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INSIDE THIS EDITION: Why Coal, Why Now? The Next Generation of Coal


The Debate on Mercury The Impact of New Air Regulations on Regional Coal Markets The Case for Clean Coal Technologies

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At DTE Coal Services, we have a solid history of managing both your energy and transportation needs. Our patented PepTecŽ process recovers waste coal from slurry ponds, improving the environment while providing you with a new revenue source. And our innovations in coal tolling and trading, as well as internet proprietary tools like RipTrackSM, help lower your costs. Our solutions are customized to match your unique demands – whether coal supply or railcar fleet management. To take advantage of the experience that comes with an industry leader, visit or call 734.913.2097 today.

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Published for: AMERICAN COAL COUNCIL 2980 E. Northern Ave., Suite B4 Phoenix, AZ 85028 Tel: (602) 485-4737


ACC Editorial Review Board Evan Ard, Evolution Markets LLC Janet Gellici, American Coal Council Rick James, We Energies Vic Svec, Peabody Energy


Published by: Lester Publications, LLC 2131 NW 40th Terrace - Suite A Gainesville, FL 32605 Main line: (352) 338-2700 Toll Free: (877) 387-2700

Message from ACC Executive Director . . . . . . . . . . . . . . . . . . . . . . . . 5

Message from ACC President . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 2005 Board of Directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 ACC Vision and Mission Statement . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 ACC Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 ACC Member Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

President Jeff Lester | (866) 953-2189

ACC Champion & Patron Sponsors . . . . . . . . . . . . . . . . . . . . . . . . . . 8 ACC History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Sales Director Bob Neufeld | (866) 953-2189 Managing Editor Lisa Kopochinski | (800) 481-0265 Art Director Jennifer Karton | (877) 953-2587 Graphic Designer Vince Saseniuk | (866) 890-8756 Account Executives Heather Campbell, Louise Peterson, Michelle Raike, Jim Siwy © 2005 American Coal Council. All rights reserved. The contents of this publication may not be reproduced by any means, in whole or in part, without the prior written consent of the ACC. Disclaimer The opinions expressed by the authors of the editorial articles contained in American Coal magazine are those of the respective authors and do not necessarily represent the opinion of the American Coal Council or its member companies Printed in Canada Please recycle where facilities exist.

Why Coal, Why Now? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 The Next Generation of Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Coal – Our Nation’s Most Valuable Energy Source . . . . . . . . . . . . . . . 22 We Can See Clearer Now! . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 The Case for Committing to Clean Coal Technologies . . . . . . . . . . . . 31 AEP Commits to Coal with IGCC Project . . . . . . . . . . . . . . . . . . . . . 36 Environmental Stewardship in the Far North . . . . . . . . . . . . . . . . . . . 38 The Debate on Mercury . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Impact of New Air Regulations on Regional Coal Markets . . . . . . . . . 43 2005-2007 Coal Outlook: Sustainable Strength on Global Steel and Power . . . . . . . . . . . . . . 46 Railroads and Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Physical Index-Based Coal Transactions . . . . . . . . . . . . . . . . . . . . . . . 59 The Value of Coal Ash: An Economic Assessment of CCP Utilization . . . . . . . . . . . . . . . 62 U.S. Mining GAAP, U.S. Mineral Reserve Reporting and New U.S. Tax Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Index to Advertisers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 About the Cover: Peabody Energy continues to lead the nation in reclamation excellence. On Arizona’s Black Mesa, Native American lands have been reclaimed for traditional livestock grazing, while restoring plants and herbs with cultural significance. The U.S. Department of the Interior honored Peabody with its first “Gold” Good Neighbor Award in 2003 for a host of environmental, economic and tribal initiatives on Native American lands. AMERICAN COAL COUNCIL

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3/23/05 10:06:54 AM

A History of Values

“Let us strive to finish the work we are in . . .� Abraham Lincoln, Second Inaugural Address March 4, 1865

At Boral Material Technologies Inc., we are committed to delivering performance, exceeding expectations through leadership, focus, persistence and respect. Based on these values, Boral has led the Coal Combustion Products industry for 40 years in developing improved products, services, and processes.


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To learn more about Boral values and how these values will assist you to meet your goals contact us at 800-964-0951 or


3/23/05 10:07:00 AM


An Exciting Time For Our Industry! Jim O’Neil, President, American Coal Council & President, DTE Coal Services


elcome to the third issue of American Coal. This annual magazine is a cornerstone of the American Coal Council’s efforts to provide timely and critical information to industry associates, public policy makers and community leaders regarding the economic and environmental value and viability of the utility-coal industry. It’s an exciting time to be a part of the utility-coal industry. U.S. and Canadian demand for electric power continues to increase. The availability of inexpensive electricity helps to fuel our nations’ economic rebound. The inexorable march of technology provides cost effective environmental options. Coal has a major role to play in economic recovery and growth. Coal fuels about 52 percent of our U.S. electric power industry. It’s an abundant resource – 250 years of reserves in the U.S. It’s also an economic resource – the price of coal-fueled electricity is $1.27/mmBtu vs. $5.42/mmBtu for natural gas and $4.31/mmBtu for oil in 2003. And, it has proven to be an environmentally sound resource – SO2 emissions have been


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reduced nearly 40 percent since 1970 and NOx reductions of 33 percent have been achieved since 1990. In recognition of these facts, an increasing number of utilities are exploring opportunities to develop new coal generation plants as part of their power portfolios. The U.S. Department of Energy is projecting that 112 GW of new coal capacity could come on line by 2025. Today, there’s 65 GW of new coal generation proposed for more than 100 plants in virtually every state in the U.S. Tomorrow’s coal plants will increasingly make use of clean coal technologies, including advanced PC systems and IGCC. Using state-of-the-art emissions controls, the future of coal-fueled power will be even cleaner and brighter than in years past. Utilities are also working to increase the utilization of coal combustion products or coal ash, in ways that enhance our environment and improve the quality and durability of our building and construction products. While coal consumers are working to further reduce emissions, our nations’ coal suppliers continue to steward the land in compliance with federal and state laws, using proven environmentally sound techniques. Others in the utility-coal industry – including railroads, ports and terminals and energy traders – are using their respective tools to ensure a sound, secure delivery system and financial viability for the industry. These sophisticated tools not only serve our needs today, but are designed to serve us well many years into the future. These are among the themes addressed in this issue of American Coal. Our authors provide you with the latest information and examples of how the utilitycoal industry is serving our nation today and implementing plans to continue to do so well into the future. We hope you enjoy this issue of American Coal and welcome your comments and suggestions for future issues.◆





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2/21/05 PMAM 3/23/05 2:38:11 10:07:29

38:11 PM


Your Association at Work By Janet Gellici, American Coal Council


s I was in the throes of editing copy, writing copy, working with our publisher and organizing distribution lists for this issue of American Coal, I took a deep breath and asked myself, “Why are we doing this?” Actually, it didn’t take me too long to answer my own question. American Coal is an educational and advocacy tool for our industry and a showcase for the American Coal Council and its members.

The magazine is one way the ACC is striving to fulfill its vision – to serve as the pre-eminent business voice of the American coal industry. Giving a “voice” to the benefits and successes of coal generation is a vital role for the ACC. I’m often asked, “What are the benefits of membership in the ACC? Why should I join the Association?” Some benefits are easy to value – discounts for conferences, economic studies and other information resources; priority vendor referrals and inclusion in our on-line and printed directories; access to our members-only Web resources; receipt of membersonly newsletters; advanced opportunities for sponsorships. Other benefits are more intangible, but equally important. Associations educate members on technical and public policy matters, business practices and legal issues, elevating the quality of products

and services. Associations provide our industry’s workforce with information and resources to help them remain competitive and skilled in the latest techniques, trends and technologies. In collecting and disseminating information on industry issues and practices, associations provide valuable background for legislative, regulatory and policy decisions. And, by informing the public about the efficiency, quality and viability of products and services, associations help bolster public confidence in the marketplace. Your membership in the American Coal Council helps us advance the utilitycoal industry’s business objectives and enhance its business practices. The ACC values and appreciates the support of its members; without you the publication of this magazine would not be possible. We’ll keep working for you! ◆

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Mailing Address: P. O. Box 610, Abingdon, VA 24212 Shipping: 26864 Watauga Road, Abingdon, VA 24211 Voice: (276) 676-2376 or (800) 390-7636 Fax: (276) 676-0300 e-mail:


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American Coal Council

American Coal Council 2005 Board of Directors Vision Statement The ACC strives to be the pre-eminent business voice of the American coal industry.

Mission Statement The American Coal Council (ACC) is dedicated to advancing the development and utilization of coal as an economic, abundant and environmentally sound energy fuel source. The Association promotes the lawful exchange of ideas and information regarding the coal industry. It serves as an

essential resource for companies that mine, sell, trade, transport or consume coal. The ACC provides educational programs, advocacy support,

COAL SUPPLIERS Jim Campbell Senior Vice President Peabody Energy Todd Myers President Westmoreland Coal Sales ACC Vice President Suppliers 2005 Bob Pusateri Vice President Sales CONSOL Energy COAL CONSUMERS Keith Drohan Director Market Origination Dominion Energy Ken Jenkins Executive Director Fuel Services Southern Company ACC Vice President Consumers 2005 Jim O’Neil President DTE Coal Services ACC President 2005 TRANSPORTATION Chris Jenkins Senior Vice President – Coal CSX Transportation ACC Vice President Transportation 2005 Tom Vorholt Vice President Dry Cargo Sales Ingram Barge

PORTS & TERMINALS Mike Ferguson Vice President - Regional Manager Kinder Morgan Bulk Terminals ACC Vice President Ports & Terminals 2005 Bill Rager Vice President & General Manager of Operations Southern Coal Handling Co., Inc. ENERGY TRADERS West Boettger Director Energy Marketing Dynegy Marketing & Trade ACC Vice President Energy Traders 2005 Dan Vaughn Manager Coal Services United Power Inc. COAL SUPPORT SERVICES Kevin Jennison Fuels Consulting Business Leader Black & Veatch ACC Vice President Support Services 2005 John Ward Vice President Marketing & Government Affairs Headwaters Resources ACC Treasurer 2005 & President-Elect 2006 IMMEDIATE PAST PRESIDENT Lance Fritz Vice President & General Manager Union Pacific

peer-to-peer networking forums and market intelligence that allow members to advance their marketing and management capabilities.


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3/23/05 10:07:41 AM

American Coal Council

Quality Educational Programs in 2005 Mercury & Multi-Emissions Compliance Strategies & Tactics for New & Existing Coal Plants March 22-24, 2005 Hyatt Regency Union Station – St. Louis, Missouri Provides utility coal consumers and coal suppliers with a macro perspective on the fundamentals of mercury and multiemissions control, including the implications of emissions compliance on plant economics, fuel choice decisions, and control technology options.

2005 Spring Coal Forum Coal’s Renaissance: Prospects for Regenerating Coal Generation May 18-20, 2005 Scottsdale Plaza Resort – Scottsdale, Arizona A focus on the resurgent interest in coal generation and the marketplace and public policy issues that will affect future demand for coal in North America.




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PRB Coal Use Risk Management Strategies & Tactics August 17-19, 2005 San Antonio Convention Center – San Antonio, Texas Hosted in conjunction with COAL-GEN An intensive course that provides utility coal consumers with advanced techniques, best practices and risk management approaches for handling, storing and consuming Powder River Basin (PRB) coal.

2005 Coal Market Strategies Conference Coal: Electrifying the Nation October 12-14, 2005 – Nashville, Tennessee A forum for senior industry executives from companies that produce, supply, transport, ship, trade and consume coal.

2005 Coal Trading Conference December 7-8, 2005 – New York City Hosted in conjunction with the Coal Trading Association The premier forum for coal traders and utility-coal executives to obtain critical marketplace and strategic intelligence. For more information on these quality educational programs, contact the American Coal Council at (602) 485-4737 or visit the ACC Web site at AMERICAN COAL COUNCIL

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3/23/05 10:20:02 AM

American Coal Council Member Companies ADA Environmental Solutions, Inc. AEP/Cook Coal Terminal Air Control Science, Inc. Alliance Coal, LLC Alliant Energy Alpha Natural Resources ALSTOM Power, Performance Projects Ameren Energy Fuels & Services American Coal Ash Association (ACAA) American Electric Power Andalex Resources, Inc. Arch Coal, Inc. Argus Media Basin Electric Power Cooperative Benetech, Inc. Black & Veatch Boral Material Technologies Burlington Northern Santa Fe Railway CAM Holdings – Central Appalachia Mining Canadian National – Illinois Central Railroad Center for Energy & Economic Development (CEED) CIT Rail Resources Coal Association of Canada Colorado Springs Utilities Commonwealth Coal Services, Inc. CONSOL Energy, Inc. Constellation Energy CSX Transportation Dakota, Minnesota & Eastern Railroad David J. Joseph Company Dominion Energy Drummond Company, Inc. DTE Coal Services DTE Rail Services Duke Power Dynegy Marketing & Trade Edison Mission Energy Fuel Services Entergy Evolution Markets LLC First Energy Foundation Energy Sales FreightCar America Fuel Tech, Inc. Gainesville Regional Utilities GE Betz GE Rail Services Glencore Ltd. Global Energy Decisions 8

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Great Northern Power Development L.P. Great River Energy Hazen Research, Inc. Headwaters Resources, Inc. Hellerworx, Inc. Helm Financial Corp. Hill & Associates, Inc. Holcim (U.S.) Inc. Ingram Barge Company Interlake Steamship Company James River Coal James River Coal Sales John T. Boyd Company Kansas City Southern Railway KCBX Terminals Company Kennecott Energy Company KFx Inc. Kiewit Mining Group, Inc. Kinder Morgan Bulk Terminals, Inc. Knott Floyd Land Koch Carbon LLC Lafarge North America Lakeland Electric LG&E Energy Marston & Marston, Inc. MidAmerican Energy Company Midwest Energy Resources Midwest Railcar Corp. Millennium Environmental Group Mineral Resource Technology Minnesota Power MRC Rail Nalco Natsource, LLC NexGen Coal Services Ltd. Norfolk Southern Corporation North American Power Group Ltd. Norwest Corporation Omaha Public Power District Ontario Power Generation Orica USA Inc. Orlando Utilities Commission (OUC) PA Consulting Pace Global Energy Services PacifiCorp Paducah & Louisville Railway, Inc. Peabody Energy Pincock, Allen & Holt Pioneer Mechanical Pittsburg & Midway Coal Mining Platts Analytics & Forecasting

PNC Bank Portland General Electric PPL Energy Plus PricewaterhouseCoopers LLP Progress Energy Progress Fuels Corp. Rail Link Railroad Financial Corp. Roberts & Schaefer Company Roundup Trading International LLC Salt River Project Sampling Associates International Savage Industries, Inc. SCANA SCH Terminal Co., Inc. Separation Technologies SGS Minerals Services SolArc, Inc. Southern Company SSM Coal Americas, LLC Stagg Resource Consultants, Inc. Standard Laboratories, Inc. Texas Genco The C. Reiss Coal Company The North American Coal Corp. The Raring Corp. Thunder Bay Terminals Ltd. Titan America TransAlta Corp. Trinity Industries Troutman Sanders LLP Tucson Electric Power Company TXU Electric Union Pacific Railroad Company United Power, Inc. University of Kentucky Center for Applied Energy Res. Usibelli Coal Mine, Inc. We Energies Weir International Mining Consultants West Virginia University National Research Center for Coal & Energy Westar Energy Western Fuels Association Western Region Ash Group Westmoreland Coal Sales Company WPS Resources Xcel Energy Xcoal Energy

Thank You ACC Champion & Patron Sponsors for 2005! The American Coal Council is pleased to acknowledge the support of its annual Champion and Partron Sponsors whose contributions advance the Association’s efforts to serve as the pre-eminent business voice of the American coal industry.


DTE Coal Services Jim O’Neil, President 425 S. Main, Ste. 201 Ann Arbor, MI 48104 (734) 913-2294

Savage Services Corporation Charlie Monroe Sr. Vice President Coal Services Development 6340 South 3000 East, Ste. 600 Salt Lake City, UT 84121 (801) 944-6629

SGS North America Inc. Marc Rademacher Vice President Western Operations 4665 Paris St., B-200 Denver, CO 80239-3117 (303) 373-4772


Ameren Energy Fuels & Services Co. Mike Mueller, Vice President 1901 Chouteau Ave. St. Louis, MO 63101 (314) 554-4174

Headwaters Incorporated John Ward, Vice President Marketing & Communications Headwaters Energy Services 10653 S. Riverfront Parkway Ste. 300 South Jordan, UT 84095 (801) 984-9400 AMERICAN COAL COUNCIL

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3/23/05 10:20:24 AM

ACC History

American Coal Council 23 Years of Service to the UtilityCoal Industry


he American Coal Council (ACC) is proudly celebrating its 23rd Anniversary this year! The ACC’s predecessor organization, the Western Coal Council (WCC), was founded in 1982 as the Western Coal Export Council (WCEC), a private industry trade group formed to promote exports of western U.S. coal to the Pacific Rim. The WCEC grew out of the efforts of a multi-national Task Force formed under the auspices of the Western Governors’ Association (WGA). In 1981, that Task Force published a study on “Western U.S. Steam Coal Exports to the Pacific Basin.” Three nations — Japan, Taiwan and South Korea — along with more than 40 U.S. companies participated in the study group. In 1986, the Western Coal Export Council changed its name to the Western Coal Council to more accurately reflect the organization’s support for expansion of both foreign and domestic markets for western U.S. coal. The strengths and practices established in those early years — including a broad-based membership, a partnering, non-adversarial approach to business, excellence in educational programming and an eagerness to work closely with other groups to advocate for the coal industry’s interests — continued to foster the WCC’s growth and development. In the spring of 2002, the WCC undertook the next step in its development as the membership voted overwhelmingly to transition from a regional to a national organization. The American Coal Council (ACC) continues to be dedicated to advancing the development and utilization of coal as an economic, abundant and environmentally sound fuel source. The Association’s national focus and its increasingly close ties with national and state organizations and other industry groups enhance its advocacy efforts. Our membership base includes coal suppliers, consumers, energy traders, transportation companies, ports and terminals and coal support service firms. Over the last 10 years, the ACC has increased its membership by nearly 500 percent. Today, the more than 140 member companies of the American Coal Council have combined their respective voices to serve as the pre-eminent business voice of the American coal industry. ◆


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3/23/05 10:20:28 AM

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3/23/05 10:20:40 AM

Why Coal, By Andy Roberts and Phil Szczesniak Platts Analytics & Forecasting



Just a few years ago, plans for adding new coal-fueled generation 50,000

fleet were few and far between. However, the energy landscape has changed noticeably and now over 50,000 MW of new coal plant

Capacity Change (MW)

to the U.S. power plant generating 40,000


capacity have been announced and are in various phases of


active development. 10,000



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0 12/31/2000



On H old

Early Development



Advanced Development


Under Construction












Coal Price Advantage (Cents/mmBtu)

Figure 1: New coal plant status by time period. Source: Platts NEWGen™Database

Generation (Millions of MWHrs)

n the last five years, little coal operating capacity has been added, but 10,000 MW are now either in construction or advanced planning and another 20,000 MW are in early development. (See Figure 1). The resurgence is driven by steady economic growth following the recession, which has helped fuel demand for electricity. Low natural gas prices in the 1990s, coupled with irrational expectations of natural gas demand growth fueled a boom in gas-fired capacity addition that was followed by a bust in gas plant usage factors at many of the new plants. At the same time, electric generation from coal grew steadily; coal capacity factors have reached an average of 70 percent nationwide and coal’s price advantage over natural gas has grown substantially. (See Figure 2). In late 2000 and early 2001, high gas prices stimulated interest in new coal plants. The current gas capacity “bubble” should not be construed as proof that new generating capacity is unnecessary. The gas capacity overbuild had much to do with underestimating nuclear re-licensing and overestimating old coal plant retirement levels. Still, some of that overbuild was attributable to unreasonable expectations of the economic survival of pure gas plants versus gas plant competition. In part, this


0 1989

1994 Coal Gen

Natural Gas Gen

1999 Gen - All Other Fuels

2004 (est) Coal Price Advantage

Figure 2: U.S. Generation by fuel. Source: Energy Information Administration; Platts AMERICAN COAL COUNCIL

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Why Now? was due to a perception that natural gas was the “fuel of economic and environmental choice.” But perceptions are changing. Current total U.S. generation growth rates of more than 50 million MWHrs per year will require the addition of over 7,000 MW of new annual capacity (at 80 percent capacity factor levels). This capacity requirement will be met using a combination of new base load capacity and increased capacity factors at existing plants. Capacity addition decisions will be made on a system-by-system basis and will vary by region. In the northeast and on the west coast, new base load coal capacity is not as likely as are other methods of meeting generation demand increases. But, in the Rocky Mountains, southwest, southeast, and Pennsylvania, new coal construction is more likely. Power generators in the Midwest will


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have to decide if it is better to run an older coal plant than it is to build new capacity. This decision is made more complicated by understanding that older, less efficient coal plants can be run efficiently in intermediate load service at today’s fuel price differentials. In fact, fuel prices will drive much of the decision-making process. The 50,000 MW of planned coal capacity should not produce a boom-bust cycle reminiscent of the recent gas plant experience. Historically, over half the nation’s generation has been produced by coal and this is still true today. If half the required new annual capacity is achieved through efficiency increases at existing plants and non-coal capacity additions, and given the knowledge that it can require as much as seven years to site, permit, and build a coal-fueled power plant, then there should

be about 25,000 MW of new coal capacity in various planning stages at any given time. Having twice that level in the planning process allows for the occurrence of a natural level of economic selection. Benefits of Coal-fueled Generation Coal is the cheapest fossil fuel available to power an electric generator in the U.S. At today’s prices, a typical large power plant saves $200 million per year in fuel costs using coal rather than natural gas. In fact, at today’s fuel prices, if all gas-fired electric generators used coal rather than gas, the combined savings would total approximately $12 billion per year. Furthermore, oil imports would increase by 11 million barrels per day if the current coal-fueled generation was produced using oil rather


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than coal. Coal saves U.S. electricity generators billions of dollars every year and contributes mightily to U.S. energy self-sufficiency. Buying natural gas on the spot market to meet changing generation needs involves greater price risk than buying spot coal. Coal prices have become more volatile

in recent years, but the level of price volatility is significantly less for coal than it is for natural gas. Note in Figure 3 that since January 2000, month-to-month spot coal price changes rarely exceed Âą 10%, while spot gas price changes over the same time frame can be significantly greater.




Month to Month Price Change








Henry Hub Spot Gas


Figure 3: End of month spot price change by fuel. Source: Platts 160,000


Million Tonnes







B i tu m i n o us C o al

Su b -b itu m i no u s C o a l

Figure 4: Proved world reserves of coal, 2003 Source: Adapted from the Statistical Review of World Energy 2004 (British Petroleum) 14

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Rest of World




South Africa






































While some level of price risk may be acceptable to electric generators, the risk of unavailable supply is not. As can be seen in Figure 4, the U.S. leads the world in proved reserves of coal (2003). Coal supplies allow for its continued use at levels above those of today for more than 200 years. Coal is the cornerstone of an energy independent America. By comparison, proven supplies of U.S. natural gas will last only 10 years at current consumption levels, while oil will last just 11 years. For comparison purposes, if all fossil fuel needs (including those met by natural gas and oil) in the U.S. could be met by using only coal, coal reserves would not be exhausted for another 65 years, while those of oil and natural gas would exhaust in a little over two years. Even the likelihood that additional oil and gas reserves will be proved in the future does not diminish the resource advantage enjoyed by coal. The coal industry contributes substantially to the national economy. There are more than 1,300 active coal mines in the U.S. in 26 states. These mines directly employ more than 70,000 workers in wellpaying jobs. Furthermore, much more coal is exported from the U.S. than is imported. In 2004, it is projected that the U.S. will export about 50 million tons of coal, while importing just 25 million tons. This export surplus contributes over $1 billion in positive balance of trade. World demand for coal (especially metallurgical grade coal) is growing substantially in order to fuel expanding Asian economies. This growth has spurred interest in high quality U.S. metallurgical coals. It is expected that exports from the U.S. will continue to grow in the future, further helping to balance U.S. trade. Impacts of Renewed Interest in Coal Renewed interest in coal will result in increased capacity at existing coal plants where space and permitting allows. But significant new capacity must occur at greenfield operations and this will provide major benefits to local and state economies. Revenues in these areas will grow. For example, 3,500 MW of new coal capacity per year will have a construction cost of about $4.9 billion with multiplier impacts adding as much as $6 billion, contributing substantially to national revenues and local, state, and federal tax coffers. Employment impacts related to construction activities could easily reach over 200,000 jobs. AMERICAN COAL COUNCIL

3/23/05 10:20:52 AM


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Lbs/MWh CO2

Lbs/MWH SO2, Lbs MWh NOx

When operating, these plants will be selling about 23 million MWHrs of power annually. For a plant providing standard power to a portfolio serving retail load, annual revenues for this power should meet or exceed $1 billion (with multiplier impacts generating another $1 billion), adding significantly to the economic and tax bases of the local communities. Employment impacts related to operating activities would be about 40,000 jobs. New coal capacity of 3,500 MW will require a significant increase in coal mine production. Total annual coal production from existing and new coal mines will need to grow an additional 10 to 15 million tons each year to meet expected demand. Within about 10 years, coal production in the U.S. will have grown by 10 percent to satisfy the demand for new coal-fueled power. New production will also be needed to satisfy the increased need for power related to the growing capacity factor. A U.S. aggregate mine productivity increase of between one and two percent per year will provide the necessary additional coal without the need to increase coal employment. If productivity falls short of that level, then coal employment will grow. If it exceeds that level, then coal employment will decline. Aggregate U.S. coal mine productivity has not changed much in the last several years. Declining productivity in certain eastern regions (owing to poorer mining conditions and stricter environmental regulation) has been offset by increased production from western operations with greater productivity. Though coal is abundant nationally, regionally it can be in shorter supply. Where supply is tight and demand is strong, as in Central Appalachia, firm prices could encourage some coal generators to enter into longer term guaranteed contracts with suppliers or into equity positions with coal operations in order to minimize price risk and volatility. As western coal production grows, there will be the need to lease additional reserves from federal or private landowners. Per ton federal lease costs have risen greatly in the last ten years to nearly $1.00 per in-place ton for southern Powder River Basin (PRB) coal, adding appreciably to total mining cost. Moving more of this coal to market will create challenges for western railroads already near capacity in the PRB. In the east,

1,800 1995

2000 Sulfur Dioxide (SO2)

Nitrogen Oxides (NOX)

2004 Carbon Dioxide (CO2)

Figure 5: Unit emissions from U.S. power plants using coal as primary fuel Source: Platts COALdat™Database

Current total U.S. generation growth rates of more than 50 million MWHrs per year will require the addition of over 7,000 MW of new annual capacity (at 80 percent capacity factor levels). This capacity requirement will be met using a combination of new base load capacity and increased capacity factors at existing plants.

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3/23/05 10:20:53 AM

Annual US Coal Generation


Total US Electricity Production















Equivalent Oil Displacement By Coal (Millions of Barrels/Day)



Coal Fuel Cost Savings ($ Billions vs. Gas)

Annual US Gas Generation


Equivalent Coal Fuel Cost ($ Billions)


Equivalent Natural Gas Fuel Cost ($ Billions)

Typical Large Power Plant

Electricity Generation (Millions of MWHrs)



At Current Consumption Levels Fuel

Reserve/Production Ratio at Current Consumption Levels

Reserve/Total Fossil Energy Requirement Ratio




Natural Gas







Environmental Control Technologies


Advanced Electric Power Generation

Coal Processing for Clean Fuels



























New York






1 2





Wyoming Totals 16

ACC_2005_07_14.indd 16

1 17



railroads will wrestle with transporting increased coal volumes to export ports as U.S. suppliers find better prices in the world market for metallurgical coal and, in some cases, steam coals. Challenges Facing Coal Challenges facing the growth in coalfueled electric generation include issues the industry has historically faced, such as environmental regulation and project financing. The industry is also confronted with new challenges, such as increased technology demands for clean coal technology and a strained transportation network. To thrive, the industry must tackle its challenges, chief among which are balancing the environmental perceptions of coal with reality. Some special interest groups have yet to fully recognize the industry’s success in reducing coal-fueled power plant emissions or its costly efforts to do even more. Note in Figure 5 for instance, that a unit of power produced today is emitting 24 percent less sulfur dioxide, 41 percent fewer nitrogen oxides, and 13 percent less carbon dioxide than it emitted in 1995. Clean coal technology programs abound in the U.S. and deserve more attention. On the national level, the Bush Administration is supporting The Clear Skies Act (S.131) which aims to reduce sulfur dioxide, nitrogen oxides, and mercury air emissions. If the legislation is passed, power plant emissions would be cut by 70 percent, eliminating 35 million more tons of these pollutants in the next decade than under the current Clean Air Act. Thirty-six clean coal technology demonstration projects are ongoing in at least 17 states. Three main areas of research, as identified by the Department of Energy’s Clean Coal Technology Compendium, include the following: • Environmental control technologies research which focuses on sulfur dioxide, nitrogen oxides, and combined sulfur dioxide and nitrogen oxides control technologies; • Advanced electric power generation research which focus on fluidized bed combustion, integrated gasification combined cycle (IGCC), and advanced combustion systems; and • Coal processing for clean fuels research which focuses on coal preparation technologies, mild gasification, indirect liquefaction, and industrial applications. AMERICAN COAL COUNCIL

3/23/05 10:20:55 AM

The need for new coal generation is now, but it can take seven years to site, finance and build a new state-of-the-art, emissioncontrolled coal-fueled power plant. The long lead time will put extra pressure on ramping up capacity factors at existing plants to meet new demand until these power plants can be ready for operation. Capacity factor increases will be essential to ensure reliability of service, especially in areas of the country where reserve margins will deteriorate in five to 10 years, including PJM, New England, Florida, the Rockies and Southern California. Over the past few years, gas plant capacity has been overbuilt. There are several important lessons to be learned from that overbuild. First, it was incorrect to presume that the high capital cost of a coal-fueled power plant made it a riskier investment than a (lower capital cost) natural gas plant, many of which have been idled. Secondly, the hope that financers might relax the equity requirements for new coal plants to levels that some of the gas plants enjoyed in the recent boom is most likely gone in the face of the economic problems resulting from gas plant overbuild. Equity requirements for coal plant builders will likely stay at least at the same levels they were before that gas capacity build-up. Lastly, all parties to new power plant construction should recognize that the whole deal is only as strong as its weakest link. Even a locked-in fuel price can be unwound when any counter party fails. Funding new coal-fueled generation will require obtaining capital outlays that involve a large number of parties. Investors and creditors must be convinced of the long-term soundness of an investment in electricity markets that can be uncertain and volatile. A large portion of a new plant’s operating cost is fuel. Coal, with lower price volatility, helps provide investors and creditors with a large measure of certainty about future power production costs. A thorough review of financing and equity agreements associated with the project is necessary. Lenders require a clear picture of the projects risks, including a profile of the project’s partners. Potential bondholders will be concerned about their level of subordination in the event of default. Commercial loans will typically be senior to all other forms of debt; these lenders will concern themselves with the financial strength of partners and the AMERICAN COAL COUNCIL

ACC_2005_07_14.indd 17

The current gas capacity “bubble” should not be construed as proof that new generating capacity is unnecessary.

consequences of failure of other partners to meet their obligations. In addition, there will need to be a review of the status of all contracts affecting the project’s performance, including engineering, procurement, and construction agreements, fuel supply contracts, interconnection agreements, and power purchase agreements. Banks expect significant progress in completing contractual agreements critical to project performance. Independent analysis is usually sought to review and critically assess all the assumptions related to the project’s cost and revenue streams. An essential step to the project’s perceived financial security involves project developers securing contracts or captive buyers for most or all of the project’s generation output. Independent analysis is also often sought to offer opinions on the project’s coal contracts, given prevailing market conditions and contract adjustment clauses. Time to obtain and close on financing can be sensitive to the sentiment of the capital markets. Borrowers can expect to spend a greater amount of time in due diligence activities if the sentiment is negative. On the other hand, commercial banks and investment banks will move

more quickly towards providing financing when capital is more freely available. Financing issues can add significantly to the time required to site and construct a coal-fueled power plant. The Future Will the current emphasis on coal-fueled generation have staying power? Yes, for many solid reasons. We have learned that there is no magic bullet – our future energy needs cannot be met by solely relying on natural gas, as was tried in the last few years. In fact, meeting future energy demand is best achieved using a mixture of available fuels, among which domestically abundant coal happens to be a highly economical, proven and attractive alternative. Coal plants can be built and operated to meet the demanding environmental constraints of today, and exciting technology is being proven today that will allow coal plants to meet the energy and environmental constraints of tomorrow. ◆

Andy Roberts is a Senior Consultant and Phil Szczesniak is a Senior Associate at the Platts Analytics & Forecasting group within Platts, a unit of McGraw-Hill. Visit

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3/23/05 10:20:56 AM

The Next Generation of Coal America and the World are Recognizing – and Capitalizing on – Abundant, Secure, Increasingly Clean Coal By Vic Svec, Peabody Energy


uring one week in early 2001, two political leaders from opposite coasts made it clear that the “politically correct” view toward coal had made a significant shift toward the reasonable. On that week, the mayor of Los Angeles announced that he was interested in additional coalfueled capacity to serve growing electricity needs for Southern California. Three thousand miles away, then-governor of Vermont Howard Dean raised eyebrows on a talk show when he stated: “Wind power isn’t going to satisfy our needs. We need a coal plant.” Between the coasts, of course, coal is far better understood and appreciated. When Peabody Energy began permitting its Prairie State Energy Campus, a 1,500-megawatt generating plant and six million ton-per-year coal mine in Southern Illinois, it surveyed residents in several neighboring counties. The result? Prairie State enjoys an overwhelming 87 percent approval rate even by those who consider themselves environmentalists. Residents understand the advantages of the “three Es” of projects like Prairie State. They are good for energy, good for the economy and good for the environment. The path for coal has overcome a number of challenges in recent years and will continue to conquer many more. Those permitting coal plants face the hard work and determination associated with any big-ticket projects. Their efforts can be bolstered by the trends… the facts… and the very favorable new realities of coal, one of America’s most important resources. Consider eight key trends that demonstrate why the next generation is likely the best generation for coal:

U.S. Forecasts Largest Coal Generation Capacity Growth in 40 Years

1) Coal-fueled generating plants are running at everhigher utilization rates. The average plant is likely to run at approximately 74 percent of capacity this year, up from just 59 percent in 1990. Hydro and nuclear plants are running at maximum capacity and natural gas plants face fuel prices that are far too high to justify high burn rates if coal-fueled generation is an option. 2) New coal-fueled plants are being developed at the fastest pace in decades. The U.S. Department of Energy identifies 106 coal-fueled plants that constitute 66,000 megawatts of new generation. While only some portion of these plants will ultimately be built, the total represents more than 200 million tons of annual coal use. 3) Coal was the fastest growing fuel in the world in recent years, and U.S. coal demand is expected to reach record levels in 2005. And, we’re just beginning a significant coal-fueled plant build-out worldwide. The World Energy Outlook says that 1,400 gigawatts of new coal-fueled generating plants are needed over the next quarter century, and just 346 gigawatts have been announced. More than three-fourths of this demand is in China, India and the United States. 4) U.S. coal exports are increasing to meet growing global demand from generators and steel makers. America’s abundant coal supplies are being tapped to serve the growing economies around the world.

The Path to Zero Emissions from Coal-Fueled Generating Plants

U.S. Coal Capacity Build-Out: Yesterday & Tomorrow 20,000 19,000 18,000 17,000 16,000 15,000 14,000 13,000 12,000 11,000 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0

Emissions from Coal-Fueled Generating Plants 4.5



Sulfur Dioxide Nitrogen Oxide

3.5 3 2.5 2 1.5 1.08


0.97 0.37


0.39 0.16



0.17 0.08

0.182 0.07

Existing IGCC (Permit Level)

Prairie State (Permit Level)

0 U.S. Average 1970

U.S Average 2003

Clean Air Interstate Rule 2010

Clean Air Interstate Rule 2015

0.03 0.06 IGCC Projection

Near-Zero FutureGen Goals

1940 1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 Source: U.S. Department of Energy NET L & Annual Energy Outlook 2005


ACC_2005_15_30.indd 18

Source: EPA’s Clean AirMarkets database; Energy Information Administration 2004 Annual Energy Outlook; GE Energy; SFA Pacific


3/23/05 10:23:03 AM

The path for coal has overcome a number of challenges in recent years and will continue to conquer many more. Those permitting coal plants face the hard work and determination associated with any big-ticket projects.

5)Coal is increasingly popular. Both presidential candidates, this past fall, touted themes of energy independence and promised billions of dollars in clean coal technologies. Coal has bipartisan support and represents tremendous security against foreign energy sources that America relies upon for oil and, increasingly, natural gas. 6)The industry is pursuing a vision of near-zero emissions from coal. Emissions from coal are at all-time lows and the industry is pursuing continuous improvements from coal-fueled generation using advanced technologies. There as many paths to continuous emissions improvement as there are companies. We see this in the tens of billions of dollars being invested in environmental retrofits for existing plants, in the scores of new plants that are being developed using 21st Century “Advanced PC” technologies, and in the interest in developing new coal gasification plants by major utilities like GE Energy, American Electric Power, Cinergy and Southern Company. Ultimately, carbon capture and sequestration technologies represent an area of bright promise. 7) Coal will also grow to fuel “Btu Conversion” technologies. The possibility of converting coal’s energy into other desperately needed energy forms – “Btu Conversion” – is gaining significant interest and investments. Methanation from coal – essentially coal gasification to produce pipeline quality natural gas – is being

pursued and may be a practical alternative to an overreliance on liquefied natural gas (LNG) imports from risky regions of the world. Coal liquefaction offers great promise for nations rich in coal but scarce in oil, and would be competitive at $35 per barrel oil prices. China, alone, has earmarked a stunning $15 billion for coal-todiesel plants. And, hydrogen from coal is a major priority of the Administration’s FutureGen plant of the future. Peabody and other major energy companies are a part of the FutureGen coalition to develop a plant that would produce hydrogen, generate electricity, achieve near-zero emissions and sequester carbon. 8)People live better and live longer because of coal. Coal contributes significantly to sustainable development, ensuring that individuals’ needs are met while meeting the needs for a stronger economy, cleaner environment and secure nation. This is shown from the strong correlation of global electrification with improvement in the United Nations Human Development Index. It is shown in the strong economies of nations (and U.S. states) that have access to low-cost electricity from coal. And, it is shown from studies such as the Klein-Kenney report that reveals that coal prevents at least 14,000 to 25,000 premature deaths each year due to low-cost electricity. Thousands of years ago, society decided that coal was essential to provide direct heat. Years later, it was essential for

Global Coal Industry Ready to Enter Its Next Phase

Coal Leads Growing Global Energy Demand Percent Change in Global Energy Consumption 7

6.9% 6.9%




Coal Use 5.8 Billion Tonnes

4 2.8%









1 2002 2003

2002 2003

2002 2003

0.4% (20)% 2002 2003

-1 -2 -3

2002 2003


Natural Gas


Source: BP Statistical Review of World Energy, 2003 & 2004.


ACC_2005_15_30.indd 19



200 AD Coal Use 1 Tonne

The proposed FutureGen power plant of the future would produced hydrogen, have ultra-low emissions and sequester carbon.


3/23/05 10:23:17 AM

steamships, locomotives and industrial uses. Today, electricity generation and steelmaking use most of the supplies, and interest has turned to significant uses for methane and diesel. And, in a glimpse of what tomorrow holds, the Academy of Engineering recently completed a year-long study of “The Hydrogen Economy: Opportunities, Costs, Barriers and R&D Needs.” One of its key findings was that, “Coal must be a significant component of R&D aimed at making very large amounts of hydrogen.” And that is the next generation for coal: 21st Century technologies for electricity production, and emerging uses to access large new markets. ◆

Vic Svec is Vice President Public & Investor Relations for Peabody Energy.

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3/23/05 10:23:29 AM

Coal — Our Nation’s Most Valuable Energy Source By Paul N. Cicio, Industrial Energy Consumers of America


he most reliable, economic and secure energy source available to our country and to industrial energy consumers is not natural gas, it’s coal. Coal is critically important in its own right, but it will also dictate the affordability of natural gas for the foreseeable future. As such, much depends on our nation’s policies that will determine how much coal will be used for power generation. Coal is the greatest energy resource in the U.S. and a true strength. It is the lynchpin of our current and past electric power production and a reliable low-cost energy source for many manufacturers. Coal has a domestic 250-year supply and is the titan of supply reliability. Energy prices do matter to energy intensive industry Energy consumers want domestically produced energy. We value reliability of supply, globally competitive prices and price stability. Major energy consuming industries include: chemical, plastics, fertilizer, cement, paper, food processing, steel, aluminum, glass and brick. Policy makers must understand the intimate relationship between energy costs to these industries, economic growth, trade deficits and inflation. Natural gas for utility power generation – a flawed energy strategy The flawed concept of shifting power generation growth to natural gas has resulted in the largest negative impact on U.S. competitiveness in recent history. Increased natural gas demand from the power sector, with flat to declining natural gas supply resulted in significantly higher prices for all consumers. Prices went up mid-year 2000 and have stayed there. The Energy Information Administration (EIA) has reported that for the period of 1992 to 2002, increased electric utility demand for natural gas accounted for 93.6 percent of the entire U.S. net increase. The cost of these policies to consumers totals nearly $200 billion and significantly 22

ACC_2005_15_30.indd 22

Our growing trade deficit is directly related to the shut down of U.S. energy intensive manufacturing. We are importing record amounts of such products. In the distant past, some industries, like the chemical producing industries were net exporters and contributed to a positive trade balance. Now, they are net importers.

Eastman Chemical’s IGCC facility in Kingsport, Tennessee.

contributed to a loss of 2.5 million manufacturing jobs. U.S. policy makers are, by their inaction on a national energy policy, “outsourcing” energy-intensive manufacturing industries. Unfortunately, once these jobs are gone, they won’t be back. By the time the Alaska Natural Gas Pipeline is delivering product to the lower 48, U.S. energy intensive industry may be but a shadow of what it once was. Expect continuing job loss The high cost of natural gas is dismantling the manufacturing sector and this results in significant job loss. What policy makers do not seem to understand is that these job losses are just the “first wave.” The U.S. has the highest natural gas prices in the world and the long-term natural gas price forecast is high-very high. As energy consuming company executives make decisions as to where they will spend their “growth” capital, it will be hard to justify doing so in the United States. Existing capital spending will be limited to maintenance only. As existing manufacturing facilities finish their economic life and shut down, more job losses will occur. Coal and clean coal technology can help reverse this trend. Just because we shut down manufacturing facilities that use energy-intensive methods to produce products, does not mean our country will stop using those products. Instead of producing them in the U.S., we now import them.

Natural gas supply has failed to meet the challenge There are three times as many rigs drilling new wells as in the early 1990s and three times as many producing wells. Despite this, natural gas production is stuck at 19 TCF per year or less. It now takes three wells to supply the same amount of gas that one well produced in the 1990s. Natural gas production in the U.S. peaked back in 1971 at 21.5 TCF and it is now about 19 TCF. The share of the energy market in the U.S. served by gas also peaked in 1972 at 35.5 percent. It is now 22 percent and has been steadily shrinking for 33 years! Natural gas powered generation puts utilities in competition with consumers The electric utility industry has alternative energy sources to produce power while industrial consumers, farmers and homeowners do not. The current situation puts consumers in competition with the electric utility companies for purchases of natural gas and consumers are losing—paying both higher natural gas and electricity prices as a result. Coal results in low variable cost of power The current use of high-priced natural gas for power generation results in high variable cost of power production but low fixed costs due to the low initial capital investment in natural gas-fired generation equipment. Coal-fueled power generation involves significant capital investment and hence high fixed costs but variable costs are low, especially if the power plant is located AMERICAN COAL COUNCIL

3/23/05 10:23:31 AM

close to the coal mines. What is better for America’s economy—high or low variable costs? All energy consumers vote for “low” variable costs and less expensive electricity prices long term. Coal is more reliable than natural gas Energy consuming industries view coal as a much more reliable energy source than natural gas. Several months of coal can be stockpiled on site and be ready for use at any time in any weather situation. Natural gas on the other hand, cannot be stock-piled and relies on “just-in-time” delivery. In the 1980s and 1990s there was sufficient natural gas production reserve capacity to meet higher than average electrical cooling demand or winter heating demand. Natural gas wells could be opened and supply increased. Today, there is no such safety net. In fact, this scenario is one of our nation’s worse nightmares — “the perfect storm.” The occurrence of an energy “perfect storm” is inevitable because of falling domestic supply, inability to import sufficient natural gas supplies and only minimal expansion of coal-fueled generation capacity due to regulatory restrictions and uncertainties. The energy “perfect storm” is a hot summer that requires turning on natural gas-fired peakers (electrical generators) followed by or preceded by a cold winter. The combination means the U.S. will ration natural gas supply. The first to be cut off will be industrial demand.

The U.S. and the world benefits from clean coal and coal gasification technology We must not fail to commercialize technology that allows the use of coal in an environmentally acceptable manner. This policy issue alone will determine coal’s fate. Clean coal technology and coal gasification can result in less emissions than even natural gas-fired generation, especially if the CO2 produced through coal gasification is sequestered for other uses such as urea fertilizer production or enhanced oil recovery. Policy makers are being encouraged to consider “Manhattan” style projects to break the environmental impasse with coal. Proposals such as the one advanced recently by Harvard University is a good example. These proposals should be given serious consideration.

Getting first things first Congress must act to give coal-fueled electric utilities regulatory predictability and Clear Skies is the best alternative. The EPA regulatory route is not. Energy consumers want Clear Skies legislation to increase the use of coal and to do so while meeting sound science-based environmental standards. There must be a way of accommodating progress in clean air quality while not putting additional pressure on natural gas demand that is costing Americans billions in higher natural gas costs. ◆

Paul N. Cicio is Executive Director of the Industrial Energy Consumers of America.

Coal is local, LNG is not — the implications are significant Sound energy policy includes all sources of energy: coal, natural gas, LNG, nuclear and renewable. Sound energy policy also dictates that energy consumers must be able to purchase from competing energy sources. When they do, the country and the consumer wins. With LNG we place the energy future of the U.S. again in the hands of a few gas-rich Middle Eastern and African countries. We send increasing dollars out of the U.S. for energy in the form of LNG. Producing, shipping, and unloading LNG here creates few jobs when compared to the more economical mining of U.S. coal and using that coal for power. LNG is important but we shouldn’t bet our country’s future on it when we have home grown alternatives. AMERICAN COAL COUNCIL

ACC_2005_15_30.indd 23


3/23/05 10:23:32 AM

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ACC_2005_15_30.indd 24

3/23/05 10:23:35 AM

We Can See Clearer Now! By Frank Hilty, John T. Boyd Company

Electric utilities responded positively to the requirements of the Clean Air Act Amendments of 1990 (CAAA) by significantly reducing power plant emissions. The success of the utility industry’s environmental performance is one of the best kept secrets in the nation.

Clean Air Act Amendment (CAAA) The Environmental Protection Agency (EPA), through the passage of the CAAA and its predecessors, set standards for emitted pollutants, including nitrogen dioxide (NO2), sulfur dioxide (SO2), carbon monoxide (CO), particulate matter (PM), and lead (Pb). Ozone, which is considered a non-emitted air pollutant formed by the combination of nitrogen oxides (NOx), volatile organic compounds (VOCs) and sunlight, was also included in this standard. Point sources, such as electric power plants and coke plants, were targeted for emission reductions under the act. The EPA has collected emissions data for CO, NOx, SO2, VOC and PM less than 10 microns (PM10) by emitting source since 1970 (Table 1). Based on EPA historical data, total U.S. emissions from all sources were reduced by 51 percent between 1970 and 2003. The transportation sector contributed significantly to these reductions, as have electric utilities which reduced their emissions of the five pollutants by an aggregate of more than 33 percent over the same period.

Even more astounding is that the utility reductions in emissions occurred during a period when coal-fueled electric generation nearly tripled from approximately 700 billion kilowatt-hours (kwh) in 1970 to 1,970 billion kwh in 2003.

It’s important to maintain perspective when examining utility environmental compliance. Figure 1 shows the electric utility contribution, for each pollutant, to total U.S. emissions. In 2003, electric utilities contributed less than


Emissions (000 tons) Source/Pollutant







Electric Utilities Carbon Monoxide









Oxides of Nitrogen









Sulfur Dioxide




















































Total All Sources

1970 to 2003 1990 to 2003


ACC_2005_15_30.indd 25


3/23/05 10:23:38 AM



Coal-Fired Generation (billion KWH)

20.0 1, 5 0 0 15.0 1,000 10.0


Emission Rate (tons/million KWH)





1970 1975

1980 1985

1990 1995

1996 1997

Coal-Fired Generation

1998 1999

Sulfur Dioxide

2000 2001

2002 2003


• To achieve NOx emissions reduction of 2 million tons per year below the year 2000 forecast of 8.1 million tons or 6.1 million tons per year of emissions.

one percent to the total VOC and CO emissions and almost 70 percent of SO2 emissions. Since 1970, the largest contributor to national emissions has been the transportation sector. Between 1970 and 2003, the transportation sector (including both on- and off-road vehicles) was responsible for approximately 70 percent of all CO, NOx, SO2, PM10, VOC and Pb aggregate emissions. SO2 and NOx emissions are contributors to acid rain. Based on EPA data, coalfueled electric utilities historically are the largest single emitter of SO2 (60 percent to 70 percent of all emissions) and a large contributor of NOx emissions (25 percent of all emissions). The CAAA provided a phased implementation approach with emissions caps. The primary goal of the CAAA’s Acid Rain Program was: • To decrease SO2 emissions to 50 percent of 1980 levels (17.5 million tons) by 2010.

Collectively, utilities have reduced emissions of SO2 and NOx to 10.9 million tons and 4.5 million tons per year in 2003, respectively. The 2003 SO2 emission levels represent 31 percent of the 50 percent reduction by 2010 required by the Acid Rain Program. NOx emission reductions in 2003 (4.5 million tons) exceeded the Program’s expectations (6.1 million tons) as they have in each year since 1999. The nearly one-third reduction in both SO2 and NOx emissions since 1990 has coincided with a more than 24 percent increase in electric generation at coal-fueled power plants. The net result is a 44 percent reduction in SO2 emissions per million kwh and almost a 46 percent decrease in NOx emission per million kwh (Figure 2).

TABLE 2: Growth PRB Coal Production Wyoming PRB Year Production (MM tons) 1970* 3 1980 68 1990 160 1995 245 2000 323 2003 363

TABLE 3: Growth of SO2 Scrubbers No. Capacity Year of Units (MW) 1970 2 228 1980 69 27,790 1990 153 69,122 1995 178 84,677 2000 192 89,675 2003 246 99,567

* Estimated

Source: EIA

Source: BOYD, MSHA 26

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Reductions in emissions among coal-fueled generators have been made possible primarily by fuel switching, retrofit technology installation or utilization of fluidized bed combustion technology. Development of Wyoming’s Powder River Basin (PRB) coalfield provided utilities with a low cost, low sulfur alternative fuel. Coal production from the PRB grew more than 100-fold from 3 million tons in 1970 to more than 360 million tons in 2003 (Table 2). After 1970, utilities began retrofitting flue gas desulfurization (FGD or scrubber) technology at some of the largest emitting stations. Through 2003 scrubbers were installed on nearly 100,000 MW of capacity at 246 coal-fueled generating stations (Table 3). Approximately 44 percent of this scrubber capacity has been installed since 1990, amounting to 30,000 MW of coal-fueled capacity. Since 1990, emissions of CO and VOCs by electric utilities have increased (Table 1); however, electric utilities are responsible for less than one percent of these emissions and 10 percent of all PM10 emissions over the same period. Since 1985, PM10 emissions have been relatively consistent at around 260,000 tons per year (plus/minus 10 percent), nearly 86 percent below 1970 levels. Essentially all of the coal-fueled electric capacity utilizes some form of particulate which combats PM emissions. Clear(er) Skies and Beyond In 2002, the Bush Administration proposed new, more stringent “multi-pollutant” legislation which addressed the emissions of SO2, NOx and Mercury (Hg) from coal-fueled electric power plants. The Administration’s “Clear Skies Act” requires emission reductions between 61 percent and 71 percent of their current levels (Table 4). SO2 reductions under Clear Skies calls for 2010 emissions to be 50 percent below the current CAAA standard. Reductions of this magnitude will likely require significant scrubber installations. It is ironic that environ-mental regulations which hindered the growth of high sulfur coal production (mostly in the midwest) will likely spur growth of these same coals in the future. EPA has also proposed other Clean Air regulations to reduce SO2, NOx and particulates at power plants. The Clean Air Interstate Rule (CAIR) would reduce SO2 and NOx emissions below the Clear Skies limits for selected states. The program AMERICAN COAL COUNCIL

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expects PM2.5 compliance by 2015. Implementation of CAIR would be superceded by passage of Clear Skies legislation. Mercury Overall man-made (anthropogenic) mercury (Hg) emissions have decreased by approximately 45 percent, from 220 tons in 1990 to 120 tons currently. Electric utilities (coal-fueled) are responsible for 40 percent (48 tons) of all U.S. Hg emissions. The Clear Skies Act emphasizes the need to reduce the level of emitted Hg. The EPA estimates that about one-third of Hg emissions are captured by generating stations through the use of existing pollution controls (scubbers, SCRs, etc.); therefore, it is likely that as scrubbing becomes more prevalent, Hg emissions will decrease. While there are currently no commercial Hg specific control technologies available, research is ongoing to develop economically viable methods. There is a public benefit to reducing Hg, but it may not be sufficient to simply seek reductions from the utility sector. EPA information indicates between 4,800 and 8,200 tons of Hg is emitted each year from all sources (including natural sources). • All man-made Hg emissions worldwide represent only about one-third of all Hg emissions. • The U.S. is responsible for approximately nine percent of the world’s man-made Hg emissions. • U.S. power plants are responsible for three percent of the world and 30 percent to 40 percent of the U.S. man-made Hg emissions. Natural sources and re-emission from previous activity represent approximately equal portions of the remaining worldwide Hg emissions. Carbon Dioxide By 2003, U.S. electric utility emissions of carbon dioxide (CO2) reached 2.5 billion tons, an increase of nearly 28 percent above 1990 levels. Accounting for changes in electric generation from coal-fueled power plants, emission rates on a tonper-million-kwh basis increased only three percent between 1990 and 2003. During 2002 (latest data available) the world emitted approximately 27 billion tons of CO2. The five largest contributing countries (China, Japan, India, Russia and U.S.) represent approximately 52 percent of all CO2 emissions (Table 5). While the

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AmerenEnergy Fuels and Services Company (AFS) provides a full range of fuel-related services to the Ameren group of companies. However, AFS also works with some unaffiliated businesses, assisting with specific fuels and emission related issues. AFS procures over 37 million tons of coal from the Powder River and Illinois Basins for use in the Ameren generation fleet. In addition to procurement, AFS provides transportation services related to negotiating and administration of rail, barge and truck contracts, as well as the management of over 5000 system railcars. Management and marketing of three river terminals on the Mississippi River is another responsibility for AFS. These terminals provide blending and rail to water trans-loading services for both in-house and third party users. Combustion by-product services for beneficial use such as flowable fill projects as well as ash disposal options are additional services provided by the AFS team. AFS provides all procurement of natural gas on both the wholesale and retail level to over 925,000 customers in the Ameren UE, Ameren Energy Generating Company, Ameren CILCO and AmerenIP territories. AFS is also currently working to develop coal bed methane (CBM) projects as well. Market research is an additional function of AFS, providing senior management as well as plant operations with the necessary information required to keep on top of the ever-changing fuel and transportation markets. Renewable energy resources and the development of “green generation projects” is yet another area of responsibility for the AFS group. AFS is “a full service” fuel and energy provider. Visit our web-site at


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TABLE 4: Clear Skies Act Emission Limits by Pollutant Units





Total Reduction 2003 to 2018 (%)


(MM tons)







(MM tons)














Source: EPA

TABLE 5: Historical CO2 Emissions of the Five Largest Emitting Countries in 2002 CO2 Emissions (billion tons) 1993


United States

















World Total

Source: EIA International Energy Annual

U.S. contributed the largest quantity of CO2 during 2002 (6.4 billion tons), the U.S. GDP was also 40 percent higher than that of the other four countries combined. The electric power industry is exploring voluntary opportunities to reduce CO2 emissions. The Bush Administration has declined to sign the Kyoto Protocol, an international treaty mandating reductions in greenhouse gases (GHG), including CO2. Instead, the President has decided to rely on voluntary reductions in GHG emissions per unit of GDP (GHG intensity). The goal of the program is to reduce the GHG intensity 18 percent by 2012. During December 2004, seven organizations signed a memorandum of

SCH Terminal Company – Calvert City Terminal The Calvert City Terminal is a new, modern coal transloading and blending facility located at Mile 14 on the Tennessee River. This terminal offers connections with five Class I railroads through the P&L Railroad, and is in the heart of the inland river system. SCH Terminal Company’s parent company, Southern Coal Handling Company, designed and built this terminal to meet the needs of utilities interested in receiving western coal or blends on western coal and Illinois Basin coals. The facility incorporates five belt scales, interlocked with the system PLC, to monitor two and three-part blends accurately and efficiently.

efficient, low-cost handling of western trains. CCT is presently transloading over 6.0M tons per year and expects to be at 10M tons per year within the next three years. The facility operates at a nominal rate of 3500 tons per hour and there is 1,000,000 tons of ground storage available.

The terminal includes a loop track that will accommodate up to 150 railcars and a rotary dump for

Gary Quinn (423) 899-0591 Bill Rager (270) 841-9907


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Please call one of the contacts below if you are interested in the services provided by CCT, or if you are interested in other coal handling concepts and services available through Southern Coal Handling Company, Inc.

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understanding with the Department of Energy (DOE) to implement the plan. The group of seven (collectively known as Power PartnersSM) include: • American Public Power Association • Nuclear Energy Institute • Edison Electric Institute • Tennessee Valley Authority • Electric Power Supply Association • National Rural Electric Coop Association • Large Public Power Council The group believes it can voluntarily reduce, primarily by carbon management, the electric power sector’s GHG intensity by three percent to five percent of the 2000 to 2002 baseline level. Summary Utilities have historically worked with EPA and other regulating bodies to achieve environmental improvements with the greatest positive social benefit by the most economical means. Utilities have committed significant company resources to environmental policies and practices, incorporating pollution prevention measures, alternate fuel utilization, application of Best Available Treatment Economically Achievable (BATEA), and development of new technology to continually improve environmental quality. Electricity demand in the U.S. is expected to continue to grow well into the future, and coal use is expected to continue to be the workhorse of electric generation. The U.S. remains a leader in the environmental research and implementation of new technologies for the utility industry. A new series of challenges are facing electric utilities as they look to the future. It is no longer a question of if, but rather a question of when new limits for reductions in the EPA’s emitted pollutants (i.e., Phase 3 sulfur dioxide, etc.), carbon dioxide (CO2) and mercury (Hg) will be mandated. While the job is not complete, electric utilities should take pride in their environmental accomplishments over the last 30 years. It is a message worthy of shouting from rooftops. ◆

Frank Hilty is a Mining Engineer with John T. Boyd Company. Visit AMERICAN COAL COUNCIL

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3/24/05 10:52:57 AM

The Case for Committing to Clean Coal Technologies By Ben Yamagata, Coal Utilization Research Center


he new Congress will try again to enact national energy legislation. Having failed last year in the U.S. Senate – by two votes – to enact an agreement between negotiators from the Senate and House of Representatives, prospects are not much brighter in 2005. The reason is a regional political squabble pitting powerful Congressional interests from Texas and elsewhere against representatives from both the Atlantic and Pacific coasts. The disagreement involves the extent of liability of producers of a fuel oxygenate additive. Unless a compromise is found, enactment of energy legislation remains in doubt. Coal technology programs were prominently included in last year’s energy bill. To emphasize broad-based support for coal technology development and demonstration, the legislation last year included research, development, demonstration and commercial deployment programs targeted at encouraging the development and use of advanced coal-based technologies. If Congress finds a way to overcome its disagreements, clean coal technology development likely will play a significant role in lawmakers’ efforts to enact meaningful energy legislation. Indeed, 200-plus years worth of domestically secure supply makes coal not just the answer to long-term energy security but, given the nation’s dependence upon foreign sources of crude oil (reaching 60 percent of daily consumption) and a growing dependence upon imported natural gas, coal is also critical to our national security. As lawmakers design a national energy plan they are tapping our proven aptitude for innovation to develop and use new technologies that will allow the cost-competitive, consumer-friendly and nearly emissions-free use of coal. Two years ago, the Coal Utilization Research Council (CURC), EPRI (the R&D organization of the nation’s electric utilities), and the U.S. Department of Energy (DOE), agreed upon the elements of a clean coal technology roadmap. That “roadmap” charts a course of action the nation might follow towards the development of a new generation of technologies. These clean coal technologies will permit coal users to convert more than half of the energy in a lump of coal into useful electricity or other important products including chemicals, liquid fuels and even hydrogen. Today’s typical power plant captures about 35 percent of the energy in a lump of coal. Not only will better technology result in the more efficient use of coal but it will be accomplished at a cost that will insure coal’s continued competitiveness. That, in turn, will insure a continued diversity of energy resources to meet our current and growing demand for energy. Most important, these R&D efforts are geared toward technologies that will allow us to use coal nearly free of emissions (the DOE/EPRI/CURC roadmap can be found at the CURC Web site at AMERICAN COAL COUNCIL

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Our collective success in achieving the goals of the roadmap will mean that the controversies over pollution from coal become the disagreements of the past. Some have questioned, and continue to question, the benefits already achieved through the country’s more than two decades of investment in clean coal technologies. The record has proven them wrong. As a consequence of the government/industry clean coal technology development program, nitrogen oxide (NOx) and sulfur dioxide (SO2) control technologies have moved into the utility and industrial marketplace and now provide cost-effective regulatory compliance. New coal use technologies, like IGCC and fluidized bed, have been incubated in the industry/government’s clean coal program. For example: • 75 percent of existing coal-fueled generating units have been or are currently being retrofitted with low-NOx burners developed through industry and government-supported R&D programs. Also, SCR technology now costs half what it cost in the 1980s and SCR systems are being used throughout the electricity generation industry as a way to comply with more stringent emissions-control standards. • As a result of DOE-supported work and work conducted elsewhere by industry, FGD (scrubbers) systems now cost one-third what they did in the 1970s. Now, several hundred commercial deployments later, it can be said that we will have achieved a projected 7 million-ton reduction in SO2 emissions (beyond what would have occurred without the DOE program) for systems installed through 2005. • As a result of public financial contributions to the development of fluidized-bed combustion (FBC) there are now over 400 FBC units worldwide with 170 units of varying capacity across the U.S. FBC is an inherently low-NOx emitting combustion technology that allows the use of fuels, such as coal pile washer waste that were not formerly usable. As the cost of natural gas has risen dramatically, and is forecasted to remain at historical highs, and as our nation’s electricity suppliers turn their attention to increasing consumer demand for more electricity, there is renewed attention to the application of advanced coal generation technology. Central to these considerations are coal combustion systems that are unlike the pulverized coal units of the past. Highly efficient and totally integrated with pollution control equipment, these newer coal combustion-based systems are forming the base of plans by many to add new generation within the next decade. Equally as exciting, and even more significant, the electric utility industry is also exploring the utilization of integrated gasification combined cycle (IGCC) for the next generation of 31

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Coal technology programs were prominently included in last year’s energy bill. To emphasize broad-based support for coal technology development and demonstration, the legislation last year included research, development, demonstration and commercial deployment programs targeted at encouraging the development and use of advanced coal-based technologies power plants. IGCC is not only very environmentally friendly, but some analysis shows that it may be a least-cost approach to the capture of carbon dioxide if regulations are ever imposed. In both cases, government has made significant R&D and demonstration plant investments that have resulted in mature technologies ready for the marketplace. President Bush also has announced his Administration’s intent to partner with industry in the planning, construction and operation of a coal-based production facility of the future. Known as FutureGen, this demonstration project will gasify coal to produce electricity and hydrogen. The CO2 from the facility would be captured and sequestered. The plant would be nearly emissions-free and the most efficient coal-use plant in the world. On top of this endeavor, President Bush, with active support from the Congress, is fulfilling a promise made in 2000 to provide $2.0 billion over 10 years to support an industry/government cost-share program to demonstrate new clean coal technologies. In seeking proposals

for the latest DOE solicitation, the Department announced that the CURC/EPRI/DOE roadmap would guide the project selection process. Today, the members of CURC, and others, are seeking a federal government commitment to a new multi-year and multi-billion dollar program to move commercially available, but still too costly, advanced clean coal technologies into the marketplace. Congress nearly enacted a program of this magnitude last year. This initiative, if successful, would provide financial and tax incentives for the deployment of full-sized commercial systems to employ IGCC and other advanced coal technologies. The focus of the program will be to get “plants in the ground” so that coal use is assured with America’s latest, best and cleanest clean coal technologies. ◆

Ben Yamagata is Executive Director of the Coal Utilization Research Center (CURC). Visit

Generating Solutions, Fueling Change CONSOL Energy Inc. is the largest producer of high-Btu bituminous coal in the United States, with 17 mining complexes in six states. In addition, the company is one of the largest U.S. producers of coalbed methane, with daily net gas production of approximately 139.6 million cubic feet from wells in Pennsylvania, Virginia and West Virginia. CONSOL Energy Inc. has annual revenues of $2.8 billion. The company was named one of America’s most admired companies in 2005 by Fortune magazine. It received the U.S. Department of the Interior’s Office of Surface Mining National Award for Excellence in Surface Mining for the company’s innovative reclamation practices in 2002 and 2003.

CONSOL Energy Inc. Consol Plaza, 1800 Washington Road, Pittsburgh, PA 15241 412/831-4000 •


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Fuel and Fireside Treatment Technologies Air Pollution Control The NOxOUT速 process is a Selective Non-Catalytic Reduction (SNCR) process using urea-based chemicals to control nitrogen oxide emissions. The patented process typically achieves 30% to 60% NOx reduction. SNCR can be a cost-effective option compared to other technologies on a $ per ton of NOx removed basis, and is a lower cost and a lower risk approach than going short term to the NOx allowance market. For higher NOx reductions using SCR technology, the NOxOUT ULTRA速 process uses urea to generate ammonia on-site as the reagent. NOxOUT ULTRA is currently being installed for large commercial SCR projects on coal fired boilers.

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3/23/05 3/18/05 10:26:12 4:10:56 PM AM

AEP Commits to Coal with IGCC Project By Rachel Dutton, American Electric Power

American Electric Power’s (NYSE:AEP) quest to keep coal as the strategic fuel of the future is the driver for its recently announced commitment to build the first commercial-scale Integrated Gas Combined Cycle (IGCC) power plant in the country.


he plant, with a proposed generating capacity of up to 1,200 megawatts, is scheduled to be in operation by 2010. AEP will rely on this new generation to help provide a reliable supply of power for its customers for the next 30 to 40 years. IGCC is a clean-coal technology that combines two technologies — coal gasification and combined cycle — that offer the environmental benefits and high efficiency of natural-gas-fired generation together with the relatively low fuel cost associated with domestic coal. Coupled with AEP’s significant planned investment in emissions-control installations at existing coal-fueled plants, IGCC signifies the company’s commitment to coal as its low-cost, low-emissions domestic energy source of the future. “Continuing significant environmental investments in our current fleet and building a commercial-scale IGCC plant are the right steps going forward to ensure that we can continue to burn coal economically while reducing our emissions,� says Mike Morris, AEP Chairman, President and Chief Executive Officer.

provides potential to co-produce high-value chemicals,� Mudd adds. “The technology offers flexible product processing. The gaseous fuels produced by gasification, consisting of primarily carbon monoxide, methane and hydrogen, can be used as a feedstock for the formation of other chemicals as well as for further combustion.�

IGCC offers many benefits “Coal gasification will allow us to remove impurities before the coal gas is combusted, rather than installing costly emission-capture equipment to remove chemicals from the exhaust gas stream,� explains Mike Mudd, Program Manager, Technology Development for AEP’s Advanced Generation program. The IGCC process results in lower emissions of sulfur dioxide, particulates and mercury. The technology also emits less nitrogen oxide and carbon dioxide. Additionally, it is anticipated that the technology offers potential for future retrofit of carbon-capture systems at a lower capital cost and with lower efficiency losses when compared with conventional pulverized coal technologies. “Besides improving efficiency and providing environmental benefits, IGCC also

Plant sites studied One of the first steps toward building this plant is determining a location. AEP plans to build the plant in one of the seven states in its eastern service territory — Kentucky, Indiana, Michigan, Ohio, Tennessee, Virginia or West Virginia. AEP engineers have identified the essential characteristics for the plant site and are evaluating potential sites that offer these features. At the same time, AEP is meeting with technology providers to determine which IGCC platform the company will adopt for the facility. AEP also is working with the regulators and legislators in these seven states to determine how to expeditiously permit the plant and how to recover construction costs. Because this will be the nation’s first commercial-scale IGCC plant, AEP is refining cost estimates to include the costs of land, permitting and other associated


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expenses. Electric Power Research Institute (EPRI) projections for engineering, permitting and constructing an IGCC plant are $1,300 to $1,600 per megawatt. IGCC and the future of coal IGCC technology is intrinsically suited for coals with low ash and a high heating value (BTU content), such as bituminous Appalachian coals readily available in AEP’s eastern service territory. More importantly, because the sulfur is removed before combustion, IGCC can use high-sulfur coals much more economically than conventional technology. This means AEP is well suited to capitalize on IGCC technology because of the abundance of high-sulfur and high-BTUcontent coal in its eastern service territory. The company firmly believes it is time to begin developing the next generation of coalfueled power plants — a new generation of plants that can use coal more cleanly, more efficiently and with fewer environmental impacts than ever before. ◆

Rachel Dutton is Manager Corporate Communications for American Electric Power. Visit AMERICAN COAL COUNCIL

3/23/05 10:26:22 AM


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Environmental Stewardship in the Far North By Cathy Brooks & Bartly Coiley, Usibelli Coal Mine


eclamation at Usibelli Coal Mine, Inc. (UCM) calls for a unique and innovative application of technology, equipment, people, and science. Although located in the remote mountainous foothills north of Denali National Park, near Healy, Alaska, the mine contends with the same laws and regulations others in the industry face. Managing the resources can be challenging with the short summer field season and long cold winters. UCM got its start in 1943 when founder, Emil Usibelli contracted to supply 10,000 tons of coal to a military base located in Fairbanks, Alaska. More than 60 years later, a workforce of 96 UCM employees led by Emil’s grandson, Joseph Usibelli, Jr., now ship approximately 1.5 million tons of coal annually to 10 customers, including three interior Alaska military bases. Most of the customers are power plants based in interior Alaska. However, UCM has established relationships in the international market, having sold coal to South Korea since 1985. The coal found in interior Alaska is a sub-bituminous coal that comes from three seams of the Suntrana Formation. The coal seams vary in depth from 18 to 30 feet with the interburden ranging from 70 to 125 feet. The mine operation consists of a dragline and truck/shovel combination. UCM began its land reclamation program in 1971, well ahead of the passage of the 1977 Surface Mining Control and Reclamation Act (SMCRA). UCM worked with Alaska’s Department of Natural Resources Division of Mining, Land and Water to establish bond release standards by selecting several sites that were considered successfully revegetated. This helped establish reasonable revegetation goals, which took into consideration the post-mining ground cover, water quality, and wildlife habitat. Conducting studies with researchers from the University of Alaska, UCM has been able to examine revegetation ranging from the natural reinvasion to actively providing seed, transplants and/or selected growth media to facilitate plant community development. A compilation of results from several studies suggested the following changes in ground cover over time (see Figure 1). The research indicated seeded grasses have a high ground cover at first while the vegetative litter and locals are essentially nonexistent. Over the next five years, ground cover from litter develops from the seeded grasses and then declines for another five years. Meanwhile, groundcover from locals slowly increases, hitting a low point of ground cover from all sources and at the 10-year mark. This could be interpreted 38

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Figure 1. Changes in Ground Cover Over Time AMERICAN COAL COUNCIL

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The coal found in interior Alaska is a sub-bituminous coal that comes from three seams of the Suntrana Formation. The coal seams vary in depth from 18 to 30 feet with the interburden ranging from 70 to 125 feet. as a reclamation failure. However, as depicted on Figure 1, from this point on, ground cover sharply increases. The conclusion is that initial grasses appear to assist soil development, but it takes 10 growing seasons to see the effect. This research and other studies helped to develop a successful reclamation plan. UCM has applied for and received phase II bond release and is in the process of applying for phase III bond release. Research also assisted in developing the mixture of grasses that would provide the necessary ground cover until the slower growing native plants began to flourish. UCM conducts aerial seeding twice during the rapid summer growing season and has experimented with hydro-seeding while continuing to look for innovative ideas. A summer crew, consisting of local college students, transplants approximately 25,000 native shrubs and trees each year. The trees and shrubs planted include spruce, birch, alder, and willow with a few other species depending upon seed availability. During the fall, local grade-school children assist by collecting seeds that are cleaned and germinated for transplanting. Reclamation is a challenge due to the lack of top soil on northfacing slopes, deep permafrost layers, abbreviated field season (best time for regrading is between September through December), and a high rate of naturally occurring erosion. The spring and summer seasons bring quick moving rain storms with abundant rainfall which challenge soil stability, especially on our 3:1 slopes. UCM constructed sediment ponds to collect and treat storm water runoff to meet the mine’s National Pollutant Discharge Elimination System (NPDES) permit limits. The sediment ponds have been designed into the post-mining land use plan as constructed wetlands. Several access roads will remain in place, something that is in short supply in Alaska. Another post-mining design feature, approved for one area of the mine, AMERICAN COAL COUNCIL

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is a man-made lake that will be stocked with fish grown in a hatchery. The hatchery will utilize the waste heat from a power plant generating electricity and heat from coal mined at UCM. UCM has worked for many years with state and federal agencies to develop reclamation standards and permit conditions that are protective, reasonable, and achievable. These permits span eight state and federal agencies, which have responsibility for more than 30 plus environmental permits required to mine coal in Alaska. ◆

Cathy Brooks is a Mine Technician in the Engineering Department at Usibelli Coal Mine. Bartly Coiley is a Civil Engineer and works with Permitting at Usibelli Coal Mine. Visit

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The Debate on Mercury By Jon M. Heuss, Annapolis Center for Science-Based Public Policy


he U.S. EPA proposed a mercury rule for coal- and oilfueled power plants in January 2004. Mercury (Hg) is a natural constituent of the earth’s crust and is present in trace quantities in coal and other geologic materials. The concern over mercury emissions from the use of coal arises from the fact that a portion of the mercury, after deposition in the ecosystem, is transformed into methylmercury, a compound that bioaccumulates in fish and seafood. Consuming seafood with high mercury content can lead to neurological damage in humans, with the most sensitive populations being children and developing fetuses. However, the extent of harm from current mercury levels in fish is a matter of debate. Using studies of populations accidentally exposed to high mercury levels and island populations for which seafood is a major portion of their diet, various national and international organizations have developed estimates of safe levels of mercury consumption. The safe levels are set below the levels at which the first effects appear in order to provide a margin of safety. States use these safe levels along with surveys of mercury in fish to issue public advisories encouraging limits on the consumption of certain fish. Because mercury has been used in various products and processes over the past century, substantial amounts of mercury have already been released into the environment. Approximately 48 tons per year of mercury are emitted by U.S. coal-fueled power plants. This is roughly one percent of total global mercury emissions. The global total (estimated at from 4,000 to 7,000 tons per year) arises in about equal amounts from natural sources (due to volcanic action, natural weathering, and re-entrainment of crustal material), current man-made emissions, and the re-emission of mercury associated with historic man-made emissions. The predominant form of mercury emission is gaseous elemental mercury (Hgo) which has a relatively long lifetime in the atmosphere. Hgo is oxidized to soluble inorganic Hg2+ species both in the gaseous phase and in clouds. Once the various chemical forms of mercury are deposited through either wet or dry deposition, the transport and transformations of mercury in the biosphere are complex with various oxidation and reduction pathways. In one pathway, sulfate-reducing bacteria convert Hg2+ to methylmercury. When methylmercury enters the food chain it can bioaccumulate, so mercury levels in older fish or fish higher up the food chain have higher mercury levels. 40

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Reducing U.S. power plant mercury emissions will have only a small effect on human exposure to mercury in the United States. The U.S. population consumes fish and other seafood that contain traces of mercury from a variety of sources from around the world. These include ocean fish and seafood (that are not affected by deposition in the vicinity of power plants), farm-raised fish (that are fed a diet low in mercury), and wild freshwater fish. Only 10 percent or less of the fish consumed in the U.S. are wild freshwater fish. Nevertheless, environmental advocacy groups have made stringent power plant controls a high priority, often using the threat to fishing in freshwater lakes a key emphasis of their arguments. The following lists the main claims from the environmental advocacy community along with the facts: Claim: Many women and children are exposed to unsafe levels of mercury. Fact: CDC’s Second National Report on Human Exposure to Environmental Chemicals in January 2003 reports that “the levels reported in this NHANES 1999-2000 subsample for maternal-aged females were below levels associated with in utero effects on the fetus, or with effects in children or adults.” Claim: The effects of mercury on child development are devastating. Fact: The highest mercury levels observed in a random sample of more than 700 one- to five-year old children and more than 1700 16- to 49-year old females were well below the lowest dose known to cause adverse effects. However, a small portion of the women had mercury levels between the EPA safe level and the level where effects have been found. Claim: The best way to protect women and children from mercury is to eliminate mercury from power plant emissions. Fact: U.S. power plants are responsible for one percent of global mercury emissions. All U.S. man-made emissions are now three percent of global emissions. Due to a mix of controls on AMERICAN COAL COUNCIL

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industrial processes, municipal waste and medical waste incinerators, bans on mercury additives in paints, and removal of mercury from batteries and many other sources, total U.S. man-made mercury emissions have been reduced dramatically (well over 75 percent) over the past several decades. Claim: The “cap and trade� proposal threatens communities with toxic hot spots. Fact: Analyses carried out by EPA during the Clinton Administration showed there were no health concerns from inhaling mercury in the air in the vicinity of power plants or from ingesting soil or from consuming crops grown in the vicinity of the plants. The only potential concern was the consumption of mercury in fish and other seafood. Modeling suggests that large power plants have greater local deposition footprints than medium and small plants. Trading of allowances is more likely to involve large power plants controlling their emissions more than required and selling allowances to smaller units rather than the reverse. The basis for this prediction comes from the economics of capital investment in the utility industry. Even though many larger mercury sources in the U.S. have been subject to regulation and control in the past decade with little fanfare, controlling mercury emissions from power plants has received overwhelming attention from the environmental


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community. EPA received more than 680,000 public comments, including over 5,000 unique comments, on its January 2004 proposal. In that proposal, EPA presented two primary approaches for regulating mercury, either through Maximum Achievable Control Technology (MACT) regulations under Section 112 of the Clean Air Act or by issuing performance standards for coal-fueled power plants under Section 111 using a cap-and-trade methodology. Because of the technical complexities of the rule and the great public interest, EPA issued another notice on December 1, 2004 asking for more input by January 3, 2005 on how the power sector will respond to various regulatory approaches, and on how EPA should estimate the human health benefits of the proposal. EPA is currently under a settlement agreement that requires the Agency to promulgate final rules by March 15, 2005. No matter what is in the final rule, the contentious nature of the debate over power plant mercury emissions probably means the rule will be challenged in federal court by one party or another. Also, many states are in various stages of considering or passing their own laws or regulations to control power plant mercury. In addition, the Bush Administration is considering pushing ahead with legislation that would control mercury, sulfur dioxide and nitrogen oxide emissions from power plants. For the coal industry, the message is that mercury will be controlled substantially over the next several decades even though the details of the regulation or even the regulatory approach are not known at the time this is written. Based on estimates in the


3/23/05 10:29:08 AM

Consuming seafood with high mercury content can lead to neurological damage in humans, with the most sensitive populations being children and developing fetuses. However, the extent of harm from current mercury levels in fish is a matter of debate.

rulemaking record, the controls will consist of a mix of traditional controls such as flue gas desulfurization (FGD) and selective catalytic reduction (SCR), coal switching, and new technologies currently under development such as activated carbon injection. Costs to the utility industry are estimated to vary from $2 billion to $8 billion per year depending on the degree of control and varying other assumptions. Since the ability to capture mercury depends on the Hg species present as well as other components such as chlorine and/or other halogens, the trace components in coal will take on increased importance. Although much progress has been made toward

developing mercury control technology, much more work needs to be done before commercially viable mercury control technology will be available for all coal/power plant combinations. The EPA capand-trade proposal would aid in this effort by fostering continued development and innovation. â—†

Jon M. Heuss is a Principal Scientist at Air Improvement Resource, Inc. and a contributing author to the Annapolis Center for Science-Based Public Policy. Visit and

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Impact of New Air Regulations on Regional Coal Markets By John Blaney, ICF Consulting

While there is still uncertainty about the specific components of new air regulations, it is clear that these new regulations will require that future SO2 emissions be reduced by 70 percent or more from current levels. NOX and mercury emissions will also be similarly slashed. SO2 emission reductions of this magnitude will lead to a large increase in installations of flue gas desulfurization equipment. SO2 allowance prices will also rise dramatically from already high levels. These two related developments will have major impacts on regional coal production levels. Scrubber Installations and Allowance Market Outlook Until recently, SO2 prices have remained below $200 per ton since the beginning of allowance trading in 1995. (See Figure 1) These relatively low SO2 allowance prices reflected the enormous bank of allowances that had been built up during Phase I of the Acid Rain program. The low SO2 allowance prices were also reflective of the relatively low cost of switching from high to low sulfur coal, which has been the predominant compliance strategy. As a result, consumption of low sulfur coals from Wyoming and Montana increased from 285 million tons in 1995 to over 400 million tons in 2004. This huge increase in Powder River Basin (PRB) low sulfur coal more than offset the decline in predominantly low sulfur coals from Central Appalachia, which fell from 271 million tons in 1995 to less than 225 million tons in 2004. Despite the large surplus of SO2 allowances and the cheap cost of switching to low sulfur coal, ICF predicted that SO2 allowance prices would rise dramatically, even under current regulations. Our prediction of rising SO2 allowance prices was based on an engineering-economic fundamentals analysis that indicated that coal-fueled generation levels and emissions levels would rise, resulting in a rapidly depleting SO2 bank. Indeed, the SO2 allowance bank has declined by over 5 million tons, falling from nearly 12 million tons at the beginning of 2000 to less than 8 million tons at the end of 2003. (See Figure 1.). The SO2 allowance bank likely declined by an additional 1 million tons in 2004, leaving the bank at about 55 percent of its level at the beginning of Phase II in 2000. With a shrinking bank and growing realization that major new cuts in SO2 emissions were coming, SO2 prices have tripled in the last year, rising from around $200 per ton at AMERICAN COAL COUNCIL

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Figure 1: SO2 Emissions and Banking Behavior


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Figure 2: Historical SO2 Allowance Prices. Source: Air Daily

Figure 3: Distribution of Remaining Coal Resources in Central Appalachia


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the beginning of the year to around $700 per ton at the beginning of 2005. (See Figure 2). The rapidly dwindling SO2 allowance bank and the sharp run up in SO2 allowance prices has put a sense of urgency behind power company executives’ compliance strategic thinking. Consequently, in the past year, electric power companies have announced that over 30,000 MW of new flue gas desulfurization (FGD) equipment will be added in coming years. This large increase reflects the growing realization that switching from high to low sulfur coal will not achieve the magnitude of reductions that will be required under the new air emission regulations. Although SO2 allowance markets will be volatile, ICF expects allowance prices will continue to rise, reaching levels over $1,000 per ton and ultimately rising to above $1,500 per ton. In addition, our analysis indicates that a total of 80,000 MW of FGD equipment will be added in coming years. Impact on Regional Coal Markets In assessing regional coal markets, most analysts are predicting a continued decline in Central Appalachia coal production and continued increases in PRB coal production levels. In Central Appalachia, the USGS coal resource assessment1 indicates that coal resources in Central Appalachia are rapidly being depleted and that remaining reserves are in thinner seams. As illustrated in Figure 3, the USGS report suggests that, for the Central Appalachian areas included in their review, more than 35 percent of the remaining coal resources are located in seams thinner than 2.33 feet, which the USGS considers uneconomic to develop. In the PRB, permitted production levels at existing mines are nearly 250 million tons above current production levels. However, in the short run, major increases in coal production from the PRB will be limited by rail capacity. Currently, the large differential between spot eastern and PRB low sulfur coal is indicative of the lack of incremental rail capacity to move additional volumes out of the PRB. The impact of dwindling low sulfur coal reserves in Central Appalachia will be limited by the projected large increase in FGD equipment and a corresponding shift away from low to medium and high sulfur coal. In addition, increases in PRB coal will also be limited by the shift away from low sulfur coal production. Medium and high sulfur producing regions like the Midwest and, to a lesser extent Northern Appalachia, will AMERICAN COAL COUNCIL

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be the chief beneficiaries of the shift in coal demand brought on by new air regulations. The required cut in SO2 emissions will also have an impact on regional coal price differentials. Given that switching to low sulfur coal has been the predominant means of reducing SO2 emissions, there has historically been a relationship between SO2 allowance prices and the price differential between high and low sulfur coals. As illustrated in Figure 4, from 1998 through the first half of 2000, SO2 prices tracked quite closely with the trend in the coal price sulfur premium. From mid-2000 through 2002, the SO2 price was far less volatile than the coal price sulfur premium, but still followed the underlying trend. Since the beginning of 2003, the SO2 allowance price has followed the sulfur premium upward, but at much slower pace. However, the SO2 allowance price has recently risen above the sulfur premium, reflecting the growing realization that the cost of scrubbing, not fuel switching, will drive SO2 allowance prices in the future. Going forward, ICF expects that the SO2 allowance price will further disconnect from the coal price sulfur premium as FGD continues to dominate SO2 compliance decisions. As a result, the price premium


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commanded by low sulfur coals will decline from the record levels of last summer. ◆ John Blaney is with ICF Consulting. He can be reached at (703) 934-3000 or at


US Geologic Survey, “Coal Availability, Recoverability, and Economic Evaluations of Coal Resources in the Northern and Central Appalachian Basin Coal Regions,” USGS Professional Paper 16265-C, 2002.

Figure 4: SO2 Allowance Price Versus the Coal Sulfur Premium * SO2 allowance price from Air Daily. ** Sulfur Premium = Differential between price of Central Appalachian NYMEX Look-Alike and Northern Appalachian <3 lb SO2 as reported in Coal Week.


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2005â&#x20AC;&#x201C;2007 Coal Outlook: Sustainable Strength on Global Steel and Power By David Khani, Friedman, Billings, Ramsey & Co., Inc.

Summary and Recommendation Friedman Billings Ramsey is releasing our 2005-2007 coal outlook report, which justifies a sustainable U.S. coal and strong metallurgical (met) coal outlook. More specifically, we are raising our 2006 and 2007 met coal prices to $80 from $65/ton and are maintaining our modest contango forecast for thermal grades. On the domestic front for steam coal, industrial-driven demand for electricity and improving policy should sustain prices near current high levels, but supply response and expected growing imports should limit further upside. On the met front, demand from global growth in steel production will continue to outstrip new met volumes by a comfortable margin. While a flattening spot price outlook for steam and rising met prices still support as much as 50 percent upside to current equity valuations, based on projected 2006 and 2007 earnings, we believe that execution and higher capital spending risk is ubiquitous. Although we are optimistic about the coal commodity fundamentals, we have a cautious view of the equities at this juncture, due to near-term valuations, and look toward opportune entry points such as pending earnings releases.

Bullish Three-Year Assessment Our three-year assessment of global coal fundamentals continues to support our thesis of a secular shift in supply and demand variables that are supportive of prices near current levels. Figure 2 (on page 50) summarizes our U.S. supply and demand projections. We raise our 2006 and 2007 metallurgical (met) coal price outlook and maintain our modest contango forecast for thermal grades from the various U.S. Basins (Figure 1). On the domestic front for steam coal, industrial-driven demand for electricity and improving policy should sustain prices near current high levels, but supply response and expected growing imports should limit further upside. On the met front, demand from global growth in steel making will continue to outstrip new met production by a comfortable margin. While a flattening spot price outlook for steam and rising met prices still support as much as 50 percent upside to current equity valuations, based on projected 2006 and 2007 earnings, we believe that execution and higher capital spending risk is ubiquitous. Hence, and given the high operational leverage, free cash flow generation remains at risk. We also expect valuation metrics to evolve beyond EV/EBITDA

Figure 1: FBR Price Forecast for Repricing of Uncontracted Coal FBR Coal Price Forecast by U.S. Basin Region















































PRB Metallurgical Source: FBR Research 46

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and P/E ratios toward critical measures such as free cash flow yield and return on capital employed, similar to the larger, global mining group. Although we are optimistic about the coal commodity fundamentals, we have a cautious view of the equities at this juncture and emphasize opportune entry points. Our full research report, the “2005-2007 Coal Outlook— Sustainable Strength on Global Steel and Power,” includes a discussion of the following subjects in greater detail. • Global steel manufacturing and metallurgical coal take the lead. For 2005-2007, we project an average market deficit of 16 million tons (MTs), representing about eight percent of total metallurgical seaborne trade. The shortfall should be driven by a projected five percent average annual increase in crude steel production, which translates into about 37 MTs of met coal. Although periods of steel inventory builds are likely, the underlying global infrastructure-driven trends are sustainable, while opportunities for new supply of high-grade coals are not abundant. As a result, we are raising our 2006 estimate ($80/ton from $65/ton) and are introducing a 2007 met coal price forecast of $80 per ton. • China supply remains a wild card. Our projections for new global met supply of about 21 MTs annually include about five MTs from new China production. However, any new China supply will likely be consumed from its projected 10 percent growth in steel production, which should require a total of about 18 MTs in additional met. While we are more confident in our supply estimates out of Australia, Canada, and the U.S., China is more challenging. However, an historical analysis of coal production, driven by more trustworthy electricity and coal trade statistics, provides us with some comfort that production of coking coals has peaked near current levels and that growth is limited for the duration of our forecast period. Beyond 2007 development of new mines in Mongolia is likely to provide meaningful supply, but this will, at least, be partially offset by the closure of unsafe smaller town and village mines, which currently account for more than 25 percent of total production of about 1.6 billion tons. • Industrial-driven growth in electricity consumption. We estimate 2004 electricity growth in coal-fueled generation at 3.2 percent, primarily driven by the growth in industrial sectors in the south central and south eastern regions, and fueled by available capacity in the non-peak months. We expect coal to capture about 50 percent of our projected 1.7 percent annual growth in total U.S. power consumption over our forecast period, which amounts to about 17 MTs of extra coal burn on average. We expect the majority of this growth to be captured by western coals in the south central and southeast industrial electricity markets. The growth in coal-fueled output is expected from increased utilization and capacity creep, partially muted by rising emission standards (NOx and mercury) and increased efficiencies at existing coal units (reversing declines). AMERICAN COAL COUNCIL

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• Marginal eastern supply response due to rising permits. Based on the analysis of approved mine permits and increased capital spending, we project an average increase of 16 MTs in Appalachia production, of which four MTs are met grade. We expect flat volumes from the Interior and Southwestern Basins but continued production growth from available PRB markets. • Net exports to remain flat due to equal increase in imports. We expect net exports to remain nearly flat over 2004 levels, driven by increased met coal exports and increased steam coal imports. We project exports to increase at an average of 2.5 MTs annually, driven by strong growth in steel production, a relatively weaker dollar and our expectation for increased global shipping capacity and flattening shipping rates. On the steam front, we expect imports to increase from South America at an average of three MTs annually due to increased supply and declining demand in Europe. • Excess supply and sulfur allowances cast uncertainty over PRB prices. We estimate the practical productive capacity of existing PRB mines at about 500 MTs, about 100 MTs higher than existing shipments. Even at demand rail capacity growth of five percent or 25 MTs, current excess capacity would take about four years to deplete. However, by 2008 and beyond, we expect increasing scrubber installations of about 25,000 MW to limit the benefits of the lower-sulfur coals such as PRB.

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• Washington policy: headline, legislative, and ideological effects. The re-election of President Bush spurred investor expectations for passage of an energy bill in the 109th Congress, and we continue to expect an ambitious bill in the 2005-2006 session. On the other hand, the President has made clear his intent to prioritize dramatic domestic reforms of social security and the tort system. The net result is that the long-awaited energy bill will probably have to wait a little longer for its turn in the national legislature; but there are other pokers in the fire. In our view, coal-focused investors will encounter headline and legislative effects from environmental policy debates on the Hill — probably in February and March 2005 — well before an energy debate heats up. • Clear skies or clean air interstate rule. The passage of mercury standards, along with the Clean Air Interstate Rule (CAIR) in March 2005, could possibly alleviate near-term pressure for passage of full-scale legislation such as the Clear Skies initiative. However, the rule does not create enough stability for utilities to accelerate the pace of new coal-fueled power plants, but it does enable more emissioncontrol technology to be installed to improve coal burn.

A flattening spot price outlook for steam and rising met prices still support as much as 50 percent upside to current equity valuations.

$2.50/ton from 2001-2003, the group doubled capital spending, including acquisitions, to $5.48/ton in 2004. As a result, none of these companies generated free cash flow in 2004. We expect capex to decline to $3.87/ton in 2005 and to drive the transition into significant free cash flows in 2006. Visibility into 2006 will be driven by individualcompany productivity and contracting activity throughout 2005. • Rollover tons limit 2005 coal price realizations. With all of the rail and operational disruptions, companies will be on the hook to deliver 2004 contracted coal to utilities in early 2005 at the preset prices. While we suspect the total amount of coal will be less than 10 MTs for the industry, this can cause company forecasts to be below the Wall Street consensus estimates.

Risks The future course of domestic and international supply, demand and prices of energy commodities may substantially differ from the forecasts outlined in this report. Domestic and international variables that may affect our forecasts include weather, general economic conditions, geopolitical developments, military conflicts and regulatory and political developments, as well as capital investment, technology, and geophysical factors affecting the production of energy commodities. These variables are likely to interact with one another and to create outcomes that may cause future prices to differ substantially from our forecasts. ◆

David Khani is Managing Director – Energy Research for Friedman, Billings, Ramsey & Co., Inc. Visit

• Upside oil and gas price volatility welcomed for coal equity prices. Although not an immediate impact on coal demand, expected upside volatility to oil and natural gas prices will continue to drive the bullish psychology of coal investors. Oil and natural gas prices remain well above our estimate of eastern coal’s BTU parity, at about $5.50 per MMBtu. • Consolidation activity, but in smaller bite sizes. As prices flatten out, we expect the price gap to narrow between buyers and sellers and cause more consolidation; however, we expect the size of the transactions to be relatively small. • Execution and visibility into 2006 free cash flow to drive valuations. After the four largest operating coal companies spent an average of AMERICAN COAL COUNCIL

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Figure 2: FBR U.S. Supply & Demand Model Output for 2005-2007. Updated As of January 27, 2005. Year Over Year Change 2005E 2006E


Total 2007E

























Total Supply - Thermal








Total 2003E



Total 2007E

Power Generation







Western Coals







Eastern Coals







Steam Exports







Weather Normalizing







Industrial Plants







Environmental Standards







Total Demand - Thermal







Thermal - Surplus (Deficit)







Thermal - Ending Inventories







Total 2003E



Total 2007E




















Total Supply - Metallurgical







Total 2003E



Total 2007E















Total Demand - Metallurgical







Metallurgical - Surplus (Deficit)







Metallurgical - Ending Inventory







Total 2003E









West Imports

Supply Thermal Appalachia Less: Diverted to Met.

Year Over Year Change 2005E 2006E



Year Over Year Change 2005E 2006E

Metallurgical Production Add: Diverted from Thermal


Year Over Year Change 2005E 2006E



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Railroads and Coal By John Wetzel, Association of American Railroads


oal dominates U.S. electricity generation and freight railroads are a big reason for that. Railroads know that efficient coal transportation is critical to our nation’s economic wellbeing and energy security and they are committed to working with coal suppliers and consumers to ensure continued safe, cost-effective and reliable service.

Railroads Deliver Two-Thirds of U.S. Coal Although all major surface transportation modes carry large amounts of coal, railroads are the principal coal transporter. According to Energy Information Administration (EIA) data, 65 percent of U.S. coal shipments in 2003 were delivered to their final domestic destinations by rail, far more than trucks (12 percent); conveyor belts, slurry pipelines, and tramways (11 percent); and water (11 percent) (see Chart 1). Over the past decade, the rail share has trended upward. This growth is partly due to the growth of western coal that moves long distances by rail and partly due to the enormous efforts railroads have made to improve their service to coal customers. Coal has long been the largest single commodity carried by U.S. railroads. In 2003, it accounted for 44 percent of tonnage, 24 percent of carloads and 21 percent of revenue for Class I railroads. Coal is also a top-three commodity for dozens of regional and local railroads. AMERICAN COAL COUNCIL

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In 2003, Class I railroads originated more than 7 million carloads and 784 million tons of coal — both down fractionally from 2002, but still the third-highest level ever. Preliminary 2004 data indicate a three percent increase in coal carloadings over 2003 levels, a result consistent with trend lines based on the past 10 years (see Chart 2). While the vast majority of this coal is delivered to coal-fueled power plants, exports are a not-insignificant portion of rail coal shipments, especially as exports have begun to rebound over the past 12 to 18 months from previously depressed levels.


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In inflation-adjusted terms, 2003 RPTM for coal was 63 percent lower than it was in 1981 — equivalent to a 4.4 percent average annual decrease — and 28 percent lower than it was in 1990.

Railroads’ Goal: Increased Efficiency and Reliability Coal-fueled power plants compete fiercely against one another and against power plants fueled by other energy sources. Moreover, ultimate electricity consumers and government regulators exert enormous pressure on electricity suppliers to keep prices low. Consequently, railroads must work closely and cooperatively with mines and utilities to maximize efficiencies and enhance competitiveness. Indeed, railroads work extremely hard to keep their coal service as responsive and productive as possible. For example, over time, higher capacity cars and more powerful locomotives have dramatically increased


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railroads’ coal-carrying efficiency. In 2003, the average coal car carried 111.4 tons, up 10 percent from the 101.6 tons in 1994. Meanwhile, the average horsepower of a locomotive in the U.S. fleet was 3,415 in 2004 — up 21 percent from 10 years ago and the average fuel efficiency was enhanced by approximately 13 percent. Highly productive unit trains of 50 or more carloads now account for the vast majority of railroad coal shipments. Railroads also strive to keep rail rates as low as possible. Revenue per ton-mile (RPTM) is a useful surrogate for railroad rates. In 2003, rail RPTM for coal was 1.56 cents, easily the lowest such figure among all major rail commodity groups.

What Are Railroads Doing to Help Ensure Adequate Future Capacity and Service? Total coal ton-miles on U.S. railroads rose from 406 billion in 1994 to some 582 billion in 2003, a 43 percent increase. According to the EIA, total U.S. coal consumption will rise from 1.1 billion tons in 2003 to 1.5 billion tons in 2025, a 38 percent increase. This means that railroads will need to be prepared to continue to handle dramatically higher coal volumes. To help ensure that adequate coalcarrying capacity is available to meet future coal transportation needs, railroads are taking a variety of actions. For example, railroads recognize that it takes time to adjust to fluctuations in coal supply and demand, so they are emphasizing the need for coordinated, timely planning with customers and suppliers. To this end, railroads meet regularly with coal companies and electricity producers to determine how to best conform rail transportation offerings to their needs. These joint efforts include such objectives as meeting peak period demand and performing track maintenance as efficiently and unobtrusively as possible. Railroads are also continuing to invest heavily in coal service. For example, 50 of the 200 locomotives the Burlington … continued on page 57


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â&#x20AC;Ś continued from page 54 Northern and Santa Fe Railway Company (BNSF) plans to acquire in 2005 will be devoted to coal service. (These are in addition to the 67 acquired in 2004 for coal movements). BNSF also plans to acquire nine aluminum rapid discharge train sets for coal service in 2005 on top of the 14 coal train sets acquired in 2004. Additionally, in 2005 BNSF will spend $18 million on double tracking on the Central Corridor and another $26 million for terminal improvements at Lincoln and Alliance, Nebraska, and Edgemont, South Dakota. Over the past 10 years, BNSF has spent more than $2.2 billion on investments specifically aimed at increasing coal-carrying capacity. Likewise, Union Pacific has spent enormous sums on its coal service, including more than $1 billion over the past eight years on locomotives and another $1 billion on track capacity enhancements for coal. Total coal investment for 2004 and 2005 will reach $300 million. Major projects include completing, with BNSF, the third main-line on the Powder River Basin joint-line between Walker and Shawnee Junction; completion of the Denver bypass project; construction of a new siding on the North Fork branch line in Colorado; construction and extension of several sidings in Southern Illinois to support coal growth; and continuing a multi-year effort to install centralized traffic control on the Central Corridor East/ West mainline in Iowa. In addition, Union Pacific will acquire more than 500 new coal cars and additional locomotives to support coal growth in 2005. CSX, meanwhile, plans to rebody approximately 1,600 open top hoppers at its Raceland, Kentucky, car repair shop in 2005. Track capacity will be expanded between St. Louis and Evansville, Indiana, to support Illinois Basin and western coal traffic growth. Ongoing track programs to maintain the quality of the railroadâ&#x20AC;&#x2122;s eastern coal network will continue, including both key corridors and gathering/distribution points. Track modification and coal handling improvements will take place at the Chesapeake Bay Piers facility in Baltimore, Maryland and the Toledo Piers facility on Lake Erie. Norfolk Southern plans 2005 capital expenditures of $938 million, much of which will benefit coal. The proposed expenditures will include 52 new AMERICAN COAL COUNCIL

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locomotives and extensive spending on refurbishing the existing fleet. It also includes replacing 237 miles of track, 2.5 million cross ties and 2.9 million tons of ballast in addition to several projects to improve efficiencies associated with service. Railroad Capital Needs U.S. freight railroads are enormously capital intensive and, compared with other transportation modes, they receive no appreciable government financial assistance for infrastructure construction and maintenance. Consequently, railroads must earn enough year after year to finance

their massive infrastructure and equipment investment needs. This challenge has been compounded recently by unexpectedly large increases in traffic that have led to capacity pressures on certain corridors and highlighted the importance of continued investment over the entire rail network. If freight railroads are to be able to meet the dramatically greater expected future demand for coal and other freight across the rail network, they must be allowed to earn enough to fund the capacity enhancements such demand increases require. The alternative is increasing


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capacity crunches, reduced levels of service, less coal available at points of demand, and eventually, a reduction in our nation’s standard of living. In addition to trying to better balance earnings with investment needs, railroads are taking other steps to position future capital investment to support coal utilization. For example, they are encouraging the use of public-private partnerships for rail infrastructure projects, especially in cases where the fundamental purpose of the project is to provide public benefits or meet public needs. They also continue to aggressively seek productivity and technological enhancements to improve operations. And, they are pursuing ways to expand their markets and support efforts (such as clean-coal research) that will help coal remain the fuel of choice in the future. Railroads also continue to strongly oppose attempts to economically reregulate the rail industry. Reregulation would be counterproductive in that it would prevent railroads from earning enough to sustain their operations and attract the capital necessary for expansion. Reregulation would force railroads to disinvest in

their networks and reduce their service, an outcome completely at odds with coal’s transportation requirements. Conclusion Railroads recognize that America’s abundant, low-cost coal resources provide a reliable source of domestic efficiency and international competitiveness. Railroads also recognize that competition to coal-based power from other fuel sources will only intensify in the coming years, meaning that railroads, coal shippers, and coal consumers will have to engage in true partnerships to enable coal-fueled generation to retain its current dominant role. Through technological advances, service improvements, competitive rates and other factors, railroads have already shown that they are willing and able to provide consistently high value to coal shippers throughout the country. ◆

John Wetzel is Assistant Vice President, Government Affairs for the Association of American Railroads (AAR). Visit


Coal….From Exploration through Combustion

Exploration & Geologic Services Mine Planning & Feasibility Studies Permitting & Environmental Services Due Diligence & Investment Evaluation Coal Market & Fuel Supply Studies Fuel Procurement Support Materials Handling Audits Management Consulting Geographic Information Systems (GIS)


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3/23/05 10:30:08 AM

Physical Index-based Coal Transactions By Matt Schicke

Introduction Over the past few years, the U.S. coal market has witnessed several changes. There has been producer consolidation, constant environmental pressures, large swings in import coal pricing, transportation challenges, continual permitting issues in Central Appalachia, and swings in targeted working inventory levels at power plants. These changes and others have increased price volatility and made the U.S. a more dynamic marketplace. A potential solution to managing the price and volume risk in a coal portfolio is by using indexbased coal transactions for physical coal supply. This structure has been successful in the international coal marketplace and other commodity markets. What is an index-based coal transaction? An index-based coal transaction allows for the physical delivery of coal where the price is settled off of an index at the time of delivery. This transaction structure allows counterparties to separate volume risk from price risk by defaulting to an index for the pricing component while still allowing for counterparties to lock up specific quality or mine specifications that meet their physical coal supply requirements.

The most common deal structure in the current market is a fixed price transaction. For example, in a fixed price transaction a buyer might agree to buy one million tons per year for a three-year term. The price and volume in a fixed price transaction are known at the time of execution. In an index-based transaction the same buyer would buy 1 million tons per year for a three-year term but the settlement price would be set when the coal is actually delivered. Generally, the way the settlement price would get established would be off the average of the daily index price for the delivery month. For example, if we were establishing a settlement price for February 2005, we might use the average daily index price quoted in the month of January 2005 for prices in February 2005. Why use index-based coal transactions? If you look at the U.S. marketplace from a high level, you will find that producers and consumers have different needs but the same goal: economic supply or offtake reliability. Ultimately, both parties need to be able to plan for the future and understand their portfolio price and volume exposure. Since coal prices have reached historic highs, producers have the incentive to lock up long-term supply contracts

at historically high prices while utilities would prefer to keep the higher price supply agreements shorter in term. In the current market, both utilities and producers are having trouble agreeing on the forward curve. If end users and producers would utilize index-based transactions versus fixedprice transactions, it would allow both parties to hedge their supply risk. Alternatively, the coal market could maintain the status quo, forcing suppliers to move inventory targets, while utilities are forced into illiquid spot markets, creating annual price renegotiations and price escalators. Transaction Components There are three basic pieces to an index-based transaction: 1. settlement index 2. settlement price 3. basis differentials The settlement index is the index that will identify the settlement price for the coal. Currently there are three different types of indices available in the market: NYMEX futures, OTC-based methodology and market assessments. If the NYMEX futures were chosen, the counterparties would simply take the monthly settlement price from the NYMEX.

Calculating Basis Differentials: Settlement Index Specifications

Physical Coal Supply Specifications

Basis Differential







Jan â&#x20AC;&#x161;05 SO2 Index $685




fixed value




fixed value

Big Sandy/Kanawha



10,000 tons

8,000 tons


Btu/lb SO2 lbs/mmbtu Ash Railroad Rail District Train Size

Total Basis Differential Value AMERICAN COAL COUNCIL

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Comments industry standard btu calculation from monthly index value

premium for smaller train size

$0.59 59

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Calculating Final Settlement Values: January 2005 Platt’s OTC Broker Index Monthly Avg. Monthly Basis Differential Jan ‘05 Monthly Physical Coal Cost An OTC-based index is comprised of price points from OTC brokers. OTC brokers assess where they believe the market is from the data they get from daily bids and offers they receive from traders, producers and utilities, as well as actual transactions that happen in the OTC market. Market assessments are generally provided by consultants or industry publications from the feedback they get on current market pricing from producers, utilities, traders, the OTC market and the NYMEX market. The settlement price is the actual price calculation that the counterparties agree upon to use for billing purposes. The components of the settlement price are the settlement period and the calculation period. The settlement period is the time frame used to base the price component. Currently, most OTC-based methodologies provide a prompt quarter and a prompt month price. The calculation period would be the amount of data points taken into account for the settlement period. The various examples of the different calculation periods are daily average, last trading day of the month or last trading week average. The basis differential is the difference in value of the index quality and location specifications to the value of the actual physical coal that will be delivered. The basis differential would be a value agreed upon at time of execution and would either be added to or subtracted from the settlement price. For example, if counterparties are using an index based on a 12,500 btu/lb, one percent sulfur maximum product, on the CSX railroad, in the Big Sandy or Kanawha rail district and the product that is being delivered is the identical product, there would not need to be a basis differential. The more common example will be when these transactions are used to value the difference from the index product based on quality (btu, ash, sulfur), transportation mode (barge, rail, truck), location


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$55.99 $0.59 $56.58

(rail districts) and load-out speed (4 hours vs. 24 hours) to the delivered coal. Relevance to the OTC and NYMEX futures markets As stated earlier, a physical index-based deal structure allows the counterparties to efficiently hedge their volume exposure. However, these transactions have not addressed a way to manage the price exposure. The way counterparties can manage their price exposure in an index-based transaction is to execute offsetting transactions in any of the following markets: OTC forwards, OTC swaps or NYMEX Futures. Although all of these methods can be effective in hedging price, swaps are ideal because they are a financially settled product and there should be limited basis risk between indices. As a financially settled product, there will never be any issues related to physical delivery and supply. There is limited basis risk in swaps because the same index can be used to settle the physical index-based supply and the swap. Currently, the OTC market is in the initial stages of trading swaps but the OTC market offers adequate liquidity for the forwards market. This liquidity provides a good platform for assessing prices for the market indices. If more producers and utilities began using index-based transactions for their physical coal supply needs and then used swaps to hedge their price risk, the swaps market would achieve the necessary liquidity. The primary benefit to the coal market of having a liquid swaps market is that it would further increase price transparency. A liquid swaps market will also bring into the market new participants who are currently limited to trading only financial derivatives but want to speculate on forward coal prices. These new participants would bring added liquidity along the forward curve and it will make available more risk management tools. ◆

Advantages and Challenges for Index-Based Coal Transactions Advantages in utilizing index-based coal transactions: • Allows counterparties to hedge volume requirements • Provides an efficient transaction process • Allows counterparties to mange price exposure separately • Enables counterparties to receive transparent market pricing • OTC (over the counter) based index methodologies are gaining momentum as an impartial representation of spot market prices Challenges in utilizing index-based coal transactions: • Interest level from utilities has been minimal • Indices are not perfect indications of market prices • Reluctance from counterparties that have had “success” with price negotiations • Index deals can be seen as “commoditizing” products as producers try to develop relationships with consumers • Liquidity and price transparency in the spot markets


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3/23/05 10:30:20 AM

The Value of Coal Ash: An Economic Assessment of CCP Utilization for the U.S. Economy By Andy Stewart, Power Products Engineering


ore than 51 percent of the electricity generated in the U.S. today is produced from coal. According to the Energy Information Administration’s (EIA) Annual Energy Outlook 2005, domestic coal demand is expected to grow, primarily to fuel the increasing need for electric power. U.S. coal production is projected to increase at an average rate of 1.5 percent per year, from 1.083 million short tons in 2003 to 1.488 million short tons in 2025. Growing energy use and a corresponding increase in the use of coal to generate electricity has resulted in the production of increased quantities of Coal Combustion Products (CCPs). CCPs are the residuals produced from the combustion of coal. Today, more than 125 million tons of CCPs are produced, 30 million tons of which are beneficially used in concrete, highway pavement, geotechnical, manufactured products and agricultural applications. CCPs are a valuable resource that costeffectively improves the quality of many building materials while creating significant environmental benefits. The enhanced utilization of CCPs offers economic value for coal-based utilities, coal and materials suppliers, ash marketers, transporters and environmental proponents, as well as providing employment and tax benefits at the federal, state and local levels. The American Coal Council (ACC) has undertaken an economic assessment documenting the value of enhanced CCP utilization. The study examines various CCP utilization applications and details associated engineering, environmental and economic benefits. Utilization trends are analyzed, including a discussion of the barriers to increased CCP use. 62

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The ACC study assesses the economic impact from CCP utilization based on: • • • • • • •

Avoided Cost of Disposal Direct Income to Utilities Offsets to Raw Material Production Revenues to Marketing Companies Transportation Income Support Industries Research

Most important to the CCP generator is the cost savings derived from beneficial reuse options, which can be significant when compared to landfilling or other disposal options.

The ACC study assesses the avoided cost of disposal in the U.S. and the cost for disposal of unused CCPs. The study further details the net economic effect of CCP utilization on the U.S. economy and tax revenue generation potential at the federal and state levels. The final ACC report will be available in mid to late April 2005. For information, contact the ACC office at or (602) 485-4737. ◆

Andy Stewart is Principal of Power Products Engineering, (952) 974-3954.


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Fast Facts About Coal • There are four types of coal: • Lignite – a brownish-black coal with generally high moisture and ash content and the lowest carbon content. Mined in Texas, North Dakota and Montana. • Subbituminous – a coal with a higher heating value than lignite. Mined principally in Wyoming’s Powder River Basin. • Bituminous – a soft, intermediate grade of coal, most common and most widely used in the U.S. Mined in Appalachia and the Midwest. • Anthracite – the hardest type of coal consisting of nearly pure carbon, with the highest heating value and lowest moisture and ash content. Mined in the Appalachian area of Pennsylvania. • Coal is present in 38 states and underlies nearly half a million square miles – 13 percent of the nation’s land area. • Wyoming is the state with the largest production of coal – approximately 396 million tons were produced in Wyoming in 2004. • The top 10 states with the largest coal reserves (billion short tons in 2002): • Montana – 119.4 • Illinois – 104.6 • Wyoming – 65.3 • West Virginia – 33.7 • Kentucky – 30.6 • Pennsylvania – 27.8 • Ohio – 23.4 • Colorado – 16.4 • Texas – 12.6 • New Mexico – 12.2

• Nearly 52 percent of the electricity generated in the U.S. in 2004 was produced coal-fueled. • EIA is projecting 112 GW of new coal generation could come on line by 2025 – representing about 42 percent of total new electric generation in the U.S. • EIA is projecting that coal prices will remain at the current $1.25 mm/BTU level through 2025. Natural gas prices are projected to drop to $4.00 mm/BTU in 2004 and gradually increase to $4.75 mm/BTU by 2025. • States in the U.S. that choose coal for their generation have lower electricity costs. Wyoming, which generates 96 percent of its electric power from coal, has the lowest cost of electricity in the nation at 4.8 cents/kilowatt hour. California, which generates just one percent of its electric power from coal, has the highest cost of electricity in the nation at 11.5 cents/kilowatt hour. • While one accident or fatality is one too many, the rates of all types of accidental injuries in the nation’s coal industry have steadily declined in the past decade. Fatal injuries at coal mines in the U.S. declined from 55 in 1992 to 30 in 2003, while non-fatal injuries declined from 13,068 in 1992 to 5,168 in 2003. • While coal used for electric generation has increased more than one-third over the past 30 years, emissions have declined. Since 1970, SO2 emissions declined {Ð} 39 percent, CO {Ð}28 percent, volatiles {Ð} 42 percent, particulates (PM10) {Ð} 75 percent and lead {Ð} 98 percent. NOx emissions have declined 33 percent since 1990.

• The U.S. has more than 500 billion short tons of coal reserves, enough to last more than 250 years at current rates of production.

• Private industry has contributed more than two-thirds of the $4.8 billion to the federal Clean Coal Technology Demonstration Program.

• In 2004, the U.S. produced 1.111 billion tons of coal. The Energy Information Administration (EIA) is projecting production of 1.138 billion tons in 2005 and 1.5 billion tons in 2025.

• As a single commodity, coal is the most significant annual user of rail transportation. According to the Association of American Railroads (AAR), nearly 800 million tons of coal were shipped domestically by rail in 2003. ◆

• Nine out of every 10 tons of coal mined in the U.S. is used by electric power plants to generate electricity. AMERICAN COAL COUNCIL

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3/23/05 10:28:35 AM

Maps – We’ve Got Maps! The American Coal Council (ACC) and Platts have teamed up to offer a variety of energy industry maps at discounted rates. Platt’s wall maps are: • The essential first step for energy business planning. • The ultimate visual aid for the energy industry. • The easiest and most comprehensive way to visualize your market. The Platts Map Store features: • Electric Power Maps • Coal Maps • Natural Gas Maps • International Maps • Environmental/Renewables Maps Platts also offers a Custom Cartography Service. Work with Platts’ cartographers to design maps unique to your corporation and your company’s needs. The service allows you to use maps for your company’s presentations, publications, websites or as giveaways to clients at trade shows and conferences.

Visit the ACC Web site to learn more about Platts’ maps and to learn how you can qualify to receive an up to 20 percent discount on your order. Visit or call Leslie Forbes at Platts at 1-800-PLATTS (1-800-752-8878). ◆

For Coal Blending, Stockpiling and Transloading

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WILL store your cargo temporarily or as your private longterm stockpile.


3/23/05 10:28:36 AM

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3/23/05 10:28:46 AM

U.S. Mining GAAP, U.S. Mineral Reserve Reporting and New U.S. Tax Legislation By Steve Ralbovsky, PricewaterhouseCoopers LLP


here are three areas of recent accounting/tax change directly affecting mining companies: recent and proposed changes in U.S. mining GAAP; a new proposed U.S. code for mining reserves and resources; and §199 – the Qualified Production Activities deduction of the American Jobs Creation Act of 2004. Recent and Proposed Changes in U.S. Mining GAAP U.S. mining GAAP has evolved from years of industry practice, analogies to other industries, and SEC commentary. In June 2003, the SEC requested the Financial Accounting Standards Board (FASB) form an Emerging Issues Task Force (EITF) working group to address certain mining GAAP issues. The EITF developed the following issues and solutions. These positions were subsequently adopted by the FASB: 1. Mineral rights – All mineral rights, as defined, are tangible assets and should be separately disclosed in financial statements. 2. Value beyond proven and probable reserves in purchase accounting – The value of an acquired company’s minerals beyond proven and probable reserves and anticipated future market prices should be considered when determining the allocation of the purchase price in an acquisition. 3. Allocation of goodwill to separate mines in an acquisition – To be considered in an upcoming mining GAAP analysis. All of these issues are viewed favorably within the industry for their recognition that mining company acquisitions are typically predicated on potential future production and anticipated future pricing of the target company’s mineral. These positions are clearly part of the business analysis in identifying, pricing and closing acquisitions, so recognizing them for GAAP is logical and fair. The purchase accounting decisions at acquisition affect future income/loss and balance sheets of the newly combined company through amortization, depletion, impairment analyses and other financial statement categories. Those items affect product pricing, coal supply agreements, cost plus contracts and a multitude of operating measurements and decisions. Deferred Stripping Accounting for stripping costs is an issue that the EITF working group and the FASB have not yet resolved. Viable positions include: • Expensing as a period cost • Allocating to inventory (the coal or mineral recovered from the mine) • Deferring and expensing according to a stripping ratio based on total anticipated production (the widely accepted understanding of the deferred stripping concept) • Treat as a development cost, capitalize as an investment, and relieve according to the recovery of proven coal/mineral reserves in a systematic manner This matter continues to be examined in early 2005. Its resolution will also affect P&L results, balance sheets, and contract settlement amounts in future years. AMERICAN COAL COUNCIL

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A New Code for Reserves In late 2003, the SEC asked the Society for Mining, Metallurgy and Exploration (SME) to draft a new code for U.S. financial statements with mineral reserves. The SME plans to present a new, fully drafted code to the SEC for comment and then submit the code to the full SME for approval in late winter/early spring 2005. The primary issues expected to be addressed in the new code include: • Competent person • Pricing • Evidence to support reserves vs. resources standards for reporting reserves and resources vs. the use of those amounts for impairment and other GAAP purposes • Mineral resources • Permitting and legal requirements Jobs Creation Act of 2004 Congress passed a rather substantial tax bill just before the November 2004 presidential election and President Bush signed it soon thereafter. §199 – Qualified Production Activities deduction grants a deduction of up to nine percent1 of earnings from qualified U.S. activities, primarily manufacturing, software licensing, motion picture/television production and construction services. ‘Extraction’ is a qualified manufacturing activity, so it appears clear mining will qualify for the §199 deduction. The deduction is limited to the taxpayer’s net income from the qualified activity and to the 50 percent of the taxpayer’s wages paid to employees from all activities, a direct assault on outsourcing. Several elements of the legislation are unclear, for miners and for all potential taxpayers hoping to take advantage of the deduction. Some of the issues that are expected to affect mining companies in particular are: • Contract mining • Royalties • Joint ventures • The interplay of §199 and percentage depletion • Is mine development construction The §199 deduction will undoubtedly be important in negotiating future coal supply agreements where they are based on after tax amounts. It will also be important in fulfilling current net of tax cost plus agreements and other activities based on a miner’s net of tax financial results. Even if you are not your company’s controller or tax person, keep abreast of these financial reporting and tax developments. They will affect your company’s results and operations. ◆

Steve Ralbovsky is the U.S. Mining Leader for PricewaterhouseCoopers and can be reached at (602) 364-8193 or at 1

The deduction is three percent of qualified earnings in 2004 - 2006, six percent in 2007 - 2009, and nine percent for 2010 and thereafter. 67

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Index to Advertisers ADA-ES, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Ad Council. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 AIR-CURE, INC. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 ALLIANCE COAL, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 ALSTOM Power, Performance Projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Ameren Energy Fuels & Services Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 American Electric Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 Black & Veatch . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . OBC Boral Material Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 COAL-GEN Conference & Exhibition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Consol Energy Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 CSX Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 Damascus Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Dings Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 DTE Coal Services Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IFC ES & S Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Fuel Tech, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Hagby USA, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Headwaters Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Helm Financial Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Hill & Associates, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 Hoss Equipment Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 Ingram Barge Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IBC John T. Boyd Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 KCBX Terminals Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 KENNAMETAL INC. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Kennecott Energy Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 Kiewit Mining Group Inc.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 Kinder Morgan Terminals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 Marston . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 Midwest Generation, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 NEXGEN Coal Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Peabody Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Platts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 PricewaterhouseCoopers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 R.M. WILSON Co., Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 RailWorks Track Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Roberts & Schaefer Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Sandvik Mining and Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Savage Services Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 SCH Terminal Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 SGS Minerals Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Stagg Resource Consultants, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 The David J. Joseph Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 The Raring Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Union Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 United Power, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Usibelli Coal Mine, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 We Energies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Weir International Mining Consultants, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Westmoreland Coal Sales Company / Westmoreland Resources, Inc. . . . . . . . . 51 Wiley Consulting, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 WWC Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 68

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INGRAM MARINE GROUP Ingram Barge Company Dry and liquid transportation service throughout the entire Mississippi River and Gulf Intracoastal Waterway System

Triangle Fleet / Triangle Anchorage Services Barge fleeting and ship anchorage at Reserve, LA

Huntington Terminal Coal transfer from rail (CSX) to barge at Mile 306.5 Ohio River

Custom Fuel Services Midstream fuel service at New Orleans, Baton Rouge, Columbus (Cairo), Paducah, Hartford, Davenport, Catlettsburg and Point Pleasant

Ingram Materials Company Photo by Gregory Thorp

Sand producer and distributor in Tennessee, Kentucky and Alabama

INGRAM BARGE COMPANY P.O. Box 23049 • Nashville, TN 37202-3049 615-298-8200 Phone • 615-298-8213 Fax Website: ACC_2005_63_OBC.indd C Ingram_Marine_Grp_2005.indd 1

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Wisconsin Public Service Corporation Weston Unit 4 Addition

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2005 Membership Directory

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CONTENTS ACC Vision and Mission Statement . . . . . . Board of Directors . . . . . . Membership Coupon and Information . . . . . . . . ACC Event Listing . . . . . . Directory Listings . . . . . .

1 1 2 2 3

About the Cover: Peabody Energy continues to lead the nation in reclamation excellence. On Arizona’s Black Mesa, Native American lands have been reclaimed for traditional livestock grazing, while restoring plants and herbs with cultural significance. The U.S. Department of the Interior honored Peabody with its first “Gold” Good Neighbor Award in 2003 for a host of environmental, economic and tribal initiatives on Native American lands. Published for: American Coal Council 2980 E. Northern Ave., Suite B4 Phoenix, AZ 85028 Tel: (602) 485-4737 ACC Editorial Review Board Evan Ard, Evolution Markets LLC Janet Gellici, American Coal Council Rick James, We Energies Vic Svec, Peabody Energy Published by: Lester Publications, LLC 2131 NW 40th Terrace - Suite A Gainesville, FL 32605 Main Line: (352) 338-2700 Toll Free: (877) 387-2700 President Jeff Lester | (866) 953-2189 Sales Director Bob Neufeld | (866) 953-2189 Managing Editor Lisa Kopochinski | (800) 481-0265 Art Director Jennifer Karton | (877) 953-2587

American Coal Council 2005 Board of Directors COAL SUPPLIERS Jim Campbell Senior Vice President Peabody Energy Todd Myers President Westmoreland Coal Sales ACC Vice President Suppliers 2005 Bob Pusateri Vice President Sales CONSOL Energy COAL CONSUMERS Keith Drohan Director Market Origination Dominion Energy Ken Jenkins Executive Director Fuel Services Southern Company ACC Vice President Consumers 2005 Jim O’Neil President DTE Coal Services ACC President 2005 TRANSPORTATION Chris Jenkins Senior Vice President – Coal CSX Transportation ACC Vice President Transportation 2005 Tom Vorholt Vice President Dry Cargo Sales Ingram Barge

Graphic Designer Vince Saseniuk | (866) 890-8756 Account Executives Heather Campbell, Louise Peterson, Michelle Raike, Jim Siwy ©2005 American Coal Council. All rights reserved. The contents of this publication may not be reproduced by any means, in whole or in part, without the prior written consent of the ACC. Disclaimer The opinions expressed by the authors of the editorial articles contained in American Coal magazine are those of the respective authors and do not necessarily represent the opinion of the American Coal Council or its member companies. Printed in Canada Please recycle where facilities exist.


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PORTS & TERMINALS Mike Ferguson Vice President - Regional Manager Kinder Morgan Bulk Terminals ACC Vice President Ports & Terminals 2005 Bill Rager Vice President & General Manager of Operations Southern Coal Handling Co., Inc. ENERGY TRADERS West Boettger Director Energy Marketing, Dynegy Marketing & Trade ACC Vice President Energy Traders 2005 Dan Vaughn Manager Coal Services United Power Inc. COAL SUPPORT SERVICES Kevin Jennison Fuels Consulting Business Leader Black & Veatch ACC Vice President Support Services 2005 John Ward Vice President Marketing & Government Affairs Headwaters Resources ACC Treasurer 2005 & President-Elect 2006 IMMEDIATE PAST PRESIDENT Lance Fritz Vice President & General Manager Union Pacific

American Coal Council Vision Statement The ACC strives to be the pre-eminent business voice of the American coal industry.

Mission Statement The American Coal Council (ACC) is dedicated to advancing the development and utilization of coal as an economic, abundant and environmentally sound energy fuel source. The Association promotes the lawful exchange of ideas and information regarding the coal industry. It serves as an essential resource for companies that mine, sell, trade, transport or consume coal. The ACC provides educational programs, advocacy support, peer-to-peer networking forums and market intelligence that allow members to advance their marketing and management capabilities. 1

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Membership Coupon Join the more than 140 companies that recognize the importance of belonging to an Association that serves as the pre-eminent business voice of the American coal industry and advocates for coal as an abundant, economic and environmentally sound fuel source. The American Coal Council (ACC) is an alliance of coal, utility, trading, transportation, terminal and coal support service companies, advocating a non-adversial, partnering approach to business.

American Coal Council 2005 Events Mercury & MultiEmissions Compliance Strategies & Tactics for New & Existing Coal Plants

March 22-24, 2005 Hyatt Regency Union Station St. Louis, Missouri

Spring Coal Forum The ACC facilitates the lawful exchange of ideas and information regarding the American coal industry. It serves as a essential resource for companies that mine, sell, trade, transport or consume American coal. The ACC also serves as a resource for those wishing to expand or enhance business relationships in North American and international coal markets.

Membership benefits include educational programming and

Coalâ&#x20AC;&#x2122;s Renaissance: Prospects for Regenerating Coal Generation

May 18-20, 2005 Scottsdale Plaza Resort Scottsdale, Arizona

PRB Coal Use

technical seminars, advocacy support, broad-based networking, Web site, electronic and printed membership directory inclusion, newsletter and members-only electronic updates, database resources, policy input, referrals and event discounts.



please send me membership information!

Risk Management Strategies & Tactics

August 17-19, 2005 In conjunction with COAL-GEN San Antonio Convention Center San Antonio, Texas

Coal Market Strategies Coal: Electrifying the Nation

Name _________________________________________________________

October 12-14, 2005 Nashville, Tennessee

Title___________________________________________________________ Company _______________________________________________________ Address ________________________________________________________ City _________________________ State ______________Zip _____________ Phone _______________________ FAX ______________________________ E-mail _________________________________________________________

Mail or FAX to: America n Coal C ouncil 2980 E. N orthern A ve., Suite Phoenix, B4 AZ 85028 (602) 48 5-4847 ~ FAX 2

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ACC Members Directory Coal Suppliers Alliance Coal, LLC P.O. Box 22027 Tulsa, OK 74121-2027 Gary Rathburn Sr. VP Marketing (918) 295-7617 FAX: (918) 295-7360 Cell: (918) 633-1222 Alpha Natural Resources, LLC Frank Kelly Manager - Midwest Sales 2137 Vermillion St., Ste. 150 Hastings, MN 55033 (651) 437-9455 FAX: (651) 437-9496 Ron Ross, GM Western Region P.O. Box 839 Price, UT 84501 (435) 637-8650 FAX: (435) 637-8653 Arch Coal, Inc. One City Place Dr., Ste. 300 St. Louis, MO 63141 Andy Blumenfeld VP Market Research (314) 994-2876 FAX: (314) 994-2719

CAM Holdings, LLC (Central Appalachia Mining) P.O. Box 1169 Pikeville, KY 41502 Terry Coleman, Chairman (606) 432-3900 ext.307 FAX: (606) 432-0031 tcoleman@ James Slater, President (606) 432-3900 ext.310 FAX: (606) 432-0031 Commonwealth Coal Services, Inc. 5413 Patterson Ave., Ste. 200 Richmond, VA 23226-2023 Wallace Taylor, VP (804) 282-9833 FAX: (804) 282-9836 wallacetaylor@ Robert Scott, President (804) 282-9822 FAX: (804) 282-9836 bobscott@ CONSOL Energy, Inc. 1800 Washington Rd., Consol Plaza Pittsburgh, PA 15241-1421 Robert Pusateri, VP - Sales (412) 831-4401 FAX: (412) 831-4594 Cell: (412) 996-0062 Drummond Company, Inc. 1000 Urban Center Dr., Ste. 300 Birmingham, AL 35242 George Wilbanks,President - Sales (205) 945-6410 FAX: (205) 945-6440 Cell: (205) 240-2274


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Foundation Energy Sales, Inc. Jim Tellmann, President 999 Corporate Blvd., Ste. 300 Linthicum Heights, MD 21090-2227 (410) 689-7652 FAX: (410) 689-7651 Larry Deal, VP, Sales 391 Inverness Parkway, Ste. 333 Englewood, CO 80112 (303) 749-8430 FAX: (303) 749-8449 Glencore, Ltd. 301 Tresser Blvd. Stamford, CT 06901 Andrew Lawson, Trader (203) 328-3113 FAX: (203) 978-2630 Great Northern Power Development, LP 601 Jefferson St., Ste. 3600 Houston, TX 77002 Chuck Kerr, President (713) 751-7590 FAX: (713) 751-7563 James River Coal Company (804) 780-3003 FAX: (804) 649-9319 Peter Socha, President & CEO 901 E. Byrd St., Ste. 1600 Richmond, VA 23219

James River Coal Sales, Inc. (804) 780-3003 FAX: (804) 649-9319 Bob Beasley, President 901 E. Byrd St., Ste. 1600 Richmond, VA 23219 Kennecott Energy Company 505 S. Gillette Ave., P.O. Box 3009 Gillette, WY 82717-3009 Kelly Cosgrove VP Marketing & Sales (307) 687-6053 FAX: (307) 687-6009 Mike Kelley Director of Origination (307) 685-6121 FAX: (307) 687-6009 KFx, Inc. 55 Madison St., Ste. 745 Denver, CO 80206 Ted Venners, Chairman & CEO (303) 293-2992 FAX: (303) 293-8430 Kiewit Mining Group, Inc. 1000 Kiewit Plaza Omaha, NE 68131 Jeff Knapton, Marketing Manager (402) 536-3645 FAX: (402) 271-2908 Mike Nimmo Marketing Manager (402) 536-3630 FAX: (402) 271-2908


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Knott Floyd Land Company, Inc. P.O. Box 2765 Pikeville, KY 41502 (606) 874-9003 FAX: (606) 874-1261 Lynn Parrish Chairman/President Earl Roop, VP Sales NexGen Coal Services, Ltd. Charles McNeil, President - CEO 3300 S. Parker Rd., Ste. 520 Aurora, CO 80014 (303) 751-9230 FAX: (303) 751-9210 Jon Kelly, Manager 500 S. Taylor St., Unit 246 Amarillo, TX 79101-2446 (806) 371-7341 FAX: (806) 371-7528 Peabody Energy 701 Market St., Ste. 900 St. Louis, MO 63101-1826 Vaughn Mavers VP Sales & Marketing (314) 342-7522 FAX: (314) 342-7529 James Campbell, Jr. Sr. VP Sales & Marketing (314) 342-7520 FAX: (314) 342-7529

Pittsburg & Midway Coal Mining 4601 DTC Blvd., Ste. 600 Denver, CO 80237-2549 Dave Lofe, Sales Manager (303) 930-4050 FAX: (303) 930-4043 Cell: (303) 913-1704 James DeMino General Manager - Sales (303) 930-4060 FAX: (303) 930-4043 Progress Fuels Corporation Fred Verardi, Sr. VP 100 E. Davie St. TPP 9 Raleigh, NC 27601 (919) 546-7659 FAX: (919) 546-7165 Albert Pitcher VP Coal Procurement One Progress Plaza TC10C St. Petersburg, FL 33701 (727) 824-6692 FAX: (727) 824-6601 Cell: (727) 480-4508 Roundup Trading International, LLC 275 Madison Ave., Ste. 1505 New York, NY 10016-1101 Jerry Daseler VP Marketing & Sales (636) 399-7266 FAX: (212) 490-0557 The North American Coal Corporation 14785 Preston Rd., Ste. 1100 Dallas, TX 75254-7891 Clark Moseley, VP Business Development Engineering (972) 448-5470 FAX: (972) 661-9072


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Usibelli Coal Mine, Inc. Steve Denton VP Business Development P.O. Box 1000 Healy, AK 99743 (907) 683-9710 FAX: (907) 683-2253 Bill Brophy VP Customer Relations 100 Cushman St., Ste. 210 Fairbanks, AK 99701-4674 (907) 452-2625 ext. 232 FAX: (907) 451-6543 Cell: (907) 322-6449 Western Fuels Association P.O. Box 33424 Denver, CO 80233-3424 FAX: (303) 450-1042 Duane L. Richards, CEO (303) 450-9976 ext. 204 Murari Shrestha, Director Engineering & Contracts (303) 450-9976 ext. 203 Westmoreland Coal Sales Co. 2 North Cascade Ave., 14th Fl. Colorado, Springs CO 80903 Todd Myers, President (719) 448-5802 FAX: (719) 448-5824 Ed Demeter, VP Sales (719) 448-5829 FAX: (719) 448-5826

Coal Consumers Alliant Energy 4902 N. Biltmore Lane P.O. Box 77007 - MSN GO 3S Madison, WI 53707-1007 Cynthia Lord Manager Fossil Fuel Procurement (608) 458-3417 FAX: (608) 458-0137 Cell: (608) 219-8050 Ameren Energy Fuels & Services Co. 1901 Chouteau Ave. St. Louis, MO 63101 Mike Mueller, VP 314-554-4174 FAX: 314-554-4188 James Sobule, Managing Associate General Counsel (314) 554-2276 FAX: (314) 554-4014 American Electric Power P.O. Box 16036 Columbus OH 43216 Mike DeBord, VP - Transportation & Combustion Services (614) 583-7454 FAX: (614) 583-1617 Ron Young, Managing Director Transportation Services (614) 583-6303 FAX: (614) 583-1619

Xcoal Energy & Resources P.O. Box 551 Latrobe, PA 15650-9628 Ernie Thrasher, President (724) 520-1630 FAX: (724) 537-6475


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Basin Electric Power Cooperative 1717 E. Interstate Ave. Bismarck, ND 58503 Mike Risan, Sr. VP Transmission 701-223-0441 FAX: 701-224-5332 Ken Hermanson Director Fuels & Transportation (701) 355-5648 FAX: (701) 255-5144 Colorado Springs Utilities P.O. Box 1103 MC-1328 Colorado Springs, CO 80947-1321 Gregory Berwick Manager Fuel Supply Energy Supply Department (719) 668-5653 FAX: (719) 668-5951 Constellation Energy 111 Market Place, Ste. 200 Baltimore, MD 21202 John Long Sr. VP Power Generation (410) 230-4910 FAX: (410) 230-4669 Dominion Energy P.O. Box 25593 Richmond, VA 23260 Keith Drohan Director Market Origination (804) 787-5765 FAX: (804) 787-6482

DTE Coal Services


Jim Oâ&#x20AC;&#x2122;Neil, President 425 S. Main, Ste. 201 Ann Arbor, MI 48104 (734) 913-2294 FAX: (734) 994-5842

James Marbury General Plant Manager 3500 Houston River Rd. Westlake, LA 70662 (337) 494-6100 FAX: (337) 494-6107 Cell Phone: (337) 515-9199

Matt Paul VP Coal & Emissions Trading 414 S. Main, Ste. 200 Ann Arbor, MI 48104 (734) 887-2053 FAX: (734) 887-2248 Duke Power Company 526 South Church St., P.O. Box 1006 Charlotte, NC 28201-1006 Sonny Cook, Jr., Director Fossil Hydro Planning & Strategy (704) 382-5825 FAX: (704) 382-5869

Michael Kolbus, Plant Manager 555 Point Ferry Rd. Newark, AR 72562 (870) 698-4500 FAX: (870) 698-4595 FirstEnergy Generation Corp. 395 Ghent Rd., Ste. 213 Akron, OH 44333 Robert Cymbor, General Manager Fuel Procurement (330) 315-7456 ext. 7 FAX: (330) 315-7464

Edison Mission Energy Fuel Services 440 S. La Salle St., Ste. 3500 Chicago, IL 60605

James Parks, Director Fuel Supply (330) 315-7450 FAX: (330) 315-7464

Larry Siler Manager Fuel Transportation (312) 583-6068 FAX: (312) 788-5536

Gainesville Regional Utilities P.O. Box 147117 Station A137 Gainesville, FL 32614-7117

Bud Walker, Regional VP Fuels (312) 583-6041 FAX: (312) 583-4916

Karen Alford, Fuels Manager (352) 334-3400 ext. 1730 FAX: (352) 334-2786 Cell: (352) 334-1730 Thomas Foxx, Coal Analyst (352) 334-3400 ext. 1736 FAX: (352) 334-2786 Great River Energy

Carlyle Sulzer Manager Generation Services 17845 E. Highway 10, P.O. Box 800 Elk River, MN 55330-0800 (763) 241-2490 FAX: (763) 241-6290 Holcim, Inc./ St. Lawrence Cement Co. 6211 Ann Arbor Rd. Dundee, MI 48131 Jim Gilbert, Commodity Manager - Solid Fuels (734) 529-4547 FAX: (734) 529-4237 Lafarge North America Matthew Nau, Director of Strategic Sourcing Solid Fuels 12950 Worldgate Dr., Ste. 500 Herndon, VA 20170 (703) 480-6638 FAX: (703) 480-6630 Brian C. Cullum, Utility Services 600 S.W. Jefferson St. Leeâ&#x20AC;&#x2122;s Summit, MO 64063 (816) 251-2167 FAX: (816) 253-2748 Lakeland Electric 501 E. Lemon St. Lakeland, FL 33801 Carol Rowland , Fuels Coordinator (863) 834-6583 FAX: (863) 834-8393 carol.rowland@ Cell: (863) 640-0308 Rick Snyder, Manager Wholesale Energy & Fuels 863-834-6586 FAX: 863-834-8393

Al Christianson, North Dakota Business Services Representative 2875 3rd St. S.W. Underwood, ND 58576-9659 (701) 442-7031 FAX: (701) 442-7231 Cell: (701) 220-4881 2005 MEMBERSHIP DIRECTORY

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LG&E Energy 220 W. Main St., 4th Floor, P.O. Box 32010 Louisville, KY 40202

Omaha Public Power District 444 S. 16th St. Mall Omaha, NE 68102

Caryl Pfeiffer, Director Corporate Fuels & By-Products (502) 627-2774 FAX: (502) 627-2550

Ronald Boro Manager Fossil Fuels (402) 514-1041 FAX: (402) 514-1043 Cell: 402-699-1937

Mike Dotson Manager LG&E & KU Fuels (502) 627-2322 FAX: (502) 627-3243 MidAmerican Energy Company 106 E. 2nd St. Davenport, IA 52801 Robert Quast Coal Portfolio Mgr. (563) 333-8219 FAX: (563) 333-8696 Paul Freund, VP Fuel Trading and Transportation (563) 333-8131 FAX: (563) 333-8696 Minnesota Power 1259 N.W. 3rd St. Cohasset, MN 55721 Kathy Benham, Fuels Planner (218) 328-5036 ext. 4624 FAX: (218) 328-6573 Cell: (218) 259-3726 Bob Davis, Manager Fuel Services (218) 328-5036 ext. 4665 FAX: (218) 328-6573 North American Power Group Ltd. 8480 E. Orchard Rd., Ste. 4000 Greenwood Village, CO 80111 Mike Ruffatto, President (303) 796-8600 FAX: (303) 773-0461


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Ontario Power Generation P.O. Box 2000, Reg Rd. 55 So. Nanticoke, ON., CANADA N0A 1L0 Ian MacKenzie Manager Fuel Ash & Site Service (519) 587-2201 ext. 3653 FAX: (519) 587-6827 Orlando Utilities Commission 6113 Pershing Ave. (32822) P.O. Box 3193 Orlando, FL 32802 Jan Aspuru, Director Fuel Services (407) 384-4081 FAX: (407) 384-4067 Fred Haddad (407) 423-9100 FAX: (407) 384-4067 PacifiCorp 201 S. Main St., Ste. 2100 Salt Lake City, UT 84111 Dave Smaldone Managing Director Fuel Handling (801) 220-4607 FAX: (801) 220-4725 Rod Roberts, Manager Engineering/Environmental (801) 220-4577 FAX: (801) 220-4028

Portland General Electric 121 S.W. Salmon St. Portland, OR 97204 Tom Shewski Manager, Coal & Transportation (503) 464-7399 FAX: (503) 464-2605 PPL Energy Plus 2 N. 9th St., PL7 Allentown, PA 18101 Ben Stothart, ManagerCoal Supply & Transportation (610) 744-5500 FAX: (610) 774-5141 Progress Energy 411 S. Wilmington Ave. Raleigh, NC 27602 Dwain Lanier, Executive Director - Fossil Fuels Department (919) 546-2400 FAX: (919) 546-4721 Bill Knight, Director Procurement & Risk Mgt. (919) 546-3261 FAX: (919) 546-2590 Cell: (919) 280-2346 Salt River Project Mail Station POB001 P.O. Box 52025 Phoenix, AZ 85072-2025 Randy Dietrich, Manager Fuels (602) 236-4311 FAX: (602) 236-4322 Tom Abdali, Sr. Fuels Analyst (602) 236-4305 FAX: (602) 236-4322

SCANA Corporation Sarena Burch, Sr. VP Fuel Procurement & Asset Mgmt. 1426 Main St., MC 191 Columbia, SC 29201 (803) 217-9321 FAX: (803) 933-8201 Gerhard Haimberger GM - Fuel Procurement and Asset Management 111 Research Dr. Columbia, SC 29203 (803) 217-9548 FAX: (803) 217-7740 Cell: 803-530-3287 Southern Company P.O. Box 2641 Birmingham, AL 35242 Ken Jenkins Executive Director Fuel Services (205) 257-7228 FAX: (205) 257-7795 Susan Comensky Director Coal Services (205) 257-0298 FAX: (205) 257-7795 Texas Genco LP Rte. 1, Box 85 Jewett TX 75846 Arlis Jones, Staff Engineer (903) 626-9708 FAX: (903) 626-9766 Mark Berend Manager Solid Fuel Operations (903) 626-9534 FAX: (903) 626-9766


3/22/05 4:28:10 PM

TransAlta Utilities Corporation P.O. Box 1900 Station M Calgary, AB, CANADA T2P 2M1 Paul Clark, Director, Fuel Supply (403) 267-7325 FAX: (403) 267-7202 Tucson Electric Power Company 3950 E. Irvington Rd. Tucson, AZ 85714 David Jacobs Dir/Fuel and Resource Planning (520) 745-7190 FAX: (520) 571-4052 Patricia Rodriguez Lead Fuels Analyst (520) 745-3264 FAX: (520) 571-4052 TXU Energy 1717 Main St., Ste. 1900 Dallas, TX 75201 Allen Childress Manager Coal Trading (214) 875-9739 FAX: (214) 875-9051 We Energies 333 W. Everett St., Rm. A-226 Milwaukee, WI 53203 Klaus Mylotta, Manager - Coal Resources & Emission Allowances (414) 221-2620 FAX: (414) 221-2683

Westar Energy 818 Kansas Ave., P.O. Box 889 Topeka, KS 66612 Randall Rahm Director - Fuel Services (785) 575-8140 FAX: (785) 575-8173 Jerry Kroeker, Manager - Fuels (785) 575-1864 FAX: (785) 575-1797 WPS Resource Corporation 600 North Adams St. Green Bay, WI 54307-9002 Karen Kollmann Director-Fossil Fuel Services (920) 433-1301 FAX: (920) 433-1011 Xcel Energy Karen Roberts Regional Manager Coal Supply 600 S. Tyler, #2703 Amarillo, TX 79170 (806) 378-2505 FAX: (806) 378-2790 Cell: (806) 767-6576 Gerald (Gerry) Zimmerman Regional Manager-Coal 1099 18th St., Ste. 3000 Denver, CO 80202 (303) 308-2736 FAX: (303) 308-2738

Energy Traders Dynegy Marketing & Trade 1000 Louisiana St., # 5800 Houston, TX 77002 West Boettger Director Energy Marketing (713) 767-6082 FAX: (713) 767-6695


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Evolution Markets LLC 10 Bank St. White Plains, NY 10606 (914) 323-0250 FAX: (914) 328-3701 Tom Hiemstra, VP Coal Services Stephen Nesis, Managing Director Koch Carbon LLC 20 Greenway Plaza Houston, TX 77046 Brad Speer, VP Coal Trading (713) 544-5678 FAX: (713) 544-6052 Cell: (713) 907-5678 Millennium Environmental Group Mike Ferguson, Director Mail Stop UE201 P.O. Box 711 Tucson, AZ 85702 (360) 891-0590 FAX: (360) 882-3185 Curt Kaminer, Portfolio Manager Mail Stop UE205, P.O. Box 711 Tucson, AZ 85702 (520) 884-2617 FAX: (520) 884-3602 Natsource, LLC 100 William St., Ste. 2005 New York, NY 10038 (212) 232-5305 FAX: (212) 232-5353

SSM Coal Americas, LLC Charles Rountree, VP 10500 Little Patuxent Parkway Columbia, MD 21044 (410) 910-0640 FAX: (410) 910-0630 John Bach, Coal Marketer 1221 Lamar 7th Floor Houston, TX 77010 (713) 371-8407 FAX: (713) 371-8960 The C. Reiss Coal Company Fletcher Dennis, General Manager Coal Supply & Distribution 2525 Harrodsburg Rd., Ste. 130 Lexington, KY 40504 (859) 296-2100 ext2111 FAX: (859) 224-0782 Bill Reiss, President P.O. Box 688 Sheboygan, WI 53082-0688 (920) 451-8910 FAX: (920) 457-4417 United Power, Inc. Daniel Vaughn Manager, Coal Services 5801 Ledgestone Dr. Evansville IN 47711 (812) 473-5810 FAX: (812) 473-5813 Cell: (812) 204-2625 Ian Tapsall, Manager, Coal Desk 187 Danbury Rd. Wilton CT 06897 (203) 762-8493 FAX: (203) 762-1025


3/22/05 4:28:11 PM

Transportation Companies Burlington Northern Santa Fe Railway Co. P.O. Box 961051 Ft. Worth, TX 76161-0051 Tom Kraemer Group VP, Coal Business Unit (817) 867-6242 FAX: (817) 352-7940 Sami Shalah VP Coal Marketing East (817) 867-6253 FAX: (817) 352-7939 Canadian NationalIllinois Central Railroad Bryan Vaughan, Director Coal 17641 S. Ashland Ave. Homeland, IL 60430 (708) 647-3847 FAX: (708) 647-3673 Ross Goldsworthy, VP Bulk 234 Donald St. Winnipeg, MB, CANADA R3C 4B4 CSX Transportation 500 Water St., J120 Jacksonville, FL 32202 Chris Jenkins VP, Coal and Automotive (904) 366-5693 FAX: (904) 359-3443 Cell: (904) 616-4359 Dennis Damron VP Coal Sales & Marketing (904) 359-3380 FAX: (904) 359-4890


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Dakota, Minnesota & Eastern Railroad Corp. 140 N. Phillips Ave., P.O. Box 1260 Sioux Falls, SD 57101 Kevin Schieffer, President & CEO (605) 782-1206 FAX: (605) 782-1299 Lynn Anderson, VP, Marketing (605) 782-1234 FAX: (605) 782-1299 Ingram Barge Company 4400 Harding Rd., 1 Belle Meade Nashville, TN 37205-2290 Tom Vorholt, VP Utility Sales (615) 298-8214 FAX: (615) 298-8213 Joe Johnson, Director, Utility Sales (615) 298-8255 FAX: (615) 298-8213 Interlake Steamship Company 4199 Kinross Lakes Parkway Richfield, OH 44286 John Hopkins, VP - Marketing (330) 659-1402 FAX: (330) 659-1445 jhopkins@ Kansas City Southern Railway P.O. Box 219335 Kansas City, MO 64121 Jeffrey Sheldon, Assistant VP (816) 983-1944 FAX: (816) 983-1418

Midwest Railcar Corporation 9876 213th Ave. N.W. Elk River, MN 55330 Rich Murphy, President & CEO (763) 441-6412 FAX: (763) 441-6422 John Meade, VP - Sales (865) 689-2988 FAX: (865) 689-2989 Norfolk Southern Corporation Ronald Listwak Assistant VP Utility Coal North 2001 Market St., 29th Floor Philadelphia, PA 19103 (215) 209-4243 FAX: (215) 209-4240 Daniel Smith Sr. VP Energy & Properties 3 Commercial Place Norfolk, VA 23510-9205 (757) 629-2813 FAX: (757) 533-4918 Paducah & Louisville Railway, Inc. 1500 Kentucky Ave. Paducah, KY 42003 Dave Goewert Assistant VP Marketing & Sales (270) 444-4338 FAX: (271) 444-4388 Rail Link, Inc. 1231 West Dry Creek Rd. Littleton, CO 80123 Jim Lynn (303) 798-2133 FAX: (303) 324-3693

Savage Services Corporation 6340 South 3000 E., Ste. 600 Salt Lake, City UT 84121 Charlie Monroe, Sr. VP Coal Services Development (801) 944-6629 FAX: (801) 944-6520 Cell: (801) 694-2208 David G. Wolach, Executive VP Savage Services Corporation (801) 944-6613 FAX: (801) 944-6520 Cell: (801) 694-2204 Union Pacific Railroad Company 1400 Douglas St., STOP 1260 Omaha, NE 68179-1260 Lance Fritz, VP & GM - Energy (402) 544-5678 FAX: (402) 501-0163 James Lorenz Sr. Business Manager Energy (402) 544-6272 FAX: (402) 233-3038

Ports & Terminals AEP/Cook Coal Terminal P.O. Box 870 Metropolis, IL 62960 Jim Garrett, Manager (618) 524-1920 FAX: (618) 524-1969 KCBX Terminals Company 3259 E. 100th St. Chicago, IL 60617 Tom Kramer, General Manager (773) 978-8317 FAX: (773) 375-3153 Cell: (312) 208-9964


3/22/05 4:28:12 PM

Kinder Morgan Bulk Terminals, Inc. Don Duff, Sr. VP Marketing & Engineering P.O. Box 625 Sorrento, LA 70810 (800) 535-8170 FAX: (225) 675-8259 Cell: (225) 892-5269 Michael Ferguson VP - Regional Manager 1801 Milford St. Charleston, SC 29405 (843) 722-2878 FAX: (843) 722-5720 Cell: (842) 412-4609 Midwest Energy Resources P.O. Box 787, W. Winter & Ajax Rd. Superior, WI 54880 Daniel McDonald VP & Controller (715) 395-3506 FAX: (715) 392-9137

Thunder Bay Terminals, Ltd. 95 St. Clair Ave. W., Ste. 1101 Toronto, ON CANADA M4V 1N6

Standard Laboratories, Inc. 1880 North Loop Dr. Casper WY, 82601 (307) 234-9957 FAX: (307) 234-0013

Hilary Goldenberg, President (416) 515-7449 FAX: (416) 515-1798

Steve Miladinovich, Jr. Western Division Manager

Coal Support Services – Analytical & Environmental Services ADA Environmental Solutions, Inc. 8100 SouthPark Way, Unit B Littleton, CO 80120 (303) 734-1727 FAX: (303) 734-0330 Michael Durham, Ph.D., President Ronda Zivalich Manager, Chemical Products Cell: (303) 921-8126

Fred Shusterich, President (715) 395-3516 FAX: (715) 392-9137

Sampling Associates International P.O. Box 338 Newport News, VA 23185

SCH Terminal Co., Inc. 2850 N. Main St. Madisonville, KY 42431

Paul M. Reagan, President (757) 928-0484 FAX: (757) 928-0482

Bill Rager, VP & General Manager (270) 821-5149 ext. 131 FAX: (270) 825-3158 Cell: (207) 841-9907 Gary Quinn, VP Utility Services (423) 899-0591 FAX: (423) 485-9233

SGS North America Inc. 4665 Paris St., B-200 Denver, CO 80239-3117 (303) 373-4772 FAX: (303) 373-4884 Marc Rademacher VP Western Operations Cell: (303) 589-0248

Coal Support Services – Equipment & Materials Suppliers ALSTOM Power, Performance Projects 2000 Day Hill Rd., CEP 2404 Windsor, CT 06095 Dave O’Neill, General Manager (860) 285-5012 FAX: (860) 285-9676 dave.o’ Pat Jennings Business Development Manager (860) 285-4010 FAX: (860) 285-4304 Benetech, Inc. 1851 Albright Rd. Montgomery, IL 60538 Chris Blazek, VP Marketing (630) 844-1300 ext. 214 FAX: (630) 844-0064 Ronald Pircon, President/CEO (630) 844-1300 ext. 213 FAX: (630) 844-0064 Cell: 630-258-2838 Fuel Tech, Inc. 512 Kingsland Dr. Batavia, IL 60510 Chris Smyrniotis, VP, Technology & Market Development (630) 845-4461 FAX: (630) 845-4501 Steve Brady (630) 845-4420 FAX: (630) 845-4501


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FreightCar America Two North Riverside Plaza, Ste. 1250 Chicago, IL 60606 (312) 928-0850 FAX: (312) 928-0890 Ed Whalen Sr. VP, Marketing & Sales GE Betz 4636 Somerton Rd. Trevose, PA 19053-6783 Bryce Uytiepo PE, Sr. Project Engineer (215) 942-3494 FAX: (215) 953-5757 Nalco Company 416 Fox Meadow Dr. Wexford, PA 15090 Peter Ten Eyck Technical Consultant (412) 576-5221 FAX: (724) 935-4577 Steve Blubaugh, Industry Development Manager Coal (888) 879-7656 Orica USA, Inc. 33101 East Quincy Ave. Watkins, CO 80137 (303) 268-5034 FAX: (303) 268-5134 David Bullis, Director Nitrogen Products - America Pioneer Mechanical 1138 164th St. Hammond, IN 46320 (219) 937-2922 FAX: (219) 937-0925 Ken Hefner, President kenmhefner@


3/22/05 4:28:12 PM

The Raring Corporation 12007 NE 95th St. Vancouver, WA 98682 (360) 892-1659 FAX: (360) 892-1624 David Raring, President Kathleen Putek, Office Manager Separation Technologies, LLC 101 Hampton Ave. Needham, MA 02494 Dave Timmerman VP Business Development (781) 455-6600 ext. 209 FAX: (781) 455-6518 Cell: (603) 793-9008 Titan America 1151 Azalea Garden Rd. Norfolk, VA 23502 Daniel Greenhaus Director, Corporate Procurement (757) 858-6545 FAX: (758) 855-7707 Trinity Industries One Tower Lane, Ste. 2900 Oakbrook Terrace, IL 60181 (630) 571-5929 FAX: (630) 571-5724 Jim Sobie, VP - Marketing

Coal Support Services â&#x20AC;&#x201C; Financial & Marketing Associations Boral Material Technologies Harry Roof Manager Utility Relations 45 N.E. Loop 410, Ste. 700 San Antonio, TX 78216 (210) 349-4069 FAX: (210) 349-8512 John Scoggan Sr. VP Utility Services 1343 Canton Rd., Ste. C Marietta, GA 30066 (770) 423-1883 FAX: (770) 423-1613 CIT Rail Resources 1211 Avenue of the Americas New York, NY 10036 Steve McClure, President (212) 536-9333 FAX: (212) 536-9397 Bill Oâ&#x20AC;&#x2122;Brien, Assistant VP (212) 536-9366 FAX: (212) 536-9397 David J. Joseph Company 300 Pike St. Cincinnati, OH 45202 (513) 621-8770 FAX: (513) 345-4374 Trey Savage, Regional Manager


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DTE Rail Services 350 Indiana St., Ste. 600 Golden, CO 80401 John Pfisterer, President (303) 216-4264 FAX: (303) 216-4281 Nick Keys, Director Sales (303) 216-4269 FAX: (303) 216-4282 Cell: (303) 888-9790 GE Rail Services 161 N. Clark St., 7th Fl. Chicago, IL 60601 (312) 853-5395 FAX: (312) 853-5182 James Zoellick, Asset Manager Headwaters Incorporated 10653 S. Riverfront Parkway, Ste. 300 South Jordan, UT 84095 (801) 984-9400 FAX: (801) 984-9410 Ken Frailey, President Headwaters Energy Services John Ward, VP Marketing & Communications Helm Financial Corporation One Embarcadero Center, Ste. 3700 San Francisco, CA 94111

Mineral Resource Technologies 2700 Research Forest Dr., Ste. 150 The Woodlands, TX 77386 (281) 362-1060 FAX: (281) 362-1809 Mike Silvertooth Business Development Manager PNC Bank, NA 249 Fifth Ave. Pittsburgh, PA 15222-2707 Christopher Moravec, Sr. VP (412) 762-2540 FAX: (412) 705-3232 christopher.moravec@ PricewaterhouseCoopers LLP 1850 N. Central Ave., #700 Phoenix, AZ 85004-4545 Steve Ralbovsky (602) 364-8193 FAX: (602) 364-8005 Railroad Financial Corporation 676 N. Michigan Ave., #2800 Chicago, IL 60611 (312) 222-1383 FAX: (312) 222-1470 David Nahass, Sr. VP Cell: (312) 543-1927 Anthony Kruglinski, President

Ed Garvey, Sr. VP (415) 398-4316 FAX: (415) 398-4816


3/22/05 4:28:13 PM

Coal Support Services â&#x20AC;&#x201C; Technical & Economic Consultants Air Control Science, Inc. 6560 Odell Pl. Boulder, CO 80301 John Fischer, CEO & President (303) 581-1070 FAX: (303) 530-7208 Cell: (303) 378-1449 Peter Fischer, VP (303) 530-2985 FAX: (303) 530-7208 Argus Media, Inc. 1012 Fourteenth St. N.W., Ste. 1500 Washington, DC 20005 Miles Weigel, Sr. VP (202) 775-0240 FAX: (202) 872-8045 Black & Veatch 11401 Lamar Ave. Overland Park, KS 66211 April Anderson-Higgs Fuels Consulting Project Manager (913) 458-9740 FAX: (913) 458-9740 Gene King, Marketing Specialist (913) 458-4606 FAX: (913) 458-2934 Kevin Jennison, Fuels Consulting Services Leader (913) 458-9762 FAX: (913) 458-2122

Global Energy Decisions

John T. Boyd Company

Gary Hunt, President 2379 Gateway Oaks Dr., Ste. 200 Sacramento, CA 95833 (916) 609-7750 FAX: (910) 569-0999

Richard Bate, VP 999 18th St., 1400 S. Tower Denver Pl. Denver, CO 80202 (303) 293-8988 FAX: (303) 293-2232

Hans Daniels Manager Coal Advisory Services 1495 Canyon Blvd., Ste. 100 Boulder, CO 80302 (720) 240-5544 FAX: (720) 240-5501 Hazen Research, Inc. 4601 Indiana St. Golden, CO 80403 (303) 279-4501 FAX: (303) 279-1528 Charles (Rick) Kenney, VP Robert Reeves, Sr. Project Manager Hellerworx, Inc. 4803 Falstone Ave. Chevy Chase, MD 20815 Jamie Heller, President (301) 654-1980 FAX: (301) 718-1878 Hill & Associates, Inc. P.O. Box 3475 Annapolis, MD 21403 Jeff Watkins, President (410) 263-6616 FAX: (410) 268-0923

Bill Wolf, Sr. Analyst 1500 Corporate Dr., Ste. 100 Canonsburg, PA 15317 (724) 873-4400 FAX: (724) 873-4401 Marston & Marston, Inc.

Norwest Corporation 136 E. South Temple, 12th Fl. Salt Lake City, UT 84111 (801) 539-0044 FAX: (801) 539-0055 Donovan Symonds, President Kirk Weber VP & General Manager PA Consulting Group 1750 Pennsylvania Ave. N.W., Ste. 1000 Washington, DC 20006 (202) 442-2543 FAX: (202) 442-2448

Kip Williams VP & Sr. Geological Consultant 3300 Nacogdoches Rd., Ste. 115 San Antonio, TX 78217 (210) 655-1185 FAX: (210) 655-0818

Jerry Eyster

Bill Meister, Sr. VP & Sr. Mining Consultant 13515 Barrett Parkway Dr., Ste. 260 St. Louis, MO 63021 (314) 984-8800 FAX: (314) 984-8770

Mark Bossard Director Solid Fuels Services (703) 227-8768 FAX: (703) 818-9108 Cell: (703) 431-1131

Mitsui Rail Capital, LLC 5215 Old Orchard Rd., Ste. 505 Skokie IL 60077 Harry Zander VP, Sales & Marketing (847) 581-3833 FAX: (847) 581-3831 Yasushi Imai (847) 581-3834

Pace Global Energy Services 4401 Fail Lakes Court, Ste. 400 Fairfax, VA 22033

Gary Vicinus, VP (703) 227-8802 FAX: (703) 818-9100 Pincock, Allen & Holt 274 Union Blvd., Ste. 200 Lakewood, CO 80228 Raja Upadhyay, President (303) 986-6950 FAX: (303) 987-8907 Platts Analytics & Forecasting 3333 Walnut St. Boulder, CO 80301 Andy Roberts, Sr. Consultant (720) 548-5776 FAX: (720) 548-5001


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Roberts & Schaefer Company 5225 Wiley Post Way, #300 Salt Lake City, UT 84116 (801) 364-0900 FAX: (801) 364-0909 Mark Collett VP Project Development Brian Petersen Sr. VP & General Manager SolArc, Inc. 320 S. Boston, Ste. 600 Tulsa, OK 74103 (918) 594-7320 FAX: (918) 594-7330 Angie Brashears, Marketing Communications Manager Dale St. Denis VP Solutions Marketing Stagg Resource Consultants, Inc. 5457 Big Tyler Rd., P.O. Box 7028 Cross Lanes, WV 25356 Alan Stagg, President (304) 776-6660 FAX: (304) 776-7867 Cell: (304) 610-8505

Troutman Sanders LLP 401 9th St. N.W., Ste. 1000 Washington, DC 20004-2134 Sandra Brown, Partner (202) 274-2959 FAX: (202) 654-5603 sandra.brown@ Weir International Mining Consultants 1431 Opus Pl., Ste. 210 Executive Towers West I Downers Grove, IL 60515 (630) 968-5400 FAX: (630) 968-5401 John Sabo, Sr. VP Dennis Kostic, President & CEO

The Coal Association of Canada 502, 205 - 9th Ave. SE Calgary, AB CANADA T2G 0R3 Allen Wright, Executive Director (403) 262-1544 FAX: (403) 265-7604 Bob Bell, Chairman (780) 420-5827 Center for Energy & Economic Development (CEED) P.O. Box 288 Franktown, CO 80116

Western Region Ash Group (WRAG) Richard Halverson – Headwaters Resources, Inc. 950 Andover Park E., #24 Tukwila, WA 98188 (206) 394-1364 FAX: (206) 394-1366 Duane Steen Administration & Project Manager Montana-Dakota Utilities Co. 400 N. 4th St. Bismarck, ND 58501 (701) 222-7804 FAX: (701) 222-4875 Cell: (701) 220-7924

Honorary Member

Contributing Supporters

Terry Ross, VP West Region (303) 814-8714 FAX: (303) 814-8716

American Coal Ash Association 15200 E. Girard Ave., Ste. 3050 Aurora, CO 80013-3955

University of Kentucky Center for Applied Energy Res. 2540 Research Park Dr. Lexington, KY 40511-8410

David Goss, Executive Director (720) 870-7897 FAX: (720) 870-7889

James Hower, Sr. Scientist (859) 257-0261 FAX: (859) 257-0360 West Virginia University Nat’l Research Center for Coal & Energy P.O. Box 6064, Evansdale Dr. Morgantown, WV 26506-6064

Vernon Songer 112 Rainbow Circle Raymore, MO 64083 (816) 331-0612 FAX: (816) 509-7530

ACC Legal Counsel Walters Law Firm, P.C. 2015 York St. Denver, CO 80205 Bill Walters ACC Legal Counsel (303) 322-1404 FAX: (303) 377-5668

Richard Bajura, Director (304) 293-2867 FAX: (304) 293-3749 Cell: (304) 216-0360

Index to Advertisers Arch Coal, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IFC CIT Rail Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IBC 12

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Mitsui Rail Capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . OBC


3/22/05 4:28:14 PM

© 2003 CIT Group Inc. "c it" and "We see what you see" are trademarks of CIT Group Inc.

The average CIT Rail Resources representative has been working with the railroad for 20 years. So when they tell you that we feature the industry’s most modern fleet and flexible leasing and financing options, you can be sure they know what they’re talking about. For details, visit us online at We see what you see.

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American Coal Issue 1 2005  
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