Major Coal Issues in the 109th Congress
Released: 2005-06-10T00:00:00

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 someof the major legislative issues related to coal in the 109th Congress, including coal and energysecurity, clean air and environmental concerns, funding strategies for technology R&D, loanguarantees for coal gasification projects, and the Abandoned Mine Land program.

Energy Security and Coal(1)

Energy that is available, reliable, and affordable is a focal point when discussing energysecurity concerns. (2) Andcoal will be part of that conversation. Out of the four major fuel sources -- oil, gas, uranium, andcoal -- coal has the largest domestic reserve base, the largest share of U.S. energy production inBTUs, 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 growingreliance on foreign sources for other major fuels. In addition, coal is forecast to be the largest sourceof domestic fuel production in the foreseeable future.

Coal supplies 22% of U.S. energy demand but over 50% of the energy used by the electricpower sector (both utility and non-utility consumers). The electric power sector consumes 90% ofall coal in the United States. The remaining 10% is used in the industrial and commercial sectorsor 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 -- from3,481 billion kilowatt hours (kwh) to 5,220 billion kwh. (3) The increase in demand is largely to be met by new coal-fired ornatural gas-fired power plants. The price of each fuel, the capital costs associated with power plantconstruction, and plant efficiencies will determine the competitiveness of each fuel source. Butbecause of limited domestic supply, natural gas supply is unlikely to keep pace with demand. Thiswill lead to increased imports, according to EIA forecasts. Per-well reserve additions are expectedto continue to decline over the EIA forecast period (2004-2025). EIA further forecasts that naturalgas will not displace coal as the dominant fuel supply for power generation despite projectedincreases in liquefied natural gas (LNG) imports, additional domestic supply from the lower 48states, 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. Thelower-cost, more efficient operations are the plants that get built. Production costs include the costsof fuel, operation and maintenance, and capital. Fuel costs are a major consideration for fossilfuel-fired plants, and the fuel cost differences between a coal-fired and natural gas-fired plant aresignificant. For instance, fuel costs for a coal-fired plant are about 24% of total costs, whereas fuelcosts for a natural gas facility are close to 69% of total costs. This price difference could give coalan advantage. However, new plant capital costs favor natural gas, accounting for only 23% of totalelectric 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 advancedcombined cycle (natural gas-fired) plants expected to be built in the years 2015 and 2025.

Table 1. Costs of Producing Electricity from NewPlants

(2003 mills/Kwh)

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

A combination of low capital costs, greater efficiency, and reasonable natural gas prices ledto the current build-up of natural gas-fired capacity. Power plant capacity rose an estimated 186gigawatts (GW) from 2000 to 2003: 27 GW in 2000; 42 GW in 2001; 72 GW in 2002; and 45 GWin 2003. About 175 GW was new natural gas-fired capacity, and only 1 GW was new coal-firedcapacity. (5) This build-uphas led to excess capacity, which should diminish after 2010. Capacity utilization would rise from72% 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 anestimated 19 GW annually from 2011 to 2025 (268 GW total). Natural gas facilities (combinedcycle; combustion turbine or distributed generation technology) are forecast to account for 60% ofthe 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 becomesmore competitive with natural gas late in the forecast between 2016 and 2025. Despite relativelylow coal costs, the high capital costs will likely limit the number of advanced coal integratedgasification combined cycle (IGCC) facilities to about 16 plants or 6 GW of commercial capacityby 2025. (6)

Rising natural gas prices will lead to the construction of more coal-fired facilities betweenthe years 2010 and 2025, according to EIA. Coal is competitive at natural gas prices of $4-$6 permillion Btus; prices above that range push up the total cost of gas-fired power facilities abovecoal-fired plants. Even so, natural gas, as a percent of the total electricity, will increase to 24% in2025 from 17% in 2003, projects EIA, while nuclear and petroleum will remain flat. Renewablesrise 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. Anestimated 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 steamplants).

If the EIA forecasts prove to be accurate, then long-term investment in clean coal could payoff because of the greater coal capacity needs beyond 2016. Among the most important factors towatch regarding coal versus natural gas-fired plants are the natural gas prices, capital costs for IGCCplants, and stricter environmental regulations aimed at pollutants derived from burning coal.

Clear Skies Legislation(7)

By mandating significant reductions in three pollutants emitted by coal-fired electricgenerating units, proposed Clear Skies legislation could have significant impact on coal productionand distribution, if enacted. Electric utilities are the largest users of coal, and legislation restrictingtheir emissions could affect coal markets in several ways, depending on the specifics of any finallegislation.

Background

In the 109th Congress, a modified version of the President's proposed Clear Skies legislationhas been introduced by Senator Inhofe -- S. 131 . The proposal would amend the CleanAir Act to place caps on electric utility emissions of sulfur dioxide (SO 2 ), nitrogen oxides (NOx),and mercury (Hg). Implemented through a tradeable allowance program, the emissions caps wouldbe imposed in two phases: 2010 (2008 in the case of NOx) and 2018. (8) The proposed caps aresummarized in Table 2 .

Table 2. Proposed Emission Caps Under S.131

Although proposed Clear Skies legislation is the focus of legislative debate, regulatoryinitiatives currently being promoted by Environmental Protection Agency (EPA) raise many of thesame issues for coal interests as does Clear Skies. These initiatives include the proposed Clean AirInterstate Rule and the proposed Mercury Rule. (9)

Legislative Issues

When Clear Skies was introduced in the 108th Congress, EPA conducted an analysis of itseffects on the coal industry. (10) While the analysis indicated growth in coal production forelectric utility consumption (from 905 million tons in 2000 to 998 million tons in 2020), coalgeneration's share of the 2020 generation mix (11) was projected to decline from 46% to 44%. The beneficiary ofthis projected decline was natural gas combined cycle, whose share of the mix climbed from 24%in 2000 to 26% in 2020. Obviously the actual mix that would result from any enactment of ClearSkies would be heavily dependent on future natural gas prices and utility decisions with respect tocompliance strategies.

With respect to compliance strategies, the EPA analysis projected a substantial increase inthe installation of flue-gas desulfurization units (FGD) to achieve the 70% reduction in SO 2 requiredby the proposed legislation. Currently, about 100,000 megawatts (Mw) of coal-fired capacity hasFGD units. EPA projected that Clear Skies would result in that number rising to just over 200,000Mw by 2020. (12) Thiswould increase the share of FGD-equipped coal-fired capacity in the country from about one-thirdto 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 implementationof the NOx SIP Call. (13)

Such an increase in emissions control (particularly FGD units) could reduce the marketadvantage that high-sulfur coal currently enjoys in the coal markets. As indicated by Table 3 , EPAanalysis indicates that the Interior Basin in particular benefits from the increased SO 2 controls.

Table 3. EPA's Projections of Coal Production Under Clear SkiesLegislation

(million tons)

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

With respect to Hg controls, S. 131 would weaken the proposed phase 1 Hg capfrom the 26 tons originally proposed by the Administration to 34 tons, based on a DOE estimateabout 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 andsubbituminous 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 productionwould be nil, beyond that estimated for SO 2 and NOx controls. Likewise, the commercialization ofemerging Hg control technology, such as activated carbon injection (ACI), would eliminate any shiftbetween coal types. However, there is substantial controversy over what any "co-benefits" level isand the future availability of ACI and other alternatives.

The pivotal issues for coal and Clear Skies include the following: (1) the potential for naturalgas to erode market share for coal due to higher pollution control costs under Clear Skies, (2) thepotential for market shift between western suppliers and eastern suppliers because of increased SO2controls, and (3) the uncertain effects of Hg controls if they exceed "co-benefit" levels or if emergingHg controls are not available.

Outlook

Clear Skies faces an uncertain future. In March 2005, the Senate Environment and PublicWorks Committee killed S. 131 on a 9-9 vote. However, many of the issues identifiedhere 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 Technology(14)

Background

The original Clean Coal Technology (CCT) program began in 1984 to demonstrate emissionscontrol technologies, advanced electric power generation facilities, and coal and industrial processingprojects. Congress had appropriated $2.5 billion for the CCT program by 1990, but since 1994 asmuch as $300 million had been deferred or rescinded because of limited commercial prospects andless Administration interest. President Bush, however, has revived the CCT program under a newbanner -- the Clean Coal Power Initiative (CCPI) -- focusing on advanced coal combustiontechnology 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 CO 2 , and 22% of nitrogenoxide air emissions in the United States.

The CCPI is a 10-year, $2 billion government-industry cost sharing program structuredsimilarly to the original CCT program. There are currently 10 active CCPI projects. The DOEwanted the early projects to focus on technologies that would reduce pollutants being addressedunder the President's "Clear Skies" proposal and Global Climate Change initiative. Round 1 projectsfeature multi-pollutant control systems, while Round 2 features two multi-pollutant controltechnologies and two integrated gasification combined cycle (IGCC) demonstration projects.Announcements for Round 3 projects are expected to occur during FY2006.

Legislative/Appropriation Issues

One of the issues that arise is funding for long-term clean coal technology versus closer-termpilot and demonstration projects. Both are being funded. Based on recent appropriation trends, thegreatest interest for closer-term R&D is with IGCC projects for electricity supply and emissionsreduction.

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 atits Wabash River site in Indiana. IGCC technology involves the gasification of coal to produceelectricity. During the gasification process, coal is co-fed with water and oxygen in a reducingatmosphere at high pressure to produce synthetic gas, carbon monoxide, and hydrogen. Sulfur andcarbon 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 obstaclesfacing IGCC is the reliability of the gasification process. Because of reliability questions, amongother challenges, large-scale competitive commercial plants may still be years away. Both Congressand the Administration continue to invest heavily in IGCC because of the potential benefits fromreduced NOx, SOx, mercury, and particulate matter. Moreover, lower CO 2 emissions throughgreater plant efficiencies and/or potential sequestration could be substantial.

The Administration is looking at very long-term investments as well. FutureGen representsthat strategy. FutureGen -- an integrated sequestration and hydrogen research initiative -- is a $1billion dollar industry/government partnership to build a coal-fired gasification and hydrogenproduction 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 wouldprovide 275 MW from electricity and hydrogen and sequester 1 million metric tons of carbondioxide annually. The project is designed to build international support to address "global warmingand energy security." (15) The prototype will allow DOE to operate a large-scale facility to prove the technical feasibility ofzero 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 sectorwould contribute $250 million (which would be capped), and about $80 million is anticipated fromthe international community.

The funding for FutureGen began in FY2004 at $9 million. Appropriations were nearlydoubled 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. DOEprojects 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 Administration has also been seeking tocancel previously appropriated funds for the original CCT program and shift that money toFutureGen. 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 programsfor FY2006:

Clean coal power initiative -- A 10 year, $2 billion effort that began in FY2002. TheAdministration has submitted a $50 million request for FY2006. Nearly $400million in funding has already been appropriated since FY2002. Rounds 1 and 2 arealready underway. DOE's Office of Fossil Energy will begin Round 3 solicitationsduring 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 CCPIand FutureGen, would rise by 5.9% to $218 million while nearly all other fossilenergy programs would be cut. Major cuts to programs other than coal are proposedwhich would reduce the total Fossil Energy program to $491.5 million -- 14% ($80.5million) less than the enacted amount for FY2005.

Coal Gasification -- Within the Coal R&D program, the Administration's request forgasification research went up from $34.5 million in FY2005 to $56.4 million inFY2006. FY2005 appropriations were $45.8 million. This level of increase is anindication of more commitment by the Administration and Congress to IGCC effortsaimed at commercialization of the technology.

Carbon sequestration -- The R&D program would receive $67.2 million in theAdministration'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 coaltechnology, potentially at the expense of other fossil technologies -- such as natural gas orpetroleum technology R&D. However, the CCPI may need consistently higher investments in aconstrained spending environment to provide the desired long-term results -- a commerciallyaffordable 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 commitmentneeded and instead abandon gasification projects altogether. Even with heavy investment in cleancoal/gasification strategies, natural gas-fired generation may retain its economic advantage over thelong-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-scalecommercial production, and decades-long R&D funding never recouped.

However, the strategy of investing in coal-gasification projects for closer-termcommercialization fits EIA's forecast that16 commercial IGCC plants will be on-line between2011-2025. The total output would still be only 7% of all coal-fired capacity, but if there are capitalcost reductions and greater technological efficiencies, IGCC is likely to continue its growth beyond2025.

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 theAdministration's request for CCPI and FutureGen. However, while both agree there is an unusedpreviously appropriated balance of $257 million from the Clean Coal Technology program, theAdministration requests rescinding the money and incorporating the funds into the fossil fuel accountfor FutureGen activities as an advanced appropriation to be used in FY2007 and beyond. The Houseapproved, instead, deferring the $257 million, while acknowledging that the funds will be used forthe FutureGen program in FY2007 and beyond.

Omnibus Energy Legislation(16)

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 aSenate filibuster. A Senate alternative ( S. 2095 ) introduced to address the differenceswith the House version over MTBE and energy tax incentives also died in the 108th Congress. Theseearlier versions both contained provisions under Title IV (Coal) that would have provided loanguarantees for various coal projects focused on developing the IGCC technology. Provisions underTitle IX supported R&D for IGCC, carbon sequestration, and other coal-related technologies. Therewere 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 ) wasapproved by the House on April 21, 2005. H.R. 6 includes provisions for coal nearlyidentical to the H.R. 6 conference report filed in the 108th Congress. (17) Within the Clean CoalPower Initiative section there would be loan guarantees for specific IGCC projects. Federal loansor loan guarantees would account for up to 30% of all obligated money in any fiscal year with thefederal 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 beauthorized for cogeneration and gasification projects between fiscal years 2006 and 2012. CoalTechnology provisions include an R&D program on IGCC systems, turbines for synthetic gas fromcoal, carbon sequestration, and loan guarantees for development of Fischer-Tropsch diesel fuels. TheSenate 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 tohave some bipartisan support, based on previous support of clean coal technology programs receivedin the annual Interior appropriations bill.

The Natural Resources Defense Council (NRDC), while on record in support of IGCCtechnology because of its potential for emissions reduction and better efficiencies, would prefer tosee more stringent standards serve as a catalyst for the industry to solve the clean air problem. (18) That sentiment is echoedby Resources for the Future Senior Fellow Dallas Burtraw. He argues that the Clean Air ActAmendments of 1990 were the catalyst that led to major reductions in SO2 despite years ofincentives. (19) AnAmerican Electric Power (AEP) representative contends that without a subsidy, large-scale IGCCdevelopment 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 studyunderway 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 inFebruary 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 taxprovisions 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 ofcomprehensive legislation debated in the 108th Congress.

Abandoned Mine Lands(22)

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 effectsof underground mining. It also established the Abandoned Mine Land (AML) program to promotethe reclamation of sites mined and abandoned prior to the enactment of SMCRA. To financereclamation of abandoned mine sites, the legislation established fees on coal production. Thesecollections are divided into federal and state shares; subject to annual appropriation, AML funds aredistributed annually to states with approved reclamation programs. Since the program's inceptionand 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, ofwhich nearly $430 million alone is in Wyoming's account, because -- even though most of the sitesawaiting 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 inrecent years.

Legislative Issues

Authorization for collection of AML fees was scheduled to expire at the end of FY2004 andwas 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 appropriationsbill for FY2005, extended AML authorization to the end of FY2005. Bills have been introduced inthe 109th Congress to extend the authorization for fee collections and make changes to the programthat would address concerns about the mechanics of the program, the fee structure, and theunappropriated balances.

Outlook

Legislation reauthorizing AML was introduced in the 108th Congress, but did not pass. Inaddition, Congress did not adopt in its FY2005 AML appropriation an Administration proposal thatwould have refunded, through a significant increase in appropriations, unobligated state balancesover a 10-year period. In its FY2006 budget request, the Administration has made virtually the sameproposal and seeks an additional $58 million to begin returning the unobligated balances. A billadvancing 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 tribesthat had completed reclamation of their Priority 1 sites. These states would no longer receive grantsfrom the AML fund itself, freeing up funds to be targeted to states with sites awaiting cleanup. It isnot apparent that the Administration proposal will receive a different reception in the 109th Congressthan in the previous one.

Another bill introduced in the 109th Congress, H.R. 1600 , is similar to legislationintroduced in the 108th Congress, and differs greatly in some respects from the Administrationproposal. The bill would extend authorization of the program through FY2020, and reduce the feecollected per ton of coal production. It would maintain the distinction between state and federalshares and would require that 50% of annual contributions be returned to states even if cleanup ofpriority abandoned mine sites had been completed. States and tribes would be allowed to use themoney 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 RuralAbandoned Mine Land Program, a program that has received no appropriation since 1995.