Major Coal Issues in the 109th Congress

CRS Report for Congress
th
Major Coal Issues in the 109 Congress
Updated June 10, 2005
Marc Humphries, Coordinator
Analyst in Energy Policy
Resources, Science, and Industry Division
Larry Parker and Robert Bamberger
Specialists in Energy Policy
Resources, Science, and Industry Division


Congressional Research Service ˜ The Library of Congress

Major Coal Issues in the 109 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 Skiesth
was introduced in the 108 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 10-
year, $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 nearlyth
identical to the H.R. 6 conference report filed in the 108 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
In troduction ......................................................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



th
Major Coal Issues in the 109 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 Marc Humphries, 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.

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)
20152025
Advanced Advanced
Advanced combined Advanced combined
Cos t s coal cycle coal cycle
Capital 31.68 11.63 28.87 11.08
Fixed 4.59 1.36 4.59 1.36
Variable 12.28 34.88 13.98 39.06
(primarily fuel)
Incremental 3.24 2.80 3.41 2.86
Transmission
T otal 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.

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 build-
up 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 Larry Parker, Specialist in Environmental Policy, CRS Resources, Science,
and Industry Division.

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 SO24.5 million tons3.0 million tons
Emissions Cap on NOx2.19 million tons1.79 million tons
(total for both zones)
Emissions Cap on Hg34 tons15 tons
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 Larry Parker and John Blodgett.
9 See CRS Report RL32273, Air Quality: EPA’s Proposed Interstate Air Quality Rule, by
Larry Parker and John Blodgett; and CRS Report RL31881, Mercury Emissions to the Air:
Regulatory and Legislative Proposals, by James McCarthy.
10 See those analyses at [http://epa.gov/air/clearskies/technical.html].
11 Generation Mix in EPA’s analysis in footnote 10, above, refers to generation capacity, not
electric generation production used in EIA projections.

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)
2020 Production under
Region2000 ProductionClear Skies Legislation
Appalachia 299 305
Interior131220
West475473
Total905998
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 one-
hour National Ambient Air Quality Standard for Ozone.

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 Marc Humphries, Analyst in Energy Policy, CRS Resources, Science, and
Industry Division.

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 large-
scale 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.

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.



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 Marc Humphries, Analyst in Energy Policy, CRS Resources, Science, and
Industry Division.
17 H.R. 6, H.Rept. 108-375, November 17, 2003.

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 Robert Bamberger, Special in Energy Policy, CRS Resources, Science, and
Industry Division.

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 theth
Administration proposal will receive a different reception in the 109 Congress than
in the previous one.
Another bill introduced in the 109th Congress, H.R. 1600, is similar toth
legislation introduced in the 108 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



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

1995.