Major Coal Issues in the 109th Congress

Order Code RL32790

CRS Report for Congress

Received through the CRS Web

Major Coal Issues in the 109th Congress

Updated June 10, 2005

name redacted, Coordinator

Analyst in Energy Policy

Resources, Science, and Industry Division

name redacted and name redacted

Specialists in Energy Policy

Resources, Science, and Industry Division

Congressional Research Service ˜ The Library of Congress

Major Coal Issues in the 109th Congress

Summary

Major legislative issues related to coal in the 109th Congress include coal and

energy security, clean air and environmental concerns, funding strategies for

technology R&D, loan guarantees for coal gasification projects, and the Abandoned

Mine Land (AML) program.

The Administration anticipates a long-term reliance on coal because of its

relatively low-cost abundance. Coal supplies 22% of U.S. energy demand but over

50% of the energy used by the electric power sector. The Energy Information

Administration forecasts electricity consumption to grow by 1.9% per year through

2025. The increase will largely be met by new coal-fired or natural gas-fired power

plants.

By mandating significant reductions in three pollutants emitted by coal-fired

electric generating units, proposed Clear Skies legislation (S. 131) could have

significant impact on coal production and distribution, if enacted. When Clear Skies

was introduced in the 108th Congress, the Environmental Protection Agency (EPA)

conducted an analysis of its effects on the coal industry. While the analysis indicated

growth in coal production for electric utility production (from 905 million tons in

2000 to 998 million tons in 2020), coal generation’s share of the 2020 generation mix

was projected to decline from 46% to 44%. Clear Skies legislation, however, faces

an uncertain future. In March 2005, the Senate Environment and Public Works

Committee killed S. 131 on a 9-9 vote.

In FY2002, President Bush initiated the Clean Coal Power Initiative (CCPI)

focusing on advanced coal combustion technology for removal of SOx, NOx,

mercury, and fine particulate matter and carbon sequestration. The CCPI is a 10year, $2 billion government-industry cost sharing program. The FY2006 funding

request for Fossil Energy R&D is heavily weighted towards clean coal technology,

potentially at the expense of other fossil technologies — such as natural gas or

petroleum technology R&D.

Legislation in the 109th Congress for an omnibus energy bill (H.R. 6) was

approved by the House on April 21, 2005. H.R. 6 includes provisions for coal nearly

identical to the H.R. 6 conference report filed in the 108th Congress. Within the

CCPI section there would be loan guarantees for specific integrated gasification

combined cycle projects. The Senate Committee on Energy and Natural Resources

approved its version of the bill (S. 10) on May 26, 2005.

Authorization for collection of AML fees was scheduled to expire at the end of

FY2004 and was extended nine months to the end of June 2005 by the Consolidated

Appropriations Act for 2005 (P.L. 108-447). Subsequently, H.R. 1268 (P.L. 109-13)

a supplemental appropriations bill for FY2005, extended AML authorization to the

end of FY2005. In its FY2006 budget submission for the Office of Surface Mining,

the Administration once again proposed the changes in the AML program included

with the FY2005 budget, this time seeking a $58 million increase in the appropriation

for the fund. This report will be updated.

Contents

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

Energy Security and Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Coal vs. Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Clear Skies Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Legislative Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Clean Coal Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Legislative/Appropriation Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Omnibus Energy Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Legislative Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Abandoned Mine Lands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Legislative Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

List of Tables

Table 1. Costs of Producing Electricity from New Plants . . . . . . . . . . . . . . . . . . 2

Table 2. Proposed Emission Caps Under S. 131 . . . . . . . . . . . . . . . . . . . . . . . . . 4

Table 3. EPA’s Projections of Coal Production Under

Clear Skies Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Major Coal Issues in the 109th Congress

Introduction

The Bush Administration considers coal a major component of its National

Energy Strategy. The Administration anticipates a long-term reliance on coal because

of its low-cost abundance. Numerous issues arise when harnessing this cheap,

abundant fuel source. This report examines some of the major legislative issues

related to coal in the 109th Congress, including coal and energy security, clean air and

environmental concerns, funding strategies for technology R&D, loan guarantees for

coal gasification projects, and the Abandoned Mine Land program.

Energy Security and Coal1

Energy that is available, reliable, and affordable is a focal point when discussing

energy security concerns.2 And coal will be part of that conversation. Out of the four

major fuel sources — oil, gas, uranium, and coal — coal has the largest domestic

reserve base, the largest share of U.S. energy production in BTUs, and the smallest

percent met by imports. The Energy Information Administration (EIA) projects that

coal imports will continue to be negligible through 2025, while there will be a

growing reliance on foreign sources for other major fuels. In addition, coal is

forecast to be the largest source of domestic fuel production in the foreseeable future.

Coal supplies 22% of U.S. energy demand but over 50% of the energy used by

the electric power sector (both utility and non-utility consumers). The electric power

sector consumes 90% of all coal in the United States. The remaining 10% is used in

the industrial and commercial sectors or used in coke plants. Coal use in the electric

power sector has maintained a share greater than 50% for the past two decades.

The EIA forecasts electricity consumption to grow by 1.9% per year through

2025 — from 3,481 billion kilowatt hours (kwh) to 5,220 billion kwh.3 The increase

in demand is largely to be met by new coal-fired or natural gas-fired power plants.

The price of each fuel, the capital costs associated with power plant construction, and

plant efficiencies will determine the competitiveness of each fuel source. But

1

Prepared by (name redacted), Analyst in Energy Policy, CRS Resources, Science, and

Industry Division.

2

As defined by some experts, energy security is assurance of (1) adequate supplies of

energy at reasonable prices compatible with economic growth; and (2) the ability to buffer

the nation and its economy from a disruption and uncertainty in supply and the price spikes

that normally accompany severe shortages.

3

DOE/EIA, Annual Energy Outlook, 2005, p. 87.

CRS-2

because of limited domestic supply, natural gas supply is unlikely to keep pace with

demand. This will lead to increased imports, according to EIA forecasts. Per-well

reserve additions are expected to continue to decline over the EIA forecast period

(2004-2025). EIA further forecasts that natural gas will not displace coal as the

dominant fuel supply for power generation despite projected increases in liquefied

natural gas (LNG) imports, additional domestic supply from the lower 48 states, and

Alaskan natural gas from a newly constructed pipeline.4

Coal vs. Natural Gas

Power plant development for electricity generation is primarily driven by

economics. The lower-cost, more efficient operations are the plants that get built.

Production costs include the costs of fuel, operation and maintenance, and capital.

Fuel costs are a major consideration for fossil fuel-fired plants, and the fuel cost

differences between a coal-fired and natural gas-fired plant are significant. For

instance, fuel costs for a coal-fired plant are about 24% of total costs, whereas fuel

costs for a natural gas facility are close to 69% of total costs. This price difference

could give coal an advantage. However, new plant capital costs favor natural gas,

accounting for only 23% of total electric production costs. Capital costs for new

coal-fired plants are closer to 60% of total costs. Table 1, below, illustrates the

dynamics of power plant economics for advanced coal and advanced combined cycle

(natural gas-fired) plants expected to be built in the years 2015 and 2025.

Table 1. Costs of Producing Electricity from New Plants

(2003 mills/Kwh)

2015

Costs

Advanced

coal

2025

Advanced

combined

cycle

Advanced

coal

Advanced

combined

cycle

Capital

31.68

11.63

28.87

11.08

Fixed

4.59

1.36

4.59

1.36

Variable

(primarily fuel)

12.28

34.88

13.98

39.06

Incremental

Transmission

3.24

2.80

3.41

2.86

Total

51.79

50.67

50.85

54.3

Source: DOE/EIA, Annual Energy Outlook, 2005, p. 89.

A combination of low capital costs, greater efficiency, and reasonable natural

gas prices led to the current build-up of natural gas-fired capacity. Power plant

capacity rose an estimated 186 gigawatts (GW) from 2000 to 2003: 27 GW in 2000;

4

Annual Energy Outlook, 2005, DOE/EIA, p. 3.

CRS-3

42 GW in 2001; 72 GW in 2002; and 45 GW in 2003. About 175 GW was new

natural gas-fired capacity, and only 1 GW was new coal-fired capacity.5 This buildup has led to excess capacity, which should diminish after 2010. Capacity utilization

would rise from 72% in 2003 to 83% in 2025, according to EIA.

EIA projects that a total of 281 GW of new capacity will be needed by 2025 —

including an estimated 19 GW annually from 2011 to 2025 (268 GW total). Natural

gas facilities (combined cycle; combustion turbine or distributed generation

technology) are forecast to account for 60% of the new capacity. Total new coal

capacity of 87 GW is to come online between 2004-2025; thus, coal capacity will be

33% of new capacity after 2011, according to EIA. New coal capacity becomes more

competitive with natural gas late in the forecast between 2016 and 2025. Despite

relatively low coal costs, the high capital costs will likely limit the number of

advanced coal integrated gasification combined cycle (IGCC) facilities to about 16

plants or 6 GW of commercial capacity by 2025.6

Rising natural gas prices will lead to the construction of more coal-fired

facilities between the years 2010 and 2025, according to EIA. Coal is competitive

at natural gas prices of $4-$6 per million Btus; prices above that range push up the

total cost of gas-fired power facilities above coal-fired plants. Even so, natural gas,

as a percent of the total electricity, will increase to 24% in 2025 from 17% in 2003,

projects EIA, while nuclear and petroleum will remain flat. Renewables rise from

359 billion Kwh to 489 billion Kwh during the same time period. Coal maintains a

50% share of the electricity market in 2025, says EIA.

New capacity is also needed to replace retired capacity and to meet rising

demand. An estimated 43 GW of fossil fuel capacity is expected to be retired from

2004 to 2025 (3 GW Coal; 15 GW of older oil or gas combustion turbines or

combined cycle, and 25 GW of oil and gas steam plants).

If the EIA forecasts prove to be accurate, then long-term investment in clean

coal could pay off because of the greater coal capacity needs beyond 2016. Among

the most important factors to watch regarding coal versus natural gas-fired plants are

the natural gas prices, capital costs for IGCC plants, and stricter environmental

regulations aimed at pollutants derived from burning coal.

Clear Skies Legislation7

By mandating significant reductions in three pollutants emitted by coal-fired

electric generating units, proposed Clear Skies legislation could have significant

impact on coal production and distribution, if enacted. Electric utilities are the

5

EIA, AEO, 2004, p. 81.

6

EIA, AEO, 2005, p. 87.

7

Prepared by (name redacted), Specialist in Environmental Policy, CRS Resources, Science,

and Industry Division.

CRS-4

largest users of coal, and legislation restricting their emissions could affect coal

markets in several ways, depending on the specifics of any final legislation.

Background

In the 109th Congress, a modified version of the President’s proposed Clear

Skies legislation has been introduced by Senator Inhofe — S. 131. The proposal

would amend the Clean Air Act to place caps on electric utility emissions of sulfur

dioxide (SO2), nitrogen oxides (NOx), and mercury (Hg). Implemented through a

tradeable allowance program, the emissions caps would be imposed in two phases:

2010 (2008 in the case of NOx) and 2018.8 The proposed caps are summarized in

Table 2.

Table 2. Proposed Emission Caps Under S. 131

Beginning in 2010

(except NOx — 2008)

Beginning in 2018

Emissions Cap on SO2

4.5 million tons

3.0 million tons

Emissions Cap on NOx

(total for both zones)

2.19 million tons

1.79 million tons

34 tons

15 tons

Emissions Cap on Hg

Although proposed Clear Skies legislation is the focus of legislative debate,

regulatory initiatives currently being promoted by Environmental Protection Agency

(EPA) raise many of the same issues for coal interests as does Clear Skies. These

initiatives include the proposed Clean Air Interstate Rule and the proposed Mercury

Rule.9

Legislative Issues

When Clear Skies was introduced in the 108th Congress, EPA conducted an

analysis of its effects on the coal industry.10 While the analysis indicated growth in

coal production for electric utility consumption (from 905 million tons in 2000 to 998

million tons in 2020), coal generation’s share of the 2020 generation mix11 was

projected to decline from 46% to 44%. The beneficiary of this projected decline was

natural gas combined cycle, whose share of the mix climbed from 24% in 2000 to

8

For more information, see CRS Report RL32755, Air Quality: Multi-Pollutant Legislation

in the 109th Congress, by (name redacted) and (name redacted).

9

See CRS Report RL32273, Air Quality: EPA’s Proposed Interstate Air Quality Rule, by

(name redacted) and (name redacted); and CRS Report RL31881,

Mercury Emissions to the Air:

Regulatory and Legislative Proposals, by James McCarthy.

10

11

See those analyses at [http://epa.gov/air/clearskies/technical.html].

Generation Mix in EPA’s analysis in footnote 10, above, refers to generation capacity, not

electric generation production used in EIA projections.

CRS-5

26% in 2020. Obviously the actual mix that would result from any enactment of

Clear Skies would be heavily dependent on future natural gas prices and utility

decisions with respect to compliance strategies.

With respect to compliance strategies, the EPA analysis projected a substantial

increase in the installation of flue-gas desulfurization units (FGD) to achieve the 70%

reduction in SO2 required by the proposed legislation. Currently, about 100,000

megawatts (Mw) of coal-fired capacity has FGD units. EPA projected that Clear

Skies would result in that number rising to just over 200,000 Mw by 2020.12 This

would increase the share of FGD-equipped coal-fired capacity in the country from

about one-third to two-thirds. A similar increase was expected for the installation of

Selective Catalytic Reduction (SCR) to reduce NOx emissions, although some of that

increase would be due to the implementation of the NOx SIP Call.13

Such an increase in emissions control (particularly FGD units) could reduce the

market advantage that high-sulfur coal currently enjoys in the coal markets. As

indicated by Table 3, EPA analysis indicates that the Interior Basin in particular

benefits from the increased SO2 controls.

Table 3. EPA’s Projections of Coal Production

Under Clear Skies Legislation

(million tons)

2000 Production

2020 Production under

Clear Skies Legislation

Appalachia

299

305

Interior

131

220

West

475

473

Total

905

998

Region

Source: EPA, Technical Analysis, Section D, p. D-3.

With respect to Hg controls, S. 131 would weaken the proposed phase 1 Hg cap

from the 26 tons originally proposed by the Administration to 34 tons, based on a

DOE estimate about the actual level of emissions that could be achieved without

dedicated Hg controls (i.e., “co-benefits”). There are substantial differences between

the Hg characteristics of bituminous and subbituminous coals, and uncertainty about

what the actual “co-benefits” levels for Hg control are. If Clear Skies reflects the

actual “co-benefits” levels, the effect of Hg controls on coal production would be nil,

12

EPA, Technical Analysis, Section D: Projected Impacts on Generation and Fuel Use,

available at [http://epa.gov/air/clearskies/technical.html].

13

The NOx SIP Call is a regional cap-and-trade program designed to reduce nitrogen oxide

emissions from 20 eastern states and the District of Columbia. Beginning in 2004, the

purpose is to reduce interstate transport of ozone and thus assist states in achieving the onehour National Ambient Air Quality Standard for Ozone.

CRS-6

beyond that estimated for SO2 and NOx controls. Likewise, the commercialization

of emerging Hg control technology, such as activated carbon injection (ACI), would

eliminate any shift between coal types. However, there is substantial controversy

over what any “co-benefits” level is and the future availability of ACI and other

alternatives.

The pivotal issues for coal and Clear Skies include the following: (1) the

potential for natural gas to erode market share for coal due to higher pollution control

costs under Clear Skies, (2) the potential for market shift between western suppliers

and eastern suppliers because of increased SO2 controls, and (3) the uncertain effects

of Hg controls if they exceed “co-benefit” levels or if emerging Hg controls are not

available.

Outlook

Clear Skies faces an uncertain future. In March 2005, the Senate Environment

and Public Works Committee killed S. 131 on a 9-9 vote. However, many of the

issues identified here also manifest themselves in EPA’s final Clear Air Interstate

Rule (CAIR) and its final Hg rule. So the issue is not likely to disappear.

Clean Coal Technology14

Background

The original Clean Coal Technology (CCT) program began in 1984 to

demonstrate emissions control technologies, advanced electric power generation

facilities, and coal and industrial processing projects. Congress had appropriated

$2.5 billion for the CCT program by 1990, but since 1994 as much as $300 million

had been deferred or rescinded because of limited commercial prospects and less

Administration interest. President Bush, however, has revived the CCT program

under a new banner — the Clean Coal Power Initiative (CCPI) — focusing on

advanced coal combustion technology for removal of SOx, NOx, mercury, and fine

particulate matter and carbon sequestration. Coal plants are responsible for 69% of

all SO2, 33% of mercury, 39% of CO2, and 22% of nitrogen oxide air emissions in

the United States.

The CCPI is a 10-year, $2 billion government-industry cost sharing program

structured similarly to the original CCT program. There are currently 10 active CCPI

projects. The DOE wanted the early projects to focus on technologies that would

reduce pollutants being addressed under the President’s “Clear Skies” proposal and

Global Climate Change initiative. Round 1 projects feature multi-pollutant control

systems, while Round 2 features two multi-pollutant control technologies and two

integrated gasification combined cycle (IGCC) demonstration projects.

Announcements for Round 3 projects are expected to occur during FY2006.

14

Prepared by (name redacted), Analyst in Energy Policy, CRS Resources, Science, and

Industry Division.

CRS-7

Legislative/Appropriation Issues

One of the issues that arise is funding for long-term clean coal technology

versus closer-term pilot and demonstration projects. Both are being funded. Based

on recent appropriation trends, the greatest interest for closer-term R&D is with

IGCC projects for electricity supply and emissions reduction.

There are two small-scale IGCC commercial plants operating today: a 250

megawatt (MW) facility operated by Tampa Electric Power in Florida and a 300 MW

facility operated by Cinergy at its Wabash River site in Indiana. IGCC technology

involves the gasification of coal to produce electricity. During the gasification

process, coal is co-fed with water and oxygen in a reducing atmosphere at high

pressure to produce synthetic gas, carbon monoxide, and hydrogen. Sulfur and carbon

dioxide are also produced and removed. The synthetic gas drives a combustion

turbine, whose exhaust is used to make steam to drive a secondary turbine. One of

the biggest obstacles facing IGCC is the reliability of the gasification process.

Because of reliability questions, among other challenges, large-scale competitive

commercial plants may still be years away. Both Congress and the Administration

continue to invest heavily in IGCC because of the potential benefits from reduced

NOx, SOx, mercury, and particulate matter. Moreover, lower CO2 emissions through

greater plant efficiencies and/or potential sequestration could be substantial.

The Administration is looking at very long-term investments as well. FutureGen

represents that strategy. FutureGen — an integrated sequestration and hydrogen

research initiative — is a $1 billion dollar industry/government partnership to build

a coal-fired gasification and hydrogen production plant to serve as a prototype to test

emissions-free and carbon sequestration technologies. The goal is to permanently

sequester CO2 in a geologic formation. A FutureGen plant would provide 275 MW

from electricity and hydrogen and sequester 1 million metric tons of carbon dioxide

annually. The project is designed to build international support to address “global

warming and energy security.”15 The prototype will allow DOE to operate a largescale facility to prove the technical feasibility of zero emission production. Out of the

$950 million cost estimate of the project, DOE would invest $500 million, plus an

additional $120 million from its sequestration program, the private sector would

contribute $250 million (which would be capped), and about $80 million is

anticipated from the international community.

The funding for FutureGen began in FY2004 at $9 million. Appropriations

were nearly doubled to $17.5 million in FY2005. The Bush Administration is seeking

$18 million for FY2006. Project funding between FY2004 and FY2006 is for plant

definition and NEPA requirements. Funding requests are projected by DOE to rise

rapidly in the near-term to $50 million in FY2007, then $100 million in FY2008, at

which time procurement and construction efforts would begin. DOE projects another

$228 million of direct funding needed between FY2009-FY2013, plus an additional

$120 million from the DOE Sequestration program during this time frame. Finally,

an additional $77 million would be needed through FY2018. The Bush

15

DOE/Office of Fossil Energy, FutureGen: Integrated Hydrogen, Electric Power

Production and Carbon Sequestration Research Initiative, March 2004.

CRS-8

Administration has also been seeking to cancel previously appropriated funds for the

original CCT program and shift that money to FutureGen. Congress has blocked

such an effort in the past two budgets.

Below is a summary of the Administration’s funding request for Clean Coal

R&D programs for FY2006:

Clean coal power initiative — A 10 year, $2 billion effort that began in

FY2002. The Administration has submitted a $50 million request for

FY2006. Nearly $400 million in funding has already been appropriated

since FY2002. Rounds 1 and 2 are already underway. DOE’s Office of

Fossil Energy will begin Round 3 solicitations during FY2006

Coal R&D programs — These programs are being encouraged by the

Administration. Within the Fossil Energy R&D program, Coal R&D

programs, other than the CCPI and FutureGen, would rise by 5.9% to $218

million while nearly all other fossil energy programs would be cut. Major

cuts to programs other than coal are proposed which would reduce the total

Fossil Energy program to $491.5 million — 14% ($80.5 million) less than

the enacted amount for FY2005.

Coal Gasification — Within the Coal R&D program, the Administration’s

request for gasification research went up from $34.5 million in FY2005 to

$56.4 million in FY2006. FY2005 appropriations were $45.8 million. This

level of increase is an indication of more commitment by the

Administration and Congress to IGCC efforts aimed at commercialization

of the technology.

Carbon sequestration — The R&D program would receive $67.2 million

in the Administration’s FY2006 request — a $21.8 million increase over

FY2005.

FutureGen — The FY2006 Administration request is $18 million.

Outlook

The FY2006 funding request for Fossil Energy R&D is heavily weighted

towards clean coal technology, potentially at the expense of other fossil technologies

— such as natural gas or petroleum technology R&D. However, the CCPI may need

consistently higher investments in a constrained spending environment to provide the

desired long-term results — a commercially affordable coal technology for electricity

generation while substantially reducing emission levels. If funding support or

incentives are not high enough, industry may forgo the long-term commitment

needed and instead abandon gasification projects altogether. Even with heavy

investment in clean coal/gasification strategies, natural gas-fired generation may

retain its economic advantage over the long-term because of moderate natural gas

prices and/or more efficient gas units. On a similar note, technology obstacles with

IGCC may not be resolved, IGCC may not be deployed for larger-scale commercial

production, and decades-long R&D funding never recouped.

CRS-9

However, the strategy of investing in coal-gasification projects for closer-term

commercialization fits EIA’s forecast that16 commercial IGCC plants will be on-line

between 2011-2025. The total output would still be only 7% of all coal-fired

capacity, but if there are capital cost reductions and greater technological efficiencies,

IGCC is likely to continue its growth beyond 2025.

The House-passed version of the FY2006 Energy and Water Development

appropriations bill (H.R. 2419), which includes funding for Fossil Energy R&D,

supports the Administration’s request for CCPI and FutureGen. However, while both

agree there is an unused previously appropriated balance of $257 million from the

Clean Coal Technology program, the Administration requests rescinding the money

and incorporating the funds into the fossil fuel account for FutureGen activities as an

advanced appropriation to be used in FY2007 and beyond. The House approved,

instead, deferring the $257 million, while acknowledging that the funds will be used

for the FutureGen program in FY2007 and beyond.

Omnibus Energy Legislation16

Background

Energy legislation initiated in the 107th Congress reached a conference-level

agreement (H.R. 6) in the 108th Congress, and was passed by the House but was

blocked by a Senate filibuster. A Senate alternative (S. 2095) introduced to address

the differences with the House version over MTBE and energy tax incentives also

died in the 108th Congress. These earlier versions both contained provisions under

Title IV (Coal) that would have provided loan guarantees for various coal projects

focused on developing the IGCC technology. Provisions under Title IX supported

R&D for IGCC, carbon sequestration, and other coal-related technologies. There

were also loan guarantees to fund a Fischer-Tropsch synthetic fuels project for diesel

fuel.

Legislative Issues

Legislation in the 109th Congress for an omnibus energy bill (H.R. 6) was

approved by the House on April 21, 2005. H.R. 6 includes provisions for coal nearly

identical to the H.R. 6 conference report filed in the 108th Congress.17 Within the

Clean Coal Power Initiative section there would be loan guarantees for specific IGCC

projects. Federal loans or loan guarantees would account for up to 30% of all

obligated money in any fiscal year with the federal share not to exceed 50% of any

one project. Pollution control projects (i.e., for mercury, NOx, SOx, and particulate

matter) would get $500 million in funding, and $1.5 billion would be authorized for

cogeneration and gasification projects between fiscal years 2006 and 2012. Coal

Technology provisions include an R&D program on IGCC systems, turbines for

16

Prepared by (name redacted), Analyst in Energy Policy, CRS Resources, Science, and

Industry Division.

17

H.R. 6, H.Rept. 108-375, November 17, 2003.

CRS-10

synthetic gas from coal, carbon sequestration, and loan guarantees for development

of Fischer-Tropsch diesel fuels. The Senate version of comprehensive energy

legislation (S. 10), among other things, authorizes CCPI for $200 million annually

for FY2006-FY2014.

Outlook

Funding for R&D and loan guarantees for the development of IGCC technology

appear to have some bipartisan support, based on previous support of clean coal

technology programs received in the annual Interior appropriations bill.

The Natural Resources Defense Council (NRDC), while on record in support

of IGCC technology because of its potential for emissions reduction and better

efficiencies, would prefer to see more stringent standards serve as a catalyst for the

industry to solve the clean air problem.18 That sentiment is echoed by Resources for

the Future Senior Fellow Dallas Burtraw. He argues that the Clean Air Act

Amendments of 1990 were the catalyst that led to major reductions in SO2 despite

years of incentives.19 An American Electric Power (AEP) representative contends

that without a subsidy, large-scale IGCC development will not take place. The AEP

argues that the Administration would need to “jump-start” development of about six

commercial-scale plants.20 The DOE has a study underway to help determine the

“best federal incentives” to move IGCC forward.21

The Senate Committee on Energy and Natural Resources held hearings on

energy policy in February 2005, but the anticipated schedule for omnibus energy

legislation in the House has slowed. Concern over spending has given rise to

differing opinions about how costly the energy tax provisions in the bill should be.

On February 10, 2005, the House Science Committee reported H.R. 610, legislation

including less controversial R&D provisions that were part of comprehensive

legislation debated in the 108th Congress.

Abandoned Mine Lands22

Background

The Surface Mining Control and Reclamation Act (SMCRA, P.L. 95-87),

enacted in 1977, established reclamation standards for all coal surface mining

operations and for the surface effects of underground mining. It also established the

Abandoned Mine Land (AML) program to promote the reclamation of sites mined

18

“Getting to Clean Coal,” C&EN, February 23, 2004, p. 44.

19

Ibid.

20

Ibid, p. 24.

21

Inside Energy, February 15, 2005, p. 1.

22

Prepared by (name redacted), Special in

Industry Division.

Energy Policy, CRS Resources, Science, and

CRS-11

and abandoned prior to the enactment of SMCRA. To finance reclamation of

abandoned mine sites, the legislation established fees on coal production. These

collections are divided into federal and state shares; subject to annual appropriation,

AML funds are distributed annually to states with approved reclamation programs.

Since the program’s inception and through FY2004, collections have totaled $7.1

billion; appropriations from the fund have totaled $5.5 billion. The unappropriated

balance in the fund approached $1.7 billion at the end of FY2004. As of the end of

FY2004, roughly $1.1 billion of this sum is credited to the state share accounts, of

which nearly $430 million alone is in Wyoming’s account, because — even though

most of the sites awaiting cleanup are in the eastern part of the nation — coal

production has shifted westward. Consequently, the western states have been making

significantly larger contributions to the fund in recent years.

Legislative Issues

Authorization for collection of AML fees was scheduled to expire at the end of

FY2004 and was extended nine months to the end of June 2005 by the Consolidated

Appropriations Act for 2005 (P.L. 108-447). Subsequently, H.R. 1268 (P.L. 109-13),

a supplemental appropriations bill for FY2005, extended AML authorization to the

end of FY2005. Bills have been introduced in the 109th Congress to extend the

authorization for fee collections and make changes to the program that would address

concerns about the mechanics of the program, the fee structure, and the

unappropriated balances.

Outlook

Legislation reauthorizing AML was introduced in the 108th Congress, but did

not pass. In addition, Congress did not adopt in its FY2005 AML appropriation an

Administration proposal that would have refunded, through a significant increase in

appropriations, unobligated state balances over a 10-year period. In its FY2006

budget request, the Administration has made virtually the same proposal and seeks

an additional $58 million to begin returning the unobligated balances. A bill

advancing the Bush changes to the AML program, H.R. 2721, was introduced May

26, 2005. Under the Bush plan, unappropriated balances would be returned to states

and Indian tribes that had completed reclamation of their Priority 1 sites. These

states would no longer receive grants from the AML fund itself, freeing up funds to

be targeted to states with sites awaiting cleanup. It is not apparent that the

Administration proposal will receive a different reception in the 109th Congress than

in the previous one.

Another bill introduced in the 109th Congress, H.R. 1600, is similar to

legislation introduced in the 108th Congress, and differs greatly in some respects from

the Administration proposal. The bill would extend authorization of the program

through FY2020, and reduce the fee collected per ton of coal production. It would

maintain the distinction between state and federal shares and would require that 50%

of annual contributions be returned to states even if cleanup of priority abandoned

mine sites had been completed. States and tribes would be allowed to use the money

for other purposes if cleanup of AML sites had been completed. Both H.R. 2721 and

H.R. 1600 would end an allocation of a portion of AML collections to the Rural

CRS-12

Abandoned Mine Land Program, a program that has received no appropriation since

1995.

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