Information Administration / Energy and Economic Impacts of 25% RPS and a 25% RFS by 2025

Transportation Module Changes from AEO2007 Reference Case

• The Policy cases incorporated two key provisions of S.23—the manufacture of dualfueled vehicles and the expanded infrastructure for distribution of fuels like E85—as

stated by study request letter.

S.23 requires that all new light-duty vehicle (LDV) sales be dual-fuel capable (high

percentage blends of ethanol and gasoline and biodiesel and diesel) by 2017. Such

provisions will probably be vigorously debated and opposed by LDV manufacturers and

owners of affected fuel dispensing stations. Since the potential to produce domestic

biodiesel supply is expected to be much smaller than the potential to produce domestic

ethanol supply, all new LDV sales were assumed to be E85 capable by 2017. The second

provision requires that at least 25 percent of all gasoline distribution stations provide E85

refueling. The costs of developing such an infrastructure will be significant, but S.23 does

not specify who will bear the costs. It is likely that such costs will be borne at least in part

by consumers and possibly by the firms required to provide the dispensing stations. Such

costs, which were not available and were not estimated for this analysis, could significantly

increase the economic impacts on the U.S. economy.

Electricity Market Module Changes from AEO2007 Reference Case

• Modified the interregional transmission cost structure to allow renewable capacity

additions from one region to serve adjacent regions, with higher associated

transmission costs, which is especially important in an RPS scenario.

• Improved the representation of competition for biomass for electricity generation and

cellulosic ethanol production.

• Added offshore wind technology as a capacity expansion option in selected coastal

regions, with revised cost and performance estimates.

Because a combined RPS and RFS had never been previously analyzed, the logic for

equilibration of biomass supply and demand between the electric power sector and the

motor transportation sector needed to be created. The newly constructed algorithm equates

the biomass supply price between both sectors.